Stimulation Manual ONGC 2008

Stimulation Suite 2008________________________________________________

Well Stimulation Suite 2008 “Developments in Stimulation Techniques and Candidate Well Selection” Program 22 February 11 to February 15, 2008 Presented To ONGC on behalf of

By Denis R. Gaudet, P.Eng. DRG Resources Ltd. Calgary, Alberta, Canada © Porteous Engineering Limited Permission granted to DRG Resources Ltd and John H Martin Associates Ltd for this course material and presentation.

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INTRODUCTION 1.1

OBJECTIVE

The objective of a previous version of the present Well Stimulation Suite 2008, called "Advanced Hydraulic Fracturing and Well Stimulation", by W. Robert Porteous of Porteous Engineering Limited, Calgary, Canada, was to help each participant of the seminar to understand the main concepts concerning hydraulic fracturing and other well stimulation methods, including the technological background, as well as many of the special features and techniques that had been developed. For convenience of participants, this present version can be divided into three segments. In the first segment, information is presented starting with the basics. The second segment assumes that the participants have already taken the first segment or have equivalent experience due to practical exposure to well stimulation, either through experience, training or, preferably, both. Therefore, in the presentation of the second segment, fundamental aspects do not receive as much classroom attention as in the first. The classroom emphasis will be on the more recent and/or advanced aspects in the second segment of the Suite. The third segment begins with a detailed discussion of matrix and fracture acidizing and then covers very recent developments in hydraulic fracturing as well as new and emerging technologies in well stimulation. While the text has been re-written, substantially updated and divided into three main categories, one for each course segment, nothing significant has been removed from any of the segments. The texts should, therefore, continue to serve well as useful reference material. Consequently, the Suite and its segments should help participants of all experience levels to find ways to improve the cost-effectiveness and overall benefits of stimulation expenditures. This course, with input from the participants, and exchange of ideas and experiences, should result in every participant improving his or her ability to profitably and prudently apply well stimulation in daily operations.

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This course is structured for presentation to both field and office personnel from the production, reservoir, drilling, completions, exploration, and economics departments. Different companies describe these departments, groups or individual team members with various terminologies. We have chosen the traditional ones. It is assumed that each attendee has enrolled in the appropriate segment(s). For enrolment in the advanced segment, a suggested prerequisite is at least basic exposure to hydraulic fracturing, in theory, practice, or both. In order to accommodate any individual who has not had previous instruction or experience, the essential concepts are presented in the first segment. The more experienced participants may find some of the first segment to be a useful refresher course. 1.2

COURSE CONTENT

The three segments of Well Stimulation Suite 2008 consist of covering the following areas: First Segment

Introductory Material Review of Reservoir Characteristics Formation Damage Theory of Hydraulic Fracturing Deciding which Wells to Fracture Predicting the Results of Fracturing Fracturing Fluids Propping Agents Basic Treatment Sizing Equipment & Operations Overview

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Second Segment Information Collection Laboratory Work Development of Best Strategy Best Design Use of 3D Simulators Economic Optimization On-site Use of 3-D Simulators Decision Tree for on-the-fly Use Operational Guidelines Quality Assurance Procedures Fracture Diagnostics Third Segment Types of Acids and Applications Sludges, Emulsions, Precipitates Acid Placement Techniques Effective Matrix Acidizing Factors Affecting Fracture Acidizing Success New Developments & Emerging Stimulation Technologies

Permission granted to DRG Resources Ltd and Canadian Petroleum Institute for this course material and presentation.

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Several commercial service organizations provide courses on portions of this subject. By their commercial nature, those organizations tend to have a particular point of view to emphasize, and the courses may not be completely devoid of commercial content or emphasis. This course is an independent presentation. The author neither favors nor disfavors any particular organization. Therefore, where controversy exists or where otherwise advisable, more than one point of view will be presented. A Bibliography and Reference List is included. This should be helpful to those who may wish to investigate the subjects more thoroughly than we have time to do in this series of presentations. Since this Suite of courses and the course notes are under constant revision to incorporate changing and emerging technology, modifications will take place before each presentation. Therefore, your comments and suggestions for improvement would be most welcome at any time, especially in conjunction with the course critiques. A form is provided to assist you in this regard. Your frankness is welcome and will assist the author to maintain an up-to-date presentation of the highest quality. Ongoing contact with the author for the same purpose is also welcomed. Due to the nature of the subject, the course contains opinion as well as fact, and in some areas there is still considerable difference of opinion. Therefore, the author offers no guarantees except that he has used his best engineering judgement and considerable experience in determining which items to emphasize. 1.3

ACKNOWLEDGMENT

In respect to the numerous advances that have taken place in well stimulation since its inception, a great deal of credit must be given to the service companies. Their willingness to make the risk investment in the very expensive field equipment, and in the very well-equipped research facilities, helped make possible the economic production of enormous hydrocarbon resources that would otherwise have remained unrecoverable. Of course, the producing companies have contributed a great deal to the science, not only in terms of Stanolind's (now BP-Amoco) original work but also with respect to the many products and concepts that originated with the oil companies. Indeed, the willingness of these organizations to apply and _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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develop new ideas has been a major factor in advancing technology. Technical societies such as the Society of Petroleum Engineers (SPE) and the Petroleum Society of CIM (CIM) have been of fundamental importance in disseminating technology as it is developed and released by companies, institutions and individuals. There is nothing as effective as the commercial marketplace to evaluate new and emerging technologies. 1.4

A POT-POURRI OF QUESTIONS

Formation stimulation is not a simple operation. At one time it was treated much more simply than it is now. However, upon deeper investigation of the details of hydraulic fracturing, it is found that the subject is indeed very complex and many seemingly diverse scientific disciplines must be sourced to fully understand the topic. Every year, new aspects are being examined. Much of the new work involves analysis of data from past jobs. Therefore one of the key messages that the participant should receive from this course is that it is of great importance to measure and record as much as possible of the technical data before, during, and after fracturing treatments. Not all of these data will be used for immediate analysis and application, but they should all be preserved. 1.

The first step in design is to determine and state the purpose or objective of a particular stimulation job. Is it to simply "break through" a damaged zone around the wellbore, or is it to stimulate the rate of production of the well to an even higher level than would be achieved by simple damage removal?

2.

In light of this, what must be accomplished in terms of treatment location, size, shape and conductivity in order to achieve the desired result?

3.

What factors are likely to interfere with attainment of the above treatment parameters objective?

4.

Is it necessary or even advisable to over-design to compensate for unknowns? What risks are involved in doing this?

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5.

What steps can be taken to identify the key factors that may have a bearing on the mechanical outcome of a particular job, and how can each one of these factors be evaluated?

6.

What design options are available to the designer and what is the cost/benefit/risk of each option?

7.

Once all factors have been evaluated and prioritized, how does one technically and economically, size the job?

8.

What options are there? For example, could the same results be achieved at about the same costs, by a shorter, high capacity treatment as by a longer, lower capacity treatment? If so, should cost alone be the deciding factor?

9.

What about short term results versus long term productivity? Is flush production significant?

10.

How reliable are in situ stress measurements and how consistent might they be in a given area?

11.

Various laboratory testing methods are available. Which ones should be used and under what conditions should the tests be run? What is the risk when some of the conditions are not adhered to, such as testing under bench conditions versus in situ reservoir confining pressure and reservoir temperature?

12.

What should you believe concerning the effectiveness of Service Company treating fluids and chemical additives? What about negative effects? Are there standard industry testing procedures so that effectiveness or performance of various materials may be compared on a standard basis?

13.

What special characteristics of treating fluids are vitally important to job success?

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14.

What should you know about the conditions under which the various chemicals should be handled, stored, and mixed?

15.

What should be the properties just before the material is pumped to the well?

16.

What checking and sampling should you be doing on location?

17.

What about the cleanliness of materials pumped into the well, both fluids and solids?

18.

What computer programs should be used in the design, and what are the major differences in programs from the various sources? Some examples are: tubing contraction due to pumping cool fluids, formation cooling due to pumping cool fluids, fracturing fluid heating due to flow in the warm formation, perforation and near-wellbore tortuosity, manner of handling the concept of fluid loss, height growth and containment, other aspects of created fracture geometry, propped fracture geometry and conductivity, proppant convection, production performance after fracturing and after clean up.

19.

How can minifracs best be employed?

20.

How can the practice of real-time monitoring best be applied?

21.

In what manner should the fluid used during a treatment be produced from the well following the job? Why is this flowback procedure an important consideration?

22.

What methods may be used to evaluate the current condition of a newly drilled well, or of a well that has been on production for a significant period of time?

23.

How does one wisely take into account the insights provided by wise historymatching techniques?

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TABLE OF CONTENTS 1.1 OBJECTIVE .................................................................................................................... 2 1.2 COURSE CONTENT ...................................................................................................... 3 1.3 ACKNOWLEDGMENT.................................................................................................... 5 1.4 A POT-POURRI OF QUESTIONS................................................................................... 6

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SECTION 2: REVIEW OF RESERVOIR CHARACTERISTICS Let us look at well-production theory as it relates to the application of fracturing in a little more detail. In general, the objective of well stimulation is to increase the productivity of a well. To do this, it will be necessary to overcome a flow restriction of some kind somewhere in the producing system. In other words, we must de-bottleneck the system. However, proper identification of the bottleneck (actual or potential) is clearly the first priority in designing completions or workovers. For example, if in a producing well, the restriction to flow is actually a flow line that has become plugged with paraffin or a malfunctioning bottom hole pump, fracturing will not be the most effective remedy for the problem. Therefore, in an existing producing well, the first step in designing a workover to increase productivity is to correctly identify and describe the problem. Be sure you are attacking the right problem before calling out the frac trucks! The subject of well performance evaluation is a course in itself. This course will deal with it in overview only. Effectiveness of properly designed and placed hydraulic fractures may be roughly estimated using graphs such as Figure 2-1 (McGuire and Sikora, 1960). This graph simplistically indicates the effect of fracture width, fracture permeability, fracture length, well spacing and formation permeability on the productivity improvement that may be expected as a result of fracturing a well that is not damaged. Later chapters deal much more fully with this and other more appropriate simulation methods for estimating post job productivity. But it is important to have an appreciation for the relative importance of fracture width, length and permeability in respect to the productivity improvement that may be expected from hydraulic fracturing.

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Figure 2-1

Estimated production increase from vertical fractures. (McGuire and Sikora, 1960)

(If the drainage is from a 40 acre square pattern, and rw = 0.25 feet, then both scaling parameters = 1 and can be ignored.) In addition to the above fracture parameters, it is important for us to examine a number of factors and their effect on the rate at which a well will produce. For this discussion, let us consider reservoir factors, formation damage, and other factors.

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2.1

RESERVOIR FACTORS THAT AFFECT PRODUCTIVITY

Let us first consider the important reservoir parameters and how they affect the ability of a well to produce gas or oil. Obviously, a reservoir cannot produce what it does not hold in storage. The factors that determine the storage capacity for hydrocarbons in a unit volume of a reservoir include the average values of porosity, and water saturation. The number of unit volumes in the portion of the reservoir influenced by a well is determined by the formation thickness over which the average values apply, and also by the dimensions of that portion of the reservoir that is affected by a single well. The pores that store the reservoir fluid are of no benefit unless they are inter-connected and able to transmit fluids to the wellbore. The measure of the ability of a formation to transmit fluids is called the permeability. The other reservoir factors that determine the ability at which a formation can produce include the radius of the wellbore, the reservoir pressure, the viscosities of the fluids in the pores, the number and type of phases flowing, their wetting characteristics and the pressure in the wellbore at the perforations. The steady state relative permeabilities to the flowing phases are actually a combination of the above factors and are important. Any of these parameters would, by themselves, control the rate at which a formation would produce, provided that the reservoir was isotropic and homogeneous and that its properties were constant with decreasing pressure. Of course very few, if any, reservoirs may truly be classified as homogeneous and isotropic. Many sandstone reservoirs are stratified due to the depositional environment in which they were formed. In many cases, lenses of sand were deposited in such a manner that they were not well inter-connected with other lenses in the same formation. Porous areas in limestone and dolomite formations may be scattered throughout the zone, and saturations may vary considerably. Natural fractures exist in some formations. The natural fractures may or may not be well networked, and the networks may be infilled by secondary deposition.

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2.2

MECHANICAL FACTORS AFFECTING PRODUCTIVITY

Some factors not related to the reservoir itself may hamper the ability of a well to produce. Some of these are mechanical in nature. It is not likely that fracturing will be the best solution in some of these cases. For example, if the number and quality of perforations is restricted, or covered with debris, or if a bottom-hole pump has become inefficient, or if there is a hole in the tubing, fracturing will not be the most appropriate solution. There is a long list of mechanical reasons for unsatisfactory production rates. The list should also include such possibilities as perforations at the wrong depth. The trouble-shooter should take absolutely nothing for granted in his/her search for possible causes of the low productivity problem. 2.3

PRODUCTIVITY AFFECTED BY FORMATION DAMAGE

One of the most common and most significant reasons for a well to fail to produce at appropriate rates is formation damage. The expression "formation damage," as used here, refers to an induced reduction in the permeability of a formation near the well bore. The reduction can occur as a result of damage within the individual pore spaces, or it may occur within a natural fissure or fracture system through which formation fluids are transmitted to the wellbore. The damage should be viewed as a partial plugging mechanism. Although there are many possible causes, all result in a zone in which the producing pressure gradient is much higher than in the rest of the reservoir (Hurst, 1953).

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Figure 2-2: Pressure distribution in a reservoir with a skin. (Hurst, 1953).

Figure 2-2, borrowed from Hurst, depicts schematically a pressure profile for a hypothetical flow system, with and without damage. The effect of the damaged zone is to require an unnecessarily high amount of reservoir pressure in order for the formation fluids to move through the damaged zone. This reduces the maximum rate at which the well would be capable of being produced. It would also reduce the maximum primary recovery from the reservoir unless it was depleting under very active water drive. Damage is, therefore, a very significant and a very expensive factor to be reckoned with. We will discuss damage in more detail later. 2.4

CAUTION

Examination of only the monthly production volumes from a well could lead to erroneous conclusions regarding a reduction in production rate. It is necessary to investigate much more closely to determine the real reason for low production. It is quite possible that the reason may simply be that weather or road conditions made it impossible for oil haulers to get to the lease. Also, there are numerous causes of reduced rates imposed by governments, such as for proration _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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to market demand, GOR or over-production penalties and so forth. Therefore, it is very important to note the number of hours on production when reviewing. Talk to those who know the facts!

2.5

METHODS FOR DETERMINING THE CAPABILITY OF A WELL TO PRODUCE

We have looked at some of the factors that can influence the production rate of a well. Let us now examine some of the ways by which we may determine the capability of an individual well to produce at a given point in time.

2.5.1

DRILL STEM TESTS

The earliest indication of the rate at which a new well may be capable of producing may be obtained during drill stem testing, while the drilling rig is still on the hole. When properly conducted, a drill stem test can yield a very good indication of several important parameters (Horner, 1951, Dolan et al, 1960, Ammann, 1960, Maier, 1962, Murphy, 1966, Matthews and Russell, 1967, Sinha et al, 1976, Ramey, 1976). These parameters include the transmissibility factor, kh/μ, from which average permeability, k, can be deduced, assuming that a good estimate of formation thickness, h, can be obtained from logs and cores, and if a good estimate of reservoir fluid viscosity is available. If sufficient reservoir fluid is produced, it may be possible to obtain a viscosity determination. Static formation pressure may be determined from an extrapolation (Horner, 1951), and average production rate during the final flow period of the test can be calculated from the incremental hydrostatic head added due to the recovery during the flow period. Formulas are published for determining damage ratio, which is the ratio of the rate at which the well could produce in the undamaged condition compared to the rate at which it is capable of being produced in the damaged condition. In other words, the rate at which a well could be capable of being produced in the undamaged state is predictable from a properly conducted drill stem test. One of the complicating factors in the use of drill stem test data to calculate damage and to predict production rates is that, in a reasonably high percentage of cases, the information obtained during _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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the drill stem test is sufficiently incomplete to cause lack of confidence in interpretations based on the Horner plot. The reliability of the Horner method depends upon test conditions and times (Murphy, 1966) being such that the later time points on the Horner plot of the final closed in pressure curve fall on a straight line, which is equivalent to semi-steady state flow. If this does not in fact occur, the reliability of the extrapolation and subsequent calculations is drastically reduced. There are numerous references given in the bibliography following the text portion of these notes that deal with pressure analysis. A number of authors, (Murphy, 1966, Matthews and Russell, 1967, McKinley, 1971, Sinha et al, 1976, Raghavan, 1976, Milner et al, 1982) beginning with McKinley, and later referenced and compared by Sinha and Raghavan, have applied typecurve matching techniques to improve the confidence in, and extend the number of drill stem tests that may be reliably interpreted. Regardless of the method of interpretation employed, provided data are reliable, a properly conducted drill stem test can provide the well completion engineer with the first quantitative indication of the producing capability of the well. As such, it may help set the target for the completed production rate. Conflicting values of formation permeability may result when data obtained on the basis of drill stem tests or other pressure build-up interpretation methods are compared with data obtained on the basis of core analysis. The most obvious reason for the difference is that the pressure build-up based methods determine the values in situ while the core analysis is usually carried out under bench conditions of temperature and pressure in a cleaned core. While the core permeability is usually measured with nitrogen, the pressure-based methods utilize the reservoir fluids. Much better agreement is obtained if the core is tested under simulated formation conditions of temperature and pressure in a triaxially-loaded cell. Some investigators have reported that the variation between permeability measurements determined under in situ conditions versus bench conditions can be (albeit rarely) as much as three orders of magnitude. This is obviously of significance to more than just the economics of fracturing.

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2.5.2 PRODUCTION TESTS Once the well has been cased, cemented and perforated, the next opportunity to evaluate its ability to produce is presented. If the well will flow, the evaluation is relatively simple. The operator may choose to run one of the basic evaluation methods such as a multi-rate flowing test (Matthews and Russell, 1967) or a standard production and pressure build-up test after the well has cleaned up and the BS&W has stabilized.

Figure 2-3 Two-Rate Flowing Test, (Matthews and Russell, 1967)

The basis for the interpretation of pressure build-up tests was given by Horner, (1951) and the technology has been added to in very great measure by a large number of authors over the past fifty years. Good references are the Society of Petroleum Engineers Monograph Series, Volume 1, by C.S. Matthews and D.G. Russell, 1967, Volume 5 by Earlougher, 1977, and an SPE textbook, (Lee, 1982).

2.5.3 HORNER PLOTS Following is a brief review of the Horner method as applied to calculate damage. The method was first presented by Horner in 1951. The derivation of the equations that are used will not be repeated here, but we will review the mechanics of application. Further details may be found either in Horner's paper or in the SPE Monographs, or in other references.

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Figure 2-4 Example Horner Graph for an Oil Well The basis of the technique is the manner of graphing the pressures and times obtained during a build-up period after the well has produced for a period. See Fig. 2-4. Horner's simple case is for an infinite, homogeneous, one well reservoir containing a fluid of small but constant compressibility. As might be expected, the basic equation applies quite well to newly completed wells in oil reservoirs in which the pressure is above the bubble point.

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Horner's equation, for the straight-line portion of the graph, expressed in oil field units, is

pws = pi - 162.6

Where:

qμB ⎡ t + Δt ⎤ log ⎢ kh ⎣ Δ t ⎦⎥

B

= formation volume factor, bbl/bbl

q

= production rate, bbl/day

μ

= viscosity, cp

h

= formation thickness, ft.

k

= permeability, mD.

pi

= extrapolated reservoir pressure, psi

pws

= Shut in pressure at a time during build-up, psi

t

= flowing time, hours

Δt

= shut in time, hours

A plot of the pressure observed at various times after the well has been closed in versus

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⎡ t + Δt ⎤ log ⎢ ⎣ Δ t ⎦⎥

should result in a straight line, provided the well was shut in for a sufficiently long period after the flow period. The slope, m, of the line may be expressed as:

m=

162.6qμB kh

Then we may calculate formation flow capacity, kh.

kh =

162.6qμB m

In the same operation, we may obtain a very close approximation of the shut-in reservoir pressure by extrapolating the straight line to infinite shut-in time, i.e. when

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Since, as we have seen, many wells are damaged during drilling operations, and a zone of

t + Δt =1 Δt

reduced permeability, or "skin" is created around the well bore. The skin factor, s, may be calculated as follows:

⎡ p1− hr − pwf ⎤ ⎛ k ⎞ + 3.23⎥ s = 1.151⎢ − log⎜ 2⎟ m ⎝ φμcrw ⎠ ⎣ ⎦

where p1-hr is the value on the straight line portion of the pressure build up curve after one hour of shut in time, and pwf = bottom-hole flow pressure prior to shut in, psi

φ

= porosity, fraction

c

= compressibility of the rock/fluid system, vol/vol/psi

rw

= wellbore radius, feet

A value of s = 0 indicates no damage, a positive value of s indicates damage, and a negative value of s indicates improved permeability in the well bore area. We may also calculate the additional flowing pressure drop caused by the presence of the skin by

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Δ p skin = 0.87sm

A more useful and meaningful term would be the Productivity Index, J. Actually, we will discuss two, Jactual and Jideal.

J actual =

J ideal =

q p - pwf *

q p - pwf - Δ pskin *

in which p* is the pressure at the transient boundary, psi and Jideal would be the Productivity Index with zero damage. A useful comparison is the Flow Efficiency. Jactual Flow Efficiency = -------------Jideal This course is not intended to deal in depth with the use of pressure build-up analysis. However, it is very important to state that considerable progress has been made in the development of analytical techniques to account for afterflow, well bore storage effects, naturally (and hydraulically) _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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fractured reservoirs, layered reservoirs, and so forth, (Ramey, 1976, Raghavan, 1976, Agarwal et al, 1979, Bennett et al, 1981), Lee (1982). The production engineer will find it very beneficial to become familiar with several of these techniques, and with their limitations One of the effects of this work has been to generate a need for the use of much more accurate and precise instrumentation than was previously available. The acquisition and preservation of good data by both downhole and surface measurement of pressure, flow rate, temperature, fluid properties and other parameters has proved to be of great value. This data collection practice should be continued.

2.5.4 INFLOW PERFORMANCE RELATIONSHIP In solution gas drive reservoirs producing below the bubble point, the Productivity Index is not a constant, and consequently its usefulness as an evaluation tool in these circumstances is reduced. However, for this type of reservoir, a technique that employs the concept of the Inflow Performance Relationship (Gilbert, 1954, Vogel, 1966, Klins and Clark, 1993, Lekia and Evans, 1990) may be used. It is also an approximation, but it is much more accurate than the PI for this situation. The Inflow Performance Relationship is specific for a given well in absolute terms. However, the equation for the dimensionless reference curve is general. In addition to the work published by Vogel, Standing extended the techniques to allow prediction of production rates at various drawdown pressures with damage removed, and also with negative damage or stimulation. A number of others have written on this particular analytical method. This is a very practical and useful tool.

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TABLE OF CONTENTS 2.1 RESERVOIR FACTORS THAT AFFECT PRODUCTIVITY .......................................... 12 2.2 MECHANICAL FACTORS AFFECTING PRODUCTIVITY ........................................... 13 2.3 PRODUCTIVITY AFFECTED BY FORMATION DAMAGE........................................... 13 2.4 CAUTION ..................................................................................................................... 14 2.5 METHODS FOR DETERMINING THE CAPABILITY OF A WELL TO PRODUCE........ 15 2.5.1 DRILL STEM TESTS ................................................................................................ 15 2.5.2 PRODUCTION TESTS .............................................................................................. 17 2.5.3 HORNER PLOTS ...................................................................................................... 17 2.5.4 INFLOW PERFORMANCE RELATIONSHIP............................................................. 23 LIST OF FIGURES FIGURE 2-1 ESTIMATED PRODUCTION INCREASE FROM VERTICAL FRACTURES. (MCGUIRE AND SIKORA, 1960) ................................................................................. 11 FIGURE 2-2: PRESSURE DISTRIBUTION IN A RESERVOIR WITH A SKIN. (HURST, 1953). .................................................................................................................................... 14 FIGURE 2-3 TWO-RATE FLOWING TEST, (MATTHEWS AND RUSSELL, 1967) ............. 17 FIGURE 2-4 EXAMPLE HORNER GRAPH FOR AN OIL WELL .......................................... 18

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SECTION 3: FORMATION DAMAGE

Earlier the phenomenon of formation damage was briefly mentioned and it was indicated that its effect was to reduce the rate at which a well could produce. The concept has long been recognized (Muskat, 1949) and is of such obvious importance to any discussion on well completions that we should deal with it in greater depth. It is so important that entire technical conferences have been devoted to this one topic. The first one was held by the SPE in New Orleans in 1974. They continue to be held annually. Let us first examine the types of formation damage, then causes of damage, both before and after perforating of the casing. Then the discussion will centre on methods of preventing damage, and finally treatment of formation damage. 3.1

TYPES OF DAMAGE

The various types of damage may generally be classified into one of the following categories: (van Poollen, 1966) clay swelling, dispersion, and fines migration, emulsions and water blocks, deposits from produced water, deposits from produced oil, relative permeability effects, mechanical types of damage, damage resulting from completion techniques, partial penetration of a formation and perforation ineffectiveness. The last two are not true examples of formation damage, but they appear the same on test interpretation and have the same effect on restricting production 3.1.1 CLAY SWELLING AND DISPERSION

Clay swelling and dispersion is a phenomenon that has been recognized for over forty years. Most clastic formations contain significant percentages of clay minerals. Depending upon the particular type of clay present, and the composition of the formation water, the clays may undergo a change in form and composition if they should come into contact with a water of different composition from the connate water, or if the temperature and/or pressure conditions of the reservoir should change.

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There are several main types of naturally occurring formation clays known as montmorillonite (more recently called smectite), illite, chlorite, kaolinite, and mixed layer clay. There are two distinct effects that can occur due to the introduction of extraneous water. First, the size of the clay particle may change drastically due to hydration of cations on the clay particle. The degree to which the hydration will occur depends upon the particular type of clay and the chemical composition of the water that is in contact with the clay. Black and Hower (1965) presented two tables showing the cation exchange capacity ranges of several clays, the ionic diameters and hydration numbers of several cations. Clays with greater exchange capacities (meq/100g) (meq = molecular equivalents) will be capable of swelling to a greater degree, thereby being potentially more damaging than clays with lower exchange capacities. The degree of swelling depends on the particular cation associated with the clay and the concentration and composition of salts dissolved in the water that is in contact with the clay. The hydration number (Angstroms) represents the number of water molecules that can be associated with each cation. Hower and Black listed (Table 1.) the ionic diameters and hydration numbers of several cations as determined by a number of investigators. Potassium and ammonium are preferred salts because the hydration number is small, indicating that for a given clay type, swelling would be minimized. In general, the montmorillonite or smectite clays are the most susceptible to swelling. A concentration of one to three percent potassium chloride in water provides the best swelling inhibition, according to Black and Hower. Environmental considerations have resulted in substitution of other sources of ammonium or potassium rather than chlorides.

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Cation

Ionic Diameter

Hydration Number

Lithium

1.20 Angstroms

7 to 15

Sodium

1.90 Angstroms

5 to 11

Potassium

2.66 Angstroms

1 to 4

Ammonium

2.42 Angstroms

2 to 4

Calcium

1.98 Angstroms

10 to 22

Magnesium

1.30 Angstroms

12 to 33

Table 3-1: Ionic Diameters and Hydration Numbers of Several Cations. (Black and Hower, 1965). The second detrimental effect that can occur due to allowing formation clays to be contacted by extraneous water is particle dislodgement and migration. Foreign water may cause flocculation of the clay particle and if it is not tightly held in place, it may become dislodged and may move with the fluid, possibly causing blockage when it encounters any restriction in the flow path, such as in pore throats. Researchers have shown that the monovalent ions are less likely to cause flocculation than the higher valence ions. However, it is possible to over-treat, according to some, and thereby cause the concentration of monovalent ions to be as damaging as multiple valent ions, in the sense of causing flocculation. In recent years, pH has been found to be an important factor in respect to the tendency for the non-swelling type of clays to become dislodged and to migrate. Some investigators have studied the effect of interstitial velocity upon initiation of fines migration and a laboratory test procedure has been devised. In the past couple of decades the scanning electron microscope (Simon and Derby, 1976) has enabled closer study of the presence, type, distribution and condition of clay particles and other fines in rock samples. At the same time it is possible to study the pore geometry and pore throat dimensions relative to clay particles.

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3.1.2 WATER AND EMULSION BLOCKS

Water and emulsion blocks are probably the oldest recognized forms of formation damage (Clason and Hower, Clason, 1955, Hower and Stegelman, 1956). It is relatively easy to understand how an emulsion between oil and water can restrict production. This is because the apparent viscosity of an emulsion is almost always greater than the viscosity of either of its two components. In some cases, the viscosity can be so great that a complete blockage to flow occurs that cannot be dislodged by reservoir energy. However, in the case of a water block, as contrasted to an emulsion, the concept is a little different. Essentially the problem is one of interfacial tension between the water droplets, the oil in the formation pores, and the rock surface. The droplet may be viewed as having a tough skin, not unlike a balloon, and although it can deform, it will not change in volume or easily break up into smaller particles. Therefore, as it tries to move from the centre of a pore to pass through the pore throat to the next pore closer to the wellbore, it may lodge in the throat and will remain there unless sufficient pressure differential exists to force it through. As mentioned, water blocks are seldom as severe as emulsion blocks and their effects will often be reduced or disappear over a period of time, no doubt influenced by capillary effects.

3.1.3 DEPOSITS

Deposits from produced waters may occur for various reasons, but mainly due to temperature and/or pressure reduction that occurs as the water is produced. As a result, compounds (Featherston et al, 1958) may form that are less soluble in water. The most common ones are carbonate and sulphate scales. Occasionally, the mixing of formation water with extraneous water, either a treatment fluid or water from another formation, may result in creation of insoluble compounds. The produced oil may also be a source of deposition. As the pressure is reduced near the well bore due to flow, light fractions may be liberated and there may be a temperature reduction. This may result in the deposition of asphaltene or paraffin (Knox et al 1962).

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3.1.4 SATURATION ALTERATION

The effect of a change in the fluids saturation in the reservoir, or a portion of it, is to change the effective (or relative) permeability to the individual fluids (Muskat, 1949). The permanency of the change, or the degree of damage, is related to the force (or pressure) available to overcome the restriction, and to the change in saturation with production. There are remedial methods that we shall discuss later.

Figure 3-1: Relative Permeability

3.1.5 MECHANICAL CAUSES Damage to the formation may be caused mechanically. Some authors have referred to particle tilting as a result of collapse of formations as a possible form of damage. In such instances oblong particles, such as shale fragments, may collapse and become tilted so as to act as more of a flow restriction than they did in their previous alignment.

3.1.6 SOLIDS INVASION

Solid particle invasion during completion operations is a common cause of damage. The overbalance pressure differential between the hydrostatic head due to the column of fluid in the well and the formation pressure is a factor. The damaging material may be only cement or mud filtrates (Rike, 1980), or if sufficient pressure differential exists so as to initiate or open fractures, even whole cement or whole mud invasion may occur.

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3.1.7 PARTIAL PENETRATION

Partial penetration may be of two broad types. Productivity may not be fully achieved if a wellbore fails to fully penetrate the hydrocarbon-bearing portion of the reservoir. The effect is similar to that of damage. Also, the perforations may not completely penetrate the casing and/or cement, or may be too few in number or may become plugged.

3.2

CAUSES OF DAMAGE DURING DRILLING

It is important to identify the types and causes of damage that may occur at various times during the drilling and the life of the well. Nobody deliberately sets out to cause formation damage. However, the execution of the various operations necessary to drill and operate wells often causes inadvertent damage. The first series of opportunities for damage to occur is during the drilling operation. The people concerned with drilling the well have numerous problems to contend with in just getting the hole drilled safely and with reasonable efficiency. While many of the possible causes of damage occur during the period when the well is under the control of the drilling department personnel, they are often not the ones in the company who will have to live with the results of the formation damage. Their attention, then, would tend understandably, to be focused more on the immediate need, which is to deliver safely, an efficiently constructed borehole, properly cased and cemented according to design. They are ordinarily not judged according to their ability to drill a damage-free borehole. Until recently, most of their training and experience may not have been oriented that way, and they may not have been totally familiar with some of the damaging side effects. That is the reason for including this section in the list of opportunities for damage to be caused. The emergence of horizontal and/or underbalanced well drilling technology has caused a marked change in the role of the drilling departments with respect to damage prevention.

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The opportunity to cause (or conversely, to prevent) damage is presented from the instant the drilling bit enters the pay formation. Drilling fluid filtrate will be lost to any permeable formation as a result of the pressure differential between the pressure due to the mud column and the formation pressure. This pressure differential must, ordinarily, be maintained in order to prevent the well from producing during drilling, which, if it occurred, could be the first event leading to a dangerous blow-out. The magnitude of the filtrate loss from the drilling fluid is related to the wall-building properties of the fluid. All drilling muds will exhibit at least some fluid loss (termed spurt loss) that occurs during the initial deposition of the filter cake. The amount of damage, if any, caused by this fluid depends on the formation rock, the formation fluid and the filtrate itself. The possibilities include water or emulsion blocks caused by the filtrate and perhaps complicated if the filtrate contains chemicals that may tend to change the rock wettability or act as emulsion stabilizers. The filtrate may also cause some of the formation clays to swell, depending on the chemical composition of both the filtrate and the clay. The possibility of clay flocculation and/or subsequent migration also exists. Drilled solids, if the particles are small enough, may physically enter the formation. The danger of particulate blocking occurring is especially present in naturally occurring or induced fissures, which may become plugged with whole mud and cuttings. This is of particular concern when horizontal wells are targeted for the purpose of encountering natural fracture systems, which may be the main flow channels. During the cementing of the casing, it is possible to lose considerable amounts of water from the cementing slurry. Slurries have very high fluid loss rates, and these rates are sometimes reduced chemically during cementing but even when reduced they are still very high compared to drilling fluid filtration rates. In some instances, whole cement has been lost to fissures or fractures. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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For many years, as indicated in some of the older references, authors (Goins et al, 1951; Cardwell, 1953; Clark and Murray, 1958; and Burkhardt, 1960) have recognized that very large pressure surges are created by the piston-like action that occurs while running drill pipe or casing into the well. These pressures can easily exceed the fracturing pressure of the formation, thereby initiating potentially severe damage. Also, any annular friction pressure due to circulating must be withstood by the formation, in addition to the hydrostatic pressure, while drilling or circulating. Any restriction in the annulus such as hole sloughing, mud rings and so forth can result in severe damage problems due to the increased circulation pressure that must be exerted to establish flow. When this happens, the drilling personnel sometimes have little choice and have to act quickly in order to avoid stuck pipe.

3.3

CAUSES OF DAMAGE AFTER PERFORATING

During the perforating operation itself there are several opportunities for damage. The physical damage to the formation caused by the perforating action is one. Another is that if the hydrostatic pressure in the casing at the time of perforating is greater than the reservoir pressure, the perforation cavity will immediately fill with fluid from the casing and may become damaged. On the other extreme, if the fluid level is too low when perforating (under-balanced), the instantaneous interstitial velocity near the well bore may initiate movement of formation fines. All perforating operations involve a certain amount of junk or debris being left in the wellbore, or even in the perforation cavity. Any fluid introduced to the well after perforating is likely going to come in contact with the formation. Consequently, very careful attention should be paid to the chemical composition and cleanliness of this fluid in relation to the formation and the formation fluids. One of the worst problems is to introduce fluids into the well that are not compatible with formation fluids, and which may cause precipitates to form.

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In some instances, more than one surface-active agent may be introduced in a treating solution. Chemicals that are cationic should not be mixed with ones that are anionic, or a precipitate may occur. If injected into the formation this may be damaging. Also the chemicals will not perform their functions. Some treating chemicals are non-ionic and would not ordinarily combine and form precipitates with other compounds. Other causes of damage after perforating include the formation of water scale, perhaps due to temperature and/or pressure change, mixing of two incompatible waters, and other causes. Paraffin or asphaltenes may precipitate from solution in the formation due to temperature and/or pressure drop, loss of solution gas or other reasons. If clay particles or other solids are released from their position in a formation due to mechanical or chemical action, the released fines may migrate with moving fluids until they bridge thereby stopping flow. The distance that fines must travel to cause plugging need not be far. For example, if a kaolinite particle moves from the pore lining to the pore throat, it can cause a significant reduction in flow. The distance travelled is measured in microns.

3.4

PREVENTION OF FORMATION DAMAGE

Some of the steps that can be taken to help prevent formation damage may be summarised as follows: 1.

Treat drilling fluids so that the filtrates from the drilling fluids are relatively nondamaging to the formation. Potassium chloride maintained at three to five percent can be helpful, especially if used in combination with water loss control. However, some open-hole logging programs are not effective in conductive mud. In some areas consideration should be given to changing the mud system over to special non-damaging drilling fluids for drilling the pay formation. The use of air or natural

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gas (Frederick, 1993) as drilling fluids is becoming more common in horizontal applications. 2.

The use of fluid loss additives in cementing slurries can greatly reduce the amount of filtrate lost to the formation. Also, the cement may be treated so as to make the filtrate less damaging.

3.

Drilling rig procedures could be reviewed from the damage prevention point of view. For example, the differential pressure between the well bore and the formation should be kept to a practical minimum. The increasingly common use of underbalanced drilling techniques is an extension of this concept. It should be recognized that circulating causes annular friction pressure to be acting against the formation, and therefore, whatever can be done to reduce circulating pressures should be considered. This would include reduced viscosity and increased annular clearance. A balance must be struck with the need to maintain hole cleaning and hole integrity. Drill pipe and casing should be lowered at controlled speeds and the casing string should include differential fill-up equipment to reduce the effects of pressure surges.

4.

Cementing operations should be designed and executed so as to protect the formation against damaging cement filtrate loss. In order to reduce the differential pressure, pumping rates should be reasonable and chemical thinners (turbulence inducers) should be employed.

5.

Materials used for well killing operations, acidizing, fracturing and any other task during completion and workover procedures should be critically examined to determine the potential for damage.

6.

A very good policy is to filter all fluids introduced to a well after the casing has been cemented.

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3.5

TREATMENT FOR DAMAGE REMOVAL

The engineer responsible for initially completing a well should not only review the planned drilling program but he should also be aware of daily operations during the actual drilling, once the bit has entered the pay formation. One of the more obvious reasons for this, of course, is that nearly all wells are damaged to some degree during the drilling process. The first problem of the completion engineer then, is to determine the degree of damage, its probable cause or causes, and then to include a provision in his completion program to alleviate the damage. The first opportunity for this is to perforate with a moderately reduced head, if well conditions will permit. If it is considered to be too dangerous to perforate in an under-balanced state, or if a through-tubing or tubing-conveyed perforating technique is inappropriate, then the fluid column pressure ought to be only slightly greater than the formation pressure. Also the fluid in the casing should be filtered and treated so as to be as non-damaging as possible. An alternative, sometimes used if it is necessary to perforate in an over-balanced condition, is to perforate in mild acid so that the first fluid to enter the perforation cavity is acid. Various damage removal procedures may be used after perforating, including swabbing, nitrogen circulation, low pressure matrix acidizing, non-acid chemical flushes for mud removal and so on. The use of ball sealers with acid can be very beneficial. Special straddle packers that enable acid to be injected into short intervals are being utilized more frequently. Specific damage removal techniques employed during workover operations include, in addition to low pressure matrix acidizing techniques, the use of solvents for paraffin and asphaltene deposits and a variety of chemical treatments for water scale. The water scale treatments are interesting in that they generally take one of two forms: either two-stage in which the insoluble scale is first converted to a soluble form and then treated with acid, or a single stage treatment that generally requires the use of a chelating agent such as EDTA. In some cases, especially open-hole type completions, the use of hydraulic/abrasive jetting techniques to remove the damaged area of rock from near the well bore has been successful. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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The use of reperforating techniques using larger and/or better charges has been effective especially if there is any doubt about the quality of the original perforating job. The use of controlled rate, high pressure gas generation techniques (Schatz, 1987) has also been noted. Finally, if the damage is deep, or if the material causing the damage in the first place is of such a nature that it will not likely flow into the fracture itself, and subsequently cause replugging, then the use of hydraulic fracturing to overcome the damage has been successful. A very much more detailed discussion of matrix acidizing is included in the third segment of this Suite.

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TABLE OF CONTENTS SECTION 3: FORMATION DAMAGE................................................................................ 25 3.1 TYPES OF DAMAGE .................................................................................................... 25 3.1.1 CLAY SWELLING AND DISPERSION................................................................... 25 3.1.2 WATER AND EMULSION BLOCKS ...................................................................... 28 3.1.3 DEPOSITS ............................................................................................................. 28 3.1.4 SATURATION ALTERATION................................................................................. 29 3.1.5 MECHANICAL CAUSES ........................................................................................ 29 3.1.6 SOLIDS INVASION................................................................................................ 29 3.1.7 PARTIAL PENETRATION...................................................................................... 30 3.2 CAUSES OF DAMAGE DURING DRILLING ................................................................. 30 3.3 CAUSES OF DAMAGE AFTER PERFORATING .......................................................... 32 3.4 PREVENTION OF FORMATION DAMAGE .................................................................. 33 3.5 TREATMENT FOR DAMAGE REMOVAL ..................................................................... 35 List of Tables TABLE 3-1: IONIC DIAMETERS AND HYDRATION NUMBERS OF SEVERAL CATIONS. (BLACK AND HOWER, 1965). ..................................................................................... 27 List of Figures FIGURE 3-1: RELATIVE PERMEABILITY......................................................................... 29

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SECTION 4: THEORY OF HYDRAULIC FRACTURING

For any discussion of hydraulic fracturing to be even reasonably complete, it is necessary to review the theoretical aspects as well as the practical. This area of oilfield technology is very interesting in that at times it has seemed as if the practical has moved ahead of the theoretical and at other times the reverse has been true. At this time, it is important for engineers to have at least a good basic understanding of the theoretical aspects in order to be able to make wise decisions concerning stimulation treatments. When one attempts to gain an understanding of the theory associated with a branch of applied science, it is usually very helpful if one knows the approximate order and timing of important developments. The SPE Monograph "Hydraulic Fracturing" by Howard and Fast is a good reference and it contains a fairly complete bibliography to the date of its publication. A more recent and much more up-to-date and complete publication is the replacement for this volume, "Recent Advances in Hydraulic Fracturing" (Gidley et al, 1989).

4.1

PRESSURE-RATE RELATIONSHIPS

Let us first consider the variables that we can measure during a fracturing treatment: pressure and injection rate. Figure 4-6 represents a well schematically. It is clear that if the well is full of fluid, the surface pressure, pt, is less than the pressure opposite the perforations, pw, by an amount equal to the pressure due to the column of fluid, ph. Therefore, under static conditions, pt = p w - ph

If we consider the effect of pumping into the tubing, there will be an added pressure difference between surface and bottom hole pressures due to the friction pressure of the moving fluid, Δpf.

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Now, under pumping conditions, Equ. 4-1

pt = pw − ph+ Δ p

f

It will be shown, later in this work, that once a

D pw

fracture has been initiated, the pressure that must be exerted at the fracture tip to extend the fracture in the same rock is relatively constant. Let's call that pressure BHTP. Some people refer

Figure 4-5: Schematic of a Cased and Perforated Well

to it as the bottom hole treating pressure. We can now substitute BHTP for pw in Equation 4.1 and therefore, for fracture extension conditions,

(4-2)

pt = BHTP - P H + Δ p f

After a fracture has been initiated and extended for any distance, if we stop the pumps, the fluid will stop moving and the friction pressure, Δpf will be zero. The surface pressure, pt will drop instantly due to the elimination of friction pressure. This reduced surface pressure, the instant after pumping stops, is termed pi, the instantaneous shutdown pressure. Thus, we can substitute zero for Δpf and pi for pt in Equation 4.2 to arrive at Equ. 4-2a

pi = BHTP - ph

Or, re-arranging:

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Equ. 4-3

BHTP = pi + ph

We can now see that the instantaneous shutdown pressure, pi is one of the most important items of information that may be obtained from the pressure recording of a fracturing treatment. It enables us to predict surface treating pressures under various pumping conditions for that formation in that well. Curves or computer printouts, or software showing or calculating the friction pressure due to pumping various fracturing fluids through various tubular arrangements are available from the service companies. 4.2

FRACTURE EXTENSION PRESSURE GRADIENT

It has also been shown that the fracture extension pressure gradient is fairly constant for a given formation in a given area and is generally expressed as fracturing pressure gradient, BHTP/D, where D is the depth of the formation in question. For most situations the gradient will vary from about 15 to 25 kPa/m (0.66 to 1.11 psi/ft). The lower range generally would represent vertical fractures, while the higher numbers have been shown to generally be associated with horizontal fractures. Therefore, if we know the gradient, based on even one fracturing treatment, we should be able to calculate the surface pumping pressure required to conduct a fracturing treatment on almost any other well in the same formation in the same area. Let us examine a simplified example of a pressure and rate versus time chart for a hypothetical but typical fracturing job, Figure 4-2. The items to observe are the pressure test of the surface lines prior to the job, the initial breakdown of the formation and the subsequent recording of the instantaneous shut-down pressure, the slow _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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bleed off of pressure into the formation following the instantaneous shut down, the increase in injection rate and surface pressure as the power of the pumping equipment is applied, the decrease in surface pressure as the hydrostatic is increased due to addition of the proppant, and the increase in surface pressure when addition of the proppant is stopped, and the flush is pumped. The record of the instantaneous shutdown pressure at the end of the job and the record of the bleed off of pressure to the formation is important and should always be recorded. Where digital recorders are available, the shut in pressure recording period should (ideally) be at least twice as long as the pumping period, or at least until closure has occurred. Oil company field supervisors and service company personnel have a natural tendency to reduce this shut-in period to only a few minutes. This is unfortunate since very valuable information may be lost.

