Formation Damage

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CHAPTER 12 FORMATION DAMAGE TABLE OF CONTENTS

12.1

INTRODUCTION ……………….…...……………....………….….….…..….…

3

Chapter Goals ………………………………………………………. Poor Productivity …………………………………………………... Formation Damage ………………………………………………… Wellbore Deposits …………………………………………………. Ineffective Perforating ……………………………………………... Treating Approaches ……………………………………………….

3 3 3 4 5 5

EFFECT OF DAMAGE ………………………………………………………….

6

Radial Flow ………………………………………………………… Darcy’s Law ………………………………………………………... Radial Reservoir Flow ……………………………………………... Productivity Index …………………………………………………. Inflow Performance ………………………………………………... Effect Of Damage Zone Thickness ………………………………… Effect Of Damage Location ……………………………………….. Matrix Treating Benefits …………………………………………… Matrix Treating Undamaged Wells ………………………………...

6 6 7 10 10 12 14 15 15

12.1.1 12.1.2 12.1.3 12.1.4 12.1.5 12.1.6

12.2

12.2.1 12.2.2 12.2.3 12.2.4 12.2.5 12.2.6 12.2.7 12.2.8 12.2.9

12.3

INDICATORS OF DAMAGE ……………………………………………...……. 17 12.3.1 12.3.2 12.3.3 12.3.4 12.3.5 12.3.6

Introduction ………………………………………………………… Offset Production …………………………………………………... Production History …………………………………………………. Reservoir Predictions ………………………………………………. Darcy’s Law Calculations ………………………………………….. Well Testing ………………………………………………………..

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Introduction ………………………………………………………… Clay Disturbance …………………………………………………... Clay Swelling ……………………………………………………… Clay Dispersion And Migration …………………………………… Low Salinity Clay Dispersion ……………………………………... Flow Induced Fines Migration …………………………………….. Effect Of Mobile Water ……………………………………………. Scale Deposition …………………………………………………… Asphalt And Paraffin Deposition ………………………………….. Emulsions ………………………………………………………….. Water Blocking ……………………………………………………. Wettability Changes ……………………………………………….. Acid Precipitates ……………………………………………………

21 22 23 23 23 24 24 26 27 27 29 30 30

Introduction ………………………………………………………… Matrix Treatments …………………………………………………. Acidizing …………………………………………………………… Solvents And Surfactants ………………………………………….. Hydraulic Fracturing ……………………………………………….. Tubing Treatments ………………………………………………….

31 31 31 31 32 32

DAMAGE PREVENTION ….....…………………………………………………. 33 12.6.1 12.6.2 12.6.3 12.6.4 12.6.5 12.6.6 12.6.7 12.6.8 12.6.9

12.1

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DAMAGE REMOVAL ………………………………………………………...… 31 12.5.1 12.5.2 12.5.3 12.5.4 12.5.5 12.5.6

12.6

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CAUSES OF FORMATION DAMAGE …………………....…...……………… 21 12.4.1 12.4.2 12.4.3 12.4.4 12.4.5 12.4.6 12.4.7 12.4.8 12.4.9 12.4.10 12.4.11 12.4.12 12.4.13

12.5

FORMATION DAMAGE

Drilling Fluid Selection ……………………………………………. Workover Fluid Salinity …………………………………………… Brines To Stabilize Clays ………………………………………….. Clay Stabilizers …………………………………………………….. Avoid Incompatible Brines ………………………………………… Surfactant Selection ………………………………………………... Drawdown ………………………………………………………….. Fluid Loss Control …………………………………………………. Injection Water Quality …………………………………………….

INTRODUCTION

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12.1.1

FORMATION DAMAGE

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Chapter Goals The purpose of this chapter is to introduce the engineer to the common causes of poor productivity which can be remedied by workover treatments. Special emphasis is given to poor productivity attributable to permeability reduction of the formation near the wellbore, commonly referred to as damage. Upon completing this section, the engineer should be able to recognize well productivity impairment, review information to identify its likely source, and avoid causing formation damage when possible. The radial flow theory necessary to understand the effects of damage and estimate unimpaired production is presented first. This is followed by a discussion of indicators of damage, causes of damage and damage prevention. Finally, a brief introduction to damage treatments serves to bridge the gap between this and subsequent sections.

12.1.2

Poor Productivity There are two major categories of poor productivity : (1) poor productivity attributable to reservoir characteristics, and (2) poor productivity caused by alterations in the formation near the wellbore or deposits in the production tubulars. Reservoir factors such as low pressure, low permeability, and high viscosity may be overcome through methods involving flooding, thermal methods and large hydraulic fracturing treatments. These approaches have in common that they are designed to affect large reservoir areas. However, for the purpose of this section, we are interested in causes of poor productivity that can be remedied by workover treatments localized to a particular well. Included in this category are formation damage and well deposits.