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1 Pressure test surface

2 Formation “breakdown”

3 Establish feed rate

lines 4 Record

5 Commence pad volume followed by proppant

instantaneous shutdown pressure 6 Start flush

7 Flush completed, shut down pumps

8 Record

9 Record Pi plus p at 2 times pumping time

instantaneous shutdown pressure Figure 4-6: Schematic Time Chart of Pressure and Rate Let's assume, in an example case, that the depth of the midpoint of the perforations is 2000 metres and that the instantaneous shut-down pressures measured at the beginning and at the end of the job are equal to 13 300 kPa. The hydrostatic pressure due to the fracturing fluid (water) is 2000m x 9.79 kPa/m = 19 580 kPa, and the bottom hole treating pressure gradient is the sum of the two divided by the depth. (13 300 + 19 580)/2000 The fracture extension pressure gradient (or bottom hole treating pressure gradient) is calculated as 32 880/2000 = 16.44 kPa/m.

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4.3

ROCK MECHANICS

The example problem that we have just examined demonstrated to us that we could calculate the pressures required to extend a fracture. Put another way, we could engineer rock failure. In order to be able to solve the previous problem, we were arbitrarily provided with some of the key information. Let us now look more closely at some of the key factors involved. At this time we are really beginning to delve into the technology of rock mechanics. The bibliography section contains many references in this area. Rock mechanics is the area of engineering study that deals with the mechanical behaviour and properties of rocks. It is an extremely complex field of study, not without controversy, in which very important investigation is still going on. A detailed treatment of the topic is beyond the scope of this course. However, because important aspects such as fracture length, height, width, orientation and location are all controlled by rock mechanical properties and behaviour, it certainly behoves us to look, at least briefly, at the subject. As mentioned previously, a partial bibliography is provided for those who may wish to pursue the topic in more detail. In the initial portion of this section of the course we shall define for our purposes, some of the terms that are used. Materials in general may be classified as either ductile or brittle. Ductile materials under load go through a plastic flow prior to failure. On the other hand, brittle materials under applied forces deform elastically nearly up to the point of failure without going through plastic flow.

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Elastic deformation refers to the ability of a material to deform under load, and then, when the load is removed, to return to its original shape. However even with elastic materials, when the load becomes great enough, permanent deformation may occur. Most rocks are considered to be brittle rather than ductile. Also, most rocks possess compressive strengths that are many times greater than their tensile strengths. Most rock mechanics theory as it applies to hydraulic fracturing is necessarily simplified by the basic assumptions that the rock is homogeneous, elastic, and isotropic. These terms are defined as follows:

•

A material is said to be homogeneous if its smallest part has the same properties as the whole

•

It is elastic if the deformations caused by the force applied to the item completely disappear when the force is removed, and

•

It is isotropic if its properties do not change with direction.

Most problems in mechanics involve the terms stress and strain.

4.3.1 STRESS When a force is applied to an object, the stress that is induced is the force divided by the area over which the force acts. In that sense, it is analogous to pressure. But, whereas a pressure is exerted equally in all directions, a stress has a single direction. This is illustrated in Figure 3.

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ΔL

Z

r

L

Y r+Δr

X Figure 4-7: Deformations Caused By an Applied Force Let F be a force acting compressively on a cylinder of radius r. The effect of F is to induce a stress

σ, with magnitude.

σ=

F

π r2

Since σ acts parallel to the z-axis of a three-dimensional system, it should be properly labelled σz. In this case, there are no forces acting in the x and y directions so we may say that: .

σ x = σ y = 0.

Stresses may be compressive or tensile, in this case σz is a compressive stress. Usually, in rock mechanics, compressive stresses are given positive values and tensile stresses are given negative values.

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4.3.2 STRAIN When a stress exists in a body it produces a deformation. For example, in the present case, the force F induces a stress, σz, which produces a reduction in the length of the cylinder from L to L -

ΔL. This is expressed in terms of the ratio of the change in length to the original length. This is known as the strain, εz.

εz =

[L - Δ L] - L -Δ L = L L

The negative sign indicates shortening rather than a lengthening. Similarly, the strain evidenced by the change of radius from r to r + Δr is expressed as:

εx = εy =

[r + Δ r] - r Δ r = r r

4.3.3 YOUNG'S MODULUS

A material that behaves elastically, stresses and strains are related linearly in the following manner:

⎡1⎤

εz = ⎢ ⎥ σ z ⎣E ⎦

.

In this relationship, E is known as Young's Modulus or the modulus of elasticity of the material, and has the units of psi or GPa. The relationship is known as Hooke's law.

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5000 lb

5000 lb

3 x 107

3 x 106

5000 lb

3 x 105

Figure 4-8: Effect of Varying Young's Modulus (Courtesy Halliburton)

4.3.4 POISSON'S RATIO Another important relationship in the properties of homogeneous, isotropic materials is the relationship between the longitudinal and the radial deformations. This relationship is known as Poisson's Ratio, ν . which is dimensionless .

ν=

εx -εz

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(Assuming Equal Young’s Moduli) 5000 psi

0.1

0.3

0.5

Figure 4-9 Effect of Varying Poisson's Ratio (Courtesy Halliburton). Figure 4-10 demonstrates schematically the effect of varying Poisson's ratio. 4.3.5 PRINCIPAL STRESSES Another term that requires definition results from the fact that all of the stresses acting on a body may be resolved into their directional effects as expressed in three mutually perpendicular directions. The stresses acting in these three mutually perpendicular directions are termed the principal stresses. When the treatment of rock mechanics problems assumes that the rock is isotropic, elastic, and homogeneous, the two properties of the material that must be identified are Young's modulus, E, and Poisson's ratio, ν. These are usually determined by a compressive measurement in the laboratory in which loads and deformations are measured. However, the properties are sometimes deduced from sonic determinations. The relationships for the velocities of the compressional and shear waves respectively are given by the following equations:

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Vc =

⎡ ⎤ E[1- ν ] ⎢ ρ [1+ ν ][1- 2ν ] ⎥ ⎣ ⎦

V sh =

where:

E 2 ρ [1+ ν ]

ρ = density of the rock, Vc = Compressional wave velocity Vsh = Shear wave velocity

4.4

FRACTURE MECHANICS

Every point in every formation is under the influence of various natural stresses. These stresses result from the weight of the overburden as well as from tectonic action.

4.4.1 IN-SITU PRINCIPAL STRESSES The system of stresses acting at a given point in a formation is impossible to define in detail due to its extreme complexity. However, it is possible to resolve the entire network into three mutually perpendicular stresses, which are termed the in situ principal stresses. This greatly simplifies the prediction of the mechanical behaviour of the formation. Figure 4-6 helps us to represent this pictorially.

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σz

σy

σx

Figure 4-10 Representation of Principal Stresses

If the only force acting on a formation were due to the weight of the overburden, then the vertical stress σz would be:

σ z = ρgh

and, the horizontal stress would be

⎡ ν ⎤ σz ⎣ 1- ν ⎥⎦

σx=σy= ⎢ 24

where: σz and σx =

=

σy =

vertical stress horizontal stress

ρ

=

density of the overburden

h

=

depth of the overburden

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ν

=

Poisson's ratio for the formation

g

=

acceleration due to gravity

This is an unreal case since there are always horizontal forces of some magnitude. The example is for illustrative purposes only. It should also be pointed out that, although we generally make the assumption that in rock mechanics the vertical stress is a principal stress, this is not necessarily accurate, since for each situation there is only one true set of principal stresses. It is not ordained that one of these should be vertical.

4.4.2 INTERNAL BOREHOLE PRESSURE Another important aspect to consider is the role of internal pressure acting on the wall of the borehole.

Fig 4-11 Effect of Internal Borehole Pressure (Courtesy Halliburton). Figure 4-7 looks down on a cross-section of the borehole and enables us to visualize some of the effects.

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In setting up this case, we have a stress σx and a stress σy both acting compressively and horizontally on the borehole. But, σx is greater than σy. Therefore, we can see that the borehole will "egg" as shown. However, this causes the elements of rock near B and B' to be placed in compression, while the elements at A and A' are in tension. We know that the tensile strength of the rock is much less than the compressive strength, 5 to 20 times according to Daneshy. Therefore, if sufficient stress is applied to cause a fracture, it will initiate at A-A', in the area of tensile stress. It can be shown mathematically that if σx is greater than σy as in this case, the pressure at which the fracture will initiate is:

p fi = 3 σ y - σ x - T

Where;

pfi T

= the internal wellbore pressure = the tensile strength of the formation

An even more rigorous approach by Haimson and Fairhurst (1967) in which the effect of fluid loss in reducing breakdown pressure is considered, yields the following equation:

p fi =

Where:

3σ x -σ y - T + po [1- 2ν ] 2 -γ [1- ν ]

po

= reservoir pressure

γ

= Biot's dimensionless porous elastic constant,

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γ = 1- cr

cb

where:

cr

= rock matrix compressibility

cb

= rock bulk compressibility

4.4.3 FRACTURE INITIATION It has also been shown that a fracture will initiate at right angles to the direction of the least principal stress, and since in extending, it will follow the path of least work, the plane of the fracture will be perpendicular to the direction of the least compressive principal stress. It is generally accepted that fractures in a given formation in a given area will trend in one particular direction, provided that there is a significant difference between the regional values of σx and σy. For the most part, except in well-developed areas, we do not know the magnitude or the direction of the principal stresses in an area, unless relatively expensive technology (Simonson et al, 1978, Abou-Sayed et al, 1978, Kry et al 1982, Jones and Sargeant, 1993, Kurashige and Clifton, 1992, Wang et al, 1991, Yew and Liu, 1993) has been employed. We will examine that aspect more closely later. We do know that while the direction of initiation may vary under the influence of stress concentrations in the wellbore area, fractures will extend in a direction that is perpendicular to the direction of the least principal in situ compressive stress. The borehole itself will have a local effect on the direction in which a fracture leaves the well bore. But, within a few hole diameters distance, the fracture will orient itself as stated. It is also important to note that the manner in which a fracture grows and extends is still in the area of controversy, although there appears to be more agreement now than in the past.

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If an "elastic" formation is bounded above and below by "plastic" formations, there is no guarantee that the plasticity will be sufficient hindrance to fracture growth to prevent propagating a fracture through the "plastic" formation. In recent years, it has been shown (Simonson et al, 1978, Voegele et al, 1981, Warpinski et al, 1982) that if a portion of the reservoir rock or the boundary rock possesses a higher level of in situ stress, the higher stress level may be sufficient to contain the fracture. This concept will be dealt with more fully later.

4.5

FRACTURE GEOMETRY AND DIMENSIONS

The magnitudes of the three dimensions; length, width, and height of a vertical hydraulic fracture are obviously of very great importance. In general, the greater the amount of fracture area created and exposed to flow, the greater will be the benefit, in terms of production increase achieved (Howard and Fast, 1957). However, other factors in addition to created area must be considered. For example sufficient fracture width is required to place the number of layers of proppant required to conduct the formation fluids through the fracture to the well bore at the required rate during production. But, increasing fracture width tends to decrease fracture area for the same fracture volume.

4.5.1 FLUID LOSS The basic relationship in respect to fracture area calculations was expressed by Carter of Pan American (now Amoco) in the appendix to the classic Howard and Fast paper. Expressed simply, the relationship states that the total volume of fluid injected into a fracture is the sum of the volume that leaks off into the fracture faces (termed fluid loss volume) and the volume of the created fracture.

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The relationship may also be expressed in terms of rate so that the rate of growth of the volume of the fracture is equal to the total injection rate minus the rate at which fluid is lost to the fracture faces.

4.5.1.1 FLUID EFFICIENCY From the same relationship we can arrive at an expression for efficiency of the fluid:

FracturingFluidEfficiency (% ) =

VolumeofFracture * 100 TotalInjectedVolum e

The key factor, then, in calculating created fracture volume, is the volume of fluid lost to the fracture faces. Expressed in terms of the efficiency with which fracture area or fracture volume is created, the lower the fluid loss, the more efficiently the fracture area or volume is created. The rate at which fluid loss occurs may be expressed in terms of a Fracturing Fluid Coefficient, known in the industry as the "C" value. Actually, various authors have tended to recognize three mechanisms, which control the rate at which fracturing fluids leak off to a formation during a hydraulic fracturing treatment.

4.5.1.2 FRACTURING FLUID VISCOSITY CONTROL In this case the principal factor controlling the rate of leak off is the viscosity of the fracturing fluid itself. It is expressed in the relationship:

C v = 0.0469[

Where:

kΔ pφ

μf

]0.5

ft [ min ]0.5

Δp = Bottom hole treating pressure minus reservoir pressure.

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k=

Average relative permeability of the formation to the fracturing fluid.

φ=

Porosity.

μf =

Viscosity of the fracturing fluid that leaks off.

4.5.1.3 CONTROL BY WALL-BUILDING PROPERTIES OF THE FRACTURING FLUID

In this case, the ability of the fracturing fluid to deposit a "filter cake" on the fracture face in much the same way as a drilling mud functions is the controlling factor. Once the filter cake has been formed, the cake itself restricts the rate of leak off. This phenomenon is expressed in the following relationship:

cw =

Where:

0.0164* m

ft

Af

min0.5

m = Slope of the curve from the fluid loss test, cm3/min1/2 Af = Area of the sample over which fluid loss occurs,

cm2.

4.5.1.4 CONTROL OF LEAK OFF BY THE RESERVOIR ITSELF In this instance, the viscosity and compressibility of the reservoir fluid act as the controlling mechanism, especially if the reservoir pressure is above the bubble point. The relationship is expressed: ⎡ kc f φ ⎤ cc = 0.0374 Δ p ⎢ ⎥ ⎣ μr ⎦

Where:

0.5

⎡ ft ⎤ ⎢ min0.5 ⎥ ⎣ ⎦

cf = isothermal compressibility of the reservoir fluid, psi-1.

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μr = Viscosity of reservoir fluid, cp. The three coefficients are summarized in Figure 413. It can be seen that any or all of the following factors can control the amount of fluid loss and consequently the efficiency of the fracturing fluid. -

average effective formation permeability

-

difference between the pressure in the fracture and the reservoir pressure

-

formation porosity

-

viscosity of the fracturing fluid

-

viscosity of the reservoir fluid

-

compressibility of the reservoir fluid

-

degree of filter cake control.

Figure 4- 12 Fluid Loss Coefficients

(* Hall and Dollarhide, (1964, 1968) of Dowell and Williams (1970) of Esso have published on the advantages of a "dynamic" fluid loss test as opposed to the static one used by the industry. The dynamic test appeared to have merit and tended, in some cases, to predict that a higher amount of fluid loss additive would be required to achieve the desired control. However, arguments have been presented to point out some of the shortcomings of the dynamic method and industry was reluctant to widely adopt the dynamic method). In actual fact, it is likely that a combination of all or most of the factors and coefficients will operate simultaneously to influence the efficiency with which fracture area is created. Some people view the fracture system as being divided into two zones at any given time. One is the area over which sufficient of the filter cake has already been deposited to the extent that the cake controls, and the other is the area at the tip of the fracture where the wall-building is still

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incomplete, and either reservoir fluid properties or the viscosity of the fracturing fluid still controls the leak off rate. Some people advocate the use of a composite fluid loss coefficient, Ceff and there are several ways to do this. One to combine them in a relationship as follows:

1 C eff

=

1 Cc

+

1 Cv

+

1 Cw

4.5.1.5 NUMERICAL MODELLING OF FLUID LOSS

The use of simulators to model fluid loss is a relatively new development. Settari proposed a new method with certain stated advantages. The model allows many of the parameters (pressure, viscosity and filtration characteristics) to vary during filtration and thus can simulate non-linear effects. It accounts for core length, difference in viscosity between the filtrate and the parent gelled fluid and shear sensitivity. He compared his work with data determined by McDaniel et al of Dresser Titan (now BJ) in which a more rigorous test method than previously applied was proposed. Economides and Nolte (1989) described various modelling concepts for fluid loss and remarked that this was still a research problem.

4.5.1.6 FIELD MEASUREMENT OF FLUID LOSS

One of the important aspects of the fluid loss process is development of methods to measure and analyze the effective fluid loss that actually occurred in the field. Some early work was done by Nierode to compare instantaneous shut down pressures at the beginning and end of fracturing treatments and thus infer a fluid loss value. Later, Nolte, Smith and others of Amoco issued a series of papers that significantly advanced fracturing theory and application. Included in the development was a method of determining various parameters from fracturing pressure decline analysis. The value of the average effective fluid loss coefficient and the fracturing fluid efficiency are two of the parameters that may be determined by this method. It is also possible to calculate a _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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number of other important factors and the method is more fully documented later in this chapter. The serious investigator may be interested in many other contributions on fluid loss and/or fracture modelling and monitoring included in the bibliography (Economides and Valko, 1993, Gu and Leung, 1993, McLellan and Janz, 1992, Rodriguez et al, 1992, Settari, 1993, Vandamme et al 1994, Warpinski et al, 1993, Weng, 1992). In general, it is probably safe to say that many of the simpler methods of describing fluid loss tend to result in estimating fluid loss values that are higher than the values actually experienced in the field. It therefore follows that pad volumes and additive loading may be higher (more costly) than necessary. (This may also have a significant effect on proppant distribution in the fracture and possibly on damage to the fracture conductivity). Recall that we determined that the relationship that determines fracture growth is, simplified, Fracture volume = injected volume - fluid loss volume. Then, for the area of the fracture to be calculated, the width must be known, estimated or calculated. 4.5.1.7 CARTER EQUATION

Carter, in his appendix to the Howard and Fast paper, gave this relationship for fracture area:

A =

Qw f 4πC

2 eff

Where:

2x ⎤ ⎡ x2 ⎢e erfc(x)+ π - 1⎥ ⎣ ⎦

x =

2 C eff π t wf

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and, in order to include the effect of spurt loss, Vsp , it will be necessary to include this as an increased fracture width such that: wi = w + [

V sp ] 15.24* a

In these equations, A = total area of one face of fracture, ft2 Q = constant injection rate, ft3/min t = total pumping time, min wf = constant fracture width, ft Ceff = fracturing fluid coefficient, ft/min0.5 erfc(x) = complimentary error function of x. Vsp = value of spurt loss from fluid loss test a

= test area over which spurt loss occurs

Since the presentation of Carter's equation by Howard and Fast in 1957, there have been several proposed methods for improving upon the Carter equation, including Williams of Esso and Geertsma and de Klerk of Shell. Of these, the Geertsma and de Klerk method appeared to be the more exact. They also proposed a shorter form which was applicable in certain defined situations and which could be handled by an engineer in the field using a hand calculator.

4.5.1.8 GLOBAL FLUID LOSS CONSIDERATIONS

Since fluid loss is of first order importance in the generation/propagation of a fracture, it is important to understand the difference in values of fluid loss determined under differing conditions. One of the least understood issues is that fluid loss can change during a fracturing treatment. As the net pressure increases, the pressure near the well bore could become large enough to reach a threshold pressure. At this point, fluid loss could increase significantly due to opening of existing microfissures or creation of new ones. This possibility mandates that the minifrac determination of _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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fluid loss, or the transfer of fluid loss data from other jobs should be representative of the situation that will exist in the current job. Similar results could occur if the fracture was to leave a less permeable (low fluid loss) zone and penetrate into a more permeable (high fluid loss) zone.

4.5.2 FRACTURE WIDTH However, for this discussion, the important observation is that fracture width, w, is a most critical variable, not only in the calculation of fracture volume and area, but also because the fracture width must be wide enough to accept proppant or a job failure will occur. One of the first important North American works on fracture width was by Perkins and Kern of Atlantic, which followed earlier work by Russian authors Khristianovich et al. Later Geertsma and de Klerk proposed their approach.

4.5.2.1 COMPARISON OF FRACTURE MODEL ASSUMPTIONS

One of the important differences between the assumptions made by the various authors who have dealt with fracture geometry is the manner in which the fracture width is treated and the assumptions that are implied as a result thereof. For example, Khristianovich and Zheltov assume that the fracture is of constant width from top to bottom and therefore bed slippage must occur at the boundaries. Perkins and Kern assume elliptical fracture width narrowing to near zero at the bed boundaries and therefore assume that slippage does not occur. For slippage to occur at any significant depth the enormous friction between the layers, which increases with depth, must be overcome. It is easier to imagine this occurring at shallower depths. However, certain special conditions may permit it to occur in other situations. Bounding coal beds may be such a case. The Perkins and Kern work arrived at some interesting generalizations concerning aspects of fracture behaviour other than fracture width, but for this part of our discussion we will concern ourselves only with the portion of their work that bears closely upon fracture width for vertical fractures. Some of these are as follows:

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-

Depth of the pay zone has little effect on width by itself, although some rock properties are depth sensitive.

-

Crack width is not very sensitive to rock properties such as Young's modulus.

-

Fracture width may be very sensitive to the apparent viscosity of the slurry of fracturing fluid and proppant.

-

Pump rates affect fracture width.

-

Total volume of fracturing fluid pumped affects width.

-

In general, fracture width will tend to increase as a result of increasing pressure drop in the fracture. Consequently, any factor which increases pressure drop in the fracture will increase fracture width.

The Geertsma and de Klerk approach, according to the authors, gives comparable results to Perkins and Kern, although due to the assumption of different boundary conditions and pressure distribution in the fracture, the Perkins and Kern calculation of fracture width is too low. The Geertsma and de Klerk method has the advantage of combining length and width determinations, updating both Howard and Fast and Perkins and Kern. Also it may be used by an engineer in the field with the aid of one chart and a hand calculator. Conway et al, 1985, described and compared a number of fracture pressure behaviour types that had been postulated by others. Warpinski et al, 1994 compared responses of the various fracture simulators to a common set of real data.

4.5.3 FRACTURE HEIGHT So far in our review of methods for determining the values of factors involved in vertical fracture geometry, we have looked at only two of the three dimensions. That is to say, we have examined methods for determining fracture length and fracture width but we have not as yet touched on fracture height. So far, in our discussion, the value for fracture height has had to be assigned in some manner and `input' into the calculations. The most common approach has

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been to assume that the fracture height is the same as formation thickness or nearly so. Many of the earlier authors tended to assume that shale beds bounding a pay zone would tend to be more plastic (less brittle) in their behaviour, and thus would resist penetration by fractures originating in the pay zone. The earlier authors tended to assume also that the vertical growth of fractures would be rather rapid until the barriers were encountered, and then further growth would be outward. This helps to explain how these earlier authors justified the assumption that vertical fracture height was equivalent to formation thickness. A considerable amount of work has been done in the area of rock mechanics research as applied to hydraulic fracturing by various organizations. Some of this important work bears heavily upon the subject of vertical fracture height. Daneshy noted that a change in rock properties between two adjacent zones did not in itself guarantee that a vertical fracture originating in one zone would not penetrate the barrier. All authors recognize the need to be able to predict the actual fracture height during a treatment, and how to control the height, if possible. Let's look at a hypothetical but reasonable case in order to properly grasp the significance of fracture height knowledge and control. If a gas cap or underlying water is present in an oil reservoir, the importance of avoiding uncontrolled and undesirable fracture growth in the vertical direction is obvious. Perhaps just as important is one other effect of uncontrolled downward growth. If downward growth is permitted such that the fracture actually grows below the pay, it is not difficult to visualize the creation of a fracture volume below the pay that is sufficiently large to contain a significant portion or perhaps all of the proppant that is supposed to prop the pay. Should this happen, it is likely that little or no stimulation would occur because the fracture would `heal' where it was not propped.

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It is critical to understand that all predictions of fracture geometry, no matter how sophisticated they purport to be, are in error to the extent that the prediction or assumption of fracture height and position relative to the pay boundaries is in error.

4.5.4 CONTAINMENT

There has been considerable work published by a variety of authors in respect to the role of in situ stresses. (Simonson et al 1978, Abou-Sayed et al, 1978, Kry et al, 1982 Voegele et al, 1981, Warpinski et al, 1982). Warpinski and others with Sandia National Laboratories have published papers that have clearly verified some of these concepts. It is fair to say that in situ stresses, if they exist in the appropriate magnitudes above and below a propagating fracture have the ability to contain the vertical growth of that fracture, while permitting the fracture to extend radially. Of course, when the pressure at the tip of the fracture in the "barrier" becomes great enough, the containing mechanism will be overcome. Figures 414 and 4-15 help to illustrate that point.

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Figure 4-13 Schematic Illustrating Effects of Containment

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This recognition of the role of in situ stresses in fracture containment indicates to this author the need for a method and a program for mapping in situ stress levels in various formations and areas. Dr. Sebastian Bell of the Institute of Sedimentary and Petroleum Geology of the Geological Survey of Canada have published this information for Western Canada. A technique for using hydraulic fracturing methods on a micro scale has been developed for this purpose, (Abou-Sayed et al, 1978) and results of a Canadian program have been published by Esso (Kry and Gronseth,

Figure 4-14

Stress Contrast and Excess Pressure Versus Barrier Penetration.

1982). In addition to mapping the stress values that exist in given portions of particular formations in specific areas, a follow-up program to catalogue fracture heights actually observed would be very interesting. This would be even more valuable if the role of the influential factors such as injection rate, viscosity, pumping times and volumes and so forth could be quantified for particular areas of interest. Methods that could be used are temperature and radioactive tracer logging programs, tiltmeter and microseismic surveys recognizing that all have limitations. In this way, a much more reliable data base should be generated which should, in turn, lead to better "assumptions" of vertical fracture height, and therefore to more reliable prediction of fracturing results. The sensitivity to breakout of the fracture in certain areas could be quantified and consideration given to that aspect in the fracture design. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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With the increased availability of three dimensional fracture propagation programs, the value of in situ stress measurement data has become obvious.

4.5.5 FRAC MODELS With fully three dimensional fracture geometry calculation methods available for wide use, it is possible to create much better fracture designs based on measured data and on "reasonable" assumptions. Some early work was done (Nolte and Smith, 1979, Nolte, 1979, Nolte, 1982) in analyzing the character of pressure changes during fracturing treatments in order to understand the implications and act on that understanding while the job is in progress. Most service companies now have treatment control units in the field which can perform the real time plots, or variations thereof, along with many other functions. We are seeing much wider availability and application of real-time simulation in the field, on the job, with actual job data being used as continuous input. The result is a video display in the frac control unit of dynamic fracture growth, including position of the fracture, which permits corrective measures to be taken in order to handle job events as they occur and still maintain control over fracture propagation. This is being done now using technology developed while using an experimental prototype unit developed by the Gas Research Institute. It functions using "what if" inputs and extremely fast (much faster than real time) simulation of the results of the "what if" statement in the field computer. This enables the engineer in charge to evaluate several options and make the best adjustment in time to have the desired effect of controlling fracture geometry. The service companies have introduced a skid mounted unit which continuously measures the pressure loss due to flow at known velocities through several sizes of pipe diameter and then processes the resultant data in the on-site computer van to calculate pipe friction based on field measured rheological properties. It should be noted that the field properties are measured on

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uncomplexed fluid that does not contain proppant. Notwithstanding that shortcoming, this innovation is a significant step toward solving the problem of determining bottom hole pressure while pumping rheologically complex systems through tubing and a packer. It is not conveniently possible to obtain a real time surface reading of bottom hole treating pressures in such configurations. Memory recorders assist in post analysis. Let us back up a step and talk some more about the shape and orientation of fractures. Reviewing some previous comments, fractures will orient themselves so as to become perpendicular to the plane of least compressive in situ principal stress. In general, fractures at greater depths tend to be vertical while horizontal fractures, if they occur, tend to occur at much shallower depths. Daneshy (1973), and others since, have indicated that fractures could, in fact, be inclined. That is, they might be neither horizontal, nor vertical, nor parallel to the axis of the wellbore. He further showed that the trace of the fracture at the wellbore may not be a true indication of the plane of the fracture a few wellbore diameters away. It may not even indicate its true compass direction. Caution is therefore advised concerning the use of wellbore inspection devices to estimate the inclination and direction of fractures. Various authors have assumed shapes for hydraulic fractures in order to develop their theory. The references should be consulted if the reader wishes to rely upon the works of any of the writers. It is important to understand the basic assumptions that each investigator made when comparing their theories. It is vital to note that in connection with fracture geometry predictions, all authors require knowledge of fracturing fluid properties. These property determinations should be conducted under simulated in situ conditions to the fullest extent possible. Also the variation in the properties of the fluid due to temperature, time, shear and breaking mechanism should be investigated and tabulated in the data base. The concentration of propping agent has a very significant effect on friction. Correlations have been developed to take this into account (Shah, 1993). _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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More on fracture models is found in a later section DECIDING WHICH WELLS TO FRACTURE If a successful result with a minimum of downside risk is to be achieved, operators must select candidate wells for hydraulic fracturing with care. One logical analysis method is suggested in the following paragraphs To be a top-ranked candidate, the well should meet the following requirements: a.

There must be sufficient reserves attributed to the well to justify the overall stimulation expense. In this use of the word reserves we imply that the resource is sufficiently abundant and that it in order for a quantity of the resource to be a termed a reserve, it must be economically recoverable.

b.

Both the rate of recovery following the treatment, and the volume of additional production should be great enough, that net present value (and/or other company economic investment requirements) criteria can be met.

c.

Other similar wells in the same area, same formation should have been successfully treated with actual production matching or exceeding predicted recovery (rate and cumulative), using similar models.

c.

Laboratory work, specific to this pool, should have been done to verify the selection of propping agent and fracturing fluid with respect to any adverse effects such as proppant crushing, chemical interaction between the proppant, the reservoir fluid, the formation rock and the fracturing fluid or any of them. The lab work should also verify that the fracturing fluid shall not be retained in the formation due to capillary forces or other reasons.

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d.

There should be some field experience in the area to support a level of confidence that containment of the fracture within upper and lower bounds can be achieved.

e.

If containment is lost during a treatment, the risk should not be greater than misplaced frac fluid and/or proppant. Unplanned vertical extension of the fracture must not lead to unwanted fluids (gas cap or gas zone or water), or to zones that the operator is not entitled to access and produce, or which, if damaged, may become the subject of litigation.

f.

The azimuth of the created fracture must not be in a direction that would adversely affect recovery or lead to premature breakthrough under planned or existing EOR patterns.

g.

The mechanical condition of the well, including casing and cementing, should support the required activities.

The above factors, plus any others that the operator wishes to assess, should be applied in an evaluation grid in order to prioritize the candidate wells. Some candidates may well be placed in a high-risk category or even be eliminated by this method.

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PREDICTING THE RESULTS OF HYDRAULIC FRACTURING

To accurately predict the results of a fracturing treatment requires a good reservoir model and a good fracture model. It also requires some similarity between the executed treatment and the one that was modeled. Further, the created fracture geometry must be similar to the predicted one. Differences in actual versus modeled geometry may well be the most significant factor in error. The following discussion provides a greater elaboration. The reader is referred to reservoir and fracture modeling and other papers/sources for more detailed discussion. The reservoir model must be able to accurately describe the reservoir that is to be fractured, in terms of shape, fluids, pressures and physical properties variation (preferably with some honoring of three-dimensional variation). It must also be capable of accepting and honoring a three-dimensionally described fracture.

The 3-D fracture models offer associated reservoir models that are used to help optimize fracture design for best size. Typically, that would be the one size that produces near the best net present value (NPV). This requires a prediction of future incremental production, hence the need for some sort of reservoir model. Typically, the reservoir models associated with the 3-D simulators are quite simplistic and would not lend themselves to the degree of sophistication suggested above. This then suggests that there is a need for methods to close the gap between predicted production and actual production, and to identify the parameters that are in error and which led to the incorrect predictions.

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One way to do this is by employing history matching techniques, (cumulative production volume versus time on production) which are relatively well known in the industry. If a good history match can be achieved without unrealistic parametric changes, the corrected values may be useful when designing the next similar job. Other tools include the use of pressure transient analysis methods. Some of these methods, if applied to an already fractured well can be interpreted to yield the value of the skin that may exist between the reservoir and the fracture, in addition to the fracture length. One of the parameters that may or may not be in error is the vertical fracture height. It is also not easy to determine with great confidence. However, the height is of very great significance if one considers that it is one of the three dimensions that not only describe the fracture geometry but which, if incorrectly assumed or estimated, will inevitably lead to incorrect calculations of at least one of the other dimensions, width and length. The difficulty in determining fracture height with confidence lies in the fact that the common techniques (temperature logging and radioactive isotope tracer logging) are both limited to investigating the very near well-bore area. If the logged temperature or radioactivity (or lack of it) may be due to some reason other than the presence or absence of a propped hydraulic fracture at that point. This is particularly true in regard to radioactive tracers since their response is very much a function of proximity to the logging source. This is not to say that these techniques can not or should not be used to evaluate fracture height. One paper describes the conundrum that one is in when the well bore is not vertical and the fractures are vertical (or vice versa). If there is more than one set of perforations, the paper describes that there could be two or more generally vertical, parallel fractures. In addition to other effects, the vertical extent of these fractures may not be easily detected due to the trace of the fracture moving further away from its intersection with the axis of the well bore. Tiltmeters and microseismic techniques do not have the same limitations.

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TABLE OF CONTENTS THEORY OF HYDRAULIC FRACTURING PRESSURE-RATE RELATIONSHIPS

38

FRACTURE EXTENSION PRESSURE GRADIENT

40

ROCK MECHANICS Stress Strain Young's Modulus Poisson's Ratio Principal Stresses

43 44 46 46 47 48

FRACTURE MECHANICS In-situ Principal Stresses Internal Borehole Pressure Fracture Initiation

49 49 51 53

FRACTURE GEOMETRY AND DIMENSIONS Fluid Loss Fluid efficiency Fracturing fluid viscosity control Control by wall-building properties of the fracturing fluid Control of leak-off by the reservoir itself Numerical modeling of fluid loss Field measurement of fluid loss Carter equation Global fluid loss considerations Fracture width Comparison of fracture model assumptions Fracture height Containment Frac models

54 54 55 55 56 56 58 59 59 60 61 61 62 64 67

DECIDING WHICH WELLS TO FRACTURE

69

PREDICTING THE RESULTS OF HYDRAULIC FRACTURING

71

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SECTION 5 - FRACTURING FLUIDS

FUNCTIONS The functions of fracturing fluids should be clearly understood by the fracture treatment designer. Let us review exactly what these functions are. The first function of a fracturing fluid is to transmit energy from the high pressure, positive displacement pumps of the fracturing trucks to the bottom of the well in order to cause a fracture to be initiated. Following crack initiation, the next function is to extend the fracture and to establish fracture width at the well bore. Once sufficient width has been established to accommodate the propping agent, the role of the fluid is enlarged to include carrying the proppant from the blender to the formation, and then transport and suspend the proppant particles within the fracture. At the conclusion of the fracturing operation, when all of the proppant has been placed into the fracture, the next function of the fracturing fluid is to revert to a very low viscosity fluid with a very high fluid loss rate (leak off) which will enable the fracture to close quickly upon the proppant prior to total settlement of the suspended proppant. Occasionally, there is an additional function of the fracturing fluid. In some instances, the ability of the fracturing fluid to dissolve rock or certain rock constituents is used to advantage. In such cases, acids may be employed as the fracturing fluid.

PROPERTIES OF THE IDEAL FRACTURING FLUID

Reactions and Residues We have listed the primary functions of fracturing fluids. One other aspect which we should remember is that, except in special cases, such as fracture acidizing, the fracturing fluid should be inert with respect to interaction with the formation rock or with the proppant. Ideally, every drop should be recovered from the formation and from the fracture. Also, the fracturing fluid should not

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react with the reservoir fluid, except perhaps, to reduce the surface tension, viscosity or to increase volatility. The most significant way in which fracturing fluids can reduce the effectiveness of the job is to cause plugging within the fracture itself due to residue. One of the worst causes of this effect is a guar gum gelling agent. Examples of extremely severe plugging, approaching 100%, have been reported as a result of laboratory testing under fully simulated in situ conditions. The same report indicated that there could also be considerable variation in the same type of product when obtained from different service companies. This is perhaps one of the most important but least understood factors, i.e. that one risks a considerable variation in quality when one specifies Brand X or equal. In the opinion of the writer, no product that is to be injected into a formation should be accepted for use by any oil company until either the oil company has tested the product under fully simulated down hole conditions in its own laboratory and passed on the product for the intended use, or else the supplier has provided sufficient evidence of adequate testing of the product to allay fears. Again, the test conditions are very important. While there exists API RP 39 that deals with evaluation of fracturing fluids, this procedure leaves much to be desired. Ideally, an improved industry standard testing procedure should be developed and used. In the absence of such, companies should consider establishing such a procedure for in-house use.

Fluid Loss Another property of the ideal fracturing fluid is that it should exhibit a controlled, predictable fluid loss. This is extremely important because the rate of fluid loss determines a large number of other variables, such as fracture volume, and to some extent the length, width and height of the fracture. The fracture geometry, in turn, is significant in terms of proppant placement and so forth. An under estimation of fluid loss rate may lead to a screen out near the beginning of the job due to inadequate fracture width, and complete job failure may result. Fluid loss may be controlled by any one of, or a combination of, three mechanisms of control; reservoir properties, fracturing fluid viscosity, or wall-building properties of the fracturing fluid itself. Due to the possibility of severe restriction to productivity that might be caused by plugging of the

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fracture bed, there is a trend away from the use of wall-building additives except for additives, which dissolve, in the produced fluids. These additives should be tested in the produced fluids. Control of fluid loss by controlling the viscosity of the fracturing fluid augmented, if necessary, by soluble wall-building additives is the most popular approach. Even in very tight reservoirs this approach is widely used since long fractures are required and proppant transport becomes a very key factor. Viscosity control is usually achieved in one of three manners; ultra viscous cross-linked gels, moderately viscous non-cross-linked (linear) gels, or very finely dispersed emulsions. These fluids tend to control fluid loss primarily due to their viscosity, but also due to the matting-out of the crosslinked gel particles, which would impart a wall-building characteristic. In the case of emulsions, fluid loss control is due to the multiple phase and interfacial tension properties of the mixture. There is room for controversy concerning fluid loss testing methods, dynamic versus static, and there is a certain amount of disagreement concerning the treatment of the first portion of the fluid loss, known as the spurt loss. There is also varying opinion on the seriousness of the effect of pressure on the fluid loss rate through filter cakes. The role of fluid loss in fracture design is more critical in higher permeability reservoirs. It is vital to determine the fluid loss characteristics by careful laboratory testing using representative and multiple rock samples. The works of Nierode, and Nolte and Smith provide us with ways of determining the correlation between laboratory and field determinations of fluid loss coefficient.

Proppant Transporter The ideal fracturing fluid should be a "perfect transporter" of proppant. That is to say, the fluid should have the ability to carry the proppant in perfect suspension, with no settling, until such time as all of the proppant has been placed in the design location in the fracture. This implies that the fluid should exhibit an effective viscosity sufficient to resist the settling effect due to gravity, or that the specific gravity of the proppant and the fracturing fluid will be the same. Since we have very

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little choice concerning the density of the propping agent, the quality of the fracturing fluid becomes all-important. The cross-linked water gels and some of the foamed materials are considered to be the better transporters. There is a certain amount of controversy in the industry concerning an acceptable laboratory method to determine the effective viscosity of the cross-linked gel systems, foams, and so forth. The traditional Power Law method of measuring shear stress at various shear rates and plotting on log-log paper has been found to be unsatisfactory due to the inadequacy of the laboratory instrumentation when testing cross-linked fluids having ultra-high viscosity. An understanding of the mechanism and the role of proppant transport is mandatory for effective design of hydraulic fracturing treatments. Let us again emphasise that unless a hydraulically created fracture is adequately propped with an appropriate propping agent, placed and held in the proper position in the fracture, there may be little or no benefit to be gained from the treatment. In order to understand the wide variation that is possible in the final shape of the deposited sand bed, we must review some basic items. These include a discussion on the proppant-fluid ratio, the ratio between injected fluid, fluid leak off and concentration of proppant in the fluid remaining in the fracture, as well as the relationship between fracture geometry and the velocity of the fracturing fluid moving in the fracture. All of these items and more are important factors in proppant transport. Also, and perhaps most important, after pumping stops, consideration must be given to the continuing tendency for the fracture to grow, the suspended proppant to settle and the simultaneous tendency for the fracture to close. The convection concept (Cleary and Fonseca, 1992) mentioned previously adds another dimension to the complications of proppant transport and placement. A number of earlier investigators have examined proppant transport, but the many of the methods used were derived from the theory put forth by Daneshy (1975). His paper, along with the one by Cleary and Fonseca, is recommended reading for all engineers involved in reservoir or production _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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engineering who want to understand well stimulation by fracturing. We will not repeat the detail of his derivations in this course, but the role of proppant transport is considered to be so fundamental in fracturing that an overview must be included.

SEQUENTIAL DESCRIPTION Let us first consider the concept of how the fracturing fluid creates the fracture. As a volume of fluid is injected into the rock, one portion of the fluid, the fluid loss volume, leaks off and is lost from the fracture. The remaining portion stays in the fracture. Then, when the next volume enters the fracture, the portion remaining from the first volume is pushed ahead, opening up new fracture volume. As it does, a portion leaks off and a portion remains in the fracture. This process continues throughout the pumping operation. The fracture width at any specific distance from the well bore will increase from zero to some nearequilibrium value as pumping continues. Consequently, after a period of pumping the width would become large enough to accept a particle such as propping agent.

First element enters fracture

1

Second element enters, first element advances.

2

1

Figure 15: Concept of Fluid Loss

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Proppant concentration factor

6

5

4

3

2 1

Figure 16: Proppant Concentration Factor

Screen out due to Inadequate width Screen out due to concentration

Figure 17: Screen-out Schematics

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One can visualise that an element of fluid into which proppant has been introduced would tend to lose some of its fluid phase but none of its proppant as it travelled along the fracture. Therefore, the proppant concentration increases as the fluid element moves through the fracture. A screen out (or sand-off, this text uses the two terms interchangeably) will occur if either the fracture width at the leading edge of the moving proppant is too small or the concentration of proppant at the leading edge becomes too high. In order to help avoid this scenario of a screen out, a volume of fluid, known as the pad volume, is added at the beginning of the job. (Sometimes a special pre-treatment fluid is pumped ahead of the pad volume. This is called the pre-pad.) The pad volume consists of high quality fracturing fluid containing all of the appropriate additives but no propping agent. The purpose is to generate sufficient fracture width ahead of the propping agent and to provide a pad of fluid at the leading edge to help condition the faces of the fracture so that fluid losses will be controlled by the time the proppant arrives at a given point in the fracture. If the proper basic information is available this volume may be calculated and this is usually done with the aid of a computer. Later we will show how the assumptions can be verified in the field by a small frac without proppant pumped before the main frac.

PARTICLE VELOCITY Once the pad volume has been pumped, the addition of propping agent can begin. If we imagine the propping agent particle moving away from the well bore, carried by an element of fluid, there are two directional components to its velocity. Horizontally, the particle has been observed experimentally (Daneshy, 1975) to move with the fluid slug without significant slippage. Some observers (Clark et al, 1977) dispute this claim, and say that the horizontal velocity of the proppant particle is only 70 to 90% of the velocity of the fluid. Again, we remind readers to also consider the contribution of convection by Cleary and Fonseca (1992). The second component of the particle velocity is the vertical (downward) direction. This portion is termed the settling velocity. It has been shown by Daneshy to be affected by the following variables: _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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-

Flow properties of the fracturing fluid, (n' and k' modified).

-

Particle diameter, d

-

Particle density, ρsd

-

Fracturing fluid density, ρf

Daneshy provided an equation that relates these variables as follows:

[2n+ 1]d ⎡ [ ρ sd - ρ f ]d ⎤ V= ⎢ ⎥ 108n ⎣ 72 k a ⎦

V h =V

10

1.82

n-1

f vsl [1- f vsl ]

Where: fvsl = the volume fraction of the slurry occupied by the fluid. He also showed that when there was more than one particle, and if there was any interference between particles, the effect of this interference was to hinder the settling velocity. To account for this he provided an additional equation to correct the settling rate.

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TRANSPORT, SUSPENSION, BED DEPOSIT Daneshy shows how sand particles are carried in the fracture in a `trajectory'. At some point, a particle introduced at the top of the fracture follows a trajectory that carries it over the already deposited particles extending out from the well bore. From that point in time forward, the remaining particles to enter the fracture will be deposited on top of these that have already settled. They will not extend further from the well bore during this phase. However, at some time, the deposited bed height will have built up at the well bore to the point where the velocity of the flowing slurry across the top of the bed will have increased to the extent that particles are carried along by the fast moving fluid and not deposited in the previous manner. The bed height corresponding to this velocity is known as the `equilibrium bed height.' Further deposition tends to create a nearly rectangular shaped bed. The angle at the nose of the bed will approach the angle of repose of the proppant. Further deposition tends to extend the length of the bed with the angle of the nose remaining the same. Daneshy's computer program provides the following profile:

•

Sand bed deposited at the end of pumping

•

Sand in suspension at the end of pumping

•

Bed shape after total deposition, assuming that all of the sand settles.

It should be noted that papers published by other transport investigators (Dowell-Conoco and Western) tend to predict faster settling rates than Daneshy. In addition, most service companies are providing predictions of fracture closure time. Cleary and Fonseca (1992) differ significantly from Daneshy and suggest that there are density, thermal, and other factors that contribute to a convection phenomenon that Daneshy did not give consideration to.

Rheological Characteristics The ability to control and predict the "viscosity" of a fracturing fluid is very important due to the role that viscosity plays in transport, fluid loss, friction in the pipe and friction in the fracture. Friction in _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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the fracture is in turn very important in respect to fracture height and fracture width, and therefore, in containment. As mentioned, treatment of "viscosity" of non-Newtonian fluids, particularly cross-linked water gels and foams, is a very complex subject and much more work must be done before an industry consensus is reached. At the moment, the best data is probably that which has been generated for water gels and certain gelled refinery products as a result of pipe flow measurements. Some correlations between laboratory and field data for thick gels with high propping agent concentrations have been published. When more of this type of data is available in data banks, fracture designs will be improved. Naturally, one of the more important and desirable characteristics of a fracturing fluid is its ability to be pumped at high rates with low frictional pressure loss. The service companies have made very significant contributions in this respect, so it is now possible to pump fluids at high rates with a fraction of the horsepower formerly required. The ability to efficiently transfer energy from the surface to the formation has been a huge contribution. It is important when planning treatments to realise that not all friction reducers are compatible with all other additives and it is well to remind ourselves that when there is an incompatibility between two additives, there is a good possibility that neither will function. Field measurements of the actual value of friction due to pumping are very easy to obtain, and this determination should be made routinely on fracturing jobs to verify the performance of service company additives. It should be noted that the frictional pressure loss that is recorded just prior to the instantaneous shut down pressure is actually a combination of frictions. These include pipe, perforation, near wellbore and fracture friction. It cannot be assumed that all of the friction is due to pipe friction. In fact, it is possible that an indication as to a restricted number of perforations open, or excessive nearwellbore friction may come from analysis of this part of the recording. This is especially true if there is an unusually high pressure loss, and if a Newtonian fluid is being pumped during the flushing of the pipe at the end of the job.

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Fracturing fluids are generally not run ‘neat'. The base fluid is usually treated with at least one or two additives of one kind or another to increase the viscosity, prevent emulsions, and so forth. One of the most common additives is a gelling agent to increase the ability of the fluid to carry proppants in suspension, and to resist leaking off into the formation. However, once the last of the proppant has been displaced out of the casing and into the formation, a very important combination of events occurs. This period can have enormous influence on the success or failure of the job. Unfortunately, it is the period to which the least attention is paid. This can be a terrible mistake. It is very important to have a clear mental picture of the situation in the fracture at the conclusion of pumping. In the ideal case, a fairly high concentration of proppant per unit area of fracture face has been carried into the fracture in perfect suspension (no settling). It is necessary for fluid loss to occur before the pressure in the fracture can fall in order to allow the fracture to begin to close. The faster the pressure is reduced, the faster the fracture closes. However, in order for fluid loss to occur, some finite time is required. If the proppant remains held in perfect suspension, the amount of time is of no consequence. In the real world, we seldom, if ever, achieve perfect transport with materials presently in use. That is to say, some settling of the proppant occurs, both during pumping and after pumping has stopped. In view of this, closure time becomes critically important. Unless there is sufficient loss of fluid after pumping stops (and before complete settling of the proppant) to enable the fracture to close sufficiently to prevent further settling, then all of the proppant will settle to the bottom. This could leave a large portion, or perhaps the entire top portion of the fracture unpropped. Some people, who have conducted diagnostic computer simulations on instances of job failures, are claiming that there is strong indication that this may be occurring in more instances (the figure 90% has been mentioned) than was previously suspected. However, it can be very dangerous to generalise and it would be very easy to draw the wrong conclusions unless all of the facts of individual cases are examined very carefully. The diagnostic technique does not result in a unique solution unless several questionable assumptions are made.

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Figure 18: History Match of Proppant Distribution at Closure The manner in which the fluid loss and viscosity characteristics change at the end of the pumping is very important, and much more development work needs to be done in this area. Service companies should be asked for data on this aspect of their fluids. In the meanwhile, a very reasonable approach to the problem would be to develop a pressure-time-rate schedule for bleeding off pressure at the surface in a very controlled manner, immediately after the cessation of pumping, in order to deliberately reduce the internal fracture pressure and allow fracture closure to take place. Some engineering record keeping and analysis of volume, rate and pressure relationships for this operation, along with produced proppant volumes should allow rules of thumb to be developed for particular fields.

Phases The `ideal' fracturing fluid will be of such composition that when it is introduced into the formation, no additional phases will be added to complicate the saturation of the formation and perhaps result in permanent impairment. For example, a dry gas formation that has no hydrocarbon (liquid)

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saturation should probably not be treated with a hydrocarbon based fracturing fluid, if a satisfactory alternative is available. Such alternatives might be (depending upon the results of laboratory tests) water, alcohol, carbon dioxide or foam based.

Gas Reservoirs with Low Level Water Saturation An earlier version of this present course pointed out in 1984 that gas reservoirs may exist that are, at the present time, under-saturated with regard to water. In other words, the current level of formation water saturation is less than would be the case if a sample of the rock was flooded with formation water and then displaced with humidified formation gas to an irreducible saturation level. The implication of such a situation, were it to exist, is that treatment of the formation with a water base fracturing fluid would likely semi-permanently raise the water saturation, thereby reducing the relative permeability to gas, and consequently resulting in lower gas production than would be the case if the water saturation had remained undisturbed. It is expected that this would not be the case if the relative permeability problem could have been avoided by using a non-wetting, highly recoverable phase. If such a highly under-saturated condition is detected by log analysis or other means, such as preserved-core analysis, laboratory work to evaluate the resultant relative permeability to gas during various clean-up stages following treatment by various base fracturing fluids may be justified. Some production companies have conducted a number of treatments on dry gas wells using hydrocarbon fracturing base fluids that are highly volatile at reservoir temperatures. The initial results of such treatments are encouraging. Careful selection of candidates and testing of proposed fluids together with formation rock and reservoir fluid samples is recommended. Care must also be taken to assure compatibility between the frac fluid and any completion fluids that may have been lost to the formation prior to the frac.

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Several formations have been examined and some field jobs have been designed with this aspect in mind (Bennion, D.B. et al, 1994). The significance of low treatment fluid recovery is far greater where short or low conductivity hydraulic fractures are prevalent. This can occur even when very large quantities of proppant are placed. The important aspect is the final location and geometry of the propped fracture; not how many tonnes were placed. If the fracture geometry is such that the fracture is adequately propped for only a very short distance in the productive part of the zone, retention of the wetting phase can be devastating. Most people are familiar with the effect of saturation on relative permeability curves. Papers by Jones et al, and by Holditch have effectively discussed the role of capillary pressure and how it relates to clean up of an invaded reservoir, with particular emphasis on low pressure reservoirs that have been fractured. A case for the use of surface and interfacial tension reduction additives can be easily made for such instances. A product has been introduced to attack the problem from a wettability point of view by changing the contact angle between the water and the sand grain surface. Normally this angle is about 0o. The product is designed to change the contact angle to between 90o and 180o. The effect is to completely eliminate or reverse capillary pressure. The capillary pressure equation is

Pcap =

Where:

2γ cosθ r

γ = liquid-vapour interfacial tension θ = contact angle between the liquid and the solid

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r = capillary radius The value of cos θ = 1 for θ = 0o = 0 or negative for θ = 90o to 180o

Chemical Compatibility Fracturing fluids ideally should be compatible with special purpose chemicals and additives, in order that the same base fracturing fluid may have its applicability extended over a large area of the field operation. Such additives include friction reducers, gelling agents, foaming agents, gel breakers, fluid loss additives, emulsion preventers, clay stabilizers and so forth. Incompatibility of chemicals run together due to lack of or inappropriate laboratory testing can lead to very poor or even disastrous results. If chemicals combine to form precipitates, neither of the chemicals will be available to perform its function, and in addition a potential for plugging will have been created. Don't mix cationic materials with anionic materials without first ensuring that there will be no loss of effectiveness or detrimental effects (serious precipitation). Mutual solvents, and/or dispersants can sometimes help "make it work" if the mixing of the two cannot be avoided.

Range Of Application The ideal fracturing fluid should be applicable over a wide range of conditions. The advantage of this, of course is that a single base fluid could be used in very broad application, and field personnel for both the service and producing companies would become more expert in handling and preparing the product. Ideally, there would be capability to fine-tune the properties to meet specific job requirements. Many people believe that the ideal base fluid is clear water, and with careful testing, adequate modification may be made to provide a near perfect fluid. In most cases, water is readily available and may be filtered to provide a standard base fluid that is relatively constant, compared to crude oil for instance, in its properties from one geographical area to the next.

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Ease of Preparation The ideal base fluid should be easy to prepare on location, and it should not be difficult to maintain control over the quality of the fluid. Some materials may be added to the base fluid entirely `onthe-fly,' and no re-circulation of fluid is required before the job in order to mix all components thoroughly. Other fluids require batch mixing and re-circulation before the job. In some instances, several stages of pre mixing are required in order to mix all the chemicals in the proper manner. This requires substantial time on location, and in some cases starts the clock running on the life of the fluid if it has internal breakers, or if it has been formulated for a time break. One of the serious disadvantages of the batch mix approach is that if the job must be postponed, or terminated early after the preparation of the chemicals has begun, the entire chemical batch must be paid for, and it may not be reclaimable. On-the-fly mixing has a clear advantage in this respect. However, batch mixing does have one very distinct advantage. Quality control is much easier to exercise when each stage of preparation can be checked prior to starting the next stage, and the final properties may be verified before pumping to the well. Also the averaging and thorough mixing effect of re-circulation tends to make for much more thorough blending.

Hazards The hazards presented by the use of a particular fracturing fluid or additive must be known, understood, and the danger minimised. Fracturing, since it involves the use of high pressure, is inherently dangerous. The service company equipment is re-used many times over, and a vast combination of corrosive and abrasive fluids pass through pumps, lines and so forth which are also subjected to tremendous shock loads. Safety should never be compromised in fracturing operations. Also, by careful planning, testing, and selection, fluids may be found that are relatively safe, and will perform as effectively as other, more dangerous fluids, given proper job execution. All fluids are dangerous when under pressure, however highly volatile fluids with low flash points, such as some hydrocarbons, are extremely hazardous. Many additives contain very hazardous _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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substances, or may be dissolved in solvents that can be lethal if taken into the body through the skin. The best policy is to be aware of the safety hazards and requisite precautions for handling and use of all chemicals involved. The service companies should have this information at the job site and in their files. If not, you should insist they get it and become familiar with it.

TYPES OF FRACTURING FLUIDS Having already defined the functions of fracturing fluids and the general properties of an ideal fracturing fluid, let us now focus on some of the available fluids from which we may formulate the best composition for a particular situation. Various materials are available from the several companies that perform hydraulic fracturing services. The user may have difficulty in differentiating between the products since the particular service companies generally give them "brand names" for marketing purposes. While the products may serve the same general purpose, e.g. act as gelling agents, there may be subtle but important differences in the products of one supplier versus another. It is incorrect and hazardous to generalise by saying that all the service organisations use the same thing under different names. The significance of the differences is often case-specific, but the team of the service company and the frac designer need to work closely together to utilise the important beneficial features of some products while avoiding the sometimes subtle, but significant, disadvantages of specific products or combinations in certain applications. This course does not seek to compare the "brand name" products. It is for the service organisations to know their business well enough to properly advise their clients, and for those clients to select wisely.

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Oil Based Fracturing Fluids Oil based fluids can be categorised as crude oils, blends of crude, condensates, refinery products, gelled oil, emulsions and polyemulsions. With all of the above fluids, it is important to check the compatibility of the fluids with the reservoir fluids. Even crude from the same reservoir may be altered considerably so as to cause problems if pumped back into the reservoir. A simple example is that paraffin or asphaltene may tend to come out of solution as solids at temperatures slightly below reservoir temperature. In some instances, they will not go back into solution at reservoir temperature. Therefore, it is possible to plug a well by injecting crude from the same reservoir. Blends of crude oil have been used to produce a composite with the desired viscosity. This is not a recommended practice due to the compatibility uncertainties. It is common to employ oil based refinery products such as reformates, kerosene and diesel oil. These products should also be tested for compatibility. They tend to vary considerably, especially reformate, which can vary from batch to batch from the same source. Seasonally there is a difference between winter grade and summer grade diesel. The principal advantage of all of the above products is that there is no need to introduce water into the reservoir, and in some cases there may be a real or perceived solvent action. In the case of the refined products, transportation costs to the well site can be very significant. In order to provide modified properties, such as better transport characteristics and fluid loss control, emulsions and polyemulsions are often used. The polyemulsions are much more popular, and generally consist of two parts oil to one part water, and the gelled water may be treated with chemicals like potassium chloride to minimise clay swelling. Oil based fracturing fluids can be gelled by several methods, often involving a reaction between aluminium phosphate ester and a base such as sodium aluminate. Other products include those, which depend on reactions between fatty acids and caustic solutions to produce a soap gel. The

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pumping pressures of such systems are typically high due to both high friction and low hydrostatic contribution.

Water Water is the most universally popular base for fracturing fluids. Ordinarily, fresh water is used as the base, but seawater has been used. The advantages of using water are numerous. Cost and safety are the obvious ones. Also important are universal availability, relatively standard composition, predictable performance, and traceability. The really significant advantage is that, provided a good source of fresh, clean water is used, it is possible to duplicate laboratory performance in the field. In comparison, crude oil tends to vary to such a degree that universal applicability of chemicals is by no means guaranteed. Laboratory work should be performed to determine the type and amounts of additives necessary to ensure that the water will not significantly damage the formation. This is usually possible. The most common treatment is to dissolve 3% by weight of potassium chloride in the water. Usually, a surfactant is added to prevent emulsion if the water will enter an oil-bearing zone, or to reduce surface tension and promote faster recovery if the water will enter a gas formation. Since water has a relatively low viscosity, and no significant resistance to fluid leak off, it is generally gelled and often a fluid loss additive is used. There is a strong tendency in favour of cross-linked gelled water. At this point, it is probably worthwhile to have a discussion concerning the manner in which gelled and cross-linked gelled fracturing fluids are prepared. Certain natural and synthetic chemicals have the ability, when added in relatively small proportions, 0.5 to 1.5% by weight, to cause the water to thicken very significantly. Later, the gelled water `breaks back' to a low viscosity. This property facilitates its recovery from the formation.

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There are three basic materials used to prepare water-based gels: guar gum, cellulose derivatives, and synthetic polymers. All of these are capable of providing moderate viscosity characteristics, or they may be cross-linked to form very viscous gels that have 5 to 10 times the viscosity of the noncross-linked material. The introduction of the cross-linking process for fracturing fluids in the late 1960's marked a very significant break-through. For the first time, an easy to handle, ultra high viscosity fluid with low friction characteristics and very good break characteristics was widely available. Developments since then have seen several refinements to improve temperature range, break control and residue control. It is important to note that, with some of these fluids, the amount of residue that remains following the break in viscosity can be quite significant, and may cause substantial formation and/or fracture plugging. On the other hand, relatively clean fluids are also available and are much preferred. The most damaging fluids are guar polymers the poorer ones of which can leave as much as 30% residue. The cellulose derivatives are believed to be essentially non-residue producing, and the synthetic polymers also produce little or no residue. The common water gelling agents are:

•

guar gum,

•

hydroxypropyl guar (HPG) gum,

•

hydroxyethyl cellulose (HEC),

•

carboxymethyl cellulose (CMC), and

•

carboxymethyl hydroxyethyl cellulose (CMHEC)

•

carboxymethyl hydroxypropyl guar (CMHPG).

When selecting a gelled and/or cross-linked system, it is very important to design the correct breaker type and concentration for the proper temperature, in order to obtain the desired break time.

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The author strongly recommends that the service company should demonstrate in their laboratory (or you should check in yours), that the recommended formulation will perform as stated by the salesman, using base fluids from the particular area. Some of the products are very sensitive to the pH of the system, and consequently this is a factor that needs to be verified, perhaps also at the site. Also, the best pH for the frac fluid may not be the best pH for the formation. This is one area where the oil company engineer must question the service company in detail, in advance, so that he can verify the proper condition during each stage of the fluid preparation. It also keeps the service company on its toes if it knows you will be checking.

Cross-Linking For the past 30 years, the concept of cross-linking water based fracturing fluid systems has been in wide use. The advantage is that much higher viscosity at the same gel concentration can be generated to assist primarily in proppant transport within the fracture and also to promote pressure loss in the fracture and consequently to generate increased fracture width. The advantage to using cross-linking chemicals rather than ever-higher concentrations of polymer is both its cost effectiveness and its relatively low damage. The fact that cross-link chemicals can be added downstream of the point of proppant addition facilitates proper mixing of the proppant into the fluid. Delayed-action cross-link chemicals are available to permit the fluid to be pumped with relatively low friction until linking occurs, preferably at the perforations. A variety of cross-linking chemicals is available from the various service companies. The technology is very competitive. Organometallic-crossinked fluids have been the most popular class of fracturing fluids for the following reasons: excellent proppant transport, form a resilient filter cake on the fracture face,

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compatible with carbon dioxide, stable at high temperatures and can be used at temperatures greater than 150 °C. The main disadvantage of these fluids is that they may be difficult to clean up especially from high permeability formations. Titanate and zirconate complexes of guar, HPG, CMHPG, or CMHEC are the most popular organometallic crosslinked fluids in use today. Borate-cross-linked fluids have always been popular because of their lower cost but had limited applications. With the increased knowledge of their involved chemistry these fluids are now being successfully used in wells with bottom hole temperatures up to 150 °C. The development of delayed cross-linkers now allows the fluid to be pumped without excessive friction loss. Correctly formulated borate fluids will have good proppant transport properties with stable fluid rheology, low fluid loss and good clean-up properties. Guar and HPG are the most often used polymers crosslinked with borates however CMHPG has been used in certain applications.

Acid In some cases, operators have found that employing acid as the fracturing fluid is the best choice. These applications would normally be in carbonate formations that have rather high solubilities, unless the acid-soluble material is present primarily as the lining of existing crevices or fractures, or unless a viscous fingering technique is used. In this application, the objective is to pump a pad or pre-flush of highly viscous material, such as cross-linked water ahead of the acid. The thinner acid will then tend to finger through the gel and create unevenly etched channels for production. The channels would be held open (hopefully) by the undissolved portion of rock that was not contacted by the acid. Another approach has been to use a highly viscous gelled acid, and Xanthan gum (Crowe et al, 1980) has been reported to be a good gelling agent. It also tends to retain some of its viscosity after spending, and may therefore be beneficial in aiding the recovery of insoluble fines that have been released as a result of the acid. One of the great disadvantages to the use of hydrochloric acid where deeply penetrating treatments are required is that it tends to react very quickly. The result is that unreactive material _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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(spent acid) is pumped as the leading edge of the fracturing fluid for a large part of the job and consequently very little, if any, etching will be done any distance from the well bore. If a viscous material had been used, a wider fracture would result and the more favourable surface area to volume relationship would allow the live acid to penetrate more deeply into the formation. Deeper penetration of reactive fluid is also achieved by means of retarded or slow-acting acids. Means have been developed to chemically retard acid reaction rates, sometimes by incorporating special surfactants for this purpose, and also by incorporating the acid as the internal phase of an emulsion, using kerosene or diesel as the external phase. Both of these methods tend to be less frequently used currently. Another method for extending live acid penetration is to pre-cool the formation using a water (for example) pre-flush. This technique recognises that acid reaction rate is much faster at higher temperatures. Acids other than hydrochloric, such as acetic and blends of acetic and hydrochloric, have been very successfully used to achieve retardation, and in addition these acids are much less corrosive to the tubulars at these higher temperatures. A later segment of this course covers the details of acid formulations and acid treatment design. However, it would be imprudent not to mention now that the most important additives to any acid formulation are the inhibitor and the emulsion preventative chemicals. These should both be very carefully selected for the specific job, and non-emulsifiers should be verified by a bottle test with the acid mixture and the reservoir oil in question. Many other beneficial additives for various purposes are available from the service companies. The true applicability of some of these expensive additives always needs to be verified and it is important to make certain that all additives are mutually compatible.

Foam The use of foam as a fracturing fluid was reported by Bullen and Bratrud, in 1975; and by Wendorff and Ainley, in 1981. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Nitrogen and carbon dioxide have been utilised in oil and gas production operations for many years. However, the use of nitrogen and water foam as a fracturing fluid is much more recent. Several advantages for foam are claimed over conventional liquid fracturing fluids. Since foam consists of at least 75% nitrogen by volume, at down hole conditions, a condition referred to as `75% quality,' the amount of liquid introduced to the reservoir is very small. This is more clearly understood when one realises that the amount of nitrogen is actually more than 75% at surface conditions. Often, quality is reduced towards the end of the treatment to permit higher proppant concentrations. An important point is that the liquid phase of the foam can be treated to help prevent emulsions from forming or clays from swelling. The characteristics of the foam are such that it tends to remain rather stable in the fracture until flow back causes a pressure drop. This pressure drop, if it is great enough, acts as the triggering mechanism to cause the foam structure to begin to break down. The materials should return in the form of a mist rather than a foam.

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Figure 19: Foam Viscosity vs. Quality The proponents of foam as a fracturing fluid claim very low leak off characteristics, particularly in low permeability reservoirs. The combination of low leak off and stable viscosity provides good proppant transport characteristics. A very significant advantage of foam is the improved fire safety, due to the inert nature of the components. Users should be aware that nitrogen is brought to the location as a cryogenic liquid at a temperature of -160C (-320F) and obviously must be treated with respect. Foam fracturing jobs are more difficult to design than conventional fracturing jobs, because the properties of the foam change significantly as pressure changes due to the compressibility of the

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nitrogen. This means that both hydrostatic head and frictional pressure loss vary with pressure and must be calculated by computer. A further point to remember when considering foam as a fracturing fluid is that since the foam has a very low density, and consequently a low hydrostatic head, much higher surface pressures are required in order to initiate and extend a fracture than would be required with a liquid system. Most significantly, it is very difficult to achieve high proppant concentrations in foam, since all the proppant must be mixed with the liquid phase. Special mechanical methods have been devised to increase these concentrations, but one should generally consider foam frac proppant concentrations to be less than half of those that are achievable with liquid systems. A great advantage to the use of foam is the ease with which flow back is initiated following the treatment. This rapid flow back minimises contact time between the liquid phase and any sensitive formation materials and can potentially result in less damage and more complete clean up. Foamed acid provides much greater formation coverage for a given volume of acid, the ratio being about four to one, and much better clean up of acid-insoluble fines or mud particles. Foamed hydrocarbons are generally applied to water-sensitive, low pressure formations that require fracturing to be commercial. Its lower surface tension properties also make it advantageous over methanol/water foams or straight water foams.

Viscoelastic Fluids Fatty amine quaternary ammonium salts are called viscoelastic surfactants and are a class of compounds that form micelles in aqueous systems that contain certain cations producing viscoelastic properties to the liquid (Brown et al 1996). These salts have been used for many years to thicken consumer products such as bleach and liquid dishwasher detergent. The deformation of these fluid systems is time dependent when shear is applied. When the system deforms its rheological behaviour is almost Newtonian.

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The texture of these fluids when static is similar to gelatin and therefore have excellent particlesuspension properties. These fluids have been used for many years for gravel packing applications. The concentration of surfactant used to provide suspension varies from 2.5% to 6% by volume of common completion brines. These fluids are very easy to prepare in the field requiring no internal breakers or polymer hydration. More recently, viscoelastic (VES) fluids are finding use as fracturing fluids for high permeability formations. The leak-off behaviour of VES fluids is less dependent upon differential pressure than HEC fluids and at fracturing pressures the fluid-loss rates of VES fluids are lower than those observed with HEC fluids. The principal advantage of the VES fluid is that very little residue is left after breaking, unlike polymer-based systems such as HEC or guar. The viscosity of VES fluids can be reduced by two mechanisms: (1) contact with oil or condensate and (2) reduction of the salt concentration. Since one or both situations usually occur during cleanup after stimulation, no additional breaker chemicals are usually required. VES fluids have been used for the fracturing of high-permeability formations and when fracpacking in particular. These materials are promoted to be cleaner than polymer based fluids. The products are available with breakers that function in the leak-off (matrix) fluid or in the proppant pack fluid. Natural dilution also assists in the reduction of viscosity.

Special Bases Over the years a number of materials have been used as fracturing fluids that might be classified as `special'. That is, the frequency with which they were used never reached that of the more common ones - acid, water, oil or foam. We will discuss some of these, including alcohol, gasfrac, nitrogen (only), and carbon dioxide (only).

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Methanol Fracturing Systems Over the years, the advantages of alcohol over water based fluids have been tried and tested with various degrees of success. These include, but are not limited to; low freezing point, low surface tension, high water solubility, high vapor pressure and formation compatibility. Methanol is also the fluid of choice for formations with "lower than irreducible” water and/or hydrocarbon saturation. Three concerns with methanol all relate to safety: low flash point, high vapor density and flame invisibility. Only with special precautions can methanol be even relatively safely used in the field. Several approaches of increasing the viscosity of methanol have been tried in the last decade. These range from foaming methanol to gelling with synthetic polymers (polyacrylamide and PEO) and modified guar. Attempts were also made to crosslink the gelled methanol with metal crosslinkers. However limitations as described by Ely restrict the use of gelled non-aqueous methanol. The most recent development referenced by SPE paper 84579 (D.V.S. Gupta) describes a modified guar dissolved in anhydrous methanol crosslinked with a borate complexor and broken by an oxidizing breaker. The system has been successfully used in the field and energized with nitrogen in under pressurized wells. A new polymer that is soluble in methanol and compatible with carbon dioxide has been recently identified. The most important property of methanol as a base fracturing fluid is the reduction of surface tension. Reducing surface tension increases the effectiveness of non-aqueous methanol in removing water blocks. There is an added benefit that in extremely water sensitive formations, a low amount of water in the base fluid can damage or swell clays to reduce effectiveness of the stimulation treatment. Other advantages, such as low freezing point makes it suitable to be pumped with liquid CO2. The methanol viscosifier with zirconium crosslinker has been shown to have good viscosity properties for proppant transport. Coupled with oxidizing breaker the system has been improved.

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A popular approach is to use a mixture of gelled alcohol and water. Some service companies are reporting using carbon dioxide and alcohol with no water. The mixture of alcohol and water possesses all of the advantages of the pure alcohol, except that some aqueous fluid is used. Potassium chloride may be incorporated, and conventional equipment is employed. There is some industry controversy in this area, related to the stability of various mixtures of some or all of: methanol/carbon dioxide/water/potassium chloride. Obtaining specific laboratory data for appropriate conditions is recommended. The main disadvantages of alcohol are cost, availability and high degree of hazard from fire and from the inhalation of fumes. Liquid Carbon Dioxide A process by which 100% liquid carbon dioxide is employed as a fracturing fluid has been introduced, (Lillies, 1982). The service company claims a number of advantages for this technique including: no risk of incompatibility with reservoir fluids, complete and rapid recovery of stimulation fluids, enabling immediate qualitative examination of reservoir fluids following the job, possible reduction in the viscosity of reservoir crude oils due to solubility of carbon dioxide. The usual benefits of incorporating a gas such as nitrogen or carbon dioxide in the frac fluid, such as rapid flow back, etc. are also present. Under certain conditions, mixtures of carbon dioxide and refined hydrocarbons with a certain composition are believed to be beneficial in treating dry gas formations that may be undersaturated with water. The miscibility of the carbon dioxide in the reservoir gas and its solubility in the frac oil are said to be important in higher recoveries of the fracturing fluid. Users are cautioned that there are considerable thermal stresses induced in the tubulars due to the great amount of cooling caused by the carbon dioxide. It is mandatory to use good computer programs to determine these effects.

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A predecessor to the use of liquid carbon dioxide was the Gasfrac process, in which a mixture of liquefied natural gases was used for approximately the same advantages, and in the same way, as the liquid CO2. The carbon dioxide is much safer and the Gasfrac is not promoted any more. Liquid Carbon Dioxide Combined with Nitrogen A process employing liquid carbon dioxide and nitrogen combined in a foam has added a novel approach regarding fracturing fluids. SPE paper 40016 (Gupta and Bobier, 1996) described the introduction of the system. A later paper SPE 84119 (Gupta, 2003) provided an update on the applications and improvements to the system. The foam exhibits increased viscosity and behaves in a manner not dissimilar to other foams. The authors claim reasonable fluid loss control, good viscosity and transport characteristics. The main advantage is that no liquids are introduced to the formation and the only additive other than the proppant is a foam stabilizer which is said to be non-damaging. This feature significantly reduces the possibility of formation damage caused by introducing liquids. That type of damage often results in low pressure, undersaturated gas reservoirs, or in rocks containing clays that may swell. No research has been found that indicates whether fines migration is mitigated or not. Since fines normally move only when the wetting phase is mobile, it can be assumed that the degree of migration would be minimized. Since the system must be closely controlled during operations, the present limit of application is in wells less than 1200 m in depth.

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The author states that all materials are environmentally safe and disposal of treating fluids is not a problem. The method, like liquid carbon dioxide treatments, requires the use of special equipment to introduce the proppant and special care in pumping the very cold materials. Thermal contraction/expansion of well tubulars must be considered.

Nitrogen (alone) as a Frac Fluid A number of wells in naturally fractured shale formations responded well (initially) to such treatments. See SPE papers 10129 and 10378. 100% nitrogen has been employed as a stimulation fluid with some limited success. The specific applications reported (Freeman et al, 1981) were to stimulate naturally fractured hydrocarbon bearing shale formations. The nitrogen was pumped at rates and pressures sufficient to open the natural fractures. The longevity of production increase depended to some extent on `roughness' of the fracture surface, and the maximum differential stress created by the difference between the confining pressure and the pore pressure. In general, the decline in productivity was very rapid. TAIL-IN CONSIDERATIONS

Fracturing fluids are employed to transport the proppant to the desired location in the created fracture. The most critical area of the fracture in which high flow capacity must be created and maintained is that portion that is nearest to the wellbore. This is also the area that is under highest closure stress due to drawdown. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Therefore, to economize, some companies incorporate higher quality proppant for only the final ten to thirty percent of the proppant. This is intended to place the best proppant in the most critical location, provided that good proppant transport characteristics have been maintained in the fracturing fluid throughout the treatment. Cleary and Fonseca (1992) have introduced the concept of convection as it affects the flow and distribution of proppants after they enter the fracture. Thoughtful individuals are advised to become familiar with this aspect when designing treatments, especially if they believe that a premium or special purpose tail-in material should be employed. An aspect of fracture conductivity (flow capacity, kw), that it is vital to understand is how the effective flow capacity of the fracture can vary with concentration, stress and grain size of a particular proppant. Generally speaking, higher proppant concentrations result in higher flow capacity. Concentrations over a monolayer of propping agent result in an ever-increasing flow capacity with increasing concentrations. The effect of the increased fracture flow capacity on productivity increase becomes nearly asymptotic at some point, depending upon reservoir characteristics, particularly the formation flow capacity prior to fracturing. The fracture can not deliver to the wellbore more than the formation can feed the fracture. The greater the grain size, the greater will be the flow capacity provided the proppant does not crush, and the greater the stress on the proppant, due to closure, the lower the flow capacity. The above generalizations, however, are not in themselves sufficient for proper job design, and it is important to conduct tests in the laboratory under specifically defined in situ conditions in which the proppant and the formation are stressed to the proper level. We will discuss the details of this when we discuss laboratory testing methods.

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BIBLIOGRAPHY AND REFERENCES Bennion, D.B., Bietz, R.F., Thomas, F.B. and Cimolai, M.P.: "Reductions in the Productivity of Oil and Low Permeability Gas Reservoirs Due to Aqueous Phase Trapping", JCPT, Nov., 1994. Brown, J.E., King, L.R., Nelson, E.B., and Ali, S.A.: “Use of a Viscoelastic carrier Fluid in FracPack Applications”, SPE 31114, presented at the SPE Formation Damage Symposium, Lafayette, LA, Feb. 14-15, 1996. Bullen, R.S., and Bratrud, T.F., "Fracturing With Foam", presented at 26th Annual Technical Meeting, Pet. Soc. of CIM, Banff, Alberta, June, 1975. Clark, P.E., Harkin, M.W., Wahl, H.A. and Sievert, J.A., "Design of a Large Vertical Prop Transport Model", Paper SPE 6814, Presented at 52nd Annual Fall Meeting, Denver, Colo., October 1977. Cleary M.P. and Fonseca, Amaury Jr.: "Proppant Convection and Encapsulation in Hydraulic Fracturing: Practical Implications of Computer and Laboratory Simulations", paper SPE 24825, presented at Washington, D.C., October, 1992. Crowe, Curtis W., Martin, Robert C., And Michaelis, Alvin M., "Evaluation of Acid Gelling Agents for Use in Well Stimulation", Paper SPE 9384, presented at 55th Annual Fall Meeting, Dallas, Texas, September 21-24, 1980. Daneshy, Abbas Ali, "Numerical Solution of Sand Transport in Hydraulic Fracturing," Paper SPE 5636 presented at 50th Annual Fall Meeting, Dallas, Texas, September 28 to October 1, 1975. Freeman, Earl Ray, Abell, James Carroll, Kim, Chin Man and Heinrich, Carl Christian, "A Stimulation Technique Using Only Nitrogen", Paper SPE 10129, Presented at 56th Annual Fall Meeting, San Antonio, Texas, October 5-7, 1981.

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Gupta, D.V.S., Pierce, R.G. and Litt, N.D.: “Non-Aqueous Gelled Alcohol Fracturing Fluid” Paper SPE 37229, Presented at the International Symposium on Oilfield Chemistry, Houston, TX, 9702-18 to 21. Jones, F.D. and Owens, W.W., "A Laboratory Study of Low Permeability Gas Sands", JPT, September 1980. Holditch, S.A. and Spivey, J.P.: "Estimate Recovery From Tight Gas Formation Wells", Pet. Engr. intl., Aug., 1993. Holditch, Stephen A., "Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells", Paper SPE 7561 Presented at 53rd Annual Fall Meeting, Houston, Texas, October 1978. Lillies, A.T., "Sand Fracturing with Liquid Carbon Dioxide," Paper 82-33-23 Presented at 33rd Annual Technical Meeting, Pet. Soc. of CIM, Calgary, Alberta, June 6-9, 1982. Wendorff, C.L., and Ainley, B.R., "Massive Hydraulic Fracturing of High - Temperature Wells with Stable Frac Foams", Paper SPE 10257 presented at 56th Annual Fall Meeting, San Antonio, Texas, October 5-7, 1981.

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TABLE OF CONTENTS 1.1 1.2 1.3 1.4 2.1 2.2 2.3 2.4

OBJECTIVE ..................................................................................................................................................... 2 COURSE CONTENT........................................................................................................................................ 3 ACKNOWLEDGMENT................................................................................................................................... 5 A POT-POURRI OF QUESTIONS................................................................................................................... 6 RESERVOIR FACTORS THAT AFFECT PRODUCTIVITY...................................................................... 12 MECHANICAL FACTORS AFFECTING PRODUCTIVITY...................................................................... 13 PRODUCTIVITY AFFECTED BY FORMATION DAMAGE..................................................................... 13 CAUTION...................................................................................................................................................... 14 2.5.1 DRILL STEM TESTS............................................................................................................................. 15 2.5.2 PRODUCTION TESTS........................................................................................................................... 17 2.5.3 HORNER PLOTS ................................................................................................................................... 17 2.5.4 INFLOW PERFORMANCE RELATIONSHIP ....................................................................................... 23

SECTION 3: FORMATION DAMAGE........................................................................................................................... 25 3.1 TYPES OF DAMAGE .................................................................................................................................... 25 3.1.1 CLAY SWELLING AND DISPERSION........................................................................................................... 25 3.1.2 WATER AND EMULSION BLOCKS .............................................................................................................. 28 3.1.3 DEPOSITS ...................................................................................................................................................... 28 3.1.4 SATURATION ALTERATION ......................................................................................................................... 29 3.1.5 MECHANICAL CAUSES ................................................................................................................................ 29 3.1.6 SOLIDS INVASION......................................................................................................................................... 29 3.1.7 PARTIAL PENETRATION .............................................................................................................................. 30 3.2 CAUSES OF DAMAGE DURING DRILLING ............................................................................................. 30 3.3 CAUSES OF DAMAGE AFTER PERFORATING........................................................................................ 32 3.4 PREVENTION OF FORMATION DAMAGE ............................................................................................... 33 3.5 TREATMENT FOR DAMAGE REMOVAL ................................................................................................. 35 4.1 PRESSURE-RATE RELATIONSHIPS.......................................................................................................... 38 4.2 FRACTURE EXTENSION PRESSURE GRADIENT ................................................................................... 40 4.3 ROCK MECHANICS ..................................................................................................................................... 43 4.3.1 STRESS ........................................................................................................................................................... 44 4.3.2 STRAIN ........................................................................................................................................................... 46 4.3.3 YOUNG'S MODULUS .................................................................................................................................... 46 4.3.4 POISSON'S RATIO ......................................................................................................................................... 47 4.3.5 PRINCIPAL STRESSES .................................................................................................................................. 48 4.4 FRACTURE MECHANICS............................................................................................................................ 49 4.4.1 IN-SITU PRINCIPAL STRESSES.................................................................................................................... 49 4.4.2 INTERNAL BOREHOLE PRESSURE............................................................................................................. 51 4.4.3 FRACTURE INITIATION ............................................................................................................................... 53 4.5 FRACTURE GEOMETRY AND DIMENSIONS .......................................................................................... 54 4.5.1 FLUID LOSS................................................................................................................................................... 54 4.5.2 FRACTURE WIDTH ....................................................................................................................................... 61 4.5.3 FRACTURE HEIGHT ..................................................................................................................................... 62 4.5.4 CONTAINMENT ............................................................................................................................................. 64 4.5.5 FRAC MODELS.............................................................................................................................................. 67 FUNCTIONS ..................................................................................................................................................................... 74 PROPERTIES OF THE IDEAL FRACTURING FLUID .................................................................................................. 74 Reactions and Residues ................................................................................................................................................. 74 Fluid Loss...................................................................................................................................................................... 75 Proppant Transporter.................................................................................................................................................... 76 Rheological Characteristics .......................................................................................................................................... 82 Phases............................................................................................................................................................................ 85 Chemical Compatibility................................................................................................................................................. 88 Range Of Application .................................................................................................................................................... 88 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Ease of Preparation...................................................................................................................................................... 89 Hazards ......................................................................................................................................................................... 89 TYPES OF FRACTURING FLUIDS................................................................................................................................. 90 Oil Based Fracturing Fluids ......................................................................................................................................... 91 Water ............................................................................................................................................................................. 92 Acid ............................................................................................................................................................................... 95 Foam ............................................................................................................................................................................. 96 Viscoelastic Fluids ........................................................................................................................................................ 99 Special Bases............................................................................................................................................................... 100 GELLING AGENTS. ............................................................................................................................................................ 112 Increase Viscosity of Oil-Based Fracturing Fluids ..................................................................................................... 112 Increase Viscosity of Water-Based Fracturing Fluids ................................................................................................ 113 CROSS-LINKING AGENTS .................................................................................................................................................. 115 BREAKERS ........................................................................................................................................................................ 116 BUFFERS ........................................................................................................................................................................... 116 FRICTION REDUCERS ......................................................................................................................................................... 117 FLUID LOSS ADDITIVES ..................................................................................................................................................... 117 CLAY STABILIZERS ........................................................................................................................................................... 118 OTHER ADDITIVES ............................................................................................................................................................. 118 ENERGIZING GASES .......................................................................................................................................................... 119 Nitrogen....................................................................................................................................................................... 120 Carbon Dioxide ........................................................................................................................................................... 120 FRACTURE FLOW CAPACITY (CONDUCTIVITY) .................................................................................................. 127 TYPES OF PROPPING AGENTS ............................................................................................................................... 135 FRAC MODELS, DATA ACQUISITION AND MANIPULATION .............................................................................. 140 Fracture Simulator Models ......................................................................................................................................... 140 TESTS ON FORMATION ROCK ................................................................................................................................... 171 PERMEABILITY......................................................................................................................................................... 171 POROSITY ................................................................................................................................................................. 171 PETROGRAPHY AND LITHOLOGY......................................................................................................................... 172 SOLUBILITY .............................................................................................................................................................. 172 X-RAY (XRD).............................................................................................................................................................. 172 SCANNING ELECTRON MICROSCOPY (SEM)....................................................................................................... 172 ROCK MECHANICAL PROPERTIES ....................................................................................................................... 173 FRACTURE TOUGHNESS ........................................................................................................................................ 173 IN-SITU STRESS MEASUREMENT........................................................................................................................... 173 RESERVOIR FLUIDS .................................................................................................................................................... 174 FRACTURING FLUIDS................................................................................................................................................. 175 PROPPING AGENTS...................................................................................................................................................... 178 CO-ORDINATED IN-SITU LABORATORY TESTING.............................................................................................. 179 LOGGING PROGRAM ................................................................................................................................................. 187 CORING PROGRAM .................................................................................................................................................... 188 DRILLSTEM TESTS ..................................................................................................................................................... 188 IN-SITU STRESS DETERMINATION ......................................................................................................................... 189 CASING DESIGN.......................................................................................................................................................... 190 CEMENTING................................................................................................................................................................. 190 DATA EXAMINATION................................................................................................................................................ 191 DAMAGE REMOVAL TREATMENT ......................................................................................................................... 192 SETTING OF OBJECTIVES ......................................................................................................................................... 193 LABORATORY TESTING ........................................................................................................................................... 194 SIMULATOR RUNS ..................................................................................................................................................... 195 ECONOMIC PRIORITIES AND CONSTRAINTS ....................................................................................................... 195 JOB OPERATIONAL PLANNING ............................................................................................................................... 197 JOB EXECUTION ......................................................................................................................................................... 198 POST JOB PROCEDURE .............................................................................................................................................. 199 FRAC MODELS, DATA ACQUISITION AND MANIPULATION............................................................................. 202 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Since there is such a wide variation in the sophistication and complexity of fracture design models, and since most service companies employ one or more of three common simulators, it is deemed reasonable to at least mention the availability of the other models. ......................................................................................................................................................... 202 ANALYSIS OF PRESSURE DECLINE CURVES AFTER INJECTION: ................................................................... 207 FRACTURE BED DAMAGE ........................................................................................................................................ 233 FRACTURE FACE AND MATRIX DAMAGE........................................................................................................... 236 REACTIVE MATERIAL............................................................................................................................................... 250 TYPES OF ACIDS ....................................................................................................................................................... 251 TYPES OF JOBS ......................................................................................................................................................... 251 GUIDELINES FOR APPLICATION ........................................................................................................................... 251 REACTIONS................................................................................................................................................................ 252 MAIN REACTIONS ..................................................................................................................................................... 252 HYDROCHLORIC ACID ............................................................................................................................................... 252 WITH CALCITE .......................................................................................................................................................... 253 WITH DOLOMITE ...................................................................................................................................................... 253 WITH SIDERITE ......................................................................................................................................................... 254 WITH DRILLING FLUIDS.......................................................................................................................................... 254 HYDROFLUORIC AND HYDROCHLORIC ACIDS .................................................................................................... 255 WITH CALCITE .......................................................................................................................................................... 255 WITH DOLOMITE ...................................................................................................................................................... 255 WITH SIDERITE ......................................................................................................................................................... 256 WITH SILICATES........................................................................................................................................................ 256 WITH DRILLING FLUIDS.......................................................................................................................................... 256 ACETIC ACID................................................................................................................................................................. 256 WITH CALCITE .......................................................................................................................................................... 257 FLUOBORIC ACID......................................................................................................................................................... 257 IMPORTANT SECONDARY REACTIONS .................................................................................................................. 258 CALCIUM FLUORIDE PRECIPITATION ................................................................................................................. 258 FLUOSILICATE PRECIPITATION ............................................................................................................................ 259 IRON HYDROXIDE PRECIPITATION....................................................................................................................... 260 TACHYDRITE PRECIPITATION ............................................................................................................................... 260 EFFECTS OF MAIN PARAMETERS DURING FRACTURE ACIDIZING.................................................................. 261 CONCENTRATION..................................................................................................................................................... 262 TEMPERATURE ......................................................................................................................................................... 262 GEOMETRY, SURFACE AREA, VOLUME ................................................................................................................ 262 VISCOSITY.................................................................................................................................................................. 263 VELOCITY .................................................................................................................................................................. 263 FLUID LOSS ............................................................................................................................................................... 264 METHODS OF APPLICATION...................................................................................................................................... 264 PERFORATION WASHING........................................................................................................................................ 264 MATRIX ACIDIZING .................................................................................................................................................. 265 NATURAL FRACTURE ACIDIZING .......................................................................................................................... 267 NEW FRACTURE ACIDIZING ................................................................................................................................... 269 FRACTURE ACIDIZING WITH PROPPANT............................................................................................................. 269 USE OF FOAMED ACID............................................................................................................................................ 271 PROBLEMS WITH SCALES AND DEPOSITS ........................................................................................................... 271 ADDITIVES AND TECHNIQUES FOR SPECIAL CASES........................................................................................... 274 INHIBITORS ............................................................................................................................................................... 274 HYDROGEN SULPHIDE............................................................................................................................................ 275 SURFACTANTS........................................................................................................................................................... 275 EMULSIONS ............................................................................................................................................................... 276 SURFACE TENSION .................................................................................................................................................. 277 WETTABILITY ............................................................................................................................................................ 277 MUTUAL SOLVENTS ................................................................................................................................................. 278 RAPID REACTION RATE........................................................................................................................................... 278 SLOW REACTION RATE ............................................................................................................................................ 279 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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DEEP PENETRATION................................................................................................................................................ 279 SHALLOW PENETRATION........................................................................................................................................ 280 IRON ........................................................................................................................................................................... 280 FINES RELEASE AND CLAY PROBLEMS ................................................................................................................ 281 FRACTURE CONDUCTIVITY.................................................................................................................................... 282 FRACTURE GEOMETRY ........................................................................................................................................... 282 CALCAREOUS FORMATION DAMAGE REMOVAL ................................................................................................ 283 SANDSTONE FORMATION DAMAGE REMOVAL................................................................................................... 284 FRICTION REDUCERS.............................................................................................................................................. 284 FLUID LOSS ADDITIVES .......................................................................................................................................... 284 HEAT GENERATORS ................................................................................................................................................. 285 COMPLEXING AGENTS ............................................................................................................................................ 285 OTHER ADDITIVES ................................................................................................................................................... 285 METHODS OF PLACEMENT........................................................................................................................................ 286 INSTRUMENTATION.................................................................................................................................................... 286 PUMPING EQUIPMENT................................................................................................................................................ 287 SPECIAL EQUIPMENT.................................................................................................................................................. 288 ADVANCED AND RECENT ISSUES IN ACIDIZING ................................................................................................. 288 High Temperature Considerations .............................................................................................................................. 291 Modeling of Acid Fracturing....................................................................................................................................... 291 Paccaloni's Methods for Improved Matrix Acidizing .................................................................................................. 291 Placement Control Methods ........................................................................................................................................ 292 Foam diversion............................................................................................................................................................ 293 How to Help Prevent Sludge by Proper Testing.......................................................................................................... 294

List of Figures FIGURE 1: CONCEPT OF FLUID LOSS............................................................................ 78 FIGURE 2: PROPPANT CONCENTRATION FACTOR...................................................... 79 FIGURE 3: SCREEN-OUT SCHEMATICS ........................................................................ 79 FIGURE 4: HISTORY MATCH OF PROPPANT DISTRIBUTION AT CLOSURE .............. 85 FIGURE 5: FOAM VISCOSITY VS QUALITY...................................................................... 98 SECTION 6 - Fracture Fluid Additives There are numerous fluid additive products available from the many companies that perform hydraulic fracturing services. The user may have difficulty in differentiating between the products since they are generally given "brand names" for marketing purposes by the particular service companies. While the products may serve the same general purpose, i.e. act as gelling agents, there may be subtle but important

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differences in the products of one supplier versus another. It is incorrect to generalise by saying that all the service organisations use the same thing under different names. The significance of the differences is often case-specific, but the team of the service company and the frac designer need to work closely together to utilise the important beneficial features of some products while avoiding the sometimes subtle, but significant, disadvantages of specific products in certain applications. This course does not seek to compare the "brand name" products. It is for the service organisations to know their business well enough to properly advise their clients. There are numerous special purpose additives for fracturing base fluids available from the service companies. Many of these should be reserved for special application. There are several, however, that are relatively broadly applied. The most important ones will be discussed very briefly, together with their purpose.