12.1.3

Formation Damage Poor productivity caused by flow restrictions in the reservoir rock is called formation damage. Formation damage is usually caused by disturbances to the formation or its native fluids during drilling, workover, and producing operations. Formation damage is generally limited to the reservoir rock lying within a couple of radial feet of the wellbore as illustrated in Figure 1.

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Figure 1. Damaged Zone Around A Wellbore Restricts Production

In contrast to reservoir limitations, formation damage can often be removed with relatively small treatments designed to treat the wellbore or penetrate only a limited distance into the formation.

12.1.4

Wellbore Deposits Material deposited in the production tubing and casing also is a common cause of productivity declines. Such deposits can consist of organic material such as paraffin, or mineral material such as calcite and barite, known as scale. These and similar solids often precipitate from produced fluids as they re-equilibrate with wellbore conditions. Removing wellbore deposits often involves a different approach than removing formation damage.

12.1.5

Ineffective Perforating

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Optimal flow rate from a particular well is also dependent upon establishing good communication between the wellbore and the reservoir. This is the goal of perforating. For various reasons however, perforations may not provide the necessary good communication. Charges may fail to ignite, or ignite below their design force, or the cement sheath may be thicker than the limited penetration depth of the gun. These limitations are associated with gun capabilities and may require re-perforation to achieve satisfactory flow. The perforating technique is also important for attaining perforating objectives. Specifically, it is widely recognized that perforations shot underbalanced in a clear fluid perform better than those shot overbalanced in mud. Overbalancing causes perforation debris and mud to become compacted in the tunnels, often necessitating an acid job to attain maximum deliverability. These are but a few examples of how the perforating process can effect well performance. For a more complete discussion refer to the section on Perforating.

12.1.6

Treating Approaches The type of treatment chosen is determined by the cause of the productivity impairment. Formation damage is often treated with acids and solvents which are injected into the rock matrix, so that flow restrictions will be dissolved. Material deposited in the wellbore may also be remove with solvents, usually with less volume than required for matrix treatment. In some cases, mechanical methods may be necessary to remove wellbore restrictions. Hydraulically fracturing a formation will often be successful at by passing a zone of damage. While such treatments are frequently designed to stimulate reservoirs by overcoming naturally low permeability, added benefit often is realized from by passing damage. In fact, smaller volume fracturing treatments are often designed only to penetrate a damage zone immediately around the wellbore. However, fracturing treatments in general tend to be more involved and costly, and there are added risks. Therefore, it is usually desirable to remove damage with matrix treatments whenever possible.

12.2

EFFECT OF DAMAGE

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12.2.1

FORMATION DAMAGE

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Radial Flow The severity of formation damage is a consequence of the radial flow pattern of reservoir fluids. Flow in an unfractured reservoir proceeds via radial geometry, in which fluids traverse progressively smaller volumes of rock as they approach the wellbore. Consequently, the greatest pressure drop occurs in the formation adjacent to the wellbore, making overall production very sensitive to permeability reductions there.

12.2.2

Darcy’s Law Henry D’Arcy, while studying the operation of sand filters for municipal water treatment in France during the mid-1800’s, deduced the basic law for the flow of a single liquid through a porous medium. Darcy (his name has long since been Anglicized) observed that the velocity of flow is directly proportional to the pressure gradient, dp/ds, and inversely proportional to fluid viscosity, µ. This proportionality is expressed in the following equation; v = - k dp µ ds

(1)

where k, the constant of proportionality is a characteristic of the porous medium called the permeability. The velocity referred to in this equation is the apparent velocity and is equal to volumetric flow rate divided by the area through which this flow occurs, i.e., v = q/A. In cgs units, v is expressed in centimeters per second, viscosity in centipoise and pressure gradient in atmospheres per centimeter. Similarly, volumetric flow rate is expressed in cubic centimeters per second and area in square centimeters. In these units the proportionality constant, k, is expressed in darcies. Darcy’s Law applies to the laminar flow region only. Turbulent flow may occur in porous media provided that flow rate is high enough, fluid viscosity low enough, or the characteristic pore dimension large enough. In non-Darcy flow the pressure gradient increases at a rate greater than flow rate. However, non-Darcy flow seldom occurs with liquids flowing through porous media except in the case where very high injection or production rates are encountered, and then only in the region nearest the wellbore. For gas wells, however, non-Darcy flow is by no means uncommon. Calculations based on Darcy’s Law on gas wells producing at high rates can be seriously in error. 12.2.3

Radial Reservoir Flow Although flow very near the wellbore probably occurs via a complex combination of geometries, most near-wellbore flow problems are analyzed by assuming a radial flow

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model throughout the reservoir. Radial flow actually occurs only in an open hole completion from a formation of uniform permeability, as idealized in Figure 2.