GELLING AGENTS. Various materials are used to thicken water, oil or acid for fracturing. The primary purpose is to improve proppant transport characteristics, but fluid loss control may also be improved. A wide range of residue content remaining after the gel has `broken' is possible, depending upon the particular type of gelling agent used. This is a very important consideration. It is also very important to have accurate readings of the reservoir temperature to give to the service company in order to formulate the proper mixture.

Increase Viscosity of Oil-Based Fracturing Fluids The viscosity of oil based fracturing fluids using polymer technology occurs by forming a polymer in situ by the formation of an “association polymer”. An organic acid or organic phosphoric acid and a base are reacted in the liquid hydrocarbon to form the associated polymer.

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The most common chemicals being used for the gellation of oils are the aluminum phosphate type products for the formation of primary association polymers. Recent developments allow the addition of solid aluminum phosphate to the pre-gelled oil, which acts as a secondary gelling agent yielding higher downhole viscosity and better temperature stability. The use of soap-type viscosifiers for oil based fracturing fluids are rarely used today. These are a mixture of caustic and tolloil fatty acids producing a high viscosity gel that has excellent sand carrying capability. Higher friction pressures are observed than when using aluminum phosphate systems. Increase Viscosity of Water-Based Fracturing Fluids The general classes of gelling agents commonly used to prepare base (linear) gels include the following:

Guar Gum This material, a naturally occurring polymer coming from the guar bean, is available in several formulations. It is normally the least expensive gelling agent but is relatively highly damaging, having a residue of 8-14%. It is easy to cross-link and can be used in brines. (Cost Factor of 1.0)

Refined (Modified) Guar Same properties as guar gum but possibly only one-third the residue.

HydroxyPropyl Guar Gum (HPG) (Derivatized guar) The main advantage for this product is its relatively low residue, 1 to 3%, thereby making it less damaging. It is typically more expensive than guar but less expensive than other water-based gelling agents. It is easy to cross-link and can be used in brines. (Cost Factor 1.4)

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CarboxyMethyl HydroxyPropyl Guar (CMHPG) (Double derivatized) Used primarily in cross-linked systems because its high cost takes it out of the running in linear systems, CMHPG typically has lower residue than HPG, although still in the range of 1 to 3%. It is easier to cross-link than HPG and can be used in brines. (Cost Factor 1.4)

HydroxyEthyl Cellulose (HEC) This is the cleanest, least damaging of the water-based gelling agents, having a residue of almost zero. It is not usually cross-linked, but can be used in brines. (Cost Factor 1.7)

CarboxyMethyl Cellulose (CMC) This material is rapidly hydrating and while stated to be suitable for both continuous and batch mix operations, it typically is difficult to mix to a lump-free fluid. It is sensitive to even low salt concentrations (2% NaCl or KCl; 0% CaCl2) and is seldom used. (Cost Factor 1.6)

CarboyxyMethyl HydroxyEthyl Cellulose (CMHEC) (Double derivatized) Higher tolerance for salt makes this a more widely used additive than CMC. It is popular for low temperature applications. It is easy to cross-link. (Cost Factor 1.7)

Xanthan Gum This product is used mainly in the drilling industry. It is relatively expensive and hence has limited current use for hydraulic fracturing but has good proppant transport capabilities. There is a 3% residue using hypochlorate oxidizing breaker but the break is unpredictable. It can be cross-linked. It is good for gelling hydrochloric acid up to 15% concentration. (Cost Factor 2.0)

Polyacrylamides and Copolymers These chemicals are rarely used for hydraulic fracturing gelling agents but are used as friction reducers in prepad and flush fluids. They are often used at concentrations of 0.2 to 0.5 kg/m3 of fluid. The material can be degraded, it is residue free, it is usually ionic in nature but cationic, anionic and nonionic forms are available. (Cost Factor 1.8) _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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CROSS-LINKING AGENTS A large percentage of fracturing fluids are cross-linked using a variety of chemicals. These chemicals, used in very small concentrations, (0.1 to 0.5 % liquid vol/vol) can produce very large increases in apparent viscosity of the base gel. The chemicals work by chemically linking the linear polymers in the base fluid together limiting the ability of the water molecules to move. Some common cross-linkers are:

•

Borates

•

Aluminium

•

Titanium

•

Zirconium

•

Antimony.

Selection of the proper cross-linking agent is based upon the type of gelling agent being used, the pH of the system, the predicted fluid temperatures, plus other factors. When using borates the pH of the base fluid should be above 8.5. When using the other metallic cross-linkers the pH will usually be in the range of 2 to 8 and will depend upon the gelling agent being used. One of the concerns when using cross-linked fluids is the shear stability of the fluid while it is being pumped down the tubulars and through the perforations. Following shear, the cross-linked fluid should reheal rapidly under down-hole conditions so the propping agents will be transported and not dropped from the fluid near the wellbore. The stability and rehealing properties of a cross-linked fluid system should be verified in the laboratory under down-hole conditions using some kind of shearing device and the reheal time determined. To minimise the effect of shear in the surface equipment and tubular goods the use of delayed reacting cross-linkers is now standard practice. The cross-link time is controlled so the crosslinking occurs near the perforations or after the fluid enters the fracture. This results in a higher viscosity fluid in the fracture than if the fluid was subjected to shear after cross-linking occurred. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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BREAKERS Gel breakers are an important part of most gelled liquid systems. They enable the gels to revert to low viscosity fluids in the formation. Various systems and mechanisms are used to break gels and almost all of them are very temperature sensitive. Some are very pH sensitive. An important development has been encapsulated breakers. These chemicals permit the fracturing fluid to be placed into the formation before the gel breaking activity begins. This provides several advantages. The gel loading can be less because the designer doesn't have to account for the immediate action of the gel breaker. Also the encapsulated, solid gel breaker will probably stop in the fracture and filter cake before it dissolves, rather than passing into the matrix. This means that sufficient population of breaker will be present within the gel-rich filter cake to help degrade all of the cake. This was not always the case until such breakers were available. For all cross-linked fluids, other than borates, the breaker chemical degrades the polymer into short chains reducing the viscosity. For borate cross-linked fluids the cross-link itself is broken. The breakers used for oil gels are usually either acids or bases and they work by interfering with the association polymers.

BUFFERS Buffers are sometimes required to help adjust the pH within certain narrow ranges required by some systems. If pH buffers are employed, you should be aware of the effect of that pH on the formation. A pH of less than 7 is preferred from a formation-fluid compatibility stand point. However, because of other factors involved, it may be necessary to override this to obtain other desired properties of the fracturing fluid. By proper pH control, polymer hydration rate, polymer temperature stability, cross-linking characteristics, gel break, and clay control may be obtained. Common pH control chemicals used are:

•

monosodium phosphate

•

sodium acetate (acetic acid)

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fumaric acid

•

citric acid

•

formic acid

•

sodium bicarbonate

•

sodium carbonate

•

magnesium oxide.

FRICTION REDUCERS While some of the gel systems have inherently low friction properties, others are enhanced by the addition of friction reduction additives. They are also used, of course, in non-gelled systems, where they may be mandatory. The effect is to conserve pumping energy and enable the job to be conducted at much higher injection rates than would otherwise by possible.

FLUID LOSS ADDITIVES In some cases, it is necessary to control the fluid loss rate from the fracture by employing additives that tend to build impervious filter cakes. The use of such additives can be crucial to job success in some cases. However, it is most important to select very carefully from additives that will not cause permanent plugging. Again, know what you are using. Commonly used fluid loss agents are:

•

silica flour

•

polymers (e.g. guar, starch)

•

silica flour and polymer

•

oil soluble resin

•

oil soluble resin and natural polymer

•

emulsions

•

insoluble gases

•

hydrocarbon phase.

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CLAY STABILIZERS Potassium Chloride Potassium chloride is the most widely used salt to help prevent clay swelling. It is usually used at two to three per cent by weight in fresh water. Due to environmental concerns and regulations, non-chloride salts of potassium or ammonium are becoming more common. Potassium sulphate has been used.

Polymers In recent years, products have been developed which may be added to fracturing or acid systems to help `stabilise' clays in place in the formation and thereby prevent them from being set free to migrate to other locations where they might act as restrictions to flow. The additives are best applied either ahead of, or in conjunction with, the very first fluid to enter the formation at time of completion. The chemicals are preventive in nature and generally will be ineffective in curing an existing problem. There is a wide range of effectiveness among the various products and laboratory testing of effectiveness of the chosen product is suggested. Some are significantly damaging to low permeability formations and prudence suggests laboratory testing before such use.

OTHER ADDITIVES Other additives are mostly employed on an as-needed basis. In all instances, it is very important to remember what we have been preaching about compatibility of additives. The list of other additives includes surface tension reducers, non-emulsifiers, biocides, ironsequestering agents, anti-sludge additives, paraffin inhibitors, water scale inhibitors, and many others. Be receptive to new concepts but be careful.

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ENERGIZING GASES Carbon dioxide and nitrogen are widely used to help provide gaseous energy to recover liquid fracturing fluids after the treatment. Their use helps eliminate the need for swabbing and also helps to reduce the fluid retention time in the formation. Quantities to use can be calculated from gas lift charts or software available from the service companies. The ratio to use depends on formation pressure, depth, hydrostatic head of fracturing fluid and temperature.

The Role and Application of Nitrogen and Carbon Dioxide in Well Stimulation The two energising additives, carbon dioxide and nitrogen, have become widely used, where available. There are a number of ways in which their application can be beneficial: •

Gas Assist - the inclusion of a gas with the treating fluid provides a means to reduce the density of the column of fluid in the tubing and consequently to enable the injected fluids to be recovered more readily.

•

Foam - foams made with a liquid phase and a gaseous phase are in reality emulsions. As such, they generally have very good apparent viscosity to enable sand transport in stimulations, recovery of solids while circulating a well, diversion of fluids during injection, and so on.

•

Solvency - Carbon dioxide is soluble to varying extents in hydrocarbons and mixtures of certain hydrocarbon frac oils are said to be miscible in natural gas. The benefit therein is that frac oils used to treat natural gas-bearing formations should be more completely and more rapidly recovered than similar frac oils without the carbon dioxide, or frac oil / carbon dioxide mixtures that do not become as miscible in natural gas.

•

Other Applications/Effects in Stimulation - There are many uses for the gases in stimulation, including in conjunction with hydraulic/abrasive jetting for perforating or slotting purposes, for workovers conducted in underbalance mode and many others.

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Nitrogen Nitrogen is ordinarily employed in the field as a gas. However, it is more conveniently transported as a liquid. The liquid, at very cold (cryogenic) temperatures, is pumped with a high-pressure cryogenic pump through a heat exchanger where it is converted to a gas and then is injected into the treating lines.

Carbon Dioxide Carbon dioxide is ordinarily pumped as a liquid (at about -10 to 0 °C), and in many cases, is carried through the length of the tubing in liquid state, only to vaporise as it enters the formation. Since it can be transported in liquid state, it has the ability to cause significant cooling. The effects of this have to be considered. The application of liquid carbon dioxide as a stand-alone fracturing fluid was discussed earlier.

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N2

CO2

-147

31

3400

7385

°C

Normal Boiling Point

Sublimation Temperature

(at 1 atm)

-196

-78

Volume Ratio gas/liquid

696

547

0.808

1.10

(at 1 atm)

(at -25 °C, 1700 kPa)

Critical Temp

°C

Critical Pressure kPa abs

(std conditions)

Liquid Density

Carbon Dioxide as an Energizer Trials to optimize the carbon dioxide content when used as an energizer for of water based fracturing fluids have been conducted in at least one area. Early production results lead the authors (SPE paper 75681) to the following preliminary conclusions: 1. 2. 3.

Using CO2 foam system rather than the conventional low CO2 ratio systems can significantly increase long-term production rates. Increasing the CO2 content alone does not have an impact on the long-term production of the wells. Reducing the maximum proppant concentration did not appear to have a negative impact on the production of the wells.

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4.

The large quantity of CO2 in the foam treatment did not significantly increase the proppant flowback from the observed wells.

The author’s use of the expression "long term" was based on data o Taken over 20 months of production, but certainly qualifies the data as being beyond "flush" production.

BIBLIOGRAPHY AND REFERENCES Cui, M., Jin, L., Wang, Z.D., Zhao, Z.Y., Yuan, W.X., Li, Y. and Dai, Z.Y.: “A Case Study of Using a Specially Formulated Fracturing Fluid to Hydraulically Fracture Ultradeep Wells To Improve Injectivity.” SPE paper 37418, presented at the 1997 SPE Production Operations Symposium Oklahoma City, OK. March 9-11. Ely, J.W.: “Stimulation Treatment Handbook - An Engineer’s Guide to Quality Control” Jennings, A.R.,: “Fracturing Fluids-Then and Now,” SPE paper 36166, JPT July 1996 p.604

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FRACTURE FLUID ADDITIVES 1.1 1.2 1.3 1.4 2.1 2.2 2.3 2.4

OBJECTIVE...................................................................................................................................................... 2 COURSE CONTENT ........................................................................................................................................ 3 ACKNOWLEDGMENT ................................................................................................................................... 5 A POT-POURRI OF QUESTIONS ................................................................................................................... 6 RESERVOIR FACTORS THAT AFFECT PRODUCTIVITY ...................................................................... 12 MECHANICAL FACTORS AFFECTING PRODUCTIVITY ...................................................................... 13 PRODUCTIVITY AFFECTED BY FORMATION DAMAGE ..................................................................... 13 CAUTION ...................................................................................................................................................... 14 2.5.1 DRILL STEM TESTS ............................................................................................................................. 15 2.5.2 PRODUCTION TESTS ........................................................................................................................... 17 2.5.3 HORNER PLOTS.................................................................................................................................... 17 2.5.4 INFLOW PERFORMANCE RELATIONSHIP........................................................................................ 23

SECTION 3: FORMATION DAMAGE ........................................................................................................................... 25 3.1 TYPES OF DAMAGE..................................................................................................................................... 25 3.1.1 CLAY SWELLING AND DISPERSION ........................................................................................................... 25 3.1.2 WATER AND EMULSION BLOCKS............................................................................................................... 28 3.1.3 DEPOSITS....................................................................................................................................................... 28 3.1.4 SATURATION ALTERATION ......................................................................................................................... 29 3.1.5 MECHANICAL CAUSES................................................................................................................................. 29 3.1.6 SOLIDS INVASION ......................................................................................................................................... 29 3.1.7 PARTIAL PENETRATION .............................................................................................................................. 30 3.2 CAUSES OF DAMAGE DURING DRILLING.............................................................................................. 30 3.3 CAUSES OF DAMAGE AFTER PERFORATING ........................................................................................ 32 3.4 PREVENTION OF FORMATION DAMAGE................................................................................................ 33 3.5 TREATMENT FOR DAMAGE REMOVAL.................................................................................................. 35 4.1 PRESSURE-RATE RELATIONSHIPS .......................................................................................................... 38 4.2 FRACTURE EXTENSION PRESSURE GRADIENT.................................................................................... 40 4.3 ROCK MECHANICS...................................................................................................................................... 43 4.3.1 STRESS............................................................................................................................................................ 44 4.3.2 STRAIN............................................................................................................................................................ 46 4.3.3 YOUNG'S MODULUS..................................................................................................................................... 46 4.3.4 POISSON'S RATIO.......................................................................................................................................... 47 4.3.5 PRINCIPAL STRESSES................................................................................................................................... 48 4.4 FRACTURE MECHANICS ............................................................................................................................ 49 4.4.1 IN-SITU PRINCIPAL STRESSES .................................................................................................................... 49 4.4.2 INTERNAL BOREHOLE PRESSURE ............................................................................................................. 51 4.4.3 FRACTURE INITIATION................................................................................................................................ 53 4.5 FRACTURE GEOMETRY AND DIMENSIONS........................................................................................... 54 4.5.1 FLUID LOSS ................................................................................................................................................... 54 4.5.2 FRACTURE WIDTH ....................................................................................................................................... 61 4.5.3 FRACTURE HEIGHT...................................................................................................................................... 62 4.5.4 CONTAINMENT.............................................................................................................................................. 64 4.5.5 FRAC MODELS .............................................................................................................................................. 67 FUNCTIONS...................................................................................................................................................................... 74 PROPERTIES OF THE IDEAL FRACTURING FLUID................................................................................................... 74 Reactions and Residues ................................................................................................................................................. 74 Fluid Loss ...................................................................................................................................................................... 75 Proppant Transporter .................................................................................................................................................... 76 Rheological Characteristics........................................................................................................................................... 82 Phases ............................................................................................................................................................................ 85 Chemical Compatibility ................................................................................................................................................. 88 Range Of Application..................................................................................................................................................... 88 Ease of Preparation ...................................................................................................................................................... 89 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Hazards.......................................................................................................................................................................... 89 TYPES OF FRACTURING FLUIDS ................................................................................................................................. 90 Oil Based Fracturing Fluids.......................................................................................................................................... 91 Water ............................................................................................................................................................................. 92 Acid................................................................................................................................................................................ 95 Foam.............................................................................................................................................................................. 96 Viscoelastic Fluids......................................................................................................................................................... 99 Special Bases ............................................................................................................................................................... 100 GELLING AGENTS.............................................................................................................................................................. 112 Increase Viscosity of Oil-Based Fracturing Fluids ..................................................................................................... 112 Increase Viscosity of Water-Based Fracturing Fluids................................................................................................. 113 CROSS-LINKING AGENTS .................................................................................................................................................. 115 BREAKERS ......................................................................................................................................................................... 116 BUFFERS ............................................................................................................................................................................ 116 FRICTION REDUCERS ......................................................................................................................................................... 117 FLUID LOSS ADDITIVES ...................................................................................................................................................... 117 CLAY STABILIZERS............................................................................................................................................................ 118 OTHER ADDITIVES ............................................................................................................................................................. 118 ENERGIZING GASES ........................................................................................................................................................... 119 Nitrogen ....................................................................................................................................................................... 120 Carbon Dioxide ........................................................................................................................................................... 120 FRACTURE FLOW CAPACITY (CONDUCTIVITY) .................................................................................................. 127 TYPES OF PROPPING AGENTS................................................................................................................................ 135 FRAC MODELS, DATA ACQUISITION AND MANIPULATION............................................................................... 140 Fracture Simulator Models.......................................................................................................................................... 140 TESTS ON FORMATION ROCK.................................................................................................................................... 171 PERMEABILITY ......................................................................................................................................................... 171 POROSITY.................................................................................................................................................................. 171 PETROGRAPHY AND LITHOLOGY ......................................................................................................................... 172 SOLUBILITY............................................................................................................................................................... 172 X-RAY (XRD) .............................................................................................................................................................. 172 SCANNING ELECTRON MICROSCOPY (SEM) ....................................................................................................... 172 ROCK MECHANICAL PROPERTIES........................................................................................................................ 173 FRACTURE TOUGHNESS......................................................................................................................................... 173 IN-SITU STRESS MEASUREMENT ........................................................................................................................... 173 RESERVOIR FLUIDS .................................................................................................................................................... 174 FRACTURING FLUIDS ................................................................................................................................................. 175 PROPPING AGENTS ...................................................................................................................................................... 178 CO-ORDINATED IN-SITU LABORATORY TESTING .............................................................................................. 179 LOGGING PROGRAM.................................................................................................................................................. 187 CORING PROGRAM..................................................................................................................................................... 188 DRILLSTEM TESTS...................................................................................................................................................... 188 IN-SITU STRESS DETERMINATION ......................................................................................................................... 189 CASING DESIGN .......................................................................................................................................................... 190 CEMENTING ................................................................................................................................................................. 190 DATA EXAMINATION ................................................................................................................................................ 191 DAMAGE REMOVAL TREATMENT.......................................................................................................................... 192 SETTING OF OBJECTIVES.......................................................................................................................................... 193 LABORATORY TESTING............................................................................................................................................ 194 SIMULATOR RUNS...................................................................................................................................................... 195 ECONOMIC PRIORITIES AND CONSTRAINTS ....................................................................................................... 195 JOB OPERATIONAL PLANNING................................................................................................................................ 197 JOB EXECUTION.......................................................................................................................................................... 198 POST JOB PROCEDURE .............................................................................................................................................. 199 FRAC MODELS, DATA ACQUISITION AND MANIPULATION ............................................................................. 202

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Since there is such a wide variation in the sophistication and complexity of fracture design models, and since most service companies employ one or more of three common simulators, it is deemed reasonable to at least mention the availability of the other models.................................................................................................................................... 202 ANALYSIS OF PRESSURE DECLINE CURVES AFTER INJECTION: ................................................................... 207 FRACTURE BED DAMAGE......................................................................................................................................... 233 FRACTURE FACE AND MATRIX DAMAGE ........................................................................................................... 236 REACTIVE MATERIAL ............................................................................................................................................... 250 TYPES OF ACIDS ....................................................................................................................................................... 251 TYPES OF JOBS.......................................................................................................................................................... 251 GUIDELINES FOR APPLICATION............................................................................................................................ 251 REACTIONS ................................................................................................................................................................ 252 MAIN REACTIONS...................................................................................................................................................... 252 HYDROCHLORIC ACID................................................................................................................................................ 252 WITH CALCITE........................................................................................................................................................... 253 WITH DOLOMITE ...................................................................................................................................................... 253 WITH SIDERITE.......................................................................................................................................................... 254 WITH DRILLING FLUIDS .......................................................................................................................................... 254 HYDROFLUORIC AND HYDROCHLORIC ACIDS .................................................................................................... 255 WITH CALCITE........................................................................................................................................................... 255 WITH DOLOMITE ...................................................................................................................................................... 255 WITH SIDERITE.......................................................................................................................................................... 256 WITH SILICATES ........................................................................................................................................................ 256 WITH DRILLING FLUIDS .......................................................................................................................................... 256 ACETIC ACID ................................................................................................................................................................. 256 WITH CALCITE........................................................................................................................................................... 257 FLUOBORIC ACID ......................................................................................................................................................... 257 IMPORTANT SECONDARY REACTIONS................................................................................................................... 258 CALCIUM FLUORIDE PRECIPITATION.................................................................................................................. 258 FLUOSILICATE PRECIPITATION............................................................................................................................. 259 IRON HYDROXIDE PRECIPITATION ....................................................................................................................... 260 TACHYDRITE PRECIPITATION................................................................................................................................ 260 EFFECTS OF MAIN PARAMETERS DURING FRACTURE ACIDIZING .................................................................. 261 CONCENTRATION ..................................................................................................................................................... 262 TEMPERATURE.......................................................................................................................................................... 262 GEOMETRY, SURFACE AREA, VOLUME................................................................................................................. 262 VISCOSITY .................................................................................................................................................................. 263 VELOCITY................................................................................................................................................................... 263 FLUID LOSS ............................................................................................................................................................... 264 METHODS OF APPLICATION ...................................................................................................................................... 264 PERFORATION WASHING ........................................................................................................................................ 264 MATRIX ACIDIZING .................................................................................................................................................. 265 NATURAL FRACTURE ACIDIZING........................................................................................................................... 267 NEW FRACTURE ACIDIZING ................................................................................................................................... 269 FRACTURE ACIDIZING WITH PROPPANT ............................................................................................................. 269 USE OF FOAMED ACID ............................................................................................................................................ 271 PROBLEMS WITH SCALES AND DEPOSITS............................................................................................................ 271 ADDITIVES AND TECHNIQUES FOR SPECIAL CASES ........................................................................................... 274 INHIBITORS................................................................................................................................................................ 274 HYDROGEN SULPHIDE ............................................................................................................................................ 275 SURFACTANTS ........................................................................................................................................................... 275 EMULSIONS................................................................................................................................................................ 276 SURFACE TENSION................................................................................................................................................... 277 WETTABILITY............................................................................................................................................................. 277 MUTUAL SOLVENTS.................................................................................................................................................. 278 RAPID REACTION RATE ........................................................................................................................................... 278 SLOW REACTION RATE ............................................................................................................................................ 279 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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DEEP PENETRATION ................................................................................................................................................ 279 SHALLOW PENETRATION ........................................................................................................................................ 280 IRON............................................................................................................................................................................ 280 FINES RELEASE AND CLAY PROBLEMS................................................................................................................. 281 FRACTURE CONDUCTIVITY .................................................................................................................................... 282 FRACTURE GEOMETRY............................................................................................................................................ 282 CALCAREOUS FORMATION DAMAGE REMOVAL ................................................................................................ 283 SANDSTONE FORMATION DAMAGE REMOVAL ................................................................................................... 284 FRICTION REDUCERS .............................................................................................................................................. 284 FLUID LOSS ADDITIVES........................................................................................................................................... 284 HEAT GENERATORS.................................................................................................................................................. 285 COMPLEXING AGENTS............................................................................................................................................. 285 OTHER ADDITIVES.................................................................................................................................................... 285 METHODS OF PLACEMENT ........................................................................................................................................ 286 INSTRUMENTATION .................................................................................................................................................... 286 PUMPING EQUIPMENT ................................................................................................................................................ 287 SPECIAL EQUIPMENT .................................................................................................................................................. 288 ADVANCED AND RECENT ISSUES IN ACIDIZING.................................................................................................. 288 High Temperature Considerations .............................................................................................................................. 291 Modeling of Acid Fracturing ....................................................................................................................................... 291 Paccaloni's Methods for Improved Matrix Acidizing .................................................................................................. 291 Placement Control Methods ........................................................................................................................................ 292 Foam diversion ............................................................................................................................................................ 293 How to Help Prevent Sludge by Proper Testing .......................................................................................................... 294

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SECTION 7 - SELECTING PROPPING AGENTS:

Three major cost items associated with hydraulic fracturing operations are: service company equipment, fluid, and propping agent (proppant). Consequently, each of these deserves careful consideration when selecting types and quantities. Any escalation of quality or quantity has a significant impact on treatment costs and on overall economics. On the other extreme, if an inadequate quality or quantity is selected, the productivity increase that is expected may not occur. This could result in an even more disappointing effect on economics. Selection of the appropriate proppant is one of the most important aspects of treatment design. The following discussion deals with the points that must be considered.

FRACTURE FLOW CAPACITY (CONDUCTIVITY) In terms of benefit, the ideal fracture would have infinite flow capacity. This could be approached with a fracture that was very wide and remained open without the need for any propping agent. Unfortunately, earth stresses nearly always will ensure that fractures will heal completely unless some form of proppant is used. The type and quantity of proppant must be chosen. The choice of whether to employ low cost, low strength sand or a higher cost, higher strength artificial proppant is affected by a number of factors. The selection process begins with the setting of the objective of the stimulation treatment. Low permeability-capacity (kh) reservoirs generally require longer fractures. The conductivity (so long as it is adequate) is of less consequence than fracture

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length. High permeability formations are ordinarily not fractured for simple stimulation purposes. However, due to formation damage, for and sand control reasons, a significant number of treatments are performed on high permeability formations. In such cases, it is very important to produce fractures that have a very high conductivity or fracture flow capacity (kfw). Fracture length need only be great enough to penetrate a short distance past the damaged zone.

4.5.6.1 CLOSURE PRESSURE (PROPPANT LOADING)

With reference to pressure causing loading on the proppant, the pressure at which the fracture closes is termed the fracture closure pressure, and is generally approximated as having the magnitude of the bottom hole treating pressure minus the reservoir pressure at any point in time. The reservoir pressure is obviously greatest at the time of the initial completion and would decline with production. Consequently, the closure pressure would become greater with depletion, or if a high drawdown situation should exist, the maximum closure pressure could be equal to bottom hole treating pressure. It should be noted that a single instance of pumping off a well to lower the fluid level to the perforations could place the proppant under maximum load, possibly causing failure. Once it fails, fines are created (in the worst possible location) and permanent impairment occurs.

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Figure 4-20

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Effect of Stress on Permeability (from Cooke, 1977)

To translate this closure pressure to the average stress that must be sustained by each particle of the proppant, we must determine the fraction of the total open fracture area over which proppant is distributed, and then divide the net closure pressure by this fraction. This covers a very wide spectrum of numbers and since fracturing treatments are now designed to employ more than a monolayer of propping agent, service companies have developed curves relating fracture flow capacity to the concentration of proppant in the fracture for various closure pressures. These curves are useful for initially selecting the main proppant. A consortium, operated by Stim-Lab, for independently determining the performance of propping agents and fracturing fluids under rigorous in situ simulated conditions, including

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longer term tests at temperature, has produced large quantities of data in the last decade or so and has essentially re-written the book on proppant conductivities. It should be mentioned that there are some cases wherein proppant may not be required. One of these cases is in fracture acidizing. This technique involves the use of acid, usually hydrochloric, as a fracturing fluid. It may be pumped into natural or induced fractures in calcareous rock and the theory is that due to inhomogeneities in the rock the acid dissolves portions of the rock in the fracture faces in an uneven manner, in effect leaving a pillar and room effect as in a mine. Sometimes slugs of gelled water are injected during the treatment in order to promote "fingering" of the acid to create areas of etched and unetched rock to help effect the room and pillar effect. A second case, (Mahoney et al, 1981) in which proppant may not be used is when coal seams are fractured in order to demethanize them prior to mining operations. Coal operators believe that sand may not be required to keep the fracs open due to the low stresses involved, also, if sand is not employed, lower injection rates are permissible and consequently it may be possible to propagate the fracture in the coal without roof penetration, which would be a hazard for the miners.

CRUSHING AND EMBEDMENT There are several important effects caused by the stress imposed on the proppant in the fracture. The proppant may crush, (Huitt et al, 1959) it may deform, (Huitt et al, 1959 Huitt et al, 1958) or it may embed (Huitt et al, 1958) in the fracture face. Any of the above phenomena may occur even under dry conditions in the laboratory. It must be remembered that under in situ conditions, (Cooke, 1973, Ahmed et al, 1979) both the proppant and the formation rock would have been exposed to the fracturing and formation fluids (Abou-Sayed et al, 1981, White et al, 1981) as well as to the temperature of the reservoir. The effect could be to cause softening of the formation face and enhanced embedment. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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The tendency of a particular proppant to crush or embed in a particular formation is a very important consideration. Crushing of proppant produces fine particles of irregular shape which may act as impediments to flow due to their fineness. They may also tend to form bridges, which may further restrict flow. On the other hand, when proppants tend to embed into the formation faces, the effect is to reduce the fracture width, conceivably to zero. Crushing and embedment must both be avoided. There is no point in creating a fracture with zero flow capacity. Most service companies should be able to provide technical information, preferably independently generated, concerning the propping agents they supply. Perhaps the key factors to be concerned with are the strength (crushing resistance) and the chemical impurities that may be present. It is very important to realize that there is great variation in the quality of fracturing sand, depending upon the source of the sand. This variation is significant and you should know and specify the source of the sand for your location. This is not to say that some of the lower quality sands cannot be used in situations that do not require quality sand. But, be careful! Some sands that are perfectly acceptable for shallow well work should not be used in deeper wells. With regard to the problem of determining the tendency of a proppant to embed in a formation, Huitt and McGlothlin of Gulf suggested a test method based upon the use of a penetrometer device which measured the amount by which a steel ball embedded in a formation under various loads.

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Figure 4-21 Geometry of Embedment. They measured the diameter, d, in inches of the impression of the sphere in the rock face, the diameter, D, and the load, L, applied in psi. The values were plotted on log-log paper as the ratio d/D on the y-axis versus L/D2 on the x-axis. Physical constants I and m were determined as follows: I = L/D2 value when d/D = 1. m = Two times the slope of the curve. B is determined from the relationship

d ⎡L⎤ = B0.5 ⎢ 2 ⎥ D ⎣D ⎦

0.5m

The constants describe the embedment tendencies. From I may be inferred the load that can be transmitted to the formation face through the propping agent before the particle completely embeds.

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The rate of change of embedment with load is given by m, and B is a measure of the degree of embedment at very low loads. This test is seldom used now since its principal application was in conjunction with partial monolayer applications which were popular when it was thought that many fractures were horizontal, and there was some probability of being able to place particles in such a manner. The important point is that even that long ago, it was recognized that interaction between proppant and formation under load was a very key consideration. As will be discussed during the laboratory-testing portion of this course, there are now much more sophisticated techniques in which the proppant, formation rock, formation fluid and fracturing fluid are evaluated together under fully simulated in situ conditions in the laboratory. A test for evaluating the resistance to crushing of rigid propping agents such as sand was also proposed by the same authors. It involved testing the proppant between steel plates to determine the particle strength. It was very sensitive to particle size variation however. The API has a test that measures the percentage of fines created when the proppant is subjected to a specific load depending upon the mesh size. The more sophisticated interactive laboratory tests are much more meaningful.

PARTICLE SIZE DISTRIBUTION Propping agent quality determinations should also consider particle size distribution. The API recommendation is that 90% by weight should fall in the specific range, not more than 0.1% should be larger and not more than 1% should be smaller than the next screen size outside the range.

ROUNDNESS Roundness of propping agents varies considerably from source to source. It is generally accepted that the rounder the particle the better, although some believe that a certain amount of out of roundness helps promote bridging to the extent that flow back of proppant from the _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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fracture is reduced. A better approach would be to use round particles and employ resin precoating technology to help prevent flow back. The standard for roundness is a series of comparative charts proposed by Krumbein.

IMPURITIES The purity of fracturing sand can be impaired by the presence of various non-silica materials such as feldspar or iron. These materials may react with either formation fluids or fracturing fluids to perhaps result in products which are harmful to the formation or which may reduce the fracture flow capacity. One should be aware of the possibility of contamination of the frac sand from cement or mud products, which may have been carried by the same transport on another trip. The service companies take every precaution to prevent this sort of problem from occurring but it still happens, on rare occasions. A Dowell paper (Steanson et al, 1979) and a short course sponsored by a resin manufacturer (Gidley, 1991) indicated some factors to consider when selecting a propping agent. The objective of a fracturing treatment is to improve production. This is accomplished through the establishment of higher conductivity. It should be remembered that the proppant is perhaps the most important factor in establishing and maintaining conductivity in the fracture. In addition to conformance with API specifications, some of the factors to take into account in the selection process include the following: •

Strength

•

Roundness

•

Cleanliness

•

Particle Size Distribution

•

Short Term Performance Tests

•

Long Term Performance Tests

•

High Temperature Performance Tests

•

Load-Cycling Effects on Proppant

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•

Resin Coatings or Other Retaining Method

•

Cost

TYPES OF PROPPING AGENTS Because we are often called upon to review older wells for workover, we should briefly mention that three propping agents that are no longer in use were fairly widely used for a short period of time during the sixties. Two of these were rounded walnut hulls and aluminium pellets. Both were used because of their ability to deform under load rather than to crush. It was thought this would be useful in partial monolayer type treatments. Later, a high strength glass bead was used in deeper wells where sand was likely to be crushed. These have been mostly replaced more recently by pellets of sintered bauxite and other artificial proppants of high or intermediate strengths for applications in which crushing resistance is required. In more recent times, a number of other proppants have been introduced. SPE papers (Cutler et al, 1983, Penny, 1987, Much and Penny, 1987) reported on standardized laboratory projects in which a larger number of experimental and commercial materials were evaluated and a methodology for such evaluation was put forth).

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Figure 4-22 Fracture Conductivity versus Closure Stress at 50C. One of the first more widely used `exotic' propping agents was sintered bauxite (Steanson et al, 1979) which is sold under several trade names, including `Super-Props' and `Super Proppant'. There are a number of intermediate strength (and intermediate price) proppants available and some are much better than others. These materials generally possess much higher crushing strength than sand and lower specific gravities than the bauxite (important in proppant transport) and it is generally recommended that improved propping agents should be considered for use where closure pressures exceed 41.37 MPa (6000 psi). One could generalize and suggest that sintered bauxite (or some material other than sand) should be used for all fractures deeper than 2438 m (8000 feet). SPECIAL PROPPANT COATINGS Resin materials are available for coating the proppant to accomplish a number of objectives, principally to help prevent flowback of placed proppant from the fracture. Proppant flowback of some amount almost always occurs. In some instances, the volume of proppant _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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recovered is substantial. In addition to the implied waste, the proppant can cause restricted production due to fill up of the well bore. Returning proppant also causes problems with downhole pumps and surface equipment. The resin coating of the proppant is usually pre-applied although the activator can be applied on the fly. There was initial concern that the coating of the proppant would occupy porosity of the packed proppant bed and would therefore restrict permeability. Independent tests tend to support the suppliers' position that the pre-coated proppant actually provides higher permeability than the same proppant uncoated under the same test conditions. At least some of the test data is part of the database accessed by the commonly used fracture design simulators. These materials have been available for several decades and are relatively widely used in some problem areas. Some operators use them relatively routinely in nearly all areas.

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TABLE OF CONTENTS SECTION 7 - SELECTING PROPPING AGENTS FRACTURE FLOW CAPACITY (CONDUCTIVITY)

121

Closure Pressure (Proppant Loading) Crushing and Embedment Particle Size Distribution Roundness Impurities

122 124 127 127 128

TYPES OF PROPPING AGENTS

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SECTION 8 - ON-SITE DATA GATHERING AND ANALYSIS ANALYSIS OF PRESSURE DECLINE CURVES AFTER INJECTION: A selection of important parameters can often be determined relatively accurately by careful application of several methods for analysis of pressure decline after pumping. These include: •

Total friction losses during pumping

•

Pipe friction that occurs within the tubular conduit from the pressure device to the entry of the perforations

•

Perforation friction, representing the loss in pressure caused by the perforations themselves

•

Near wellbore friction, representing the friction caused by near wellbore effects other than the perforation holes

•

ISIP, the pressure immediately after pumping stops, usually (and often erroneously) assumed to represent fracture extension pressure

•

Closure pressure, usually less than ISIP, representing the pressure magnitude at which the walls of the closing fracture have begun to interfere with each other.

•

Multiple closures, meaning when more than one closure event is recorded. This could represent two or more of the principle stresses being reflected.

There are terms, which have become common, used to describe the operations for obtaining some of the data. Microfracs refer to pumping operations of a small scale designed to determine the in situ stress that exists at one or more layers. The pumping rates are generally rather low, less than 1m3/min. Very accurate pressure recording instruments and accurate volumetric pump rate recording equipment, preferably on the same chart or disk is required.

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Minifracs refer to larger scale operations conducted either the day before or earlier on the same day as the main stimulation operation. These pumping operations are carried on at fullscale pump rates. The purpose is to determine or confirm certain information that had to be assumed for the design of the treatment. Subsequently, if necessary, the treatment design would be modified in the field to accommodate the new, accurate data.

FRAC MODELS, DATA ACQUISITION AND MANIPULATION

Fracture Simulator Models

Numerous simulator models have been created to describe the hydraulic fracturing process. The reference section of this manual contains references dealing with many of them. As of this writing, one of the most modern, impartial and concise comparisons is contained in Warpinski et al, February 1994. His article compares a selection of models of various complexities on the basis of real case data response comparisons set up by the Gas Research Institute. This article is recommended reading in its entirety, along with the accompanying commentary (Cleary, February, 1994). The articles are drawn upon extensively for the following discussion. Fracturing models may be classified in groups of approximately equal declining complexity. 1.

Planar 3D models: TerraFrac, by TerraTek Inc. HYFRAC3D, by S.H. Advani

2.

GOHFER, a unique finite-difference simulator from Marathon Oil Co.

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Planar pseudo-3D models: A.

Models using the "cell" approach: STIMPLAN by NSI Inc. ENERFRAC, by Shell TRIFRAC by S.A.Holditch & Associates, Inc.

B.

Models employing overall fracture parameterization: FRACPRO by Reservoir Engineering Systems (RES), Inc. MFRAC-II by Meyer & Assoc.

4.

Perkins-Kern-Nordgren (PKN) and Geertsma-deKlerck (GDK) models: PROP by Halliburton Chevron's 2-D model Conoco's 2-D model Shell's 2-D model Pseudo-3D models run in constant height mode

A description of each of the model types, as provided by the suppliers, is given in the Warpinski paper. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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The designer of a stimulation treatment must realize that the most important contribution he/she can make is to use all the available knowledge to a) design, and b) execute successful (meaning most profitable) well stimulations. This implies that, in order for the person best-informed with respect to the design decisions and reasons behind the decisions to be available for all-important on-the-fly decisions, the designer must go to the field for the implementation. Further, the instrumentation, software and skills in the field must be sufficiently adequate to enable very rapid and proper decisions to be made while the job is being pumped.

Satellite Links Links between the treatment control van at the well site and any point on the globe are possible using satellite equipment and technology. The service companies can provide this added and very useful service so that a team of experts may be assembled in a "war room" distant from the job. The experts can view the same data as is being displayed in the field and can advise the field supervisors by telephone link as to recommended action based on the real time observation. By means of satellite/internet connection, the data can be instantly transmitted to any world location. There it can be observed in real-time and analyzed or commented upon by experts at the remote office location. Thus the "high-level" expertise, in-house or consultant, can contribute without being physically present on location. Implicit in this is that the software/computer system will be faster than real-time and thus enable predictions/changes to be made on the fly. Most decisions in the field will be guided by an interpretation of the meaning of changes in the net pressure (at the entry to the fracture minus the closure pressure). Therefore, accurate fluid/proppant friction properties must be incorporated in the database so that the computer can convert input data from surface pressures to bottom hole pressures. Of course, if surface indication of pressure that is measured at the bottom of the hole were available, this would dramatically improve the _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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analysis of net pressure. The best compromise is to have tubing in the well and pump down only the tubing or only the annulus with the other conduit full of fluid but static. It can then be used to measure bottom hole pressure directly, correcting only for hydrostatic head. One should use the available data to initially design the treatment, then use field-obtained data, such as is generated on a small, unpropped frac (minifrac or data frac) pumped ahead of the main frac to redesign the main fracture taking into account the parameters calibrated from the small frac. The redesign would include a prediction of pressure performance during the main frac. Then the main frac would be performed with real-time monitoring. The monitoring would identify pressure variances from the predicted. This would then enable additional parametric changes to be identified, incorporated in a design change modelled for verification in muchfaster-than-real-time, while the job is being pumped, and the changes incorporated in a revised job design while it is still underway. Of course, for very short duration treatments, there may not be sufficient job time to implement a revision. In addition to a skilled designer who can interpret the meanings of the pressure variances, an important part of the operation is the model with the appropriate accuracy, versatility and capabilities. Less sophisticated models are available, as indicated, and may have some value for simplistic designing and monitoring. However, if the real objective is to improve the cost-effectiveness of well stimulation, then the models employed, and method of employment can be crucial. Ultimately, there is little doubt that the most effective results will be achieved by those firms that insist on focussed teamwork involving both the design and the execution teams, and especially the on-the-fly optimization changes. History matching, where possible, should always be done to validate parametric data for use on future designs and thus apply the science costs to improving efficiency.

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There is a considerable amount of author-pride in the various models that have been suggested. Ultimately, the designer must remember that the objective is to make wells more profitable. Any activity, data set, or software aspect that does not maximize this goal must be reconsidered and possibly replaced by a better activity, data set or software. One of the features of the more sophisticated models is that they require a considerable amount of data to fully realize their special capabilities. The data in some instances is either difficult to obtain with reliability, or expensive to obtain. Some short cuts to values have been developed, but many have severe shortcomings, such as reading only values that are very close (centimetres) to the well bore. To use these data could lead to mis-interpretation of far field effects. There will continue to be improvements in data quality, model sophistication and flexibility as well as designer skills

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TABLE OF CONTENTS SECTION 8

ON-SITE DATA GATHERING AND ANALYSIS

133

FRAC MODELS, DATA ACQUISITION AND MANIPULATION

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Fracture simulator models

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Satellite links

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SECTION 9 - BASIC TREATMENT SIZING Once a well has been designated as a candidate for fracture stimulation, the design team must decide on a number of important aspects. What fracture fluid will be employed? What proppant will be used? What pumping and other related field equipment and instrumentation will be required? And after the above and other considerations have been dealt with, the remaining question is: What size frac would be best? The decision is more easily made if it can be made solely on the basis of maximum net present value (NPV). However, individual companies have other corporate criteria that are used fore comparison and ranking (or elimination) of investment opportunities. These criteria often include a maximum time allowed for the investment to be recovered (payout time). Operational risks associated with the treatment must be evaluated and considered. Further, the corporations usually have a team tasked with providing guidelines for items such as the following:

♦ future oil price ♦ future interest rates (or numbers used by the corporation to reflect the corporation's prediction)

♦ escalation rate for operating costs ♦ risk factors regarding ability to market (or be shut-in by government decree)

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Such information, once it is available, can be used to estimate the revenues and expenses associated with future incremental oil production attributed to the stimulation. Reservoir models can then be used to predict the production rate versus time and the cumulative production versus time for the untreated well and for the well when it has been treated with a given frac design. The simulator can be used to compare the most probable job size (somewhat intuitively determined) with a number of job sizes smaller and larger than the base case on the basis of net present value (NPV). Usually, the maximum NPV involves a larger fracturing treatment. The economics curve becomes somewhat asymptotic at NPV values less than maximum. To choose the job size that yields the maximum calculated NPV is to ignore the technical and economic risks associated with larger treatments. For example, to generate larger fracture lengths, in contained fracture mode, results in larger net pressures. There are many sound reasons to be cautious about excess net pressure, including loss of containment or rapidly increasing fluid loss characteristics that could lead to sudden screen-out. Prudent designers often select job sizes significantly smaller than those that yield maximum NPV, choosing instead to observe where the curve of NPV versus job size begins to become asymptotic. In cases where previous treatments in the area have been designed and performed using similar simulators, opportunity exists to compare the simulated production history with the actual history. Differences can often be reconciled by altering the original treatment design parameters until a history match is achieved. The altered variables, where appropriate, can be taken into consideration when designing future jobs in the same area.

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STIMULATION ECONOMICS: Well stimulation is very often an expensive operation, in some cases amounting to more than a million dollars per job. Therefore, as with other expensive aspects of a business, the selection of appropriate stimulation options should be based on an economic comparison. However, there are several economic decisions that need to be made at various times during the process of identifying candidates, designing the completion or workover program and obtaining the information wanted and/or needed to help make the correct decisions. The age-old question as to how much science is really needed continues, justifiably, to be raised. It is usually considered in the context of the cost of obtaining information versus what is the risk of carrying on without that information. The second important aspect from an economic decision sense is what is the correct size of treatment to perform for a particular situation. Of the above two questions, the first needs to be considered in light of the possibility of designing an ineffective treatment due to lack of a piece of information that, had it been available and considered properly, would have prevented the design mistake. In fact, a suite of information of various kinds is necessary for even marginally effective design. In addition, each situation may present some particular problems which can best be addressed by taking into account pieces of information that can be obtained at extra (optional) cost. One of the best sources of information that has no marginal cost to acquire is obtained from existing files (if there are any) for the given area. For example, if there is sufficient information available to establish confidently that fractures tend to be contained within certain vertical limits, there is likely no justification for spending funds to obtain in situ stress data. On the other hand, if there is concern that the fracture may grow out-of-zone to a significant extent, the justification for obtaining the data is strengthened. It is not wise to pump a large fracture treatment if 90% of the surface area exposed by the fracture is non-productive. In some cases a treatment that is much smaller and far less expensive would achieve the same or even better benefit. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Additionally, one must consider the priority ranking of various types of information in the decision-making process. Some are of first order importance and of key economic significance; others may be of far less importance and only of marginal scientific value. Again the key question to ask is: "What is the greatest risk, if we assume the wrong value for an unknown piece of data, and how does the cost of that risk compare with the cost of obtaining the data?" The other category of economic decision, concerning job sizing is the one that generally has the greatest economic impact. Prior to making the economic comparisons to select the size of the treatment, a number of decisions would have been made regarding the type of treatment to perform. This discussion assumes that the type has already been selected and the question to be answered relates to the size. There are a number of ways in which various treatments can be compared on an economic basis in order to select the most attractive one. An appropriate comparison for many cases is to compare the present value of incremental future production versus the incremental cost, on a present value basis, to obtain that incremental future production. The following information will be required to calculate the present value of the revenues: •

Prediction of future production versus time after the stimulation, on both a rate and a cumulative basis

•

Oil or gas price to be realized after the stimulation treatment, net of any royalties or other non-operating cost charges against production.

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•

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Discount rate that will be applied against future income to represent the effect of giving consideration to the time value of money, or the opportunity rate.

In order to determine the net benefit of the stimulation, the costs of producing the incremental oil or gas must be deducted from the income resulting from the sale of the production. A list of such costs would include: •

The additional operating costs required to produce the additional oil or gas

•

A cost escalation factor that would be applied to estimate the increasing cost of operations each year.

•

The fixed stimulation costs which include those costs which do not vary with the size of the job. These would include the cost of the rig rental and operation, the cost of rental of the fracturing equipment, cost of transportation of the equipment, and the cost of engineering, labour and supervision.

•

The variable stimulation costs which depend on the size of the treatment. These would include the cost of propping agent, stimulation fluid, plus transportation of, and storage for, these materials. These are usually expressed as a factor of the unit-size fracture treatment.

In order to make a proper economic comparison between alternative options, a common basis for the comparison must be selected. There are several such standards of comparison. One of the most commonly used is Net Present Value.

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This means the present value of all future incremental production must be calculated and the present value of the additional operating cost to produce the incremental oil must also be calculated, added to the cost of performing the fracturing treatment. Then the sum of the present values of the costs must be subtracted from the sum of the present value of the production. The resultant number is the Net Present Value of the particular alternative. Several sizes of treatment are compared and the one size near the highest Net Present Value is selected, provided other criteria are also met by this size. The other criteria may include a statement that the treatment must recover all costs within a fixed period of time, such as one year. This economics calculation can be done using appropriate computer software. However, knowledge of the factors listed above will be necessary. Each situation has its own set of factors unique to it. These must all be taken into account in some manner in order to obtain a proper comparison.

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TABLE OF CONTENTS SECTION 9 - BASIC TREATMENT SIZING BASIC TREATMENT SIZING

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STIMULATION ECONOMICS

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SECTION 10 - EQUIPMENT AND OPERATIONS OVERVIEW Fracturing Equipment: The equipment required to conduct a fracturing operation consists of certain core items as well as a number of ancillary pieces of equipment that may be required for special applications. Tank trucks to haul fluid Tanks for fluid - specs Preheating equipment Filtering equipment Tank manifold with hoses in and out Blender Chemical concentrate trailer with synchronized proportioning system and field laboratory equipment Hydration/conditioning unit to process diluted gel concentrate Proppant transportation/storage/transfer equipment Nitrogen or carbon dioxide transportation and pumping units Pumping unit to pump additives, acid, or hold pressure on the annulus for packer completions Two-tiered manifold for pressurized suction and high-pressure discharge with hoses and High-pressure steel line in and out Tree-saver or fracturing well-head Check-valves Pressure-relief valves Isolation valves High pressure line for bleeding off well pressure to a safe location Crane truck for transporting and handling heavy equipment items Instrumentation/data acquisition/processing unit Sensing/sending equipment with signal lines to instrumentation/data centre, _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Data acquired includes clean and proppant-laden fluid density, tubing-head and casing- head pressures, injection rate Wireless communication equipment for onsite communications Fire-protection and ambulances (depending upon circumstances).

Operations Overview Often, the person who designs the fracturing treatment (Oil Company or Service Company) is not the same one who will be responsible for the conduct of the treatment in the field. This suggests that there must be very open and proactive communication between the design team and the field team, so that an executable design will result. Best communication begins early during design and continues through until the well has been placed back on production after the treatment and subsequent clean up. Issues that must be addressed include the following: Ability of the field location (well site) to enable all of the necessary equipment to be placed in logical position on firm ground or constructed base and at the same time is positioned at the required safe distance from the wellhead and other items such as fluid recovery tanks with distance-mandated locations. Ability to organize the equipment so that no equipment movement is required once pumping operations commence. Timing, order of delivery to location, and possibly storage requirements of equipment and materials. Inspection of equipment and materials and verification of readiness according to a suitably detailed checklist. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Review of the specific program in the field to be certain that all involved understand the overall operational objective, the order of operations and the individual responsibilities both in the planned program and in plausible "what-if" situations. Command authorities within the Oil Company and for Service Company should be very clear here. Safety details should be elaborated during a tailgate meeting for all on location. An important item is the detailed manner in which pumping equipment will be shut down as required to avoid over-pressuring of the tubular equipment.

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TABLE OF CONTENTS SECTION 10 - EQUPMENT AND OPERATIONS OVERVIEW

EQUPMENT AND OPERTIONS OVERVIEW

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Fracturing equipment Operations overview

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Stimulation Suite 2008 Part Two Advanced Hydraulic Fracturing © Porteous Engineering Limited

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TABLE OF CONTENTS INTRODUCTION

155

1

INFORMATION COLLECTION

157

2

IMPORTANCE OF LABORATORY WORK

164

3

TESTS ON FORMATION ROCK

165

PERMEABILITY

165

POROSITY

165

PETROGRAPHY AND LITHOLOGY

166

SOLUBILITY

166

X-RAY (XRD)

166

SCANNING ELECTRON MICROSCOPY (SEM)

166

FINES MIGRATION

167

ROCK MECHANICAL PROPERTIES

167

FRACTURE TOUGHNESS

167

IN-SITU STRESS MEASUREMENT

167

RESERVOIR FLUID

168

FRACTURING FLUIDS

169

PROPPING AGENTS

172

CO-ORDINATED IN-SITU LABORATORY TESTING

173

DEVELOPMENT OF BEST STRATEGY

175

LOGGING PROGRAM

181

CORING PROGRAM

181

DRILLSTEM TESTS

182

IN-SITU STRESS DETERMINATION

183

CASING DESIGN

184

CEMENTING

184

DATA EXAMINATION

185

DAMAGE REMOVAL TREATMENT

186

SETTING OF OBJECTIVES

187

LABORATORY TESTING

188

SIMULATOR RUNS

189

ECONOMIC PRIORITIES AND CONSTRAINTS

189

JOB OPERATIONAL PLANNING

191

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JOB EXECUTION

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POST JOB PROCEDURE

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BEST DESIGN USE OF 3-D SIMULATORS

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FRACMODELS, DATA ACQUISITION AND MANIPULATION

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ANALYSIS OF PRESSURE DECLINE AFTER INJECTION

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ECONOMIC OPTIMIZATION

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OPERATIONAL PLANNING & GUIDELINES

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JOB PLANNING

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PRE JOB-DAY SITE ACTIVITIES

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EARLY JOB-DAY SITE ACTIVITIES

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MAIN FRAC ACTIVITIES

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POST-FRAC ACTIVITIES

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DECISION TREE FOR ON-THE-FLY USE.

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ON SITE USE OF 3-D SIMULATORS

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FRACTURE DIAGNOSTICS

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REAL TIME AND POST TREATMENT DIAGNOSTICS FOR CONTINUOUS IMPROVEMENT

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OCCURENCE OF MULTIPLE HYDRAULIC FRACTURES

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QUALITY CONTROL/ ASSURANCE

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FRACTURE BED DAMAGE FRACTUREFACE AND MATRIX DAMAGE CHECK LISTS

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LIST OF FIGURES In-situ stress measurement in open hole

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Interactive Test, Set-up Fracture Bed. (Ahmed et al, 1979)

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Interactive Test Set-up, Fracture Face. (Ahmed et al, 1979)

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Damage to Fracture Conductivity

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Case History Demonstrating Benefits of Proper Laboratory Testing Methods

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INTRODUCTION

This two-day course is the second part of a series of courses in three parts. The three segments of Well Stimulation Suite 2008 consist of main topics covering the following areas: First Segment Introductory Material Review of Reservoir Characteristics Formation Damage Theory of Hydraulic Fracturing Deciding which Wells to Fracture Predicting the Results of Fracturing Fracturing Fluids Propping Agents Basic Treatment Sizing Equipment & Operations Overview Second Segment Information Collection Laboratory Work Development of Best Strategy Best Design Use of 3D Simulators Economic Optimization Operational Guidelines Decision Tree for on the fly Use On-site Use of 3-D Simulators Fracture Diagnostics Quality Assurance Procedures Third Segment Types of Acids and Applications Sludges, Emulsions, Precipitates Acid Placement Techniques Effective Matrix Acidizing Factors Affecting Fracture Acidizing Success New Developments & Emerging Stimulation Technologies

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This is the advanced level portion, which implies that participants have either taken the twoday course, dealing with fundamentals of well stimulation, that preceded this one, or they have equivalent knowledge or practical experience or both. Following this segment of the course is a presentation on matrix acidizing and new and emerging stimulation technology. The material we will cover in this present portion consists of

♦ Information collection ♦ Importance of laboratory work ♦ Development of best strategy ♦ Best design use of 3-D simulators ♦ Economic optimization ♦ Operational guidelines ♦ Decision-tree for on-the-fly use ♦ On-site use of 3D simulators ♦ Fracture Diagnostics ♦ Quality assurance procedures Questions and classroom discussion of any of the topics is encouraged. Relating the discussion to specific field problems or cases can be very useful. To the extent that time permits, there will be an open discussion of Well Stimulation issues following the presentation of the scheduled material.

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INFORMATION COLLECTION Hydraulic fractures have been designed for the purpose of stimulation of oil, gas and water wells for over fifty years. The complexity of the designs has increased with the availability of vastly improved understanding, design tools and information. However, not all treatments require complicated and/or difficult designs. Many very simply designed treatments have been quite successful in improving productivity. That is not to say that there is no room for economic optimization. In the advanced application of hydraulic fracturing, 3-D simulators are employed to model the hydraulic fracturing process as an aid for treatment design. In addition to the usual parametric information required to properly describe the situation to be modeled, additional information may need to be determined in various laboratories, if risks are to be minimized and for best results. The use of 3-D simulators is now an integral part of prudent fracture treatment design. These simulators require input of a substantial amount of data for best results. The data are not always readily available in the required quantity, type, or form. An adequate description of certain parameters is of relatively more importance than other parameters. Models are generally more sensitive to in situ stress variation and permeability variation than to variation in other formation parameters. However, due to difficulty and cost of obtaining the data, in situ stress data are seldom available. When they are, there are usually insufficient data points to adequately describe enough of the layers in the target formation as well as in the formations above and below the target to a sufficient distance from the target.

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However, the use of wireline logging tools, such as the Di-Pole Sonic, for the indirect obtaining of data that can be related to in situ stress has increased. Interpretive techniques have improved with increasing reliability. Some relatively simple techniques have been developed (Barba & Batcheller) to enable digital log data to be tabulated in a rock-properties spreadsheet, from which a resulting stress profile is calculated. The profile can then be pasted directly to and utilized in 3-D fracture simulators. The above type of data is made much more reliable if at least one in situ stress determination by conventional pressure injection methods is used to calibrate the logdetermined values. The service companies and consultants who employ the 3-D models have prepared data sheets that list the input data required to properly use the models. It will require time to assemble all of the data, to substitute reasonable assumed values for the unavailable data, to load the simulator, and eventually to test the model for sensitivity to variations from the assumed data. A partial list of the input data would include the following:

♦ Well mechanical parameters such as tubular description ♦ Total vertical depth ♦ Total measured depth ♦ Casing Internal diameter ♦ Tubing outside diameter ♦ Tubing inside diameter ♦ For each layer representing a change in rock properties: ♦ depth, ♦ rock type, ♦ permeability, ♦ porosity, ♦ in situ stress or mechanical properties. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Note: a layer may be only 1 meter in thickness. There could be several layers in a single zone. A layer, therefore, is not an entire zone. This is what makes the input data set for 3-D simulators significantly different than for 2-D simulators.

To help define where new layers should be considered, a good technique is to assemble all the logs from the well and mount them on a wall or large table so that depths are normalized. The list of logs would include not only the usual wire line logs but also drilling time logs, or other tools that would indicate a change in rock properties. A series of layer/layer interfaces should result with each interface defining another layer.

The method described by Barba and Batcheller can then be used to assign stress values for each layer.

♦ Perforated interval ♦ Reservoir temperature ♦ Preferred type of fracture fluid ♦ Preferred type and size of proppant ♦ Producing bottom hole pressure ♦ Initially assumed frac pumping rate ♦ Initially assumed pad volume and proppant addition schedule ♦ Preferences regarding use of nitrogen or carbon dioxide At some point early in the design process, we need to consider the role of the various tools that help us to examine the records and results of previous treatments. The purpose is to help validate parameters such as created fracture height, and possibly the number of parallel fractures created. The tools employed could be multiple isotope radioactive logs and/or temperature logs, and others. If any of these data are available, the model-predicted fracture heights need to be compared to the (interpreted) actual values. Some adjustment to the models (or the assumptions e.g. number of fractures) may be necessary in order to make a match. Once a match is made the same adjustments may logically be applied more confidently to other cases in the same area.

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There is still considerable controversy regarding the usefulness/reliability of in-wellbore techniques such as downhole video cameras, impression tools and so forth, for determination of far field fracture geometry. The interpretation of micro-seismic signals has been advanced significantly to the point where it can be a useful diagnostic tool. Some very interesting work has been done (Warpinski, 1996) regarding the use of surface and downhole tiltmeters for estimating the orientation, dip, azimuth and length of hydraulic fractures. Much of the work is in the San Joaquin Valley (California). Some of the interpreted results suggest that fracture orientation and dip (in the specific area) are somewhat surprising in contrast to "conventional wisdom". Horizontal fractures have been mapped at depths far greater than would "normally" be expected. Factors such as very depleted reservoir pressure and subsidence have been suggested as being important in this respect. A number of authors have indicated that there is reason to suggest that multiple, nearly parallel fractures can occur. The incidence of such occurrences is apparently greatest when the axis of the well bore and the inclination of the fracture are not parallel, and when more than one point of initiation of the fracture is available, such as when more than one set of perforations was exposed. Barba and others have reported on interesting work in this respect. A substantial amount of work has been done in regard to the use of multiple isotope radioactive tracers, together with before and after logging with r/a tools designed to differentiate the isotopes. This writer believes that these techniques can be very useful. However, since the detectability of the tracers by logging devices in the well bore is limited to a very short distance (less than 1 meter) from the wellbore, the usefulness is limited to this region. The various vested interests have their own interpretation to place on the _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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results of the fracture treatment and any diagnostic indicators. The additional evidence from this type of r/a tracing may contradict interpretations. This writer believes all evidence should be considered and the limitations on all diagnostic tools need to be known. In the end, the success or otherwise of a stimulation will be measured in terms of a number of items: Hydrocarbon production increase Water or (unwanted) gas production increase All-in cost Short term versus longer-term productivity increase Net present value of the treatment or equivalent economic measuring device. Often, the results of treatments do not measure up to expectations. Then the analysis begins to determine what may have happened to cause deviation from expectations and then to determine what improvements can be made for future similar cases. It is during this process that the vested interests present, sometimes vigorously, their own point of view. The owner/operator should recognize this tendency and seek the right or best answer from all possibilities, discrediting none until a clear reason is established. Beware of generalities. Some of the most important information that can be assembled is that dealing with the experiences of designing, conducting and evaluating previous treatments in the same formation and area. The incidence of near wellbore tortuosity, difficult formation breakdowns (fracture initiations), unusual pumping pressure, and premature screenouts is important. Occurrences of fracturing to an unwanted portion of the reservoir, perhaps leading to undesirable water (or gas) production should be noted.

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One of the uncertainties is always the height of a created vertical fracture and the extent of the upper and lower fracture boundaries above and below the perforated interval. Various methods, discussed earlier, are available for helping to define these items. However, the indications are very often clouded, or even contradictory. Similarly, it is very useful to know the time that is required for the fracture to close sufficiently so that proppant settling and proppant flowback will be curtailed. It is important to note that the models employ electronically stored, laboratory-determined data retrieved from an internal database regarding fracturing fluids and proppants. If the field prepared/supplied version of the product (frac fluid or proppant) is not up to specifications, or if there are other conditions (such as contamination) which invalidate the catalogued data, then the use of that data could lead to substantial error in the simulated performance. Unless it is recognized as such, the bad data may be relied upon both during the job execution and in the post job analysis of the operation, leading to very erroneous conclusions. Consequently quality control/quality assurance procedures (detailed elsewhere in this course) are extremely important. In terms of information collection and analysis, a very useful tool is available for comparing wells that may be candidates for re-fracturing. Very simply, the procedure is to graphically compare wells in a field by plotting productivity index (PI) against permeability thickness (kh). A best-fit straight line through the data should separate under-performers from overperformers. The better wells probably would not benefit greatly from re-stimulation, while the poorer performers should be studied more closely to look for reasons for their poor performance. It is probable that many of these will be candidates for re-stimulation. Be careful to recheck to identify incorrect determinations of kh. The results of attempts to history match actual versus model-predicted production versus time, and the knob twisting (adjustment of various assumed or interpreted parameters) that was necessary to produce a match can be very enlightening.

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It is easy to conclude that certain changes that produce good matches are unrealistic, and to discard such possible solutions too early. It is better to develop several relatively successful history matches without passing premature judgement on the realities. Then, when all possibilities have apparently been identified, perform a critical review to select those that survive the test of corroboration by other hard evidence.

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IMPORTANCE OF LABORATORY WORK A significant advancement, (Ahmed et al, 1979) was in the sophistication in laboratory testing and examination of rocks, fluids and proppants, individually, and more importantly, interactively. No longer is it sufficient to say a particular core was "tested in the laboratory." The variation in sophistication of tests is now so great that the description of how the tests were carried out is of extreme importance if one is to understand the true value, if any, of the tests conducted. For example, the test method used for fluid loss of fracturing fluids has evolved as follows over the years: 1.

100 psi across 1 sheet of filter paper, at room temperature

2.

100 psi across 3 sheets of paper at room temperature

3.

1000 psi across wire screen at room temperature

4.

1000 psi across wire screen at reservoir temperature

5.

1000 psi across core wafer at reservoir temperature

6.

1000 psi across core cylinder at reservoir temperature under dynamic test conditions

7.

Fully simulated in situ test

8.

Numerical fluid loss model

9.

Minifrac analysis

Except for additive preliminary screening purposes, the first four above are useless. The seventh, eighth and ninth have become more frequently used for critical or expensive jobs.

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TESTS ON FORMATION ROCK The availability of formation rock samples, cores or cuttings, for testing is a distinct advantage. On occasion, it is critical that the core should be obtained under very carefully controlled conditions, such that underbalanced coring may, in some special cases, be required. This is to help obtain a sample that has not been seriously invaded during the coring process. Handling and preservation of the core at all times, beginning at the well site, are equally important parts of the task. The advice of professional special core analysis firms can be very useful here. PERMEABILITY It is important to recognize that a high percentage of all standard core analysis values are the results of measurements conducted under bench conditions of temperature, with very little confining pressure on the core sample. When tested under confining pressure representative of in situ conditions, values determined on the same core may be reduced by up to three orders of magnitude. More commonly, however, the reduction is in the order of 30 to 40%. Since formation permeability is of first order importance in designing the required fracture geometry, it is critical to have valid in situ permeability data. The best source of such data is usually based on pressure build up behaviour. This is not to minimize the importance of having good cores. It is to suggest caution in the application of the results of bench condition core analysis. Pressure transient methods are by nature averages, albeit accurate averages. However, for definition of lithological changes within the averaged layer system, core analysis combined with log analysis can be very useful.

POROSITY Porosity is also affected by confining pressure, but to a lesser degree. Correlation with logs is suggested, as a means of determining the level of confidence one should place in either. In addition to being an important factor in reserves determination, porosity is a factor in determining the degree of control exerted by the formation on the leak off rate of the fracturing fluid. That, in turn, controls a number of other events including fracture growth and proppant placement.

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PETROGRAPHY AND LITHOLOGY Petrographic examination and lithological description of core sections will be of great assistance in determining the degree to which the rock may be sensitive to certain fluids. It also helps the frac designer to select the layers with varying rock properties for fracture modelling purposes.

SOLUBILITY Solubility testing of core samples helps determine if fines are likely to be released as a result of any acid based fracturing treatment, or pre-treatment. A body of work indicated that a complete chemical analysis of rock samples might provide significant information concerning the true proportions of clay minerals present. It may also be useful to those skilful in predicting the in situ creation of clays or alteration of minerals. Some investigators claim that these concepts may have a bearing on productivity following treatment.

X-RAY (XRD) X-ray diffraction examination allows the designer to have better information concerning the exact mineralogical composition of the materials comprising the rock. As above, this is useful in assessing the potential for sensitivity to fluids. Another type of analysis, based upon energy dispersive X-ray probe instrumentation, often associated with SEM equipment, enables only elements to be identified, and by relative amounts, minerals can be inferred.

SCANNING ELECTRON MICROSCOPY (SEM) Scanning electron microscopy is a very important addition to the tool kit of the fracture designer. Professional interpretation of images produced by this instrumentation enables the designer to determine the manner in which the various components, particularly clays, exist in relation to the shape and size of the pores, and to assess the potential for damage due to swelling or the release and subsequent migration of clays. It may also be used to examine the actual damage caused by tested fracturing fluids.

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FINES MIGRATION A test procedure has been devised to determine the interstitial velocity at which damaging fines migration can occur. For purposes of this discussion, one must remember that the term migration refers to movement of fine particles over short distances, perhaps measure in tens of microns. A fine particle need only move from a position of relative insignificance to one in which it is plugging a pore throat to be very damaging. Some excellent work has been done to indicate that this can occur in some rocks at very low velocities even when formation fluids are the flowing media. ROCK MECHANICAL PROPERTIES Several laboratory tests are useful in the prediction of fracture geometry. These include determination of Young's modulus, Poisson's ratio, shear modulus and fracture toughness. Actually, shear modulus is a relationship between Young's modulus and Poisson's ratio rather than a separate determination. Young's modulus and Poisson's ratio can be determined by conventional laboratory methods if the laboratory is equipped to measure axial load and axial and transverse deformation.

FRACTURE TOUGHNESS Fracture toughness is a special test to determine the resistance of a material to fracture extension. The test is described by Abou-Sayed, Brechtel and Clifton in the appendix to their paper. IN-SITU STRESS MEASUREMENT An additional test that is conducted in the field rather than in the laboratory is the determination of in situ stress magnitude by means of very small hydraulic fractures. The method, which is described in the literature, can be very useful in guiding the design of the treatment, where knowledge of the degree of containment of vertical fracture growth is important. Some data bases for certain areas have been published. Some service companies wisely maintain their own databases.

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RESERVOIR FLUIDS As with cores, it is often required that reservoir fluids samples be obtained under representative, controlled conditions at the wellsite. This aspect has been determined to be the most important in regard to testing of acid/oil reactions in areas where extreme sludge formation problems have occurred. In such instances, it was necessary to test the acid packages with the live, uncontaminated reservoir fluid at the wellsite before significant oxidation and light end losses had occurred. During fracturing, the reservoir fluid in the rock adjacent to the propagating fracture

Figure 6-23 In-situ Stress Measurement In Open Hole

must be displaced in order for fluid loss to take place. In the process, some mixing of reservoir fluid and fracturing fluid takes place. The mixing can create great problems or none at all, depending on the compatibility of the two fluids. A chemical analysis of the connate water, a hydrocarbon analysis of the liquid hydrocarbon, and a gas analysis are all helpful. Reservoir fluid viscosity and compressibility are necessary for proper design. All of these tests can be performed in a properly equipped reservoir laboratory (not all are properly equipped). Again, databases are maintained by some organizations to provide a basis for estimates. A very important test that, in the opinion of the author, should always be run is a carefully conducted fluid compatibility test in which fracturing fluids are mixed with reservoir fluids under reservoir temperature conditions, and subjected to a level of shear consistent with that which would occur during fluid loss from the fracture to the formation faces. The tendency to form emulsions should be noted. If completely clean breaks are not obtained in a few minutes, _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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consideration should be given to modifying the fracturing fluid composition. In addition to the possibility of forming emulsions, one should also test for the tendency for precipitates to form upon mixing of the fluids. Precipitation of asphaltenes can be easily triggered. A second aspect of compatibility is related to the mixing of waters. If salt water or seawater were used as the base fracturing fluid, it would be important to determine whether undesirable precipitates would result from mixing with the formation water. A complete water analysis of both waters would provide enough data for a water chemist to judge. Sometimes crude oil or condensate (not recommended, and in some areas illegal) from one reservoir is considered for use as a treating fluid in another formation. An indispensable test is to mix the two fluids at the appropriate temperature, and then centrifuge and/or filter the mixture, and observe.

FRACTURING FLUIDS When evaluating fracturing fluids, the quality of the source fluid should be checked. Crude oils should be free of suspended solids, and should be dry. Filtering and centrifuging should determine the quality. Waters should be clear and free of contaminants. Again, filtering and a good water analysis will provide the assurance required. For waters, pH is an important property and can affect gelling and gel-breaking effectiveness. Compatibility of the base fluids and reservoir fluids should be determined, as mentioned in the discussion of reservoir fluids. Acids should be pure and free from excess contaminants. “Pure” hydrochloric acid is clear. A brownish or yellowish colour indicates contamination by iron or other chemicals. Normally, HCl is delivered to the field with a pale yellow colour indicating the presence of iron from the

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supplier and/or service company piping system and storage tanks. Request a chemical analysis when in doubt. An important aspect of the base fracturing fluid is that it must be able to be effectively modified by the addition of various additives to result in a satisfactory fracturing fluid with the appropriate properties. For example, many crude oils and some refined products from some sources are difficult to gel. Only representative pilot testing will enable this to be pre-determined. Further testing will be necessary when the material has been delivered to the field to determine if there has been any contamination in handling and/or transit. Water in very small amounts can be a serious contaminant for some systems. The manner in which a fluid loss test should be performed has been previously described, and it should always be performed at reservoir temperature, unless a cooling preflush will be used in which case the proper temperature should be simulated in the laboratory. Recalling the discussion on proppant transport, we remember the importance of being able to determine the ability of the fracturing fluid to carry the proppant. The only reliable laboratory method so far devised develops a shear rate versus shear stress curve from which a consistency index and flow behaviour index is derived. These factors are then used in various equations for proppant transport, and for friction calculations. The next best approach is a research approach, which is accurate but requires large-scale pipe flow measurement equipment. Flow through parallel plates, to simulate fracture geometry, would be an even better system of measurement. Regardless of which of the methods is used to determine the indices, a further important consideration is to perform the test at the appropriate temperature conditions and with simulated shear history and to continue the measurements until a set of fracturing fluid rheological properties versus time is generated. This will be useful in modelling the process from beginning of injection until all of the proppant has stopped moving after pumping stops.

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This area of laboratory testing is still in need of improvement, especially for testing rheologically complex fluids such as cross-linked gels. Some work has been published in this respect and various laboratories have been and are continuing to work on the problem. Many of the instruments designed for testing non-Newtonian fluids simply cannot replicate conditions or perform adequately under simulated stimulation conditions or they can't properly handle the extreme apparent viscosity of cross-linked gels. Special equipment has been built and tested for this purpose, but except for full scale parallel pipe-flow systems, additional progress is needed. Substantial empirical and laboratory data has been developed and forms the basis of most simulator databases. The amount of residue that remains after the fracturing fluid has `broken' is of great importance and should be determined in the laboratory when screening various fracturing fluids. Laboratory and field experience has unquestionably confirmed that this aspect was unwisely ignored for many years. It is clear that residue from the gelled fracturing fluid or from the filter cake deposited by the fluid can and probably does remain in the fracture. As pointed out elsewhere in this course, damage in the fracture itself is far more significant in regard to ultimate reduction in productivity than damage in the matrix of the host rock. When one considers the relatively low magnitude of the differential pressure required to cause lifting of a filter cake from the fracture face, or movement of unbroken gel, it can be quickly realized that very significant impairment can occur. The damage is due to the movement of solids to areas where they can have a more significant damaging effect. Disappointing job results were (in the past) blamed on other factors. The correct approach is to take measures to deal with the described phenomenon. These measures would include more accurate determination and use of downhole temperatures for selection of gel concentrations and breakers, modelling of heat transfer effects during fracturing, minimization of the total amount of polymer pumped by use of tapered gel concentrations, and use of encapsulated breakers, all in an effort to eliminate unbroken gel or unbroken gel filter cake.

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In respect to the above problem, the author has published (Porteous and Delbaere, 1989) on his own experience in this regard, including a field case study of a large job in Australia wherein a 100% increase in post-frac production rate (determined by tests) was achieved after removing damage due to unbroken gel filter cake in the fracture. A very important consideration in respect to all laboratory testing of fracturing fluids is that to the fullest extent possible, the tests should be conducted under conditions similar to those that will be experienced by the fluid on the job. Time, temperature, confining pressure and differential pressure are all important. Interaction with formation constituents may also be a factor. For some aspects, so is the degree of shear. Recent developments in laboratory testing procedures has made use of dynamic tests to measure fluid loss, filter cake development and the clean-up cycle commencing with a determination of the threshold pressure differential required to initiate and then maintain flowback through the filter cake. Wise investigators would determine the threshold pressure for both broken and unbroken gel filter cake samples. The test conditions of differential pressure across a given length of rock should be compared to the differential pressure available in the actual formation per unit length of rock. Unrealistically high values of differential pressure have traditionally been used in the laboratories. The better independent laboratories are now using realistic pressures. In many of these tests, some fluids emerge well ahead of others. This can be a valuable screening method.

PROPPING AGENTS Propping agents should be sampled and tested in the laboratory on a routine basis to determine that the specifications are being met. The important items for routine quality control are particle size distribution, maximum per cent of fines, solubility, and presence of contaminants. On occasion, crush resistance tests should also be performed. Generally speaking, most of the available propping agents have been tested under realistic conditions by an independent laboratory funded by an industry consortium consisting of most

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of the key players and service organizations. The tests do not assure quality will be delivered in the field however. Consequently, field sampling and occasional quality checks are suggested. Various suppliers to the industry offer resin-coating technology. The use of resin applied to the surface of propping agent, either at the surface (common) or in situ after placement (rarely) can be helpful in reducing the amount of propping agent that is produced into the wellbore following placement in the fracture. While there has been some concern expressed regarding a possible reduction in permeability due to the volume occupied by the coating, the suppliers claim lab data does not support this. Data in the catalogues of modern simulators suggests that the resin-coated proppants have higher conductivity than the non-coated version of the same proppants under the same conditions. These data are available in the simulator database and can be easily viewed; either on the job or during a sales call on the servco representative's laptop, if he has the simulator on board.

CO-ORDINATED IN-SITU LABORATORY TESTING

A number of laboratories are promoting and offering very sophisticated laboratory testing programs under very closely simulated in situ conditions (Ahmed et al, 1979,). More recently, Bennion has written extensively on the subject. The basic elements of the program include a determination of the effects upon the fracture face and the effects upon the propped fracture conductivity of duplicating the time, temperature, fluid pressure, pore pressure, and confining pressure conditions, and fracture flow sequence. Interaction may be a key factor and is inherently evaluated due to the test design. The tests are described in the reference (Ahmed et al, 1979), and were the most representative known to this author at that time. They are not inexpensive, but neither is a mistake in the design of an expensive fracturing treatment. As mentioned, several laboratories are now capable of providing this and variations of this service.

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Figure 6-25 Interactive Test Set-up Figure 6-24 Interactive Test, Set-up

Fracture Face. (Ahmed et al, 1979)

Fracture Bed. (Ahmed et al, 1979) Even though it is not new, this reference is recommended reading. Discrepancy can occur if the damaging effects of the interaction of reservoir rock, reservoir fluid, fracturing fluid and proppant are not considered when predicting the results, and therefore the economics of hydraulic fracturing. Tests of this nature are almost a necessity for massive hydraulic fracturing (MHF) jobs. In fact, they should be considered whenever a substantial number of wells in a given reservoir will be fractured. Amortization of costs over a number of jobs makes the testing cost more palatable. Tests like this require careful attention to detail, beginning with selection of the samples to be tested and including such items as selecting test time periods (including loading rates) sufficiently long enough to yield representative, useful data. Generalized test times, volumes, and pressures set up to facilitate standard production line operations are simply not good enough.

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DEVELOPMENT OF BEST STRATEGY In this section we want to talk about the best strategy for design and implementation of a hydraulic fracturing job or program. We will assume that the decision has already been taken that fracturing (as compared to matrix acidizing, for example) is the preferred stimulation technique and that the risks are manageable. The first step, already taken is to identify whether the well is a candidate for damage removal or for stimulation or perhaps for both, with an off-ramp after damage removal. It is a candidate for damage removal if the information suggests that damage exists (positive skin factor), that damage removal alone may be sufficient to achieve the production rate objective (magnitude of the skin factor), and that an effective damage removal treatment can be designed, given the particular circumstances, type of damage and so on. If simple removal of damage (establishing a skin factor of zero) will not be sufficient to raise the production rate of the well to desired levels, then the efficacy of performing a damage removal treatment ahead of a fracturing treatment is a moot point. That is not to say that in such an instance, one should not use acid to assist in establishing a satisfactory injection rate and to help overcome NWB tortuosity. Ordinarily, it is a good idea to arrange for appropriately formulated acid (or other fluid) to assist in the event that establishing a satisfactory injection rate is difficult. There is little point in having to pay waiting time for very expensive equipment and personnel on location while waiting for acid to be ordered, loaded and delivered to location, especially when daylight operations are mandated. If a single perforated productive zone will be open in the well at the time of fracturing, then one must make the necessary calculations to decide whether to fracture through tubing and a packer, or whether the treatment can be conducted safely without a packer. If it is possible _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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to conduct the treatment without a packer, then there is a choice to be made between treatment down the tubing only, or down the annulus only or down both. Each has its advantages and disadvantages in respect to maximum pressure limitations, leeway between expected pressure and maximum pressure for any unanticipated pressure. For real-time monitoring purposes, the treatment that permits pressure monitoring through a static column is much preferred. In that instance, it may be advantageous to perforate the well a day or more before the fracturing treatment and to perform a breakdown, injection test and closure pressure determination also a day before starting the main fracture treatment. If satisfactory injection can not be achieved, the necessary remedial steps can be taken and if that fails, tubing and a packer can be used. For such situations, it is very expensive if the entire frac fleet and crew are on location when the problems are encountered. Ergo, the reason for doing the preliminaries a day or so in advance. In respect to perforating, there are many opinions, but evidence is mounting to support the use of a single, relatively short perforated interval for a single fracturing treatment. Multiple sets of perforations open at the time of fracturing may well lead to undesired events and undesired results. Some evidence exists to suggest that multiple, parallel fractures could result. This could have a very serious and detrimental effect on the execution of the treatment (very high pressures) and on the resultant geometry (much shorter fracture length than planned), and therefore on the post-job production rate upon which treatment economics are based. Since only a single set of perforations will be used, one must decide where the perforated interval should be. There is no simple answer to this. One could suggest that if there were a danger of breaking out of zone downward to water, it would be better to perforate near the top, away from the problem. Another criterion might be to perforate the interval that has the best reserves, on the basis that if, for whatever reason, that interval is not perforated and does not get stimulated, the job by definition will be a failure.

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As stated, the use of 3-D models and real time monitoring is assumed. Since these procedures are not without cost, it would be appropriate to maximize the benefit from the additional information. Since much of the data employed will not be from the subject well or will be the result of second or third order processing, it will be helpful to do as much calibration as possible using the subject well data. When employing today's onsite data processing systems, some pieces of information are of fundamental significance. Of these, the one with perhaps the greatest effect is closure pressure. Nolte-Smith log-log plots are commonplace tools for indicating the growth pattern of the propagating fracture.

i.e., whether the fracture is growing radially and confined to

the zone, whether it is growing both radially and vertically in a "penny" shape, or whether it is growing vertically in a catastrophic, uncontrolled manner, or indeed whether it has "stopped growing". The net pressure employed in the log-log plot is also used in the 3-D models as an output plot. Of course, net pressure must be calculated by the model, based upon input closure pressure data. The predicted net pressure graph is compared against the actual net pressure plot generated during the treatment. Variations from the predicted are evaluated for significance and it may be decided to alter the treatment program in some way as a result of such interpretation. Prior to the main treatment, many operators will perform one or more minifracs and other pumping tests to evaluate some or all of: Closure pressure Near wellbore pressure losses Rate of pressure loss due to leak-off to the formation using clear frac fluid Rate of pressure loss due to leak-off to the formation using gelled frac fluid Based upon the information so obtained, the office-designed fracture treatment can be redesigned using the newly obtained calibration information.

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This enables the fracturing treatment to be carried out after the design has been calibrated with site-specific information. The on-site (or satellite-connected) decision-makers are then in a much better position to react confidently to on-going developments. For example, if they have real-time bottom-hole pressure information that is direct (rather than inferred from surface indications in an active conduit), they may make the decision to terminate the treatment early if it is apparent that uncontrolled vertical growth is occurring, and that a screenout is highly likely. Such a decision is frequently made and in the process, many thousands of dollars have been saved by avoiding sand cleanout operations. In considering the risks to such a decision remember that the cleanout costs are immediately due and payable. The additional benefit from completing the larger treatment may not be realized for some time, possibly years and the lost value is in discounted dollars. Another application for the site-specific information is in managing the flowback rate and procedure. One option is to not commence flowback until closure has occurred, thereby minimizing (theoretically) the amount of frac sand produced back into the wellbore. Alternatively, flowback could be commenced immediately after pumping stops, if desired, but at a very controlled rate until closure has occurred, after which the rate may be increased moderately. One of the least-honored aspects of intelligent stimulation design is to properly define the objective in more than general terms. To state that the objective is to improve the productivity of the well by stimulation methods is a little weak. One should specify a measurable goal. For example: the objective is to stimulate the well to a production level of at least 25 m3/day after 3 months of poststimulation production, with job payout in less than 1 year and using a design optimized for best NPV measured on the first three years of post-frac production.

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To arrive at the actual design required to (theoretically) achieve the objective requires modeling of both the unfractured reservoir and the fractured reservoir. To determine the fracture treatment details, the reservoir parameters, and others, will have to be determined or estimated, appropriate fluids and proppants will need to be selected, mechanical well limitations considered, and a reasonable fracture design created, modeled, and adjusted. During this design activity, one of the important observations will be whether the model predicts that the fracture will propagate vertically and radially within the targeted zone, or if it will break out of the confined zone. Even if the model predicts containment, one must test the sensitivity to breakout due to a small overpressure. Further, the model-predicted containment requires verification by an actual field measured confirmation. Methods such as temperature logs, multi-isotope radioactive tracer logging, magnetic particle logging and other methods can be used. The use of PTA methods to analyze for fracture length should also be considered. All of the above methods have shortcomings and require cautious interpretation. If the risk is real, it should be recognized as such and the treatment either avoided or carried out cautiously, perhaps in modified form, with eyes wide open. Define the risks, constraints (frac to water etc.) Given the above, what needs to be done with what safeguards? One of the objectives of our business is to discover and produce the greatest amount of hydrocarbons in the most efficient manner, recognizing that there are long term and short term aspects to consider. This statement suggests the importance of imaginative conceptualizing and careful planning to achieve both the goals. This is as it should be. The use of planning and research methods integrated into everyday operations (some would say and vice versa) should result in continuous technical advancements. If properly evaluated and integrated into operations, these advancements should help lead to the achievement of

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some of the broader economic goals, which in themselves may be moving targets to some degree. Various companies approach this in different ways, but in the most effective cases, the use of an organized, planned approach is common. Flexibility, so as to be able to accommodate appropriate technical improvements is mandatory. This writer suggests that the initial well completion operation is so critical that all factors that might impinge upon its success should be open to review and input by the well completion designer and other members of the business unit team. Specifically, the writer suggests that the well completion engineer should be involved in the planning of the drilling program, so that his needs and concerns will be given due consideration. For example, the following items are all worthy of consideration even though not all items may apply in the case of any one well. For purposes of this discussion, the only aspects of the well completion that will be given consideration are those related to hydraulic fracturing of a single zone. Obviously, if complications such as multiple zones, provision for gas lift, and so forth are to be included, the list of considerations would become overly complex for the time available in this course. The size, grade, linear mass, and thread design of the production casing, and the design of the associated cement job may be determined by the requirements of the stimulation design. This may impinge upon other aspects of the drilling program including, possibly, the requirements for the drilling rig itself and the associated equipment. This would obviously be an unusual case, but that decision can't be made after the rig has already started drilling. The drilling program should also include provision for minimizing damage to the reservoir by selecting and controlling the drilling fluid such that the water loss is reduced to a reasonable _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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level, and so that the filtrate that is lost is of such a nature that a minimum of damage will occur. Also, by exerting careful control on the total hydraulic pressure exerted against the reservoir rock by the drilling fluid, considering both the hydrostatic pressure and the friction pressure due to circulation, the loss of whole mud to the reservoir rock can be minimized. Such loss, should it occur, can result in very serious, perhaps permanent damage. This kind of damage can also occur due to pressure surges caused by lack of care in controlling the speed with which drill pipe or casing is lowered into the hole. This concept is well known and well documented in the literature. The drilling program should also contain provision for obtaining data that may be required by or be useful to the completion engineer.