Figure 2. Radial Flow

As a practical matter, however, flow from densely perforated completions can be successfully analyzed by employing the radial flow model. When Darcy’s equation is modified for radial geometry and converted from cgs units to customary field engineering units of psi, barrels per day, millidarcies and centipoise, the final equation relates surface production rate to pressure drop, formation permeability and fluid viscosity :

Q

-3 = 7.08 x 10 kh (Pe re µ Bo ln rw

Pw)

Q

=

flow rate, stock tank barrels/day

k

=

average formation permeability, millidarcies

h

=

interval thickness, feet

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Pe

=

formation pressure at external drainage radius, psi

Pw

=

flowing wellbore pressure at perforations, psi

µ

=

oil viscosity at formation temperature, centipoise

Bo

=

reservoir fluid volume factor,

re

=

drainage radius of well, feet

rw

=

wellbore radius, feet

reservoir barrels stock tank barrels

Notice that the factor Bo appears in the equation. This factor is used to account for the volume change of crude oil from the time it flows into the wellbore to the time it is measured in a stock tank. This factor is determined from an analysis of a crude sample taken at a particular point in a well’s production history. This equation can be used to estimate an oil well’s flowing potential, if the required reservoir and wellbore factors are known or can be estimated. A slightly different equation exists for gas wells, and includes terms to account for gas compressibility. This equation takes the form Q(MScf/D)

-4 2 = 7.03 x 10 kh (P e re µ T z ln rw

P2w) (3)

where the additional term T is Rankine temperature, and z is a dimensionless factor accounting for gas deviation from ideality. The drainage radius is inferred from well spacing. For example, the drainage radius for a well spacing of 40 acres is 660 feet. This can be verified by noting that a circle with radius of 660 ft can be inscribed within a square 40-acre unit. Similarly, for 160 acre spacing, the drainage radius is 1320 ft, and for 640 acre spacing, the drainage radius is 2640 feet. Thus, quadrupling the spacing doubles the drainage radius. Common well spacings and corresponding drainage radii are summarized in Table 1 :

TABLE 1

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Well Spacing Acres

Drainage Radius Ft

10 20 40 80 160 320 640

330 467 660 933 1320 1867 2640

While the concept of a drainage radius and wellbore radius is precise, neither quantity is known with great precision. In the case of the wellbore radius, for example, this radius is clearly not the inside radius of the casing, nor even the outside radius of the casing, but rather the radius of permeable formation beyond the cement sheath at the cement-formation interface. This radius is not always precisely definable because of hole enlargement or filter cake deposition. Additionally, flow is through a perforation at this point and hence, departs markedly from radial flow in the immediate vicinity of the perforation. Nonetheless, these imprecisions on the determination of rw have less effect than might be anticipated because of the logarithmic term in which re and rw appear. For example, in an 8” diameter wellbore (rw = 4 in or 333 ft) for a well on 40-acre spacing (re = 660 ft) the ratio of re over rw is 1980 and the logarithm of 1980 is 7.59. An increase in the internal radius from 4 in to 6 in, i.e., 50 percent increase in the value of rw yields a value of 7.18 for the logarithmic term which is a decrease of less than 6 percent in the value of this quantity. Thus, the effect of the uncertainty is greatly reduced in the final calculation. In the practical application of this equation Pw is generally determined by measurements with a bottomhole pressure bomb positioned adjacent to the sand face near the middle of the perforated interval during the period when the well is flowing. Pe’ the pressure at the drainage radius is generally estimated from a shut-in pressure buildup test. For relatively permeable formations, this can be determined within a reasonably short shut-in period (say 24 hours) provided bottomhole pressures have substantially stabilized during this period. More involved methods, however, must be employed on formations of low permeability to obtain a suitable Pe.

The viscosity of the crude at reservoir temperature can be obtained from a hydrocarbon report if available, or estimated from correlations of oil gravity and viscosity. Viscosity is measured in centipoise, and can be compared to water at 1 cp. Using the above equation, the average permeability of the formation may be estimated from

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a given flow rate at known pressure drawdown (Pe - Pw). This calculated permeability will represent an average, which will include the effects of any damage zone that is present. As discussed further in the text, comparing this average permeability with independently measured formation permeability from core data or a buildup test often serves as an indicator of well damage. Alternatively, this equation can be used to estimate flow rate from a knowledge of formation permeability. In this case, permeability may be inferred from buildup test data or core permeability measurements, when available.

12.2.4

Productivity Index For field applications in which comparisons among wells in the same formation are often relied upon as an indicator of damage, many of the terms in Darcy’s equation will cancel out to give a simplified, convenient measure of productive capacity, called productivity index, J :

J=

q Pe - Pw

(4)

The productivity index can be used to compare well performance within a given formation, where formation properties are constant. The Specific Productivity Index, J per foot of interval, is a way of accounting for differences in formation thickness from one well to the next.

12.2.5

Inflow Performance The productivity index is a limited concept in that it assumes that there is no relative permeability during production; i.e., no other reservoir fluids are being produced with the primary production fluid. Since the production rate is directly proportional to the pressure drawdown, both will decrease proportionally as the well is depleted, and the productivity index should remain relatively constant. The only reservoir characteristic that will alter the productivity index is the presence of relative permeability.

In particular, the productivity index will decline in a well with a solution-gas drive reservoir when the reservoir pressure falls below the bubble point of the formation’s crude oil. The bubble point is the pressure at which gas begins to evolve from the crude. As gas is released from the oil, it begins to fill the pore spaces, making it more difficult for oil to flow. An inflow performance curve which is more applicable to a well producing below its bubble point is shown in Figure 3. This curve demonstrates that a greater drawdown is

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required to obtain a given production rate as reservoir pressure declines below the bubble point (when the straight-line relationship does not hold). When producing at reservoir pressures below the bubble point, the productivity index will decline with time.

Figure 3. Typical Inflow Performance Relationship for Solution Gas Drive Reservoirs

When evaluating the productivity of a well by comparing its specific productivity index to that of other wells, it will be necessary to first determine if a given well is producing above or below its bubble point pressure. If the specific productivity index of a well is lower than the specific productivity index of offset wells, it may not be damaged but simply producing below its bubble point. The bubble point for various crudes will differ from one field to another, depending on the fluid properties and temperatures of a given formation.

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FORMATION DAMAGE

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Effect Of Damage Zone Thickness As a natural consequence of radial flow, formation damage that is located closest to the wellbore exerts the greatest adverse influence on production. Of course, the thicker or deeper the damage zone is, the greater the reduction of productivity. However, once damage to the near wellbore region occurs, deepening of the damage adds a progressively smaller contribution to production loss. This is mathematically shown by manipulating Darcy’s equation to include a zone of damaged permeability, kd, of thickness rd. The resulting equation relates the productivity index of the damaged formation to the native formation (J/Jo) and the depth and magnitude of damage :

αlog J/Jo =

re rw

log re + αlog re rw rw

(5)

where α is the ratio of damage zone permeability to virgin permeability. These dimensions are illustrated in Figure 4 for an idealized damage zone. Plotting the above equation for various amounts of damage, α, as a function of depth of damage radius shows that the greatest effect of damage is within the first two inches of the wellbore (Figure 4), with diminishing influence as depth of damage invasion increases.

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Figure 5. Effect of Moving a Zone of Damage of Constant Thickness Outward from the Wellbore

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Effect Of Damage Location The fact that damage is most harmful near the well also implies that a damage removal treatment will be effective even though it may not penetrate deeply enough to remove all damage. This is also mathematically founded in Darcy’s equation, which, when rearranged to describe a residual zone of damage around the wellbore gives : ln J/Jo = ln

re rw

re k r + o − 1 ln d rw kd ru

(6)

Figure 5. Effect of Moving a Zone of Damage of Constant Thickness Outward from the Wellbore

As shown in Figure 5, a hypothetical zone of damage 6 inches thick exerts less influences as it is placed further from the wellbore. This demonstrates that, although deep damage removal may be desirable for complete recovery in some cases, it is not essential. Benefits can be derived from removing damage near the wellbore even if the deeper portion can’t be removed.

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12.2.8

FORMATION DAMAGE

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Matrix Treating Benefits Removing damage with solvents can result in productivity many times the damaged productivity, depending on the extent of initial damage. For example, Figure 4 indicates that a well which contains a 90% reduction in permeability in the first foot around the wellbore has a flow efficiency near 35%. Therefore, a properly designed damage-removal treatment has the potential to increase the production rate by a factor of three. Such damage removal benefits are estimated on the assumption of uniform, radial removal of damage from within the matrix of the rock, hence such treatments are often referred to as matrix treatments. Hydraulic fracturing, as discussed later, can also yield these benefits, by a mechanism which causes the damage to be bypassed. However, a fracture treatment must be intentionally designed in order to be effective. Fracturing a treatment intended for matrix injection will generally yield disappointing results.

12.2.9

Matrix Treating Undamaged Wells Matrix treating only offers the potential for significant productivity improvement in damaged wells. Little benefit can be expected if no damage is present. The negligible benefits of undamaged well treating can be dramatized with the aid of Equation 5, this time by approaching the limit of α = ∞ for the hypothetical case of a treatment which infinitely increases near wellbore permeability of a 6-in. well completed on 40 acre spacing. Physically, this would require underreaming the formation with a drill bit, thereby removing all rock. As shown in Figure 6, very little benefit can be expected from even such an extreme operation as removing all rock radially out to 10 feet. A productivity index increase of two fold is about the best to expect. In reality, such permeability increases are not possible with matrix treatments, and production increases would be negligible. Furthermore, some damage removal treatments may create damage if not performed properly. For these reasons, there should be evidence of formation damage before a matrix treatment is implemented.