LOGGING PROGRAM In order to design the fracturing treatment, the completion engineer may require certain logs in addition to the suite of logs needed by the geologists. The logs which should be considered mandatory for the completion engineer include a suitable sonic log, a density log and a gamma ray log so that a suitable data bank of mechanical properties information may be constructed as the field is developed. This information will be very useful on the first well if in situ stress information is not available. Sophisticated 3-D simulators require the maximum possible definition of lithology in the layers from 50 metres (if possible) above the zone of interest to 50 meters (if possible) below the zone of interest. The number of lithological layers that can be entered into simulators like FRACPRO or M-FRAC is practically unlimited. The more accurate the definition of layering that can be obtained before the design, the better will be the final design and the closer will be the matched pressures.

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In addition, a calliper log and an acoustic cement bond log (as a minimum) will be necessary to assess the quality of the primary cement job, and the likelihood of maintaining the integrity of the cement job during subsequent high-pressure treatment operations.

CORING PROGRAM As a minimum, a coring program extending from two metres above the pay to two metres below the pay is suggested. This should provide the minimum required samples for laboratory evaluation, including fracture toughness tests, and moduli determination on the bounding layers for containment evaluation. Core samples should be available for porosity and permeability determination under in situ conditions of pressure. The core sample for the interactive tests of the fracturing fluid, formation fluid, proppant and reservoir rock are very important. This may be the most important use to which the core from a particular well may be put, especially for major MHF investigation.

DRILLSTEM TESTS Especially on early wells, formation tests should be conducted over the zone of interest in order to determine the in situ permeability-thickness product, damage ratio, or skin factor, reservoir pressure and to obtain reservoir fluid samples. This information will be very useful in determining the true capability of the reservoir to produce prior to stimulation. One of the key factors that will determine the usefulness of the test is whether sufficient time has been allowed for the various flows and shut in periods. It is very helpful to run a temperature recorder during the test in order to get perhaps the best reading of the reservoir temperature. The above suggestions, although quite conventional are not always employed.

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IN-SITU STRESS DETERMINATION As described earlier in this course, and in more detail in the literature, a determination of the minimum in situ compressive stress from at least three elevations is very useful and may be critical in some cases. The stresses should be measured in the reservoir zone, as well as in the zones that the designer expects will act as barriers to propagation of the fracture in the vertical directions. Recall that these determinations are best made based on interpretation of the pressure record of a micro-fracturing operation at each elevation. This operation may be carried out in cased hole or in open hole. Both have objectionable features which must be considered and plans must be made to accommodate the determination. The procedure in cased hole requires that a minimum of two extra sets of perforations be made. In most cases, it will be necessary to perform remedial cementing operations to seal off the unwanted perforations. The open hole procedure requires the use of open hole inflatable straddle packers. This introduces an element of risk, in that the packers could become stuck. There may also be a reluctance of the drilling personnel with respect to deliberately creating a series of small fractures in open hole. The data are extremely useful. By proper planning and communication, the objections can be anticipated and handled. Very accurate instrumentation is required for this kind of measurement, and the program should specify this item. This type of determination should be done with the assistance of experts in the acquisition and interpretation of such data.

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Some inferences concerning rock properties may be made on the basis of the examination of carefully obtained drilling data. Details concerning changes in drilling conditions such as hole sloughing, changes required in mud properties such as viscosity, density, details of fluid loss or fluid entry into the well bore and drilling rate changes may all provide clues as to the rock properties in situ. In addition to indications from any hole ovality, strain relaxation tests on oriented cores have been successfully applied to determine the directions of the major and minor horizontal stresses. Often this work is done in advance of the stimulation, and is sometimes confirmed, or otherwise, with tiltmeter surveys during the pumping operation.

CASING DESIGN As discussed briefly, the casing design may be very strongly influenced by the requirements of the stimulation treatment. Among the other factors to be considered, the designers (both from the drilling department and the completion department, if they are different) must consider the possibility that the casing may be subjected to severe thermal stresses, especially where liquid CO2 is used, and they may have to add strength to accommodate this factor alone. They should also bear in mind that the thermal stresses will be acting at the same time as the stresses induced as a result of the fracturing pressures.

CEMENTING The quality of the primary cementing job becomes very important whenever well stimulation by hydraulic fracturing is employed. A poor quality cementing job may cause failure of the entire completion. The important factor is that all of the mud must be displaced by the cement slurry and the slurry must be properly designed and mixed.

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Failure to obtain a high-strength cement seal across the barrier zones will probably be disastrous.

DATA EXAMINATION After collecting all of the data during the drilling operation and prior to the actual fracturing procedure, it is necessary to examine and manipulate the data so that the best information for proper fracture design will be available. The steps involved in the procedure will include the calculation of reservoir parameters such as permeability-thickness factor, reservoir pressure and temperature, and damage ratio (or skin factor) from drill stem tests. This is very important information, and it is critical for the user to remember that in this instance the information is obtained in situ, and is more accurate because it is deep investigating. At the same time, logs should be evaluated, along with cores, in order to provide the designer with a picture of the detail of the reservoir `fabric' including the heterogeneity. Values such as porosity and lithology from logs and cores may be correlated and any differences may be reconciled. Similarly, permeability from cores may be correlated to permeability from drill stem tests, especially if the core tests are done at in situ conditions. It is very important to arrive at an estimated effective in situ permeability for the reservoir that may be used as a starting point in the fracture design. The investigator should recognize that while it is not usual, it is not unheard of to have to correct (reduce) bench condition core permeability by one or two orders of magnitude in order to correlate to in situ condition permeability. A thirty to forty percent correction is very common. The degree to which the formation has been damaged should be calculated from the drill stem test data. This information will also provide a good indication as to what the reservoir productivity could be if the damage was removed.

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DAMAGE REMOVAL TREATMENT If the damage ratio is significant, the designer may want to consider planning a treatment to remove some or all of the damage. The design of the treatment will depend upon the nature of the damage, but will generally involve the use of a treating fluid that contains an acid, an organic solvent or a mud dispersant, with suitable non-emulsifying properties. There are exceptions to this and, the best information available should be used to select the proper damage removal treatment, being careful not to damage the formation by the treatment itself. The key to success is often related to the manner in which the job is designed and performed. Careful control of pressures and rates should ensure that the formation is not hydraulically fractured during the job. Failure to exercise such care may lead to portions of the formation not being sufficiently exposed to the clean up chemicals. A common procedure is to spot the acid with the tubing or coiled tubing located below the bottom of the perforations, so that the acid must flow past all of the perforations prior to being subjected to significant pressure. Following a gentle, staged-pressure wash, a small amount of fresh acid is usually squeezed in order to establish that communication has been created with the reservoir. If more than one set of perforations exist, it is usually beneficial to use a packer to selectively squeeze some of the acid into each of the sets of perforations. This helps to ensure that all sets are open prior to the fracturing operation, and that the fracture will have the opportunity to propagate in all sections. The desirability of having several sets of perforations exposed during fracturing is a moot point, as discussed earlier. In wells with existing perforations, it is a factor that must be considered. Special techniques (e.g. ball-off treatments with perforation ball sealers) are available for helping to make certain that all perforations are open prior to commencing the fracturing job. The acid that has been squeezed into the perforations could be produced, and an estimate of production rate could be made prior to the fracture treatment, if possible, in order to assess the pre-frac condition. At this point, the designer must decide whether additional treatments for damage removal are required, and whether fracturing is required. Generally speaking, if damage still exists, and if

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removal of the damage could obviate the need for a fracture treatment, it should be taken care of prior to proceeding with a fracture. One school of thought suggests that if the well will need to be fractured anyway, why bother with the damage removal effort. The reason for considering damage removal treatments ahead of a frac is that, depending upon the nature of the damage, the damage mechanism will probably not be removed by the frac. The damage zone will be penetrated and a frac driven through it. However, the damaging material, e.g. emulsion, may ooze into the fracture and subsequently impair productivity in the main connection from the reservoir. The decision to remove damage prior to a frac is a case-specific one.

SETTING OF OBJECTIVES

Once it has been decided that fracturing is likely to be required, the specific objectives of the fracturing treatment should be determined. Specifically, the approximate dimensions and major parameters should be estimated, based upon the productivity increase ratio that is desired. From that value and the use of very simple curves, the approximate fracture length, based upon reasonable conductivity values, should be estimated, considering the probable contained fracture height. That value may be estimated from the available rock mechanics data. This very rough guess as to the design outline should permit detailed simulator work to be carried out to determine what must be done to accomplish the overall goal of the fracturing treatment, and to optimize the treatment design.

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LABORATORY TESTING At this point, detailed specific laboratory tests can be conducted (or possibly the catalogue data can be used) that should result in the selection of the appropriate propping agent and the appropriate fluid. The tests would first screen the fluids to determine whether the less expensive ones like water could be used. The presence of water-sensitive clays and of particles that may be subject to dislodgement and migration must be considered. Unless these are present in significant quantities, they can probably be handled by use of adequate concentrations of potassium chloride (or other clay-swelling inhibitor) in the fracturing water and by means of fines stabilization chemicals in a pre-pad volume stage. If it is decided that a water base treatment should be considered, continue with the design. Ultimately, the final design fluid could be tested under simulated in situ conditions in complete interaction with reservoir rock and fluids to assess fracture face damage, and again with proppant added in order to assess residue damage to the proppant bed and the tendency for crushing or embedment. Prior to the in situ interactive testing, however, it will be necessary to determine the appropriate detailed composition of the fracturing fluid. Specifically, the amount of gelling agent, crosslinker, breaker, buffer, if required, clay swelling inhibitor, fluid loss additives (if any), low surface tension additive and any special additives. The composite fluid should be tested for viscosity and fluid loss behaviour under reservoir conditions, and these tests should be continued throughout the breaking period. Recall that the degree of proppant settling depends upon these factors, as does the rate at which fracture closure occurs. These data should be used to develop a closed-in time and flow back procedure that details timing, maximum rates and key observations that will be required. There are varying opinions and experience regarding shut-in time, flowback rates and the desirability of "forced closure". There must be a certain amount of on-site judgement exercised, but it will be better exercised if the person knows what he is trying to accomplish.

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At this point in the planning, the in situ laboratory tests could be conducted to determine fracture face damage and fracture flow capacity. The times, temperatures, core saturation, pore pressure, confining pressure and differential pressure, direction of flow and sequence of fluids should all be selected and scaled in accordance with job expectations.

SIMULATOR RUNS Following this work, the data could all be used in a simulator to design a series of job sizes so that the appropriate (optimized) job size may be selected, and so that the proppant concentration schedules may be modified to place the desired propped fracture bed in accordance with proppant transport characteristics. For these purposes, an estimate of the maximum permissible injection rate should be made, based upon the difference in in-situ stress levels, not just on mechanical limitations and on pumping power available. Once a design has been established, the entire program can be simulated in a threedimensional simulator to evaluate the time-stepped growth of fracture geometry, particularly the length to height ratio, and the degree to which the vertical growth of the fracture is not optimal. This may indicate that greater or lesser injection rates and/or viscosities are required. It may occasionally indicate that economically successful fracturing is not technically feasible. Simulation of the unfractured and fractured reservoir performance can then be compared to predict the productivity improvement, and the treatment can be further optimized on the basis of simple economics, for example net present value of the investment. A demonstration of the use of a current simulator is part of this course.

ECONOMIC PRIORITIES AND CONSTRAINTS Obviously, the sizing of the job will be influenced by the economics. Optimum size will be the size that returns maximum economic value while achieving the overall objective.

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Many factors will influence the details of the final program and it would be impossible to discuss all of them here. However, in a general sense, the above approach is a useful way to organize job design beginning with the drilling program. With respect to the decision as to whether to stimulate or not, and the choosing of the most economically attractive option, some guidelines can be given. The objective is to make the correct economic decision. The first given is that the cost of property acquisition and drilling operations up to the point of the actual completion should not be factored into the cost of all the frac options. These costs have been "sunk" and are not recoverable under any applicable scenario, except perhaps from a new buyer of the property. The costs in each of the options that must be compared include only the costs related to the completion that have not yet been spent at the time of the economic comparison. These would include, but not necessarily be limited to: •

Cost of fracturing base fluid, including transportation and storage

•

Cost of all chemicals, proppants and other materials

•

Cost of all service company equipment, including service, transportation, extra time

•

Cost of rig and other equipment (e.g. safety) necessary to prepare the well before and after the treatment

•

Cost of all personnel related to the completion, including supervision

•

Cost of all overheads as related to the completion

•

Cost of lease preparation before the completion and lease cleanup afterward

•

Cost of environmentally and legally acceptable disposals.

On the revenue side of the ledger, one must value the additional oil recovered. One can also value the accelerated production. This is not often done, because the accelerated production

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resulting from the same ultimate recovery is usually considered as additional since the last volumes recovered are so far in the future that their present worth is very small. To enable this to be done, a proper pre-job production analysis should be done to identify the correct decline and consequently the correct forecast of unfractured production. Appropriate costs of operating the wells need to be known and taken into consideration. The time value of money also needs to be estimated and factored in.

JOB OPERATIONAL PLANNING When a final design has been decided upon, and no doubt the service company will have become involved by then, a meeting should be set up with a responsible service company representative, someone with operational authority, in order to discuss the objective of the entire operation, and therefore the importance of each component in relation to the whole. The entire procedure should be reviewed in detail, including plans and assignments for quality control, verification of quantities, sampling, data acquisition, safety inspection, and well-site authority, in addition to the technical details of the job design and execution, including what-if scenarios. Discussion should be invited from the service company people to be sure that they have had a chance to express their concerns, if any, as well as to provide them with an opportunity to make helpful suggestions. In many cases, operating companies have developed "alliance" relationships with one or more service companies. In such cases, the above scenario should happen routinely.

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JOB EXECUTION During the job, the treatment should be conducted exactly as planned, including all of the quality control checks and all of the planned data acquisition. In particular, all planned sampling should be done, and all measurements recorded as planned. Nothing should be taken for granted. In order to facilitate analysis of the data after the job, all clocks and watches should be synchronized before the job during the tailgate safety meeting, and all samples should be labelled as to the time taken, as well as other identifying data. All noted and recorded events should have the time noted. It is not unusual for events to occur which make on-the-fly decisions necessary. Again, it is not possible to detail all possibilities here, but the best decisions will probably result if the person who has been responsible for the design from the beginning is also on the job. His knowledge of the reservoir, the likelihood of containment, his analysis of the quality of the cement job, and the details of all of the laboratory tests should enable him to make the best judgement as to what is actually happening. In the light of his judgement and advice, the well owner's operations supervisor and the service company person in charge can take the appropriate operational action. In the event that the person most involved in the design is unable to be physically present on the job, satellite communication of monitor data to an offsite monitor, perhaps hundreds of kilometres away can be arranged with direct voice communication to the field control unit. One could reasonably expect that the service company person in charge would be able to provide top advice, based upon his personal experience in the area. However, occasionally servco personnel are mobilized from another station or camp and they may have little or no direct experience with the local formation. Regarding on-the-fly decisions, Nolte's papers are recommended reading, since they discuss interpretation of pressures during treatments.

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POST JOB PROCEDURE Following the shutting down of the fracturing pumps, there are a number of important considerations that we should discuss. The pressure recorder should remain connected to the well pressure, so that the rate of pressure decline may be monitored for up to twice the pumping time, or until closure, whichever occurs first. Also, the rate at which the pressure declines following the instantaneous shutdown event is a good indication of fluid leak off rate from the fracture, and may help govern the flow back procedure. In some cases of slow bleed off, it may be advisable to almost immediately bleed off fluid at the surface at a rate that is less than the critical sand transport velocity. This should help relieve pressure in the fracture and hasten the time at which the fracture would have healed enough to prevent further proppant settling. However, this concept and its variations are in the area of controversy, especially in view of theories related to the role of convection in proppant distribution and settling, and the implications thereof. It is important that samples and notes should be very complete during the flow back period. The recovery of all liquids and solids should be measured and recorded at frequent times. Samples should be taken at these times and observations concerning the visual appearance of the samples are extremely helpful in the analysis of the job. This is particularly true if the analysis is done some time after the completion of the job when memories are poor. A temperature log run at the appropriate time soon after pumping stops should help identify the vertical extent of the created fracture in the vicinity of the well bore. Radioactively traced fracturing sand is also useful for locating the propped height. If sand is radioactively tagged, it should be the same size as the sand that it is mixed with or separation due to particle size may occur during proppant settling. Frequently as many as three radioisotopes have been injected consecutively during a single stimulation in an attempt to determine fracture height at the

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wellbore and proppant location at the wellbore. One method is to tag the pad fluid, the first half of the proppant and the last half of the proppant all with different radioisotopes. Following recovery of all load fluids from the well, and after a relatively steady production rate has been established, a properly designed pressure build up test should be conducted, and interpreted, possibly employing type curves, derivatives and so on, to estimate the in situ fracture parameters which may then be compared against design values.

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BEST DESIGN USE OF 3-D SIMULATORS

The use of simulators in the fracture design phase involves several aspects. 1.

To test a design to see if it can achieve the desired results

2.

To test a design to see if it can avoid the risks

3.

To test a design to see how sensitive it is to changes in either the given information or the design variables

The commonly used 3-D simulators, M-Frac and FRACPRO, and others, can be very useful for prediction of the geometry and conductivity of the propped fracture. Of course, the accuracy of the predictions is highly dependent upon the accuracy of the input data as well as on the model assumptions. Unless verification of the predicted fracture geometry, height in particular, is done, the model may go on predicting incorrectly through many applications. However, if verification indicates the model predictions of height are correct, then the model can be of paramount assistance. It should enable the designer to determine if in fact the economic objectives of the stimulation can be achieved. It may also be useful for assessing the degree of risk associated with the treatment, particularly in regard to loss of containment and subsequent results, such as fracturing to water. One application in the author's experience is in using the model to predict whether two zones separated by a barrier could be fractured simultaneously without communicating to water which was located below the lower zone and separated from the lower zone by a thin barrier. The question arose during a course presentation for some overseas clients from North Africa. . An (interpreted) combination log was available to enable a lithology profile to be approximated and rock mechanical properties to be inferred therefrom. The rock data was then plugged into the model and various runs were made to determine the ability to create a fracture that encompassed both zones but did not go to the water. Several runs _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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were also made to indicate the sensitivity to changes in injection rate, frac fluid viscosity and treatment volume. The model was then run, for the case of individually fractured zones, with the lower zone treated with a much less aggressive treatment. The end result (theoretical) was that the best approach would be a two-stage segregated treatment involving a separate design for each zone. This was because the treatment required to fracture both zones simultaneously would also very likely penetrate to the water. Unfortunately, we do not yet have follow-up knowledge about whether a treatment was carried out in the field, and the result.

FRAC MODELS, DATA ACQUISITION AND MANIPULATION

Since there is such a wide variation in the sophistication and complexity of fracture design models, and since most service companies employ one or more of three common simulators, it is deemed reasonable to at least mention the availability of the other models.

Numerous simulator models have been created to describe the hydraulic fracturing process. The reference section of this manual contains references dealing with many of them. As of this writing, one of the most, impartial and concise comparisons is contained in Warpinski et al, February 1994. His article compares a selection of models of various complexities on the basis of real case data response comparisons set up by the Gas Research Institute. This article is recommended reading in its entirety, along with the accompanying commentary (Cleary, February 1994). The articles are drawn upon extensively for the following discussion. Readers are asked to recognize that nearly all models have undergone, and continue to undergo updating and new versions offer new features and/or improvements to the older ones. The generalities of Warpinski's comparison still apply.

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Fracturing models may be classified in groups of approximately equal declining complexity. 1.

Planar 3D models: TerraFrac, by TerraTek Inc. HYFRAC3D, by S.H. Advani

2.

GOHFER, a unique finite-difference simulator from Marathon Oil Co.

3.

Planar pseudo-3D models: A.

Models using the "cell" approach: STIMPLAN by NSI Inc. ENERFRAC, by Shell TRIFRAC by S.A.Holditch & Associates, Inc.

B.

Models employing overall fracture parameterization: FRACPRO by Reservoir Engineering Systems (RES), Inc. MFRAC-II by Meyer & Assoc.

4.

Perkins-Kern-Nordgren (PKN) and Geertsma-deKlerck (GDK) models: PROP by Halliburton Chevron's 2-D model

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Conoco's 2-D model Shell's 2-D model Pseudo-3D models run in constant height mode A description of each of the model types, as provided by the suppliers, is given in the Warpinski paper. The designer of a stimulation treatment must realize that the most important contribution he/she can make is to make use of/honour all the available knowledge to: a) design, and b) execute successful (meaning most profitable for the oil company) well stimulation. This implies that, in order for the person who is best informed with respect to the design decisions and reasons behind the decisions to be available for all-important on-the-fly decisions during field execution, the designer must go to the field for the implementation. An acceptable alternative is for the real time field data to be transmitted live by satellite to the location of the designer, who must also be in voice contact with the key personnel in the field. Further, the instrumentation, software and skills in the field must be sufficiently adequate to enable very rapid and proper decisions to be made and implemented while the job is being pumped. Implicit in this is that, especially for very large treatments, the what-if portion of the software/computer system will be faster than real-time and thus enable predictions/changes to be made on the fly. Most decisions in the field will be guided by an interpretation of the meaning of changes in the net pressure (pressure at the entry to the fracture minus the closure pressure). Therefore, unless a static column pressure is available, accurate fluid/proppant friction correlation data must be incorporated in the database so that, even under conditions of constantly varying density and injection rate, the field computer can convert input data from surface pressures to bottom hole pressures. Of course, if surface indication of pressure _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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measured at the bottom of the hole were available, this would dramatically improve the accuracy of the analysis of net pressure. The next best compromise is to have tubing in the well and pump down only the tubing or only the annulus with the other conduit full of fluid, but static. The static column can then be used to measure bottom hole pressure directly, correcting only for (constant) hydrostatic head. One must use the data that is available prior to going to the field to initially design the treatment. Then field-obtained data, such as is generated on a small, unpropped frac (minifrac or data frac) pumped ahead of the main fracture may be used to redesign the main fracture on site taking into account the parameters calibrated from the small fracture (minifrac). The redesign would include a prediction of net and surface pressure performance during the main fracture treatment. A typical treatment recording would include: Pre-job pressure test Minifrac 1 for closure and kh with thin fluid Minifrac 2 for fluid loss from gelled fluid Main frac, with pressure matching during the main frac Post frac pressure decline over a significant time period The main frac would be performed with real-time monitoring. The monitoring of the main treatment would identify actual pressure variances from the predicted. This would, ideally, then enable (for larger jobs) additional parametric changes to be identified, incorporated in a design change (possibly modelled for verification in much-faster-than-real-time), while the job is being pumped, and the changes incorporated in a revised job design while it is still underway. Of course, for very short duration treatments, there may not be sufficient job time to run a simulation to determine effect. An intuitive revision, based upon an understanding of the reasons for variance, may need to be implemented.

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In addition to a skilled designer who can interpret the meanings of the pressure variances, an important requirement of the operation is that the model must be accurate, versatile and userfriendly. Less sophisticated models are available, as previously indicated, and they may have some value for simplistic designing and monitoring. However, if the real objective is to improve the cost-effectiveness of well stimulation, then the models employed, and method of employment can be crucial. Similarly there are more sophisticated models available, some of which do not lend themselves well to on-the-fly changes. Ultimately, there is little doubt that the most effective results will be achieved by those firms that insist on focussed teamwork involving both the design and the execution teams. Their ability to make appropriate on the fly optimization changes can result in very significantly better results. History matching, where possible, should always be done to validate parametric data for use on future designs, thus applying the science costs to improving efficiency. There is a considerable amount of author-pride in the various models. Ultimately, the designer must remember that the objective is to make wells more profitable. Any activity, data set, or software aspect that does not help to efficiently achieve this goal must be reconsidered and possibly replaced by a better activity, data set or software. One of the features of the more sophisticated models is that they require a considerable amount of data to fully realize their special capabilities. Some of the data may, in some instances, be either difficult to obtain with reliability, or expensive to obtain. Some methods for determining these values have been developed, but may have significant shortcomings, such as investigation limited to very close (centimetres) to the well bore. To use these data could lead to misinterpretation of far field effects.

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There will continue to be improvements in data quality, model sophistication and flexibility as well as designer skills. One of the mentioned uses of models is to help determine if risks can be managed satisfactorily. One of the risks that designers frequently face, and which has been mentioned several times in the course, is the risk of fracturing out of zone, possibly causing water production to occur. Generally, the prime factor that works in favor of maintaining containment is stress contrast. That is, the stress in the barriers is significantly greater than that in the target zone. If the stress contrast is minimal, the factors that could cause loss of containment, primarily viscosity and pumping rate, become far more significant. The model can be used to test the sensitivity to slightly greater values of rate and/or viscosity to determine the "safe" working envelope. An additional check would be to examine the sensitivity of the model to different levels of stress from those assumed or calculated. If the model indicates that a slight increase in viscosity or rate or a slight change in rock stress could make a difference, the designer may want to design away from trouble, by using a lower viscosity and rate.

ANALYSIS OF PRESSURE DECLINE CURVES AFTER INJECTION:

A number of important parameters can often be determined relatively accurately by careful application of several methods for analysis of pressure decline after pumping. These include: •

Total fluid friction losses during pumping

•

Pipe friction that occurs within the tubular conduit from the pressure sensing device to the entry of the perforations

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Perforation friction, representing the loss in pressure caused by flow through the perforations themselves

•

Near wellbore friction, representing the friction caused by a variety of near wellbore effects other than the perforation holes

•

ISIP, the pressure immediately after pumping stops, usually assumed to represent fracture extension pressure

•

Closure pressure, representing the pressure magnitude at which the walls of the closing fracture have begun to interfere with each other.

•

Multiple closures, meaning when more than one closure event is recorded. This could represent two or more of the principle stresses being reflected.

There are terms, which have become common, used to describe the operations for obtaining some of the data: Microfracs refer to pumping operations of a small scale designed to determine the in situ stress that exists at one or more layers. The pumping rates are generally rather low, less than 1m3/min. Very accurate pressure recording instruments and accurate volumetric pump rate recording equipment, preferably on the same chart or disk is required. Minifracs or Datafracs refer to larger scale operations conducted either the day before or earlier on the same day as the main stimulation operation. These pumping operations are carried on at full-scale pump rates. The purpose is to determine or confirm certain information that had to be assumed for the design of the treatment. Subsequently, if necessary, the treatment design would be modified in the field to accommodate the new, accurate data.

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ECONOMIC OPTIMIZATION A useful feature of 3-D simulators is the ability of the simulators to compare several sizes of treatment on an economic basis to select the one with the best value. There are many economic criteria that companies may use for comparison and selection. A popular one is net present value. After all of the injection rate, fluid and proppant selection decisions have been made, or assumed, the model can be used to estimate the geometry, proppant distribution, and conductivity. The production model can then estimate the improvement in recovery rate and cumulative incremental production associated with the design. Then a series of jobs of larger and/or smaller scale can be modeled. The resultant production improvements can be forecasted for each case. The cost factors associated with the stimulations can be input and the improved future production can be valued using the oil company's forecasts of price, interest rate etc. From the resultant data a best treatment size can be selected that would yield a satisfactory (not necessarily the greatest) NPV as well as meet other company economic criteria, such as pay-out time for the investment. As with all such selection methods, the accuracy is only as good as the accuracy of the forecasted commodity prices, interest rates and other market factors. For the model to operate effectively, a considerable amount of economic and cost data is required. Much of this, such as job-size-related stimulation costs will be available from the service company and some, like production operating costs, oil price forecasts, discount rate employed in company economic models and so forth, will have to come from the oil company itself. .

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OPERATIONAL PLANNING & GUIDELINES Operational aspects of hydraulic fracturing treatments are very important due to a number of factors including high pressures, expensive services and materials, large number of personnel, and the potential for significant harm to the well in the event of unforeseen or unplanned for developments. Regulatory and company rules, guidelines and policies for various local and international jurisdictions may or may not be in place to cover the various possibilities. Obviously, such rules will take precedence over what is said here. For convenience, we have divided the topics for discussion into chronological groups of topics Job planning Cement quality evaluation Logs available? Quality? Consider vertical growth may reach top of cement - possible collapse if annulus not internally pressured adequately Activities since cement quality logs were run Subsequent activities may have affected cement job effectiveness What can be the worst effects of a failed cement job? Condition of casing: Especially in older wells or in wells in which considerable activity (drilling, completion, workover) has been conducted since the casing string was installed. Also where known external casing corrosion exists. Casing Inspection Log Limit allowable pressure to 80% of burst (based upon published engineering tables), for new casing - less with older or suspect casing. Pressure test-casing if possible. May need to use a packer and backup pressure unit

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How much equipment of all kinds will be on location? Will this require extra safety services? Is there room, considering regulatory and company on-site spacing requirements? Will service company abilities be compromised by set-up requirements dictated by location constraints? Is the ground strength adequate, especially for upright fluid storage tanks? Is the tank area bermed for spill containment? Are access roads adequate for the equipment? Does the geography (e.g. closed valleys) present safety problems in H2S areas? What is required by regulators and good practice? How much time will be required to haul and load the necessary fluids after tanks are in place? How much time will the service companies require to assemble, transport and position their equipment and materials? Arrangements for flowback fluids capture, storage and disposal. Flowback operations When to start What flowback rate schedule to follow Monitoring of sand return Planning for sampling of returns Pre-job-day site activities Site preparation and inspection by Service Company Tank inspection, fluids delivery, filtration, tank-loading Well operations to remove/install necessary equipment Tubing replacement and cleaning Well head equipment inspection, change-out (if necessary) Cleaning of well bore and replacement of existing well fluids with filtered fluid

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Early job day site activities Quality control/ check lists/ tests See check lists at the end of this sub-section. Safety checks and meeting Pressure testing of surface lines, valves and equipment Minifrac operations and data acquisition Breakdown, injection rate ISIP Closure pressure Decline rate compared to model-predicted rate Data interpretation and redesign activities Adjust permeability in model to get a match in fall-off rate Adjust fluid leak-off characteristics to get a match in gelled fluid leak-off rate Interpretation of any remaining discrepancies, such as NWB friction Redesign to account for all of the above and to provide a predicted net pressure for monitoring and control purposes Main frac activities Overall observation for leaks Observation of excessive vibration Observation of activities such as tank switching, proppant flow, blender operation, dry and liquid chemical addition, nitrogen or carbon dioxide addition, pumping equipment performance Fluid sampling at the blender on-the-fly Overall indicators (pressures, rate) actual versus planned, variances and reasons therefore. Availability and readiness to make on-the-fly decisions and communicate these to the fracture service company operator-in-charge _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Post frac activities Post-pumping data acquisition Pressure bleed-off and flowback operations according to pre-planned schedule Equipment release and removal from site

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DECISION TREE FOR ON-THE-FLY USE. One of the distinguishing features of hydraulic fracturing treatments is that once they commence, they generally are rather fast-moving. When a decision is required, there is not much time to consider the alternatives. For this reason, it is helpful to think about the whatifs in advance so that reasonably good decisions can be made quickly when required. Some of the situations that require decisions include: -

Service company equipment may not be properly assembled in accordance with accepted safety standards, e.g. no hose-covering blankets to contain spray on acid or hydrocarbon pumping jobs.

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Surface lines do not pressure test perfectly

-

Formation does not break-down easily.

-

Pressure to inject after breakdown is higher than expected.

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Closure pressure is not clear following a pre-job pump-in and flow-back at constant rate test.

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Pressure decline following first (ungelled fluid) stage of the minifrac is more rapid than model-predicted.

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Pressure decline following second (gelled fluid) stage of the minifrac is more rapid than model predicted.

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Near well bore (NWB) tortuosity (as inferred from the real-time data) is evident.

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NWB tortuousity is greater than acceptable.

-

After pumping begins and after proppant begins to enter the formation, the plot of log net pressure versus log time changes from a slope of 1:2 to a slope of 1:1.

-

Once pumping begins a higher than normal pressure seems to be developing based on surface pressure readings of a dynamic (not static) column

-

Once pumping begins, slope of the log-log plot changes from flat or positive to distinctly negative.

-

Once pumping begins, slope of log-log plot changes from flat or positive to distinctly negative and then to positive at 1:1 or greater.

-

Increasing annulus pressure is observed when fracturing through tubing with a packer.

Examples of other considerations: -

What happens if the resin coated prop has not reached the formation yet and the slope turns negative?

-

In general, what to do if a screen-out to maximum pressure occurs Flowback and repressure? Shut-in under pressure and let it bleed-off to closure pressure? Start forced closure (may already be closed if fully packed to a tip screenout)?

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If job proceeds normally to end of displacement, displace to an agreed amount (usually 0.5 m3 short of calculated volume to top of perforations). For data interpretation purposes, continue to record pressure at least until closure and preferably for twice the pumping time. Decide on, and specify a flowback procedure including when to begin and the initial rate. The rate should be moderately increased as pressure declines, especially after closure pressure has been reached, and the flow should be monitored for indications of returning sand.

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ON SITE USE OF 3-D SIMULATORS Most service companies have the ability to supply computer-equipped vans on-site with the capacity to measure and record a large number of treatment variables. Many of these vans are equipped with computers loaded with 3-D simulators similar to the ones used to create the treatment design. Besides the ability to display job variables in a number of interesting presentation formats, the simulator can be used to process and re-process data on location. This allows many pieces of assumed information to be validated on site. One common and simple application is to use the on-screen plotting capabilities is to help ascertain the closure pressure after the first formation breakdown. Others are Compare plots of the leak-off period after short pumping times (for clear fluids) against the computer predicted plot to calibrate actual formation kh versus assumed kh. Similarly, using gelled fluid, calibrate actual non-Newtonian behavior versus that which was predicted based on catalogued fluid performance information. Using the calibrated data, recalculated the treatment to develop new predictions of net pressure versus time for the main frac, as well as other information using the new data. For example if there is concern about the possibility of extending the frac out of zone and perhaps to water, one can measure the effects of the newly developed values by viewing screens which show the time-steeped fracture growth in three dimensions. One can also perform a series of checks at the beginning of the treatment to estimate the magnitude of perforation friction and other near wellbore restrictions.

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During the treatment it is almost standard to have one screen display a log-log plot of net pressure above closure pressure versus time (Nolte-Smith plot). Seasoned observers use this plot to monitor the pattern of growth, and particularly to identify if rampant, relatively uncontrolled vertical growth is occurring, as indicated by a negative slope. Normal, contained radial fracture growth is usually characterized by a relatively constant positive slope. If the fracture should stop growing radially, as indicated by a zero slope, the observer will watch for the first indications of the next slope change. If it is steeply positive, he may call for an end to proppant addition and commencement of the displacement period. If the steady positive slope should increase to a significantly higher (double) value, it is likely an indication that fracture growth has become restricted and that, since proppant and fluid are still being injected, the pressure will increase more dramatically. Eventually, and probably soon, the maximum permissible pressure will be attained, and the job will be terminated, probably necessitating a clean out of the undisplaced proppant. Besides the log-log plot many observers prefer to view a plot of the predicted net pressure on the same screen and scale as a plot of the actual net pressure generated during the treatment. This plot may then be used for early identification of variances. Possible causes of the variances can be considered and perhaps appropriate action can be taken. On occasion, the minfrac and other pre-mainfrac pumping operations indicate unusually high pressure. The simulator's capacity to model several different scenarios (e.g. the creation of multiple fractures rather than a single fracture) can be very useful.

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FRACTURE DIAGNOSTICS Usually one diagnoses problems, and one does not usually diagnose success. Therefore, the reason one engages in diagnosis of fracturing treatments is that the treatment did not achieve its goals. One of the more obvious reasons why the goal may not have been reached is that the fracture was created in a shape of a location different from what was predicted. Most diagnostic efforts, then, are aimed at attempting to ascertain the geometry and location of the created fracture. One characteristic of hydraulic fracturing for oil and gas field purposes is that we are unable to obtain a direct measurement of the geometry of the fracture we created. We must therefore rely on indirect measurements to piece together the probable solution. There are a few fundamental aspects of the created fracture shape and location that are important to know.

-

Horizontal, vertical or inclined?

-

Azimuth, if vertical

-

Dip, if horizontal

Location of the top and bottom of a vertical fracture and the distance between the wellbore and the tip of the fracture. Location of the portion of the vertical fracture that is propped, and the adequacy of proppant concentration throughout its height and radial extent. Location of the horizontal fracture at the wellbore

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Propped thickness of the horizontal fracture at the wellbore and throughout its extent. None of the above variables can be measured in the field with absolute certainty. However, there are a number of methods, which individually or in combination can provide good indications. Each also has its limits which must be recognized. An excellent summary paper, with good references, (Warpinski, 1996), described the state of fracture diagnostics at the time. The main tools that are in relatively wide geographical use today are: temperature logs, multi-isotope radioactive tracers, and in some areas, surface and downhole tiltmeters and microseismicity interpretations. All have their individual limitations and their individual corps of detractors. The paper describes the methods and limitations. Since none are absolute, other corroborative evidence is very valuable. Taken together, the evidences can be convincing. In this part of fracturing technology, one thing is clear. A mass of evidence is better than very limited or no evidence. However, the opportunity to gather meaningful evidence is fleeting and one must make a concerted effort to capture information at the time that it is available. This is one reason why it is so important to detail the activities to be carried out and the information to be gathered well in advance. A simple example: If it is desired to use temperature change to determine where treatment fluids have been injected, it will be necessary to have a pre-injection natural temperature gradient determined. Naturally, this must be done before the pumping job. Also, arrangements must be made to log the well as soon as possible after pumping has stopped in order to record the temperature changes before dissipation has progressed too far. Underdisplaced sand in the tubing can certainly interfere with getting a logging tool safely in _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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and out of the hole. So arrangements must be made to circulate any settled sand out of the hole immediately after the frac job. This may require special equipment and careful procedures. There is little advantage to waiting until unsatisfactory results are obtained (much less oil than expectations, or often, more water than expected), to decide that it would be convenient to know why the job failed. Without evidence to support or refute ideas, one theory is as good as another. There have been a number of papers written which show how pressure transient analysis can be used, with assumptions, to estimate the length (or half-length as some would prefer) of a created fracture. While helpful in their present form, many of these methods would be more useful if they would accommodate a fracture map wherein the conductivity of the fracture could be varied throughout its area. The fracture models are reaching a level of sophistication whereby they can create the information to put on the "map" (with, perhaps, a little adjustment).

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REAL-TIME AND POST-TREATMENT DIAGNOSTICS FOR CONTINUOUS IMPROVEMENT One of the major challenges in well stimulation is to measure the effectiveness of stimulation treatments to continuously improve the results until a satisfactory level of optimization has been achieved in the area. Some of the questions that we would like to answer are:

• • • • • • • • • •

Do fractures effectively cover the pay zone? Are fractures confined to the pay zone? Does the fracture grow into an unwanted gas bearing or water-bearing zone? What is the optimum number of fracture treatment stages and treatment size to cover thick pay zones? How much more length/height/production is obtained if treatment size is increased? Is the final fracture conductivity sufficient to achieve the desired production? What is the optimum proppant? Is the hydraulic fracture oriented in the same direction as the primary set of natural fractures? What direction should a horizontal well be drilled to complete it with transverse (or longitudinal) multi-stage fracture treatments? Is the well pattern appropriate to maximize sweep efficiency in steam/water-flood areas? Do the injected waste and drill cuttings remain within the selected zone?

An array of methods is available for helping to gather data that may be useful in the diagnostic process. These include: - net pressure analysis (Nolte, Smith) to determine fracture parameters - multi-isotope radioactive tracing to help determine fracture height and possibly number of fractures - temperature logging to help determine fracture height - production logging to determine production intervals and fluid properties - well testing to help determine effective fracture characteristics - borehole televiewers to indicate fracture trace at the well bore - borehole image logging to indicate fracture trace at the wellbore - caliper logging _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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- microseismic mapping techniques to help determine azimuth and dimensions - surface tiltmeters to indicate fracture azimuth and length - downhole tiltmeters to help determine fracture dimensions, particularly height Representatives of Pinnacle Technologies have categorized and described these methods in SPE 59735. Some of the comments in the following paragraphs borrow from that paper. The various techniques for fracture diagnostics and/or mapping can be categorized as follows: Indirect methods including: Net pressure analysis Production analysis Direct, near-wellbore methods, including: Production logs Radioisotope tracers Temperature logs Borehole televiewers Borehole image logs Caliper logs Direct, far field methods, including Surface tiltmeter maps Downhole tiltmeter maps Microseismicity Please refer to the figures at the end of this section, also from SPE 59735. The authors classify the relative abilities of the various methods to determine important parameters according to the following table. It is suggested that the full paper should be read for a more complete explanation. In addition to the classification, the paper also presents a number of case histories of varying situations to support their position.

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This chart, by Pinnacle Technologies, provides a guideline for the types of measurements

and degree of uncertainty that each method can provide. parametric uncertainty.

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This diagram shows schematically the arrangement for using downhole tiltmeters in an observation well.

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Microseismic signals can be captured and resultant maps can help indicate important fracture dimensional and directional parameters.

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Surface and downhole tiltmeters can be employed to help determine fracture dimensions and orientations.

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OCCURRENCE OF SIMULTANEOUS MULTIPLE HYDRAULIC FRACTURES Numerous papers have been written and numerous unreported anecdotal experiences have suggested that multiple hydraulic fractures can be generated, and multiple natural fractures can be opened simultaneously during injection. The implications of these phenomena on hydraulic fracture operations and on post-treatment well performance (or lack thereof) are most significant. The occurrence of multiple hydraulic fractures where only one is designed obviously affects the geometry of the resultant fracture(s), even if (fortuitously) all the proppant is placed. This geometry change affects the post-frac production, probably unfavorably, mainly because the fracture radius in situations in which more than one fracture is generated will necessarily be shorter than when a single fracture results. Further, the fractures must compete for fluid and the rate of injection into each fracture will be less. At the same time, when multiple fractures are parallel and at approximately the same depths, rock displacement is made complex by offsetting forces which force narrow fracture widths. The narrow fracture widths inturn limit the entry of proppant and could lead to premature screenouts. Pinnacle Technologies and other authors published SPE 64772 from which the illustrations here were borrowed. The following drawing helps explain two ways in which multiple fractures can be generated.

The left hand situation depicts limit entry over a long interval, while the right hand example shows point-source entry with additional fractures generated from the single source, perhaps influenced by existing natural fractures.

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The following drawing helps indicate how the model described by the authors was

simplified for calculation purposes. The authors suggested several scenarios for widths of the fractures which could result in different operational outcomes.

The above sketches indicate how the fracture widths could vary depending upon the number of fractures and on the level of contribution of "tip-effects" as described by the authors.

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The entire paper should be read to gain the full benefit of the suggestions presented by the writers. The table below, also from SPE 64772, provides insight into the numerous configurations of multiple fractures and the effect of each on important parametric values.

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The following drawings describe treatment in which the predicted net pressure was vastly exceeded by the actual. History matching using multiple fractures explained the happening.

The authors provided a graphical presentation of a theoretical comparison between fracture width, the number of fractures, fracture radius and the resultant net pressure.

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QUALITY CONTROL/ ASSURANCE Quality assurance procedures are extremely important with regard to well stimulation, including fracturing. One of the more important considerations is formation and fracture damage caused by the fracturing operation and materials. Most of the emphasis has been with regard to the damage that can be caused by fracturing fluids which are incompatible with the formation (for one reason or another such as clay swelling, fines release and subsequent migration, fluid retention and so forth). While all kinds of damage should be avoided, if possible, one should recognize the relative significance of fracture face damage and fracture pathway (or bed) damage. Studies have been done to demonstrate that if a sufficiently long, sufficiently conductive fracture is created, substantial permeability reduction for a few inches from the fracture faces will have a significant but relatively small effect on production rate. However, if the fracture bed itself is damaged, the effects can be much (perhaps an order of magnitude) more significant. A very small amount of "fines" contamination within the fracture can result in a huge loss (80 or 90%) of the conductivity of the fracture. Obviously, a similar reduction in productive capacity would result. Consequently, one should be very concerned about the solids that are pumped into the fracture. This includes contaminants in the frac fluid, fine particles in the proppant, residue from fracturing chemicals and so on. Quality control on these items should not be left to chance and should be imbedded in company field operating policy. We elaborate on this subject in the following paragraphs.

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FRACTURE BED DAMAGE Damage to the flow capacity of the fracture itself can be extremely detrimental to the productivity of the fractured well. In fact, it is safe to say, that damage within the fracture bed, particularly if the damage is close to the well bore, is the worst possible location for damage to occur. The damage may occur due to any one or a combination of possible causes, some of which may be under the control of the operator. One of the more common causes is the presence of fine particles due to crushing of the larger frac sand particles under closure stress. The degree of damage due to this cause may be minimized by selecting a proppant that possesses sufficient crush resistance for the stresses that it must endure. This selection process should be sensitive to the fact that the ability of a particular proppant to withstand crushing depends on its strength, roundness, particle size variation, number of layers and the load applied. Also proppants of the same type vary significantly depending upon the particular quarry.