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Figure 6. Stimulation of an Undamaged Well

12.3

INDICATORS OF DAMAGE

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12.3.1

FORMATION DAMAGE

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Introduction There is a large incentive for being able to identify the presence of treatable formation damage, since the economic return of a field often depends on maintaining maximum productivity from each well. Treatments performed on undamaged wells are wasted at best, and may actually lead to increased damage. We can avoid many problems associated with incorrect diagnosis by exploiting the evaluation tools available, including productivity comparisons, calculated production estimates, and well testing.

12.3.2

Offset Production A common indicator of well damage is low productivity relative to offset wells in the same formation. The specific productivity index, J/ft of interval, provides a means for quantifying this comparison. A substantially lower specific productivity index relative to other wells in the field suggests that damage is present. However, although this is a useful approach for initial screening, this concept is limited by the heterogeneous makeup of many formations. Therefore, additional diagnostics and data should be gathered prior to deciding a course of remedial action.

12.3.3

Production History Comparison of present production with past production history is a good indicator of problem wells, providing that normal reservoir decline is accounted for. Productivity index, J, is especially useful for comparing production from the same well at different times, since formation factors are likely to remain constant. After an abnormally high production decline has been verified, the well’s history can give important clues as to the type of damage present. Low productivity may be traceable to a specific completion, workover or production practice. For example, formation damage is often common after well killing operations, especially if drilling mud is used as a workover fluid. Injection of unfiltered brines into disposal or injection wells is a common cause of reduced injectivity. Instances such as these should be looked for in well files when damage is suspected.

12.3.4

Reservoir Predictions

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Reservoir engineering calculations which predict production history are important guides to a well’s potential, against which actual performance can be measured. A decline in productivity which is inconsistent with reservoir predictions is reason to suspect damage.

12.3.5

Darcy’s Law Calculations The previous subject detailed the use of the radial flow equation to estimate production, and the use of this approach is an important part of diagnosing possible problems. If rock permeability and hydrocarbon properties are known, a rough estimate of productivity index can be calculated using Darcy’s equation and compared to the actual value. Although limitations on our knowledge of the true rock permeability will make accurate predictions difficult, large discrepancies imply formation damage.

12.3.6

Well Testing Well testing is generally understood to encompass flow testing and pressure buildup testing. Flow testing can provide productivity index, fluid ratios, and a measure of average permeability. Changes in flow rate or relative fluid production from one test period to another are often signs that the well is damaged. Pressure buildup testing is a relatively sophisticated approach to measuring reservoir permeability and obtaining an indication of formation damage. A buildup test involves flowing the well at constant rate buildup of pressure in the formation is monitored. The rate at which this pressure re-establishes itself after being drawn down is a measure of the native formation permeability, and the presence of a damage zone. The ideal system is a single well in an infinite, homogeneous reservoir containing a fluid with constant properties but with no altered zone around the well. If this well is shut in at the sand face after producing at a rate q for Horner time, th, the sandface pressure at time ∆t after shut-in given by :

Pw - Pi = 162.6

qµ Bo log kh

th + ∆t ∆t

(7)

This equation suggests that a plot of Pw vs log (th + ∆t/∆t) will be a straight line for circumstances adequately described by the ideal reservoir model. Bulk formation permeability can be obtained from the slope, m, of this straight line by : K=

162.6 qµBo mh

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Original reservoir pressure, Pj, is obtained by extrapolating the straight line to infinite shutin time; i.e., where (th + ∆t)/∆t = 1 (See Figure 7). In actual buildup or fall of test, it is rare for straight line to be observed over all shut-in times. Instead, field curves have various shapes, which can be explained with the depth-ofinvestigation concept. Field curves can logically be divided into three regions, as shown in Figure 8. At early times, the depth of investigation is near the wellbore. Accordingly, conditions in the altered zone (such as formation damage) determine the character of the curve. In addition, continued production into the well (afterflow) because of surface shut-in influences the curve in this region. “Afterflow” occurs because the compressibility of fluid in the wellbore will permit residual feed in, even after shut in. This effect, which interferes with early time data analysis, can be eliminated or reduced by using bottomhole shut-in equipment. Formation damage is often indicated by the shape of the curve in region I. A steeply rising slope suggests a high pressure drop caused by formation damage. A numerical estimate of damage, called the skin factor, “s”, is obtainable from this region. Although its calculation is beyond the scope of this text, it is worthwile to gain an appreciation of typical skin factor magnitude. A skin factor of 0 indicates that no damage is present, while positive skin factors are typical of damaged formations. Typically, a skin factor of 5 - 10 may indicate moderate levels of damage, while factors above 10 indicate severe damage. Very high skin factors, say 30 and above, may sometimes be attributable to ineffective perforation penetration or incomplete perforation of an entire interval. These possibilities should be investigated in cases of high skin factors. Negative skin factors often are indicative of stimulated wells. In the middle time region, the depth of investigation has moved beyond the region of influence of the altered zone and is not yet affected by conditions at the drainage boundary. Bulk formation properties are the dominant influence. A straight line with slope m usually occurs, from which bulk-formation permeability can be obtained just as if the reservoir were infinite. Permeability can be obtained from the slope of the MTR using equation 8. The flow rate q, is the maintained prior to the shut-in period. If they are not accurately known from hydrocarbon analyses, the viscosity and formation volume factors can be estimated from correlations using API gravity and gas/oil ratio obtained at the wellsite. The buildup measurement of kh gives us a value to compare with average kh obtained from production testing. If kh (buildup) is significantly greater than kh (flow), formation damage is indicated. At late times, the depth of investigation has reached the well’s drainage boundaries. Pressure behavior is accordingly influenced by conditions at these boundaries