Figure 4-26 - Damage to Fracture Conductivity

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An early paper by Coulter and Wells (1972) demonstrated the drastic effect that even a very small percentage of fines in a proppant bed could have on fracture flow capacity. They also showed that the magnitude of this effect tended to decrease as proppant concentration increased. Fines may also be produced as a result of erosion of the fracture faces as the proppant is being placed. Another cause of fines being released is dislodgement due to chemical disequilibrium termed as chemical interference action. Perhaps the most important cause of damage within the fracture is residue from the fracturing fluid itself. This was recognized by van Poollen (1957) and many articles have been written on the subject since then. Cooke, (1975) of Esso, presented laboratory data indicating the severe degree of impairment that can result. He identified guar polymer fracturing fluid as being perhaps the worst. Again, very specific in situ test procedures are recommended and will be discussed later. The possible sources of fracture flow capacity reduction that can result from the frac fluid include; residue from gelling agents and fluid loss additives, release of formation fines, emulsions, either pumped or created inadvertently, impurities in the proppant or frac fluid. A number of papers (Roodhart et al, 1987, Much and Penny, 1987, McDaniel, 1987, Porteous and Delbaere, 1989) have been published that deal with quantification of the impairment to fracture conductivity. The aspects studied included longer-term exposure under load, effect of gel residue, and the effect of the greater concentration of gel residue and fluid loss additives in the filter cake. The last paper dealt with field experiences concerning gel residue in the fracture and its subsequent removal. The initial work concentrated on the effects of longer term loading of proppant under in situ conditions, and resulted in a general reduction of conductivity values which may be expected as compared with values previously determined by suppliers and service companies. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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The work regarding gel residues and residue from fluid loss additives confirmed that further reductions occur. Products were developed which made an initial attempt at either removing residue damage after the fracture treatment or preventing the damage in the first place by providing an alternative non-damaging fluid loss additive that also served as a highly effective, delayed action gel-breaker. The significance of the results of this work is obvious when modelling the results of treatments, both predictively and by history matching. Field results (Porteous and Delbaere, 1989) confirm this. Contamination (Osborne et al, 1975) to the proppant can occur at several points during its route from the mine to the well. Contaminated cars and truck transports are the usual sources. In some cases, the proppant as mined contains a relatively huge percentage of impurities. Fracturing fluid can become contaminated either at source or at several points during its transportation and preparation. For this reason, some areas are serviced by single source organizations who will supply fluid, tank truck, storage tanks and heating units so as to be able to guarantee high quality fluid ready to be turned over to the frac service company. Chemical precipitates of various kinds can occur within the fracture due to chemical incompatibilities that may exist and/or due to chemical stability changes that may result from changes in pressure and/or temperature conditions. One of the sources of serious contamination that has been recognized is iron. One of the primary sources for iron contamination is the surface of the tubulars, particularly the mill scale from new pipe. This scale or other iron oxides or sulphides may dissolve in hydrochloric acid which is often used in conjunction with or ahead of fracturing treatments. The iron will tend to precipitate from the spent acid solution as a gelatinous hydroxide when the pH begins to rise. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Some important work has been done by several of the service companies to identify iron as a serious complicating ingredient in the formation of sludge and as a stabilizer in regard to emulsions and some of the crosslinked gels. Another source of damage in the fracture bed can be pipe dope that has been improperly, carelessly or too liberally applied to the tubing connections. In view of the above considerations, most operators now perform an acid cleaning or sand scouring of the tubing prior to the well stimulation or other pumping operation. Care must be taken to prevent entry of the cleaning fluid into the formation.

FRACTURE FACE AND MATRIX DAMAGE We have seen that when considering the total effect of a hydraulic fracturing treatment on the productivity of a well, we must also consider the damaging effect as well as the beneficial effect. There is little to be gained by ignoring the negative aspects. We have already examined briefly how damage can occur within the fracture itself and how that damage can adversely affect the productivity. In this section, we will examine the damage that can occur on the faces of the fracture and even in the rock matrix. As mentioned earlier, van Poollen (1957) recognized early that fracturing fluids could themselves contribute to formation damage. A number of other authors have also contributed papers on this aspect, and the topic continues to deserve careful attention.

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As with any contemporary topic, there is a certain amount of difference of opinion regarding the damaging effects of fracturing fluids. Tiner et al, 1974 recognized that damage could arise from a fairly wide variety of mechanisms. Fluid incompatibility is one of them. There are a number of ways in which incorrect fluid selection may be damaging to the matrix or fracture faces. For example, the fracturing fluid may facilitate dissolution of the binding or cementing material of the reservoir rock. This may lead to a variety of subsequent events including significant loss of strength, which would cause the affected portion of the rock to collapse upon closure. In addition, insoluble fines could be released which may migrate to cause plugging of pore throats in the matrix or, even worse, they could accumulate in the fracture proppant bed. In a related sense, improperly treated water may cause certain sensitive clays to swell in volume causing severely restricted flow. The softening of the fracture faces could result in the propping agent embedding in the fracture face much more easily than it otherwise would do. This not only results in loss of permeability and width in the fracture but also loss of permeability in the formation rock itself in the area near the embedment. In the event that the fracturing fluid is incompatible with the formation fluid it would be possible for emulsions to be created. Some of the most serious ones are acidoil emulsions as a result of poorly planned acid formulations. These can result in completely plugged permeability. Under certain conditions, paraffin or asphaltenes can be precipitated in the formation as a result of stimulation treatments. Introduction of fracturing fluid to a reservoir could result in fluid retention problems. This effect could result from the failure of a viscous, gelled fracturing fluid to revert from its high viscosity, perhaps due to failure of a breaker to perform, or perhaps even when a proper break does occur the particular base (ungelled) fracturing fluid may possess a viscosity that is inappropriately high for the particular reservoir. Fluids might also be retained and/or distributed in the small capillaries of the reservoir due to imbibition. Very high capillary pressures may prevent recovery of the fluids. Some in the industry have pointed out that introduction of an additional phase (such as diesel fuel into a dry gas reservoir, or more recently, water into an under-saturated reservoir with respect to water) may cause a reduction in effective matrix relative permeability to gas due to the saturation change. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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The author of this present course pointed out in 1984 that he believed that gas reservoirs exist that are, at the present time, under-saturated with regard to water. In other words, the current level of formation water saturation is less than would be the case if a sample of the rock was flooded with formation water and then displaced with humidified formation gas to an irreducible saturation level. The implication of such a situation, were it to exist, is that treatment of the formation with a water base fracturing fluid would likely semi-permanently raise the water saturation, thereby reducing the relative permeability to gas, and consequently resulting in lower gas production than would be the case if the water saturation had remained undisturbed. It is expected that this would not be the case if the relative permeability problem could have been avoided by using a non-wetting, highly recoverable phase. If such a highly under-saturated condition is detected by log analysis or other means, laboratory work to evaluate the resultant relative permeability to gas during various clean-up stages following treatment by various base fracturing fluids may be justified. Some production companies have conducted a number of treatments on dry gas wells using hydrocarbon fracturing base fluids that are highly volatile at reservoir temperatures (Bennion et al, 1993.) Residues may be left in the formation as a result of the fracturing treatment. Lack of care in respect to selecting the particular source for the base fracturing fluid can result in silt or organic matter being introduced with the frac water or paraffin or asphaltene with the frac oil. Propping agents can be rich in fines and may also be contaminated with cement or mud products or other material originating in railroad cars or trucks. Surface equipment such as tanks, bins, pumps, hoses, hot oil units, discharge lines are all sources of contaminants. Tubing joints can be serious sources of mill scale and other scale contaminants. As pointed out, many polymers leave a certain amount of residue. It is generally believed that this residue enters the fracture and is screened out at the formation face. This is the worst place, as it remains in the fracture. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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These authors pointed out that it is possible for insoluble precipitates to form as the result of chemical reaction between certain gelling agents and constituents of the formation or formation fluid. They cautioned against certain anionic gelling agents in the presence of divalent ions such as calcium or magnesium. Insoluble fluid loss additives may actually enter and plug matrix pores and can be a significant problem. Some excellent work has been done by Cooke, 1975; Holditch, 1978; Ahmed et al, 1979; and Jones et al, 1980 concerning the causes and effects of damage to the fracture faces and to the fracture. Jones indicated that very substantial damage could be caused to the permeability of a formation due to invasion of water and that the severity was more pronounced in low permeability formations. He indicated that the damage could result in loss of 95% of the permeability. Another of his conclusions was the composition of the water was less important than had been thought. Some would still argue that point. One of the important conclusions of Holditch was that even if the fracture faces sustained up to 95% damage to a depth of 12.5 cm (five inches) the effect on productivity index would be negligible. Holditch later modified some of his early conclusions. Ahmed et al developed a highly sophisticated laboratory technique for interactive testing under in situ conditions to evaluate the degree of damage that might result to the fracture faces and within the fracture bed. He also presented a very interesting case history in which a history match of actual production was compared with predictions using various predictive approaches.

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Figure 4-27

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Case History Demonstrating Benefits of Proper Laboratory Testing Methods.

The general conclusions that one might reasonably draw from the material presented in this section of the course is that while there is some controversy regarding the degree and effect of damage that may be associated with fracturing treatments, there is little disagreement that the worse place for damage to occur would be within the proppant bed itself. Also, the prudent designer would do all possible to minimize the potential damage that might be caused to the matrix and fracture faces. Very sophisticated (and commensurately more expensive) laboratory testing procedures became available (Ahmed et al, 1979; Much and Penny, 1978), and have been modified more recently. These should be considered for those instances in which large amounts of money will be spent on stimulation treatments, or where important regional evaluation decisions rest on the effectiveness of a particular fracturing treatment, or series of treatments.

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CHECK LISTS We have developed a number of checklists for operational planning and quality control. Earlier in the operational planning section we presented a list of issues for consideration. The list was divided into a number of chronological phases Before awarding the work Before leaving town Before the job pumping starts During the pre-job preliminaries Fluid and Prop quality confirmation Instrumentation Pump and Blend Equipment Communications Associated services We provide in this section a set of relatively detailed checklists that operators can use either as is or modified for their particular application and convenience.

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Identification

Company ___________________________________________ Individual _________________________________________ Address ___________________________________________ Telephone __________________________________________ ___________________________________________ Fax _______________________________________________ Well Name _________________________________________ Legal Description ____________________________________ Pool ______________________________________________ Formation __________________________________________ Mechanical Information

Total Measured Depth _________________ Total Vertical Depth __________ Plugged Back Total Depth ________________ Casing Description (Each String): Diameter: ________ Grade: _______ Weight: ________ Depth: _______ ________ _______ ________ _______ ________ _______ ________ _______ Production Casing Cementing Details: Lead Cement: _____T,___________________________________________________________________________________ Tail Cement: ______T, ___________________________________________________________________________________ Bond Log Available _____________________________________________________________________________________ Perforations:

________to _______, ______ jspm, ____ g, _____ phase ________ _______ ______ ____ _____ ________ _______ ______ ____ _____

Tubing Description: Diameter: ________ Grade: _______ Weight: ________ Depth: _______ Packers and Downhole Equipment: Describe and include sketch: __________________________________________________ ______________________________________________________________________________________________________ ______________________________________________________________________________________________________ Wellhead Description: Describe and include sketch: ____________________________________________________________ ______________________________________________________________________________________________________ ______________________________________________________________________________________________________ Preliminary Objective: ______________________________________________________________________________________________________ _______________________________________________________________________________________________________ _______________________________________________________________________________________________________ ____________________________________________________________________________________________________ ______________________________________________________________________________________________________ _______________________________________________________________________________________________________ _______________________________________________________________________________________________________ ____________________________________________________________________________________________________ Check List of Files to be Supplied:

Raw Reservoir Information:

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Well Logs ____________, ____________, _____________, _____________, ______________________ Core Analysis _______________, Core Samples _________________, _________________________ Drill Stem Tests _______________, ________________, _____________, _______________________ Production Tests _________________, Reservoir Fluid Analysis ______________________________ Reservoir Fluid Samples ____________, Rock Mechanical Properties _________________________ Derived Reservoir Data (for each layer) Layer Interval: Layer Thickness Permeability Porosity Saturation

__________ __________ __________ __________ __________

_________ _________ _________ _________ _________

__________ __________ __________ __________ __________

__________ __________ __________ __________ __________

Mineralogical Composition Available _______________________________________________________________________ Reservoir Sensitivity and Quality Analysis ___________________________________________________________________ Reservoir Fluid Properties: Viscosity _________________ Density ________________ Bubble Point ________________________ Reservoir Pressure ____________________ Reservoir Temperature ____________________________ Frac Materials Data: Viscosity vs. Time at Temperature: Base Gel w/ breakers _______________ Crosslinked Gel w/ breakers __________________ Filtrate ________________ Broken Gel _______________ Fracture Conductivity Data (Long Term) Plotted versus Concentration and Closure Pressure ______________________________________________________ Derated for frac gel residue ________________________________________________________________________ Frac Fluid Filtration Loss Data Generalized catalogue data __________________ Specific w/ this Formation ____________ How measured _______ Complete Interactive Data _________________________________________________________________________ Frac Materials Samples All Chemicals to be Evaluated ____________ All Proppants to be Evaluated ________________________________________ All Base Fluids to be Evaluated ____________________________________________________________________________ Other Useful Information Evidence of Containment Effectiveness: R/A Traced Proppant ___________________________ Temperature Logs __________________________________ Fluid Production from Non-Target Zones _____________________________________________________________ Fracture Height Logs (Predictive) ___________________________________________________________________ In Situ Stress Profile _____________________________________________________________________________ History Matched Production Simulation ______________________________________________________________ Production History Data For Wells in the Area ________________________________________________________________

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Economics - Costs Well Operating Costs vs. Time Unfractured well __________________________________ Fractured well _________________________________ Well Treatment Costs Equipment _____________________________ Equipment Transport _____________________________________ Crew ____________________ Crew Transport and Daily Subsistence _____________________________________ Fluids and Chemicals __________________________________________ Proppants ____________ , ___________ Transportation of Materials _______________________________________________________________________ Rig Costs ______________________ Associated Services Costs _________________________________________ Technical Supervision and Design __________________________________________________________________

Economics - Revenues

Oil or Gas Wellhead Price vs. Time _________________________________ Economics - Interest

Cost of Borrowing vs. Time ________________________________________

Objectives for Economic Optimization:

Payout Time ______________ Number of Months at Allowable ____________________,

NPV: _______________________

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On-Site Check List Pre-job Inspections

Location: Equipment spotted so as to maintain safety clearances as required by regulatory bodies. _________________________________________________________________________________________________ Safety equipment in place and ready to operate as per regulatory bodies_______________________________________ As per Company policy: ____________________________________________________________________________ First Aid or Medical personnel on location as required by regulatory bodies_______________ Head count __________ Escape routes identified and personnel notified in Pre-Job Safety and Operations Review Meeting _________________________________________________________________________________________________ Materials: Service Company Materials List in hand _______________________________________________________________ Inventory of Materials on Location Checked ____________________________________________________________ Adequate Frac Fluid _______________________________________________________________________________ Adequate Fuel in Each Unit:_________________________________________________________________________ Equipment: Tanks, Valves, Hoses: Adequate number _____________________ Proper Standard ____________________________ Blender: Tub Clean ____________Sand Hopper Clean ______________Sand delivery capacity adequate even for job end increases _____________________Blender grounded _________________________________________________ Suction Pump Functioning With Adequate Discharge Pressure ______________________________________________ Discharge Pump Functioning With Adequate Discharge Pressure ____________________________________________ Outlets, Valves, Hoses: Adequate number ____________________ Proper Standard _____________________________ Flow Meters on both sides ___________________________________________________________________________ Manifold Unit: Proper pressure rating _________________________________________________________________ Pumpers: Proper power _____________________________ Proper pressure __________________________________ Sand Transports or Tanks: Proper quantities and types of prop _____________________________________________ No truck movement necessary during job ______________________________________________________________ Discharge Lines: Adequate quantity __________ Proper design ________________ Check Valves ________________ Pressure Sensors ________ Density Meters _______ Other _________ Staked ________________________________ Pressure Bleed-off Line Installed and staked: ______________________________________________________ _____ Instruments and Computer Truck Functioning ______________________________________

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Personnel: Understand the purpose, planned procedure, possible changes, especially re: sand concentration, contingency plans. Frac Operator _______________ Computer Operator _______________ Blender Operator _____________ Jobsite Supervisor ___________ Rig Push _______________________ Materials Preparation: (checks to be made on each tank) Base Fluid:

Specification

Actual

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Source ________________________________________________________________________________________________ Filter: ________________________________________________________________________________________________ pH ______________________________________________________________________________________________ Density: ______________________________________________________________________________________________ Temperature: __________________________________________________________________________________________ Water content: _________________________________________________________________________________________ Viscosity: _____________________________________________________________________________________________ Base Gel: Temperature: ___________________________________________________ _______________________________________ PH: _________________________________________________________________________________________________ Viscosity _____________________________________________________________________________________________ Time to Cross-link: _____________________________________________________________________________________ Job Execution: Injection Test: Closure Pressure ___________________ Method ___________________ ______________________________ Minifrac: ISIP (1) __________ (2) __________ (3) _________ Closure Pressure ______ ______________________________ Fluid Loss Coefficient: ___________________________________________________________________________________ Containment: __________________________________________________________________________________________ Frac Geometry Model: ___________________________________________________________________________________ Changes in Design: ____________________________________________________________________ _________________ ______________________________________________________________________________________________________ Main Frac Observations: During Pad Volume: ___________________________________________________________________________________ During Low Concentration: _______________________________________________________________________________ During Moderate Concentration: ___________________________________________________________________________ During High Concentration : ______________________________________________________________________________ During Displacement : ___________________________________________________________________________________ Closure Time: _________________________________ _________________________________________________________ Time Initial Flowback Started ___________________ Rate __________________ Observations of time, rate, pressure, gel characteristics, proppant returning ___________________________________________________ _______________________________________________________________________________________________________________ _______________________________________________________________________________________________________________ ____________________________________________________________________________________ Final Inventory of tanks, sand bins, chemicals taken __________________________________ _________________________ Samples Obtained: Pad ___________________ Prop Fluid _________________________ Flush _______________________ Flowback Fluid (1 hr) ______________ (3hr) _________ (6 hr) _________ (12 hr) _________ (24 hr) __________________

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Stimulation Suite 2008 Part Three Acidizing and New Stimulation Technology

© Porteous Engineering Limited

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INTRODUCTION This is the third part of a series of courses in three parts. The three segments of Well Stimulation Suite 2008 consist of main topics covering the following areas: First Segment Introductory Material Review of Reservoir Characteristics Formation Damage Theory of Hydraulic Fracturing Deciding which Wells to Fracture Predicting the Results of Fracturing Fracturing Fluids Propping Agents Basic Treatment Sizing Equipment & Operations Overview Second Segment Information Collection Laboratory Work Development of Best Strategy Best Design Use of 3D Simulators Economic Optimization Operational Guidelines Decision Tree for on the fly Use On-site Use of 3-D Simulators Fracture Diagnostics Quality Assurance Procedures Third Segment Types of Acids and Applications Sludges, Emulsions, Precipitates Acid Placement Techniques Effective Matrix Acidizing Factors Affecting Fracture Acidizing Success New Developments & Emerging Stimulation Technologies

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This segment is the last portion of the Well Stimulation 20086 Suite, a series of presentations of basic and advanced aspects of well stimulation. This session deals with Matrix and Fracture Acidizing and New Stimulation Technology. During this portion, we shall discuss the following topics:

♦ Types of acids and applications ♦ Sludges, emulsions and precipitates ♦ Acid placement techniques ♦ Effective matrix acidizing ♦ Factors affecting fracture acidizing success ♦ New developments and emerging stimulation technologies

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WELL STIMULATION USING ACIDS The use of acids in oil and gas wells is a common technique which has been applied since 1895 (Williams et al, 1979). The main reason for the use of acids in wells is that the most commonly used acid, hydrochloric, reacts readily with a common reservoir rock, limestone, to increase the permeability of the rock, and thus the productivity of the well. Since the initial applications of hydrochloric acid, a number of service companies have been created to provide application of the technique. There have also been many improvements such as the introduction of other types of acids, and a host of special additives. A number of application techniques have given a high degree of sophistication and complexity to the process. As a result, a rapidly changing technology has evolved which demands that special attention be given to the treatments for proper application of acids in the oil and gas industry. In this section of the course, attention will be given to the various types of acids, application techniques and the basic technology details that are required for wise application.

REACTIVE MATERIAL

One of the most basic requirements for successful acidizing is that there must be a reaction between one or more rock constituents and the acid. This is not always properly confirmed by designers. For example, there is essentially no reaction between hydrochloric acid and sandstone or between hydrochloric acid and most clays. Sometimes, in damage removal

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cases the acid need only react with the damage-causing material, e.g. with invaded drilling fluid.

TYPES OF ACIDS

There are several types of acids which have been used for treating oil and gas wells. The most common has been hydrochloric, with others being hydrofluoric (in combination with hydrochloric), acetic, formic, phosphoric, sulfamic, chloroacetic and fluoboric.

TYPES OF JOBS

There are a number of ways in which acid can be applied in wells. The most common is the perforation wash, often associated with a small volume acid squeeze. Larger low pressure matrix squeeze jobs are also performed as are jobs in which the acid is either employed as a hydraulic fracturing fluid, or is used to treat a previously created hydraulic or natural fracture. Occasionally, acid is used to clean the well tubing or casing of scale or deposits. It is also used in some cases to clean out a mud channel ahead of a squeeze cementing operation, or as a carrier fluid for surfactants and emulsion breakers.

GUIDELINES FOR APPLICATION

In order to properly apply an acid treatment, certain information will be required. It will be most important to define the objective of the treatment along with the constraints. Just as in planning a fracturing stimulation, or any other completion, it will be necessary to know the condition of the well, whether it is damaged and to what degree. If damage exists, the cause and nature of the damage will need to be determined. The composition and physical characteristics of the rock will have to be defined, and some laboratory work may be _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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required to determine the manner in which the rock materials react with acids or other solvents. In addition, a description of the reservoir will be required including the proximity of water or gas bearing strata and the presence or absence of fractures. The type of porosity, the water saturation, wettability, capillary size, and mineralogy including trace minerals, clays and other reservoir quality parameters will require definition. Based upon data such as that above, and other information, the possibilities for treatment design will emerge.

REACTIONS

The main reason for the application of acid, is that the acid will be chemically reactive and will dissolve part of the reservoir rock, or solid plugging material. This section will focus on the reactions, beginning with the main ones and then detailing some of the secondary reactions which are nonetheless important. Similar discussions will be provided for the types of acids in common use.

MAIN REACTIONS

The main reactions that will be dealt with in our discussion are the ones between the acid and the important reactive reservoir constituents, such as calcite, dolomite, occasionally siderite, and various silicates. The reactions involving the acid and drilling fluids will also be discussed, since mud and mud filtrate damage removal is a common application for acids.

HYDROCHLORIC ACID

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By far the most common acid is use in oilfield operations is hydrochloric. It consists of a solution of hydrogen chloride gas in water. The most frequently used concentration is 15%. The commonly accepted terminology means that 15 mass percent hydrogen chloride gas is dissolved in the water. Various concentrations are employed, ranging from about 5% to about 35%. The higher number represents (approximately) the maximum amount of hydrogen chloride gas that can be dissolved in water.

WITH CALCITE

The most common application for hydrochloric acid in oilfield operations is to dissolve limestone, which in its pure crystalline form is properly known as calcite, CaCO3. The reactions are as follows: CaCO3 + 2HCl

-->

CaCl2 + H20 + CO2

WITH DOLOMITE

Hydrochloric acid also reacts with the other common calcareous material, dolomite, which is usually given the chemical formula CaMg(CO3)2. The reaction may be expressed as: CaMg(CO3)2 + 4HCl --> CaCl2 + MgCl2 + 2H2O + 2CO2

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WITH SIDERITE

In the Western Canada Sedimentary Basin, one of the more common carbonates is a ferrous carbonate, FeCO3, known as siderite. It often occurs as clasts in a number of formations, including the Cardium. The following reaction is possible: FeCO3 + 2HCl --

FeCl2 + CO2 + H2O

There are some other important aspects in respect to this reaction that will be discussed later.

WITH DRILLING FLUIDS

The usual constituent of drilling fluid with which we may be concerned (relative to acid reaction) is the clay (bentonite) from which the drilling mud is prepared. When the dry bentonite is mixed with water to prepare the drilling fluid, the water combines with the bentonite to cause the bentonite to swell several times its dry volume. Some early work theorized that by contacting hydrated bentonite with hydrochloric acid, the bentonite could be made to release some of the water it associated with when it was hydrated. If this were true, then the mud particles could be dispersed by a chemical dispersant and they may then be removed from the well more easily. This was the basis for suggesting hydrochloric acid as a "mud clean-out" solution. Of course, in carbonates it could also function by dissolving the rock adjacent to the mud. It could also react with any drilled carbonate solids that became a part of the mud system.

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HYDROFLUORIC AND HYDROCHLORIC ACIDS Since hydrochloric acid does not appreciably react with clay silicates, and since hydrofluoric acid does react to some degree with such materials, the industry sought a way to use hydrofluoric acid. However, hydrofluoric acid is extremely corrosive to human flesh, and it is therefore extremely hazardous to handle. A safer way of using it in the oilfield had to be devised. This was achieved by reacting a powdered salt of hydrofluoric acid, such as sodium bi-fluoride or ammonium bi-fluoride with hydrochloric acid to produce a solution of hydrofluoric acid in the hydrochloric acid. Some of the hydrochloric is obviously consumed in this reaction. The dust from the bi-fluoride must not be inhaled and breathing mask-filtered air is suggested for those who are required to handle this material.

WITH CALCITE

The reaction between the hydrochloric acid and the calcite progresses essentially as if the hydrofluoric was not present until the concentration of the hydrochloric becomes weak and the concentration of calcium in solution increases. At this time, the fluorine combines with the calcium to form an insoluble calcium fluoride precipitate. For this reason, hydrofluoric/hydrochloric blends are not recommended for application in formations with high calcium carbonate content.

WITH DOLOMITE

The same precautions are suggested as for calcite formations.

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WITH SIDERITE

Similar precautions are advised, but for other reasons. Insoluble iron hydroxide could form as the pH increases. In another reaction, the salts in solution may combine to form an insoluble fluosilicate. This will be discussed further a little later in the course.

WITH SILICATES

Hydrofluoric/hydrochloric acid can react with silicates. The reaction with certain clays such as bentonite, (smectite, montmorillonite) and others, is much more rapid than with sandstone. Other clays may react very slowly, and the effectiveness of such acids on removal of some of these clays is in question. During the reaction with sandstones containing clays and/or feldspars, a very complex series of reactions, defined by Labrid (1975) may take place and may result in the precipitation of colloidal silica and perhaps fluoaluminates. In the presence of sodium or potassium, fluosilicates may also be precipitated.

WITH DRILLING FLUIDS

The use of HF/HCl mixtures for removal of drilling mud lost to formations can be very effective. Labrid (1975) also described the stages of chemical dissolution in the reaction of HF/HCl mixtures and clays. As stated, one also has to be aware of the precipitation reactions and reaction kinetics, if damage is deep.

ACETIC ACID

For acidizing formations under hot conditions, an organic acid has been used for several years. The acetic acid reaction rate on calcium carbonate is relatively slow in the presence of

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the reaction products, even at high temperatures, and the corrosion rate of the acid on tubular goods is also quite low at rather high temperatures. These are significant advantages. WITH CALCITE

2CH3COOH + CaCO3 --> Ca(C2H3O2)2 + H2O + CO2

FLUOBORIC ACID

An important contribution to the acidizing technology is the development of a relatively new technique for both stimulating sandstone formations and stabilizing the fines in such formations (Thomas et al, 1978). The technique is based on the use of fluoboric acid, HBF4. In the sandstone, the fluoboric acid hydrolyses to form hydrofluoric acid. The HF then reacts with the sandstone or the clay fines relatively rapidly. Thus, a product of the first reaction is consumed. Therefore the hydrolysis reaction is stimulated and further generation of HF takes place. This sequence of events enables some HF to be generated relatively deep in the formation. In contrast, the HF in HCl/HF acid would spend relatively rapidly, and deep stimulation would be impossible by the simple HCl/HF. The hydrolysis reaction is: HBF4 + H20 -->

HBF30H + HF

As the acid spends on the clays and fines in the sandstone, the reaction may be represented as follows: HF + Al2Si4016(0H)2 -->

H2SiF6 + AlF3 + H20

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borosilicate has the ability to fuse the platelets together thereby helping to prevent their disintegration and migration. This clay stabilizing effect is a significant advantage of this process. The Dowell authors showed that the system also has the ability to stabilize quartz fines. A typical treatment would consist of a preflush of HCl, a moderate treatment with HF/HCl, a spacer of NH4Cl and then the HBF4. The well would be shut in for a fairly long time, up to 96 hours, depending upon the temperature. More recently, the application technique has been modified so that shut-in times are not so long.

IMPORTANT SECONDARY REACTIONS

There are a number of secondary reactions that can occur under certain conditions. The designer of well treatments should become familiar with these reactions, their significance, and the conditions under which they can occur.

CALCIUM FLUORIDE PRECIPITATION

One of the most important harmful reactions that can commonly occur is the precipitation of calcium fluoride from solution as a result of the reaction between calcium carbonate and hydrofluoric/ hydrochloric acid. The calcium combines with the fluorine to produce calcium fluoride, a precipitate that is insoluble in water. For that reason, HF/HCl mixtures should not be used on carbonate formations, and should always be preflushed with a spacer of hydrochloric acid to dissolve and flush away any small quantities of calcium. To be particularly careful, (and wise) some operators follow the hydrochloric acid with ammonium chloride to increase the certainty of flushing away the cations previously dissolved by the HCl. One possible source of calcium is the filtrate associated with cement slurries. Also, if the HCl/HF mixture is to be displaced from the tubing using water treated, for example with potassium chloride, then the _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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acid mixture should be separated from the flush by a buffer of hydrochloric acid or ammonium chloride. This is to help prevent precipitation of fluosilicates, which is discussed below.

FLUOSILICATE PRECIPITATION

In the reaction of HF/HCl mixtures with sandstone, one of the products of the reaction is fluosilicic acid. This in turn can combine with several ions commonly found in formation water, or associated with acid reaction products, such as sodium and potassium. The products of these reactions could include fluosilicates of those elements mentioned. All of these are insoluble and can cause significant loss of productivity. A similar set of reactions can occur as a result of the reaction of the HF/HCl mixture on clays, which are rich in aluminium, and in which the first product is fluoaluminic acid rather than fluosilicic acid. Similarly, the end precipitate is an aluminoferric rather than a fluosilicate precipitate. Wise application and limits to the application of these particular acid mixtures will help prevent such precipitation. As insurance, it is nearly always advisable to include the mixed acid in a sandwich of hydrochloric acid at the front and behind the mixture. Some prefer to separate the HCl/HF mixture from the displacement fluid with a spacer of ammonium chloride, rather than HCl. The first, or leading portion of HCl is essential. Gdanski and Schuchart of Halliburton in a series of papers published from 1992 and later have contributed some related and important new theory on this subject. DiLullo and Rae of BJ have also published important conclusions on the subject of sandstone acidizing.

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IRON HYDROXIDE PRECIPITATION

Iron is perhaps one of the worst contaminants in acidizing, and it is almost always present. Sources of iron include impure hydrochloric acid delivered from the tanker. The yellow colour usually associated with hydrochloric acid in the field is due to iron impurities. Pure HCl is clear and colourless. Other sources of iron, beside the acid itself and the trucks in which it is transported, include the mill scale in new tubing, the rust from used tubing, iron sulphide scale from tubing that has been exposed to hydrogen sulphide, and so on. Another important source of iron is the formation itself. Many common rock constituents contain iron. For example, siderite, chlorite, glauconite, pyrite, all contain iron. For the iron to be harmful it must be the ferric form. The more common ferrous iron is not a major problem. As a matter of interest, Williams, Gidley and Shecter (1979) report that in the presence of iron and hydrochloric acid, the ferric iron will be converted to ferrous. Therefore as long as the ferric is contacted by acid in the tubing, there is a good chance that it will be reduced to ferrous. However, if bits of mill-scale are carried to the formation in the solid state and are then dissolved, or if iron-rich rock components are dissolved, then there is a greater chance that the hydroxide that forms as the acid spends and the pH rises will be ferric hydroxide. In order to help prevent the introduction of iron into formations during acidizing or other tubingconveyed well injection treatments, some operators slowly circulate a pill of acid to near the bottom of the tubing and then quickly reverse it to disposal prior to the main treatment. The objective is to remove most of the soluble iron in advance of the main treatment so that it will not be dissolved and carried into the formation by the main treatment.

TACHYDRITE PRECIPITATION

The use of concentrated HCl in dolomite formations may result in the precipitation of tachydrite (also referred to as tachyhydrite in the mineral literature), which is insoluble in the relatively unspent acid. As the acid spends the material may become more, but not totally, soluble and

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significant plugging may still occur. Therefore, an overflush of water may be very beneficial in helping to redissolve some or all of the tachydrite, which is said to be soluble in fresh water.

EFFECTS OF MAIN PARAMETERS DURING FRACTURE ACIDIZING

The rate and manner with which acid reacts with the reservoir rock is obviously of great importance. The designer will set as an objective the generation of additional permeability in the reservoir by the chemical removal of some of the rock. However, the locations from which the rock is to be removed is very important. For example, a designer may wish to increase the permeability dramatically in a cylinder that extends say one or two metres from the well bore. His purpose is to reduce the pressure drop through the damaged zone and also to reduce the producing pressure drop by permeability improvement (stimulation) in the area of greatest pressure loss. This may be done with a relatively fast reacting acid system. The best that can be done is to enlarge the wellbore to that radius. Simple reservoir calculations for radial flow will show the maximum effect. On the other hand, if the formation is undamaged but has very low permeability, the designer may try to create a moderate but deeply penetrating improvement in permeability by creating an etched fracture, say, to a radius of 200 metres from the well bore. There are a number of factors that the designers of the above two types of treatments must consider in order to make the appropriate decisions as to the fluid to pump and how to pump it. These factors will all have an influence on the way the acid reacts with the rock and must be examined individually before they can be considered collectively. A CIM paper by Knox and Ripley (1979) adequately describes the effect of several of the more important parameters. This is the main source of some of the following information. The paper and its references should be consulted for more detail.

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CONCENTRATION

The instantaneous reaction rate of concentrated acid is faster than the reaction rate of weak acid. However, in a well acidizing treatment one must consider that if, say, 28% HCl is used to treat a well, the reaction will start rapidly. Then as the acid spends down to 15%, the reaction will slow. By the time the concentration of the spent acid is down to 15%, however, the solution will contain the products of the reaction to this point, calcium chloride, carbon dioxide and water. The presence of these materials in solution will retard the reaction rate. Therefore the rate of spending from 15% will be slower than if the concentrated acid had not been used. Overall, the more concentrated acid will take significantly longer to react down to a particular concentration than the weaker acid.

TEMPERATURE

The role of temperature in acid reaction rates has to some degree been misunderstood in the past. It is true that increasing the temperature of the reaction between HCl and limestone will increase the reaction rate. However the effect is far less dramatic than it was once thought to be. The effect of increasing temperature on the surface reaction rate of dolomite is much more significant and must be considered when acidizing or fracture acidizing dolomitic formations, especially in formations with low to moderate temperatures.

GEOMETRY, SURFACE AREA, VOLUME

The spending time of acid is affected by the amount of surface area of the reactive material that is in contact with the acid. For example, a cube of limestone will require much more time to consume a quantity of acid than a similar mass of limestone that has been powdered. The amount of surface area is a moving target in matrix acidizing, since the size of the pores is constantly being affected by the job in progress. On the other hand, the volume to surface area relation during fracture acidizing can be more or less constant for a given fluid, pump rate

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and so on. The area/volume relationship can be changed by changing the job parameters such as pump rate, viscosity and fluid loss.

VISCOSITY

Viscosity has an effect on reaction rate because it suppresses turbulence and therefore makes it more difficult for the hydrogen ions (in the acid) to contact the rock surface. This, then, will tend to slow the reaction rate to a large degree. The effect is even more dramatic in fracture acidizing because the use of higher viscosity in such treatments also results in greater fracture width so that two factors combine to cause an even slower reaction rate. Therefore, the use of gelled acid systems can be very beneficial if properly designed and executed. The ability of the spent gelled acid to transport fines can be a significant benefit, provided the fines are completely removed and do not bridge the fracture closer to the well bore. There is an obvious reason to keep the well fluids moving once cleanup begins. There may also be a reason to control the flowback rate so that fines (from afar) do not drop out (near the wellbore) as velocity inevitably slows during the early recovery period when rates could otherwise be initially high.

VELOCITY

The acid reaction rate will increase with increasing velocity until the acid goes into turbulence. The reason given by Knox and Ripley for this is that the distance that must be travelled by a hydrogen ion to contact the rock surface is minimized as the flow regime approaches turbulence. Then, once turbulence is reached, even faster injection rates tend to not change the reaction rate, but to cause the acid to penetrate further down the fracture into the formation before spending. So increasing velocity has the effect of increasing reaction rates up to a point, and then further increasing velocity has no effect on reaction rate, but it does affect (favourably) the Acid Penetration Distance, using the term as defined by the authors.

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FLUID LOSS

The shape of hydraulic fractures created during fracture acidizing operations is of great importance in determining the effect of the treatment on productivity. Fluid loss is one of the more important factors which determines the shape of fractures. Of course, rock mechanical properties and in situ-stresses are perhaps the main factors, but these are not within our control. Fluid loss control may help promote deeper penetrating fractures with a given volume of fluid and, in the case of acids, permits the acid to penetrate deeper into the formation before it spends. The difficulty with attempting to control fluid loss from acid solutions to reactive formation, is that the pores are being constantly enlarged. The ability of the fluid loss additive to remain functioning to seal a given pore is thus diminished. The role of fluid loss additives in matrix acidizing is primarily to act as a diverting agent to direct the acid away from the more permeable sections to parts of the formation that would not otherwise be expected to receive much of the acid.

METHODS OF APPLICATION

There are many well situations for which acid may be used. The particular problem that is to be addressed and the formation and well conditions will determine the method of application to be used.

PERFORATION WASHING

One of the more common uses for acid in oil and gas well operations is to help clean out perforations which are plugged or partially plugged with drilling mud or other solid plugging material such as scale. For this application it is advisable to do all possible to ensure that the acid is directed to each perforation. In some cases, the acid will tend to flow mostly into the

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first few perforations that become opened. Therefore a number of ways to help direct the acid to all of the perforations have been devised. One method is to simply wash the acid past the perforations, from the bottom upwards, under very low pressure in order to avoid squeezing the acid away too rapidly. Another is to inject ball sealers into the acid in a continuous operation with a ball being injected regularly so as to spread the acid injection over as many perforations as possible. A third method is to employ any one of a number of perforation-washing tools that are available. These tools generally function by means of opposed packer cups to contain the acid which is forced through ports between the cups. The cups are very closely spaced so that intervals as short as one-third metre may be treated. The packer cups (similar in design to swab cups) are set by pumping, and released when pumping stops. Therefore they may be set and reset throughout a perforated section several times in order to spread the treatment as evenly as possible.

MATRIX ACIDIZING

The concepts and practices of matrix acidizing have sorted themselves out reasonably well in recent years. Prior to that there were nearly as many ideas and techniques as there were practitioners. The primary application for matrix acidizing is to help remove formation damage in the area near the well bore. The type of damage and the composition and texture of the rock matrix will be important factors for the designer to consider. Other factors such as the constraints presented by the presence of nearby water-or-gas (in the case of oil producers) bearing zones must also be considered.

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The purpose of matrix acidizing is to place the proper acid solution in the formation in an evenly distributed manner so as to treat a cylinder of rock surrounding the well bore to a given radius. This purpose, therefore, implies that the well is not to be fractured during the treatment, or else the cylindrical placement of acid will not be achieved. Consequently, one of the primary considerations in matrix acid treatment design is to avoid fracturing pressures. The manner in which fracturing pressures for a given formation in a given area may be determined has been covered extensively in another portion of this course. The next primary consideration must be the selection of the appropriate treating fluid composition. This will be largely determined by the nature of the problem that is being treated, including the chemical composition of the plugging material, if there is one, and the chemical composition of the rock matrix constituents and the reservoir fluids. If either the plugging material or the rock matrix contains carbonates, then the use of hydrofluoric acid in any form is to be avoided. There is an exception to this. If minor amounts of carbonate are present in the matrix, hydrofluoric acid may be used provided it is preceded and followed by sufficient hydrochloric acid to consume any carbonates and carry the products of reaction away so that the hydrofluoric acid does not come in contact with them. Some prefer not to follow with hydrochloric acid but prefer to employ ammonium chloride instead. As discussed earlier, undesirable precipitates can form from the combination of the fluorine ion and calcium, and the reaction between fluosilicic acid and almost any cation including sodium or potassium. The use of potassium chloride water as a displacement fluid is a questionable practice when hydrofluoric acid is used. Some prefer to use ammonium chloride spacers, hydrocarbons or nitrogen in such circumstances. Other design considerations include the ability to place sufficient solvent to the required radius from the well bore before the solvent becomes ineffective due to spending. The SPE monograph on Acidizing Fundamentals (Williams et al, 1979) provides a detailed discussion and charts of the reaction rates of hydrofluoric/hydrochloric acid mixtures on sandstone and presents a simplified design method which is based on the use of the charts, combined with _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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calculations of the maximum allowable injection pressure and the way to calculate the maximum injection rate that may be achieved within this limiting pressure. A very important consideration is that deep formation damage is likely to be far too expensive, or perhaps impossible to remove by matrix treatments due to the depth limitation to which reactive solvent may be placed. In such cases hydraulic fracturing, using a non-reactive fluid plus proppant, may need to be employed. An alternative method may be provided by some of the more sophisticated procedures employing chemical generation of solvents in-situ. For further information relative to sandstone matrix acidizing, the reader is invited to refer to the previous discussion on the use of fluoboric acid and also the references dealing with a process known as Self Generating Mud Acid (SGMA) (Templeton et al, 1978). As mentioned earlier, both Halliburton and BJ have published on new concepts in sandstone acidizing.

NATURAL FRACTURE ACIDIZING

Where natural fractures exist in formations it may be very difficult to effect a successful matrix acidizing treatment. This is because the acid may tend to flow through the natural fracture system rather than through the rock matrix. Where completely healed (or sealed) natural fractures exist, if indeed they exist any place, the matrix approach may work. Assuming the natural fractures are at least partially open, a different approach is required. For such cases, it is fair to assume that the fracture system is the main conductive mechanism for transporting fluids to the well bore. Therefore, it is also likely to be the main conducting system for transporting fluids away from the well bore such as damaging muds or filtrates.

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With the above assumption in mind, the treatment should be designed to treat the damage that exists in the fractures, and to improve the conductivity (permeability times thickness) of the fractures. This requires that the composition of the solvent should be tailored so as to dissolve any plugging material or any geologically deposited or precipitated material in the fractures. However, since in travelling down the fracture to reach the plugging material, the solvent must come in contact with the formation material on the fracture surface, the composition of the formation and reaction possibilities with the solvent or partially spent solvent must be considered. One obvious consequence is that the acid may react with the formation so quickly that only spent acid is pumped very far down the fracture. Therefore, as discussed by Knox and Ripley (1979), Acid Penetration Distance is a predominant design parameter that is itself dependent upon a number of factors including, acid concentration, pumping rate, acid viscosity, fluid loss rate, and fracture geometry parameters such as fracture width, length and height, which are in turn largely controlled by in-situ stresses and rock mechanical properties such as Poisson's ratio, and Young's modulus. The effects of the above variables on acid reaction rate is discussed in an earlier section, and in detail in the referenced paper. One of the aspects of fracture acidizing that has been discussed in the literature is the final condition of the etched fracture faces after the recovery or spending of all reactive materials. If the reaction on the fracture surfaces is so even that the fractures may completely heal, the net benefit will be very small. On the other hand, if the fractures can be etched in an uneven manner so that the unetched portions will prevent the fractures from completely closing, the conductivity of the system will be much greater, and more benefit will accrue. There have been a number of methods proposed to create uneven etching. These include:

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Use of an oil wetting agent mixed with the acid and pumped with a small quantity of oil. This causes a portion of the rock to become oil wet and thus inhibits contact by the following acid with those portions. The result, theoretically, is an uneven etching. For uneven etching to occur in an otherwise homogeneous rock, the deposition of the oil wetting chemical must be uneven. The accomplishment of this uneven deposition determines the success or otherwise of such treatments.

o

Use of viscous volumes (slugs) of non-reactive fluids such as gelled water to act as diverters for following slugs of acid. The concept suggests that the thinner acid will finger through the thicker material in an uneven manner (not bank-like displacement) and thus expose portions of the rock to acid while other portions are not exposed.

o

Use of fluids of different densities. By pumping fluids of greater or lesser densities than the acid as slugs ahead of the acid, the tendency of the acid to override or underride the slug can be influenced.