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Figure 7. Ideal Build-up

Figure 8. Actual Build-up

12.4

CAUSES OF FORMATION DAMAGE

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12.4.1

FORMATION DAMAGE

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Introduction Formation damage implies that hydrocarbon flow through reservoir rock has been impaired. Solids plugging probably is the major cause of damage problems. As a category, solids include native clays and fines, materials precipitated from reservoir fluids (mineral scale, asphalt, paraffin) and solids introduced by drilling mud (barite, bentonite, drilled rock). They can range in size from sub-micron clay particles to perforation and wellbore-filling scale deposits. Some clay solids are illustrated in Figure 9.

Figure 9 Examples of Native Formation Clays

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Figure 10. Osmotic Swelling of Clays

Other established causes of damage are emulsion blocking, water blocking, and wettability changes. These conditions adversely affect production through different mechanisms but nevertheless the end result can be as harmful as solids damage. A more recently recognized form of damage occurs as a result of reprecipitation of dissolved material during sandstone acidizing.

12.4.2

Clay Disturbance Clays are probably the fine particles most often responsible for damage. They can impair permeability several ways. First, all clays are prone to dispersion and migration when disturbed. Foreign fluid invasion and fluid flow forces are common disturbance which are often blamed for causing clay migration subsequent plugging. The second widely accepted damage mechanism involves swelling. There is a variety of clay known as smectite (montmorillonite) which can expand to several times its size upon water absorption. This expansion is believed capable of causing blocking of pore spaces, especially if the clays are located at critical pore throats. These clays are also more prone to disperse and migrate when they expand. Consequently, they can restrict pores by a dual mechanism of expansion and migration if disturbed. A scanning electron microscope photo of smectite is included in Figure 9. In actuality, attributing damage to either of these mechanisms exclusively is overly simplistic. Clay damage probably proceeds via a combination of these and other mechanisms in most cases.

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Clay Swelling Swelling is believed to occur because of an osmotic pressure difference between the bulk fluid and the interlayer region of the clay particle. This theory explains the sensitivity of clays towards brines with salinity sharply lower than the connate brine. Water molecules from a less-saline brine will enter a clay structure containing higher salinity brine. This occurs because osmotic forces tend to equilibrate the lower bulk salinity with the higher salinity in the vicinity of the clay layers, as conceptualized in Figure 10. Divalent cations such as Ca ++ and Mg ++ limit clay swelling by holding the clay layers together more tightly. This is also true of K + and NH4+, monovalent cations which are effective at reducing swelling because they fit well into the clay structure. Regardless of which cation is responsible for stabilizing clays, the effect is reversible. Stabilizing cations can be replaced by re-exposure of clays to sodium, after which the clays are prone to low salinity damage.

12.4.4

Clay Dispersion and Migration Clays also reduce permeability by dispersing and migrating. In this case, they can lodge in pore throats, causing blockage. Although this pore blockage occurs on a microscopic scale, the result is a reduction of the bulk rock permeability. Migration can be caused by salinity incompatibility with introduced brine and mechanical forces on particles during fluid flow. Either or both of these causes may be operative at the same time.

12.4.5

Low Salinity Clay Dispersion Abrupt salinity reductions of the clay environment will often cause clay particles to detach from each other and the sand grain surfaces, as shown in Figure 11. Clays in this detached state are free to migrate until they bridge at pore constrictions and reduce fluid flow. The charge characteristics of clays explain their tendency to disperse upon exposure to low salinity brines. Clays are characterized by a negative surface charge which attracts a diffuse layer of cations such as Na+ and Ca++. This layer of cations experiences two opposing forces which counteract each other. A diffusional force away from the clay surface. The tendency for diffusion increases if the salinity is reduced, causing the layer of ions to expand and exert repulsive forces on nearby particles, as shown in Figure 11. This mechanism believed to be responsible for dispersing clays, especially if salinity reduction is abrupt. However, evidence has shown that reduction in salinity sometimes will be completely non-damaging if introduced gradually. This suggests that the repulsive forces causing dispersion can be rendered less damaging if they are taken in a stepwise

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fashion. This observation has important practical implications for workover fluids. If low salinity brine must be used, severe damage can be avoided by exposing the formation to progressively lower salinity brine until the desired strength is attained.

Figure 11. Low Salinity Causes Clay Dispersion

12.4.6

Flow Induced Fines Migration The foregoing discussion suggests that dispersion damage can be avoided by the proper choice of fluids introduced to the formation. This is true, up to a point. Clays, as well as other fine particles, can be mobilized by fluid forces exerted by fluid flow, and this problem is more difficult to avoid. As shown in Figure 12, fluid flow velocities increase dramatically towards the near wellbore region, and it is possible to entrain particles from a few feet into the reservoir, particularly in a high rate well.

12.4.7

Effect of Mobile Water Entrainment of fines by fluid flow has been shown to be related to the mobility of the water phase. Clays and silica fines, being generally water-wet will experience greater fluid forces if the water phase flows. This concept is illustrated in Figure 13, which portrays physical laboratory observations made under a microscope. Field observations tend to support this concept, since it is generally true that the onset of water production marks the onset of sand production in poorly consolidated fields. Coning, flood breakthrough, and workover fluid leakoff are a few mechanisms by which an irreducible water phase, and hence fines, may become mobilized.

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Figure 12. High Fluid Velocity near Wellbore Can Cause Fines Migration

Figure 13.

12.4.8

Scale Deposition Scale deposition occurs because produced fluids seek to regain equilibrium with the new environment in the wellbore. As a result, solid mineral material, called scale, is often deposited if solubility limits are exceeded under well conditions. Common scales include CaCO3 (calcite), CaSO4 • 2H2O (gypsum). and BaSO4 (barite).

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Calcite scales are generally deposited as a result of pressure drop and CO2 gas evaluation from produced brine, according to the equation : Ca++ + 2HCO3 ➙ CO2 (gas) + CaCO3 + H2O Deposition may occur in the perforations or tubing, depending on flow conditions. Figure 14 shows a scale buildup in a laboratory perforation which was exposed to downhole flow conditions. The above equation also implies that calcite scale can form if a natural brine rich in HCO3 is exposed to a Ca++ brine. This is also an established damage mechanism. Calcite scales are very soluble in ordinary acids, so their removal is generally straightforward. Scales such as CaSO4 and BaSO4 are deposited as a result of temperature and pressure drops which the produced fluids experience. Although these scales can be deposited in the perforations or tubing, they usually occur in the tubing. Both of these scales are insoluble in acids although there are treating chemicals available which will convert CaSO4 into an acid soluble form. There is no solvent for BaSO4, therefore this scale is often mechanically removed.

Figure 14. Scale Buildup in Simulated Perforation

12.4.9

Asphalt and Paraffin Depostion Asphalt and paraffin are organic species which precipitate from produced hydrocarbons. Temperature and pressure changes can be responsible for inducing their appearance when they are present in the oil. Although reductions in temperature will cause reduced solubility, reductions in pressure have a more complicated effect. Pressure reductions may actually increase asphalt solubility by allowing methane and CO2 to escape. Both of these

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gases are known to reduce asphalt solubility. However, paraffin is less soluble in the absence of methane, so its solubility decreases as pressure decreases below the bubble point.

12.4.10

Emulsions An emulsion is a dispersion of one immiscible phase in another (Figure 15). Emulsions can exhibit varying degrees of stability, some having lifetimes of only seconds, others being indefinitely stable. Much of the world’s oil is produced in the form of emulsions, one estimate being as high as 70%. These emulsions are usually produced by fluid shear in the tubing, and therefore do not affect formation productivity. However, the formation of emulsions within the pore spaces of rock does occasionally occur, and in these cases productivity suffers.

Figure 15. An Emulsion is a Dispersion of One Phase in Another

The viscosity of an emulsion is generally mush higher than the viscosities of either of the individual phases, and may approach several thousand centipoise (compare to roomtemperature water at 1 cp). Because of their high viscosities, emulsions will inhibit flow if they occur within pore spaces, as predicted by Darcy’s Law. An illustration of the magnitude of this effect is given in Figure 16, which shows the productivity reductions possible for various emulsion viscosities as a function of depth of emulsion.

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Figure 16. Production Rate Decrease Resulting from High-Viscosity Emulsions and Increasing Radius of Blocked Formation

Emulsions can be generated by mixing of oil and aqueous fluids within the reservoir or in the wellbore. For example, mixtures of acid and some produced crudes can create thick stable emulsions which result in high injection pressures during acid jobs. Also, the misuse of surfactants in acidizing and workover fluids has been suspected of stabilizing emulsions in formation rock. Although surfactants are often added to prevent emulsions, and under incompletely understood downhole conditions their behavior is often unpredictable. Emulsions can be induced to form by fluid shear and agitation. Although such forces may be present in the formation during routine well production, current experience suggests that formation damage from this mechanism is not a common occurrence. Instead, incompatibility of workover or acidizing fluids with crudes is a more established source of emulsion problems.