NEW FRACTURE ACIDIZING

Many of the concepts of natural fracture acidizing may be applied to acidizing of newly created hydraulic fractures. One of the differences is that the newly created fracture surfaces will probably be clean and free of geological depositions and precipitates. This implies that the acid will contact only one solid material, the material that comprises the rock matrix. Therefore, some of the job parameters are simplified.

FRACTURE ACIDIZING WITH PROPPANT

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Occasionally, proppant is employed with fracture acidizing treatments. The main application is in instances in which the acid etching is likely to be very even. Therefore the fracture conductivity will be very low due to low fracture width under closure conditions. The alternative is to include a propping agent with the acid just as in a normal fracturing treatment. There are some differences that must be considered. In a non-acid fracturing treatment, the propping agent will probably be in contact with firm fracture faces. When acid is employed as the fracturing fluid, the fracture faces may be softened or pock-marked to some extent by the reaction of the acid with the rock. The strength of the fracture faces may be reduced to the point that embedment of the propping agent into the faces can occur under closure stress conditions. The result of this is that effective fracture width will be reduced, possibly to zero. Another important factor is that generation of an adequate fracture width to accommodate the propping agent may be difficult. This is because if there are naturally occurring fractures or fissures, the pressure imposed to generate a hydraulic fracture may be sufficient to open the fissures. If this happens, the leak-off rate will increase dramatically and the pressure in the fracture will drop. As this happens the fracture width (which is largely due to internal fracture pressure) will diminish. A screen out may occur due to inability of the propping agent to enter the narrow fracture. The problem may possibly be addressed by means of: o

Larger pad volumes

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Use of fissure-sealing agents in the pad

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Use of viscous fracturing fluids

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Higher injection rates

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USE OF FOAMED ACID

Foamed acid, using either nitrogen or (occasionally) carbon dioxide, has been in use for a number of years (Ford, 1980). By far the most popular gaseous phase of foamed acid is nitrogen. Perhaps this is because it remains as a gas and does not go into solution at well treatment pressures. Therefore a foam structure with its advantages is maintained. For the purposes of this discussion, the term "foamed acid" will refer to nitrogen-foamed acid. There are several advantages to foamed acid. One of the more attractive ones is that of fluid loss control. A properly formed foam exhibits excellent fluid loss control properties, and since the reactive phase is rather small, the fluid loss control tends to remain throughout the treatment when reactive formations are contacted. There is a tendency to used concentrated acids such as 28% HCl as the acid phase. This is due to the high quality (50% to 90% gas phase) of foamed acid, the relatively small amount of acid present and the desire to increase rock dissolving capability under these circumstances. Another advantage to foamed acid is that energizing gases are introduced to the formation at the same time as the acid. Therefore the recovery rate of the spent acid, and perhaps of undissolved fines, is increased.

PROBLEMS WITH SCALES AND DEPOSITS

Introduction In oil field production operations, the formation of deposits and scales in the formation, in downhole equipment and in surface facilities can cause considerable difficulty.

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Some scales are inorganic in nature and are largely the result of deposition of minerals from water. Others are organic, and are often sourced from the reservoir hydrocarbons. A mechanism must be present to cause either type of deposit to form. This can be in the form of a change in physical conditions (temperature, pressure) or a change in chemical equilibrium. Unless that mechanism is removed or sufficiently altered, the deposits will likely form again. Therefore, a permanent solution probably involves more than just removal of the deposit. A number of simulators of various degrees of sophistication are available for predicting scaling tendency. One of the better ones was developed by Alberta Research Council. For our purposes, we shall confine our discussion to the deposit removal challenge. Some scales are not simply organic or inorganic, but may be layered deposits of both. Some deposits are located in a position where they can be easily contacted with solvent and fresh solvent can be circulated past the scale. An example would be a deposit in the tubing, provided the tubing diameter was not completely occluded. Other locations are more difficult to treat. If deposits exist within the formation, it may be very difficult to contact the surface of the deposits other that at the immediate wellbore contact point. So treatment of these kinds of problems requires both a mechanical/hydraulic and a chemical aspect. In some cases of formation interstitial plugging, if the circumstances permit, the best approach may be to fracture through the deposit area into a portion of the formation where conditions do not support further deposition.

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At least one doesn't need to concern oneself unduly with the scale-dissolving chemistry. However, in many cases we must attack the problem with chemistry. Before embarking on a search for solvents that will work, and certainly before pumping untested solvents into a well, it is very wise to obtain representative samples of the scale or deposit for examination in a qualified laboratory. The examiner will want to determine the scale composition and then the appropriate solvent composition to remove the deposit. Occasionally, as mentioned, there are actually two deposits; an oily (organic) one and a water based (inorganic) one, occurring in concentric layers or rings. In such cases, it has often been useful to consider pumping two different solvents combined in an emulsion or dispersion. As mentioned, solvent selection begins with identification of the deposit. Given an adequate identification, most laboratories (service company and professional) will be able to suggest an appropriate solvent from among the available oil field solvents. The simplest is water, and more often an acid or other chemical will be required. For organic deposits, hydrocarbonbased solvents (e.g. toluene, xylene have been used). Specialty solvents such as EDTA have been used for many years and continue to be effective in the right applications. When the scale has been removed and when the conditions which led to its formation in the first place are understood, it may be possible to design a treatment to help prevent or slow the formation of new deposits. Often such a treatment will involve squeezing a chemical inhibitor mixture into the formation.

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ADDITIVES AND TECHNIQUES FOR SPECIAL CASES

One of the most important aspects of the successful use of acids is the proper selection and use of appropriate additives. In many cases, there are proper or preferred sequences to follow in job execution and other special techniques for enhancing success ratios.

INHIBITORS

One of the more important additives for acid solutions to be used in wells is the inhibitor. This is also the one to which, regretfully, perhaps the least attention is paid. It is important to recognize that hydrochloric acid has the ability to dissolve iron (steel) as used in well tubing and casing. The rate of dissolution can be controlled by the use of chemicals called inhibitors. The name is very appropriate because the reaction of the acid on the steel is only slowed, not stopped. Therefore even inhibited acid will dissolve the tubing or casing if it is left in contact for sufficient time. The reaction is very temperature-dependent and the amount of inhibitor required to give a certain level of protection must be drastically increased at higher temperatures. The service companies have developed curves for the design of inhibitor concentrations. The curves generally are created from tests done on a particular steel and show the metal loss in mass per unit area per day for various concentrations of inhibitors at various temperature conditions. It is important to remember that the reported numbers are averages and the attack of acid on steel is seldom even. Perhaps the most effective inhibitor was the arsenic-based inhibitor, which was discontinued for safety reasons some time ago. The inhibitors function by creating a protective film between the metal of the tubing and the acid solution. The organic inhibitors currently in use are _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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generally quite effective for the normal condition, and up to a moderate temperature level. However, there are special conditions created when hydrogen sulphide is present. The condition known as sulphide stress cracking of the metal surface can occur unless special stress cracking inhibitors are used (Keeney et al, 1968). An important characteristic of inhibitors is that they do not tend to stay well mixed in the acid. Consequently the inhibited acid solution should be well agitated just prior to pumping it to the tubing. Many inhibitors perform better and more reliably when the acid contains a mutual solvent such as EGMBE (ethylene glycol monobutyl ether).

HYDROGEN SULPHIDE

When hydrogen sulphide is present, as mentioned above, the (ordinary) inhibitor may be seriously affected. A special inhibitor for hydrogen sulphide conditions should be used. Also, and perhaps equally important, there is a serious safety hazard which must be addressed. As is widely known, hydrogen sulphide is a very deadly gas even at very low concentrations. Safety precautions must be followed if hydrogen sulphide is even suspected. An important item for consideration is that hydrogen sulphide may be produced on an acid job even though the well is not sour. This is because tubing and sometimes even casing is reused from well to well. If tubing has been in a well in which there was a hydrogen sulphide environment, there is likely to be an iron sulphide scale formed on the tubing. If this scale is then contacted with acid, it is probable that one of the products of reaction will be deadly hydrogen sulphide gas.

SURFACTANTS

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Acidizing almost always involves the use of chemicals which have the ability to alter the surface and/or interfacial tension properties of the acid. These chemicals are called surface active agents, or surfactants. While they may be similar in a general way, their specific purpose and effectiveness varies considerably. A very important factor that must be taken into consideration is that chemical additives must be compatible. Additives are anionic, cationic, nonionic or amphoteric in behaviour. Cationic surfactants and anionic surfactants should never be mixed in the same solution without first performing detailed laboratory work to confirm the effectiveness of the mixture in all respects, and to confirm that no harmful precipitate is formed. The result may otherwise be that a precipitate will be formed that could possibly plug the formation and, perhaps worse, both chemicals will be ineffective.

EMULSIONS

The most widely used family of surfactants in acidizing is the one known in the trade as emulsion breakers, sometimes referred to as de-emulsifiers, demulsifiers, non-emulsifiers and so forth. The purpose of the additives is to prevent the formation of emulsions between the acid or the spent acid and the crude oil of the reservoir. There is no universal non-emulsifier. Many disaster stories can be told regarding failure to use a non-emulsifier, or failure to use the correct one, of failure to recognize that the presence of other chemicals in the acid, or the reservoir, may affect the functioning of the non-emulsifier. Acid treatments should never be performed unless a series of laboratory tests has been done to determine the correct concentration of the correct non-emulsifier to employ for treating a particular reservoir. It is also important to verify the effectiveness of the chemical in preventing emulsions with the spent acid.

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A standard test procedure was suggested by the API in API RP 42 Second Edition January 1977. The API website no longer lists this publication. This should have been the minimum test standard. It was resisted by some service companies because the standard required the use of finely dispersed solids consisting of silica flour and bentonite to simulate the emulsion stabilizing effect of the fines which are found in formations. This applies in the live acid test as well as the spent acid test.

SURFACE TENSION Occasionally, operators require that the acid and spent acid have a very low surface tension in order that the acid may be recovered from the fine matrix capillaries more easily. There are a number of additives of varying effectiveness available from the service companies for this purpose. Data substantiating the effectiveness of the additives should be requested and provided.

WETTABILITY

The surfactants that are commonly used are mostly water-wetting agents. That is they cause the rock to be preferentially water-wet in the presence of both oil and water. Caution is advised, however, and the wetting characteristics of any surfactant employed by the service company should be determined. Further caution is advised in that some chemicals tend to water wet sandstone while oil wetting carbonates and/or vice versa. API RP 42 also provided test procedures for determining wettability tendencies of surfactants.

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MUTUAL SOLVENTS

Sometimes wetting agents by themselves will not be as effective as desired in actually converting the rock surface to a water wet condition. In many of these instances the use of mutual solvents such as EGMBE (Ethylene Glycol MonoButylEther) can be effective in stripping the oil wetting natural surfactant from the rock surface. It has been observed that EGMBE may actually make many of the additives perform better than if the mutual solvent were not present. However, as with all additives, mutual solvents should be checked in the laboratory with all of the fluids and solids involved to be sure there are no incompatibilities or adverse effects before using in the field.

RAPID REACTION RATE

In certain instances, it may be desirable to increase the rate at which the acid reacts with the reservoir rock (or scale). One of the ways to do this is to employ concentrated acid. The reaction rate while the acid is still concentrated is more rapid. However, as the acid spends, the reaction rate is slowed due to the presence in solution of the reaction products. Another way to increase the reaction rate is to increase the temperature at which the reaction takes place. This may be done by heating the acid, heating the formation either by pumping a hot fluid into a colder formation, or by causing an exothermic reaction to take place in the reservoir, thereby allowing the acid reaction to take place in a warmer environment. One of the service companies has introduced a chemically heated acid to achieve the latter. It appears to be somewhat similar to the approach used many years ago by another service company in which powdered magnesium or aluminium was reacted with acid downhole to create substantial heat. These approaches, if they can be properly controlled, may have application in increasing the reaction rate on dolomites under cool ambient bottom hole conditions.

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SLOW REACTION RATE

In instances where it is desired to slow or retard the reaction rate, there are a number of approaches, including the following: o

Cool the formation by a cold preflush. Some of the service companies have computer programs for determining the volumes, rates and temperature changes involved.

o

Simulate the products of reaction in solution by adding carbon dioxide or calcium chloride to the acid. Or start by using more concentrated acid (the reaction rate after the acid spends to fifteen percent is retarded due to the reaction products of the previous partial spending - common ion effect).

o

Employing acid systems in which the acid is the internal (dispersed) phase of an emulsion.

o

Using slower reacting organic acid systems or mixtures.

o

Use of an oil wetting surfactant.

DEEP PENETRATION

To obtain deeply penetrating unspent acid, the pumping rate, concentration, and viscosity of the acid can all be increased. The fluid loss of the acid should be decreased. A caution with respect to injection rate and viscosity increase is important. It must be remembered, from the fracturing portion of this course, that the height of hydraulic fractures is largely determined by the in situ stress and the stresses imposed during fracturing. There may

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be a limit beyond which additional pump rate and additional viscosity will increase only fracture height rather than depth of penetration.

SHALLOW PENETRATION

To achieve shallow penetration is essentially to do a matrix acidizing treatment, already discussed. Diversion technology may be useful.

IRON

Iron, particularly ferric iron, can significantly affect the performance of the acid package in respect to emulsification tendency and more particularly in regard to the tendency to form sludge deposits. Because of this recognition, an increased level of attention has been given to the provision for testing acid packages in the presence of iron. Where iron is present and because it is desired to prevent the precipitation of ferric hydroxide, there are a number of additives that are effective to varying degrees. Both citric and acetic acid, if incorporated in the treatment solution have the ability to maintain a lower pH of spent acid and to increase the amount of iron that may be retained in solution by the acid. Together they work synergistically and effectively. Other effective chemical methods to address the problem of ferric iron have been developed by the service companies. A major source of iron is the mill-scale on the interior of the tubing. Together with other materials that may be on the interior of the tubing, such as previously pumped solids, pipe dope and so on, the mill-scale and associated debris should be flushed from the tubing by slowly pumping a pill of hydrochloric acid and suitable additives to near the bottom of the tubing, and then quickly reversing to surface disposal. The same cleaning pill should be pumped through the surface treating lines as well.

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The same general precaution should be taken when acidizing through coiled tubing. However in that case the acid should be flushed through the coil while it is still reeled and not while it is in the hole. This is because unnecessary reverse circulation down the annulus and up coiled tubing is not recommended because the coiled tubing may have very little resistance to collapse pressure. If it is also desired to clean the inside of the production tubing, the wash could be done down the coiled tubing while it is inside the production tubing, and up the annulus between the two.

FINES RELEASE AND CLAY PROBLEMS

Most formations contain fine particles in addition to the main rock forming grains. The fines may be either much smaller grains of the same material that makes up the bulk of the rock, for example silica or calcite, or they may be material that represents alterations of the rock material that has taken place over geologic time. For example, feldspar may alter to kaolinite clay. They may also represent deposits that have been formed over long periods of time as a result of a change in the chemistry of the fluids flowing through the rock. Depending on their composition, fines may be soluble or insoluble in acid. If they are soluble, there is no problem posed by their presence, provided enough solvent is available to consume all the fines to a given radius. If fines are only partially consumed, and are dislodged from their original position, they may be set free to move in the reservoir pore system. Should that happen, the particles may bridge at a pore throat, either individually or collectively. This could restrict production. If the released fines that cause bridging are not soluble in acid, a much more serious problem could result. A permanent flow restriction could be created. In carbonate reservoirs, the fines may migrate all the way to the well bore and be produced. If they did not, more acid could be injected to enlarge the flow passages and thereby release the fines to flow to the well bore. In sandstone reservoirs the problem is more difficult since the matrix rock is not as easily soluble.

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The designer of completions for reservoirs containing insoluble fines is faced with the problem of conducting the completion without releasing the fines. Fortunately, there is a family of chemical additives available from the service industry that is designed to alleviate this dilemma. The chemicals are called clay stabilizers (or fines stabilizers). They function by causing the clay particles, which are in a certain position in the rock matrix before disturbance, to be fixed in that position by a chemical additive. Various proprietary chemicals are used for this purpose and their effectiveness varies greatly. Before embarking on a widespread program involving the use of clay stabilizers, the particular reservoir rock should be tested with a number of available stabilizers. The tests should be designed so as to determine both degree of effectiveness of the chemical, and degree of flow impairment caused by the chemical. Some special acids are said to have clay stabilization ability (Thomas et al, 1978).

FRACTURE CONDUCTIVITY

Where high fracture conductivity in calcareous formations is required, the concepts previously presented regarding etching patterns and depth of penetration must be considered. Alternatively, proppant may be incorporated in the treatment, especially if laboratory work indicates that even etching patterns will be difficult to avoid.

FRACTURE GEOMETRY

As discussed earlier, fracture geometry is largely controlled by the in situ stresses which exist in the various formations, and in the layers within each formation. The designer needs to know the approximate contrast in stress level between the zone of interest and the surrounding formations in order to design job execution limits. These limits will be affected by the factors that control the friction pressure in the fracture under dynamic treatment conditions. These include viscosity, pumping rate, and total volume pumped. When those limits have been determined, the designer may then employ specific options to try to control the shape of the created fracture, and the shape of the etched portion of the fracture. These include such items as type of acid or acid blend, diverting methods and so forth. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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CALCAREOUS FORMATION DAMAGE REMOVAL

To remove formation damage in a calcareous formation can be easy or difficult depending upon the location and type of damage. The first task is to identify the cause of the damage. This will help the designer to prescribe an effective material to cure the problem. However, the next task is to determine the location of the damaged area and how the treatment material may effectively and thoroughly contact the damaging (plugging) material. If the material that is causing the plugging is acid soluble, then the location of the damage becomes all-important. If the damage is deep in the reservoir (more than a few feet), the acid required to dissolve the plug may spend on the limestone nearest the well bore and never reach the target. Either large volumes of solvent may be required, or an alteration in the design of the solvent may be suggested. For example, a much slower acting acid may be required. One of the most important restrictions that face the designer of damage removal treatments in carbonates is the inability to use hydrofluoric acid. This fact coupled with the inability of hydrochloric acid to dissolve clays or drilling muds is a significant restriction, especially if damage is deep. Occasionally, physical removal, in addition to the use of chemical means, is suggested. This could involve the use of energizing gases such as nitrogen to help transport the plugging material to the well bore. The use of special devices to control the interval into which the solvent is to be injected is a common approach. The carbonate formations present one advantage over sandstones for the designer of damage removal treatments. The designer may achieve success by simply enlarging the flow channels

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between the damage point and the well bore. This may permit the damaging substance to be produced to the well bore and removed.

SANDSTONE FORMATION DAMAGE REMOVAL

To remove damage in sandstone reservoirs is in some ways more difficult than in carbonates. The option of dissolving a channel to the damaged zone, while not impossible, is not practical. The major advantage for the designer is the ability to employ hydrofluoric acid if required. The usual precautions for the use of this material are advised. The ability to remove deep formation damage is much greater in sandstone than in limestone due to the better ability to get deeper penetrating reactive solutions to the point where they are needed.

FRICTION REDUCERS

When high injection rates are required during acidizing treatments, special friction loss additives are available for acid. As with all other additives, they should be tested for compatibility with the other ingredients in the acid and also with the formation rock and fluids.

FLUID LOSS ADDITIVES

There are a number of ways to control the fluid loss of acidic solutions. One is to employ the chemical additives which are used for this purpose in conventional acidizing treatments. Another is to employ insoluble agents such as silica flour or 100 mesh sand to help divert the acid away from natural fissures. One cannot ignore the potential damaging effect of these solids. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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By incorporating the acid in an emulsion, or by using gelling agents, the rate at which fluid is lost may be reduced due to viscosity. The use of foams is an effective fluid loss control mechanism (Schernbol et al, 1979).

HEAT GENERATORS

As discuss earlier, techniques are available to generate heat in the acid solution, or in the formation just ahead of the acid solution. These techniques may be helpful in slow reacting formations such as shallow dolomites. They may also help prevent precipitation of paraffin due to injection of cold acid.

COMPLEXING AGENTS

The use of complexing agents, also called sequestering agents, to help prevent the precipitation of ferric chloride is well known. The most common ones are acetic acid, citric acid, lactic acid, gluconic acid, EDTA (ethylene diamine tetracetic acid) and NTA (nitrilo triacetic acid). All have their application and some are more effective or expensive than others. There is a major caution. The use of citric acid must be carefully considered. Although it is effective, there is a danger of calcium citrate precipitation in the absence of sufficient ferric oxide. This is also true, although to a reduced degree, when it is used in a mixture with acetic acid.

OTHER ADDITIVES

There are a number of other additives which are applied with acidizing solutions. Perhaps the most important of these is the family of antisludge additives. A great amount of work has been

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done by the industry on the problem of sludge formation during, and as a result of, acid treatments over the past 35 years (Moore et al, 1965). The one thing that appears to stand out from this research is that the screening and laboratory testing procedures are very critical and that the API test procedure can be used as a guide, but more rigorous procedures to account for specific field conditions are also required. For example, the presence of iron in the acid solution has been shown in some cases to be an important factor in sludge formation tendency.

METHODS OF PLACEMENT

In addition to selecting the appropriate solvent, the correct method of placement is vital to the success of acid treatments. Paramount in proper placement is the availability and use of proper tools and instrumentation.

INSTRUMENTATION

The ability to monitor the performance of the acidizing treatment, whether it be a matrix or a fracture treatment is vitally important to the success of the treatment. For this reason adequate instrumentation is required. For fracture acidizing treatments, the same instrumentation is suggested as is needed for hydraulic fracturing treatments, including the computerized monitoring and data acquisition units. The absolute minimum instrumentation for any type of treatment should include a pressure recorder and a pumping rate and volume indication. It is better if the pressure and rate can be recorded on the same strip chart and the cumulative volumes noted on the chart.

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Certain items of laboratory equipment should be available on location. The most important of these is a good supply of sample bottles. Water tight, screw top, acid resistant plastic bottles are preferred. A portable centrifuge and tubes will also be helpful. A hydrometer and hydrometer jar are required for verifying the concentration of acid delivered to the location. However, using the titration method is more accurate and the test is not influenced by salts that may be dissolved in the acid. Litmus paper will be useful for determining the pH of the returning spent acid. Where gelled solutions are to be employed, methods of determining the quality of the gel such as rheometers and/or funnels are helpful. Thermometers and portable heating baths make representative emulsion testing easier.

PUMPING EQUIPMENT

For matrix acidizing operations, one of the prime requirements is to avoid fracturing the formation. Consequently, the ability to pump slowly and steadily is very important. Very accurate measurements must be possible of volumes pumped and very small changes in pressure. This implies that a measurement tank and an accurate pressure recording device must be available on the acid truck. The pumping system must be leak free, including the pump valves. Any decline in pressure after pumping stops must be confidently interpreted as a formation response. Acid resistant pump packing is an important requirement in this respect as well as in enabling completion of the job. The best measurement tanks for the acid pumper are rubber or epoxy lined to reduce the amount of iron introduced.

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SPECIAL EQUIPMENT

For larger jobs, the acid storage tanks should above all else be vented, leakproof, clean and rust free. The discharge nozzles must be adequate to permit designed pumping rates. Tank bottom capacity should be small and should have recessed suction pits to enable nearly complete emptying. For larger jobs, a small transfer pump to transfer tank bottoms to the last tank is helpful in salvaging all possible acid and also in minimizing the volume of tank bottoms that must be neutralized and disposed of after the job. RECENT DEVELOPMENTS AND NEW TECHNOLOGIES The first part of this portion of Well Stimulation Suite 2008 deals with new developments in hydraulic fracturing and acidizing technology. It will be include a section on stimulation technologies other than acidizing and fracturing.

ADVANCED AND RECENT ISSUES IN ACIDIZING

The theory and application of acidizing technology for improved recovery of oil and gas resources has continued to develop. Some of the more significant advances of recent years are discussed here, with reference, as needed, to older technology as well. Some of the issues have been related to the following topics: o

Chemistry of the reaction or series of reactions and how to avoid undesirable and perhaps unexpected effects of acidizing, particularly when using HF/HCl acid

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o

Treatment of high temperature wells - corrosion aspects

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Treatment of high temperature wells, chemical and formation aspects including improved live acid penetration

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Creation of emulsions, sludge and other deposits as a result of acidizing with HCl

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Methods for increasing the effectiveness of damage removal and other matrix acidizing treatments

The possibility, and even probability, of causing damage during acidizing treatments has been well addressed by investigators over many years. A particularly good reference at the time of its publication is Walsh et al (1982). The mineralogical composition of reservoir rocks and the composition of both reservoir, injected (e.g. mud solids and filtrates) and treating fluids is often very complex. It would be fortunate if there were not some amount of precipitated material resulting from the various interactions. The challenge is to get the required job done with a minimum of additional created damage. The main point is to remember to get the job done rather than put all the emphasis on avoiding additional damage. Service companies (Economides et al, 1989), (Halliburton Energy Services, 1994) have provided "decision-tree" or "expert" systems for the design of matrix acidization treatments. A number of published articles have appeared since then. Nevertheless, an understanding of the various and complicated reactions is helpful. While some fundamental work was published by Labrid (1975) and others, recent developments (Gdanski, several since 1994) suggest that some aspects may have gone unnoticed in earlier work.

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Gdanski (1994) has reported the results of an investigation into solubilities of sodium and potassium fluosilicate with a view to determining optimum safe HCl-HF acidizing compositions for treating sandstone formations containing feldspars. His work revealed that the multistage reaction was not as previously described. Consequently, an explanation for previously unexplained (properly) deposition following HF acid treatments was developed and tested. This further resulted in a recommended set of treatment solutions for various temperature conditions. Please see the following table. Fluid Recommendations For Na-Spar Temperature Range T

175 0F

HF Mixture 13.5% HCl - 1.5% HF

T < 175 0F

9.0% HCl - 1.0% HF

Possible Fluid Recommendations for K-Spar Temperature Range 250 0F

T

250 0F > T 0

HF Mixture 13.5% HCl - 1.5% HF

200 0F 0

9.0% HCl - 1.0% HF

200 F > T

175 F

7.0% HCl - 0.75% HF

175 0F > T

125 0F

6.0% HCl - 0.5% HF

125 0F > T

100 0F

6.0% HCl - 0.4% HF

Fluid Recommendations for Illite Temperature Range T

200 0F

HF Mixture 13.5% HCl - 1.5% HF

200 0F > T

125 0F

9.0% HCl - 1.0% HF

125 0F > T

100 0F

7.0% HCl - 0.75% HF

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More recently, Gdanski and Schuchart of Halliburton as well as Di Lullo and Rae of BJ have published additional, more definitive data, particularly with respect to the selection of acidizing compositions for specific formation mineralogy.

High Temperature Considerations Hydrochloric acid treatments of high temperature reservoirs remains a problem for two important reasons: o

Effectiveness of organic acid inhibitors at high temperatures becomes very limited.

o

Reaction rate of commonly used acids is very fast at high temperature.

The net effect is that the number of resultant problems due to attempting this type of treatment and the cost of such problems is often greater than the benefit under the conditions. If a treatment must be designed and done even under such conditions, the informed opinion of the very best authorities should be sought.

Modeling of Acid Fracturing

Although not widely used so far, more advanced numerical models of acid fracturing processes are available (Settari, 1993). One of the main practical problems is to quantify the conductivity of the closed, etched fracture.

Paccaloni's Methods for Improved Matrix Acidizing

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Engineers with AGIP have developed systematic approaches to matrix acidizing in an effort to improve upon the success ratio for such treatments in exploration, appraisal and development wells of both calcareous and clastic formations. (Paccaloni et al, 1993, Paccaloni et al, 1988). The authors present a theoretical base for a very practical technique that includes setting matrix acidizing operational goals (e.g. reduce skin factor to zero) and making rate and pressure predictions prior to the job. The actual field job is then performed with the goals and predictions in mind and variances are accounted for and, hopefully, overcome. Significant in the approach is the recognition of the operational aspects in addition to the design features. Emphasized features include the use of coiled tubing to clean out the entire treatment area within the wellbore prior to starting the treatment, pre-cleaning of the tubing string before the operation and provision of sufficient treating fluid and pumping power to achieve the pressure and rate goals. In some cases, the choice of stimulation fluid was found to be the reason for a fairly high percentage of initial damage removal treatment failures. It is particularly interesting to note that the authors report that they feel very strongly, based on field experience, that the use of HCl preflushes ahead of HF/HCl acid treatments for damage removal in severely damaged sandstone formations should be dispensed with. It is far more important to get the most aggressive acid for the problem rather than to try to protect an already brain-dead well against further damage from the secondary reaction of HF reaction products and some minor rock constituents. For wells that are not severely damaged, the preflush is still recommended. It is a question of specific case priority. Graphical solutions for developing targets for damage removal for a specific well are presented in the 1988 paper.

Placement Control Methods

While selecting the best chemical formulation for a matrix treatment is important, it is arguably less important than the method of placement. Unless the majority of the exposed wellbore is

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treated sufficiently, there is likely to be remaining damage after the treatment. Placement of the appropriate fluids across and into the whole zone is often critical. Availability and use of coiled tubing is fundamental to the success of many matrix treatments. The coiled tubing allows the acid or even more importantly each stage of the acidizing treatment to be placed across the entire zone. This is not as easy to accomplish without the coiled tubing, and is often overlooked, in some cases because of the added complication. Even though the entire zone is exposed, sometimes the higher permeability sections will accept a majority of the fluid at the expense of less fluid entering the lower permeability portions. In such cases, a method to divert the fluids is often very helpful, if not essential.

Foam diversion

Thompson et al (1993) have conducted a series of controlled laboratory experiments in which factors that influence the foam-diversion of acid from high permeability to low permeability were identified and quantified. They concluded that the important factors were foam quality, rock permeability, permeability contrast, whether the foam was brine- or acid-based, If injection rates are sufficiently high and the number of perforations accepting fluid is sufficiently low, the use of ball sealers can be an effective diverting technique, at least inside the casing. There is often concern that behind-the-casing communication may carry fluids directly to the high permeability area again, without significant treatment of the zone to which the ball sealers were supposed to divert the treatment fluids. Occasionally, temporary plugging materials such as graded rock salt carried in a saturated brine solution (or other degradable solids) can be used where it is suspected that diversion is needed behind the casing as well as at the perforations.

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How to Help Prevent Sludge by Proper Testing

The problem of precipitation of sludge, usually but not always associated with asphaltene and paraffin and often complicated by iron has been recognized for a number of years. As a result of some particularly nasty situations in Canada, several aspects of the identification and handling of the problem have been high-lighted: o

Proper wellhead sampling

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Prompt and proper field testing

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Effect of iron

o

Separation of additives such as surfactants

o

Inter- reaction of various chemicals necessary for the treatment

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RECENT FRACTURING TECHNOLOGY Fracturing Fluids Driven by competitive forces and sometimes also by client effort to reduce costs, servcos have developed a range of products. The use of cleaner frac fluids, some based on viscoelastic surfactants is emerging as an important issue. The emergence over the last decade or so of industry consortium-supported independent testing laboratories has significantly improved the confidence of the industry regarding the quality of frac fluid performance data. Hot hole fluids As worldwide oil and in some places, natural gas, prices continue to increase, the need to explore and develop deeper reservoirs increases. One of the challenges is to develop fracturing fluids that will meet performance requirements at the higher temperatures. Cold hole fluids For colder reservoir conditions (e.g. shallow gas areas) there is a different challenge. We need frac fluids that will gel in colder climates that will perform as required (including breaking time and low residue requirements). Importantly, the fluids must also be economical for use in sometimes marginal low pressure shallow gas applications.

Fluid Recovery Concerns In addition to the impairment caused by residual viscosity after gelled fluids have "broken", there is also concern about recovery of fluids from rocks in which the fluids are retained as a result of imbibition into capillaries. _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Several fluids and additives have been proposed for improving this aspect, which is not limited to water-based fluids. Propping Agents While propping agent technology has given us a number of artificial proppants, the preponderance of propping agent used is still sand. The supplies of economically producible fracturing quality sand are finite. Production economics will surely force an increase in costs which will in turn force users to choose between accepting lower standards (probably not a good choice) and using artificial proppants, whose supply is not so limited. Some investigations have already been proposed in regard to the necessity of using proppants at all for some applications (Mayerhofer et al). Development of a Low Density Proppant SPE papers 84308 and 84309 discuss the development of a very low specific density (1.10 to 1.15 g/cm3) artificial proppant. This is a relatively new development and is well worth considering, as more experience is developed. The low density almost precludes proppant settling and therefore the need for high viscosity for transport is obviated. Viscosity is a factor in fracture width, however. Nonetheless, if gelling agents can be eliminated from the frac fluid recipe, the potential for residue or unbroken gel damage in the fracture is greatly reduced.

Proppant Retention Problems and Technology Following the successful placement of a fracturing treatment it is obviously desirable that all of the placed proppant should remain in the fracture.

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Often, significant amounts of proppant are produced out of the fracture and cause production operations problems due to erosion, scoring of equipment, workovers to clean out the proppant, proppant and fluid disposal and flared-gas environmental problems and so on. Several products are available from service companies to assist operators in reducing the frequency/severity of the problem. These include curable resin-coatings on the proppant, fibers mixed with the proppant and additives to change the characteristics of the proppant surface to make them more "sticky". All methods have claimed some degree of success and all have not been 100% successful. A paper (Petroleum Society 2001-106) compared the performance of these methods in a field trial and (in that case) concluded that the curable resin-coated proppant was best. Some clear success has also been achieved by careful control of the flow-back rates, particularly during the first few hours and days of the frac fluid recovery period. This allows the increasing effective stress on the proppant during drawdown to cause the proppant to achieve closer packing. This helps to lock-in the proppant grains and was clearly successful in a case in the writer's personal experience. The case involved a high permeability gas well requiring s short, high conductivity frac to overcome near well bore damage. Data Acquisition and Interpretation The disadvantages of packer completions in respect to data acquisition are well known. The data are required to monitor the treatment in real time and to make appropriate on the fly decisions that could have great impact on the treatment effectiveness. The lack of a static-leg to use as a conduit for well pressure from the bottom of the tubing to the surface forces operators to make a difficult decision. They must decide whether they want to pay for an expensive installation of bottom-hole sensing/surface readout equipment or whether they _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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prefer to rely on likely inaccurate computer calculation based upon catalogued performance of fracturing fluids. There are numerous examples of incorrect decisions being made as a result of reliance on inferred rather than measured data. A common cause of incorrectly inferred information is when an unprogrammed change in fracturing fluid characteristics takes place. This change could be due to a single tank of frac fluid not performing within catalogued specifications. The computer doesn't recognize the change and continues calculating friction properties as before. In fact the friction properties are not correct. The result is that the calculated bottom hole pressure and calculated net pressure are incorrect. Since net pressure variations are the basis for many decisions taken during job progress, there have been erroneous decisions taken which have a harmful economic impact. . Memory recorders, if used for bottom hole data, can help in post-job analysis of such situations. They can't provide real time data however and the field personnel are still left naked insofar as having correct information in real time when they can use it effectively. Fracture Diagnostics Developments Significant developments in the area of fracture diagnostics are continuing. A number of papers have been published in the most recent years regarding the use of more unusual diagnostic tools including: Surface tiltmeters Downhole tiltmeters Studies of microseismic events Multiple-radioisotope tracer applications Integrated interpretation of multi-sourced information Laboratory Testing Techniques _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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Some interesting laboratory testing developments have emerged relatively recently. There has been a concern about the amount of damage caused by well stimulation treatments involving gelling agents and unbroken gel, especially hydraulic fracturing. The concern was proved to well-founded in a number of instances reported in the literature. Service organizations have responded well by developing better breaker systems, by developing chemicals to treat unbroken gel in fractures and by the application of well known encapsulation techniques to transport the gel breaker to the fracture as a solid. This helps ensure that there will be sufficient breaker concentration in the fracture, where the preponderance of gel filter cake will be located. Most service companies either by patent or license now have access to this technology. Some interesting work has been done by at least one testing laboratory to evaluate the threshold differential pressure required to lift the filter cake deposited on formation samples during fluid loss tests by various treating systems under dynamic (circulating) test cell conditions. They have attempted to reconcile the lab determined threshold pressure with the available differential pressure at the fracture face in the reservoir and use that as one basis for comparing possible treating fluids. Modelling and Simulator Improvements While small improvements in simulators are made on a continuing basis, one such improvement is the ability to have more than one set of perforations open during fracture modelling. Treatment of Horizontal Wells The application of damage removal and well stimulation techniques in horizontal wells continues to develop. The major problem in damage removal treatments is to identify and treat the entire damaged area cost effectively. Unless it can be shown that damage is very shallow, _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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relatively large volumes of fluids will be required, even if the treating fluid can be made to penetrate evenly. More than likely the fluid will penetrate preferentially to the higher permeability or undamaged rock, leaving the lower permeability or more damaged rock untreated. The use of coil tubing conveyed, rotating washing nozzles holds promise.

HYDRAULIC FRACTURING OF HORIZONTAL WELLS The treatment of horizontal wells by hydraulic fracturing can be very difficult. Many H-wells are drilled carefully and under-balanced in an effort to avoid formation damage during the drilling phase. This, hopefully, may result in an unstimulated completion that meets expectations. However, many operators have found that in spite of so-called best efforts, there is still a significant amount of formation damage. The removal of this damage can involve a variety of approaches. Some prefer to use coil tubing and a jet-washing approach, employing a variety of nozzles and techniques for application. Others prefer to hydraulically fracture through the damage, raising questions concerning the best location to initiate the fractures, how many should be initiated, what size should they be and how can we do this? In terms of avoiding damage and removing damage should it occur, suffice it to say that there are high hopes and lower successes. One of the difficulties in damage removal is in making certain that all damaged intervals are adequately treated. The mechanics are probably as important as the chemistry. In areas in which natural fractures are prevalent, and especially where connecting to the fracture system is essential for adequate production, many operators employ uncemented liners. The purpose of the liner is to prevent loss of the wellbore due to cavings which are known to occur. The operator's reason for not cementing is that all potential fracture systems should be exposed and not damaged. The liners are later perforated at the appropriate intervals, according to logs. If the well fails to meet expectations, a damage removal treatment is attempted. However, inability to control fluid movement in the uncemented annulus is the problem. There is no effective way to effectively treat the desired intervals with confidence. A foam diversion program is the current most popular choice in some areas. Fracture initiation at specific desired intervals is also problematic and most uncertain.

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The above suggests that the answer may lie in properly cementing the liners in place using a carefully designed slurry that will minimize invasive damage. The desired intervals may then be selectively perforated and treated beginning at the toe. That alone will not eliminate problems. SPE paper 64383 by Pinnacle Technologies and Amerada Hess provides an excellent analysis of problems, analysis and solutions to a variety of problems in a particular North Sea field. Readers will be exposed to some excellent analytical approaches that may be very useful for similar applications in other areas. A notable observation was that pressure-sensitive fluid loss issues were related to natural fractures (fissures) and that slugs of 100 mesh proppant required concentrations of at least 480 kg/m3 (4.0 pounds / gallon) to seal. It was also noted that cross-linked fluid after the proppant slug would be less likely to create complex (multiple) fracturing, and therefore result in lower pressures and more successfully completed treatments. This paper is recommended reading for those contemplating fracturing of horizontal wells.

Multiple Fractures Through Coiled Tubing: In a shallow gas area, multiple consecutive fracture treatments for greater zonal coverage using CTU-conveyed straddle packers has developed into a major application. One service company reports that they are doing up to 50 fracs per day out of one station using this method. In some wells, as many as thirteen individual zones are being treated. The users suspect, and some say they have confirmed, horizontal fractures in the highly stratified, highly lenticular reservoir.

Refracturing Of Already Fractured Wells Once wells have already been fractured the question or re-fracturing arises (either immediately after the treatment or at some time (perhaps years) later.

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One obvious context is when the stimulated well fails to produce up to (realistic) expectations. The issue is whether or not the first treatment was optimally designed and conducted. The second context is whether, (even with an optimally designed and conducted first frac), could a second frac provide even enhanced results? In the first case, if a poorly designed or conducted frac was done, there is a very good chance that a properly conducted one would yield better results, if it could be adequately completed. There is a multitude of reasons why the first may have been sub-optimal. Insufficient size, inadequate proppant type or concentration, inappropriate fluid, fracture contamination are among the most obvious. However, other reasons should also be considered, and, to a reasonable extent, evaluated. Other causes include: loss of containment leading to inadequate frac generation in the zone of interest and perhaps to unwanted fluid production from other zones, generation of a frac in an unfavorable azimuth and many others. Once a frac has been pumped that causes the containment to be lost, there is a very high probability that succeeding fractures will also have lost containment, perhaps through the same boundary failure. Some limited success has been achieved in retreatments, but the probability of no success is high. One of the questions always raised is whether the second frac will follow the trajectory of the first one or whether a different frac plane will be generated. A number of investigators have developed theory and there is field evidence that the second fracture may follow a different plane. The theory suggests that the creation of propped fracture leads to a different stress regime in the immediate area of the propped frac. This regime could be sufficiently different that the new frac would be oriented differently. This situation is more likely when the regional horizontal stresses are almost equal, as compared to the case when they are vastly different. The implication, if the above were true, would be that even successfully treated wells could be improved by exposing even more undrained reservoir. Schlumberger, Mitchell Energy, GRI and Pinnacle staff authored SPE63030 regarding results of a project designed to evaluate and take advantage of this concept. Initial results appear to be encouraging and this concept should be considered in any company's review of candidates for optimization by restimulation. A reading of this paper should provide a level of confidence in this thinking.

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TABLE OF CONTENTS INTRODUCTION ...................................................................................................................243 REACTIVE MATERIAL................................................................................................250 TYPES OF ACIDS .......................................................................................................251 TYPES OF JOBS.........................................................................................................251 GUIDELINES FOR APPLICATION..............................................................................251 REACTIONS................................................................................................................252 MAIN REACTIONS......................................................................................................252 HYDROCHLORIC ACID....................................................................................................252 WITH CALCITE .............................................................................................................253 WITH DOLOMITE..........................................................................................................253 WITH SIDERITE ............................................................................................................254 WITH DRILLING FLUIDS ..............................................................................................254 HYDROFLUORIC AND HYDROCHLORIC ACIDS............................................................255 WITH CALCITE .............................................................................................................255 WITH DOLOMITE..........................................................................................................255 WITH SIDERITE ............................................................................................................256 WITH SILICATES ..........................................................................................................256 WITH DRILLING FLUIDS ..............................................................................................256 ACETIC ACID....................................................................................................................256 WITH CALCITE .............................................................................................................257 FLUOBORIC ACID ............................................................................................................257 IMPORTANT SECONDARY REACTIONS ........................................................................258 CALCIUM FLUORIDE PRECIPITATION .......................................................................258 FLUOSILICATE PRECIPITATION.................................................................................259 IRON HYDROXIDE PRECIPITATION ...........................................................................260 TACHYDRITE PRECIPITATION ...................................................................................260 EFFECTS OF MAIN PARAMETERS .................................................................................261 CONCENTRATION .......................................................................................................262 TEMPERATURE............................................................................................................262 GEOMETRY, SURFACE AREA, VOLUME ...................................................................262 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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VISCOSITY ...................................................................................................................263 VELOCITY.....................................................................................................................263 FLUID LOSS..................................................................................................................264 METHODS OF APPLICATION ..........................................................................................264 PERFORATION WASHING...........................................................................................264 MATRIX ACIDIZING ......................................................................................................265 NATURAL FRACTURE ACIDIZING ..............................................................................267 NEW FRACTURE ACIDIZING.......................................................................................269 FRACTURE ACIDIZING WITH PROPPANT .................................................................269 USE OF FOAMED ACID ...............................................................................................271 PROBLEMS WITH SCALES AND DEPOSITS ..............................................................271 ADDITIVES AND TECHNIQUES FOR SPECIAL CASES..................................................274 INHIBITORS ..................................................................................................................274 HYDROGEN SULPHIDE ...............................................................................................275 SURFACTANTS ............................................................................................................275 EMULSIONS .................................................................................................................276 SURFACE TENSION.....................................................................................................277 WETTABILITY ...............................................................................................................277 MUTUAL SOLVENTS....................................................................................................278 RAPID REACTION RATE..............................................................................................278 SLOW REACTION RATE ..............................................................................................279 DEEP PENETRATION ..................................................................................................279 SHALLOW PENETRATION...........................................................................................280 IRON..............................................................................................................................280 FINES RELEASE AND CLAY PROBLEMS...................................................................281 FRACTURE CONDUCTIVITY .......................................................................................282 FRACTURE GEOMETRY..............................................................................................282 CALCAREOUS FORMATION DAMAGE REMOVAL.....................................................283 SANDSTONE FORMATION DAMAGE REMOVAL .......................................................284 FRICTION REDUCERS.................................................................................................284 FLUID LOSS ADDITIVES..............................................................................................284 _____________________________________________________________________________________ © PORTEOUS ENGINEERING LIMITED

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HEAT GENERATORS ...................................................................................................285 COMPLEXING AGENTS ...............................................................................................285 OTHER ADDITIVES ......................................................................................................285 METHODS OF PLACEMENT............................................................................................286 INSTRUMENTATION........................................................................................................286 PUMPING EQUIPMENT ...................................................................................................287 SPECIAL EQUIPMENT .....................................................................................................288 ADVANCED AND RECENT ISSUES IN ACIDIZING .........................................................288 Introduction....................................................................................................................283 High Temperature Considerations .................................................................................291 Modeling of Acid Fracturing ...........................................................................................291 Paccaloni's Methods for Improved Matrix Acidizing.......................................................291 Placement Control Methods ..........................................................................................292 Foam diversion ..............................................................................................................293 How to Prevent Sludge by Proper Testing.....................................................................294 RECENT FRACTURING TECHNOLOGY.

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