12.4.11

Water Blocking Water blocking refers to the condition in which a high water saturation impedes the flow of hydrocarbons within pore spaces. Water blocking is a relative permeability effect, and can be explained with the aid of Figure 17, which describes the effect of the presence of two immiscible fluids on each other’s permeability. On each vertical axis is the permeability of each phase in the absence of the other. For fluids which don’t interact with the formation, these permeabilities are the same for both phases. The relative permeability curve also shows how the presence of a second phase will reduce the permeabilty of the first.

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Increasing water saturation has the effect of progressively reducing oil permeability.

Figure 17. Example of Relative Permeability

Water blocks may occur as a result of coning or fingering of water from another zone, or temporary loss of workover fluid. Acid jobs tend to leave small temporary water blocks, which explains why restoring production often involves a short cleanup period during which spent acid is recovered. Water blockage from coning or fingering illustrated in Figure 18 is more of a problem, since it will not clean up as a temporary block will. Increasing drawdown will generally have the effect of bringing in more water, thus aggravating the problem. In such cases, recompletion of the well may be necessary.

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Figure 18.

12.4.12

Wettability Changes In an oil well, water usually is the wetting phase, meaning that it coats the grain surfaces and is more tightly held in the smaller pore spaces. This situation is desirable, since it allows the oil phase to flow through the larger, more permeable pores. Refer back to Figure 17, which summarizes the basics of relative permeability effects. From this figure, it is obvious that the presence of two immiscible phases reduces the permeability of each one, and this was termed water blocking. It is also shown that the permeability to the phase which wets the rock, in this case water, is more severely affected by the presence of the other phase. In other words, when two fluids compete for flow in the same permeable medium, the wetting phase will be constrained to the smaller, less permeable pore spaces. Wettability changes may occur through the use of surfactants which are incompatible with the formation. For example, some surfactants with net positive charges have been known to adsorb on sandstone surfaces which are negatively charged. The other part of the surfactant molecule may then have enough hydrocarbon character to cause oil to be attracted to the surface, causing oil wetting. Oil wetting may also occur following acidizing if a clean silica surface is exposed to crude oil with strong natural surfactants. These and other causes of wettability changes are more thoroughly discussed in the chapter on Solvents and Surfactants.

12.4.13

Acid Precipitates A relatively recently recognized mechanism for damage involves the precipitates which can form during sandstone acidizing treatments. As discussed in the section on sandstone acidizing, several precipitates including silica gel may appear during acid spending. Improper treatment may allow these to reduce job success or actually increase damage.

12.5

DAMAGE REMOVAL

12.5.1

Introduction Damage removal is the general term given to treatments designed to remove the effects treatments remove the damage while others overcome its effects without actually removing it. There are many techniques available for restoring productivity to a damaged well, depending upon the type of formation and the type of damage. Most treatments fall into the general categories of matrix treatments, hydraulic fracturing treatments, and wellbore

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treatments.

12.5.2

Matrix Treatments Matrix treatments are designed to more-or-loss uniformly permeate the fabric of the rock in order to dissolve damaging particles or deposits. This requires that the injection pressure be kept below fracturing pressure, and that treating fluids contact all parts of the interval intended to be treated. This latter requirement can be accomplished by various diverting techniques, the subject of a later chapter. The various types of matrix treatments are briefly introduced in the following paragraphs. A detailed discussion of each appears in their respective chapters.

12.5.3

Acidizing Acidizing is perhaps one of the earliest applications of matrix treating. Most reservoirs fall under the categories of sandstone or carbonate, and each calls for a different type of acid matrix treatment. Sandstones are most effectively treated with combinations of hydraulic (HF) and hydrochloric acid (HCI). Hydrofluoric acid is the component which actively dissolves damaging clays. On the other hand, carbonate formations are most often acidized with HCI because this acid reacts very quickly with carbonate rock. The acid etches out channels in the rock which are able to bypass the damage.

12.5.4

Solvents and Surfactants

12.5.5

Damage attributable to emulsions, water blocks, wettability changes, and organic deposits is usually treated with surfactants and organic solvents. Surfactants are surface-active molecules which can break emulsions, reduce water blocks and restore wettability if properly chosen and applied. Organic solvents are used to dissolve asphalt and paraffin deposits. Some special organic solvents can also break emulsions. Hydraulic Fracturing Hydraulic fracturing is another category of well treating. Hydraulic fracturing involves generating a fracture within hydrocarbon formations and rendering the crack conductive, either by propping it open with sand or by etching it with acid, if it is in a carbonate. These treatments usually are done to effect reservoir stimulation by partially overcoming naturally low permeability. However, fracturing is occasionally used to bypass formation damage as shown in Figure 19. Usually, fracturing to overcome damage will involve smaller job sizes.

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Figure 19. Bypassing Damage by Fracturing

12.5.6

Tubing Treatments Low productivity which is caused by mineral or organic scale deposits in tubing is removed by treating the wellbore. In the case of soluble scale, acid circulated down to the obstruction is frequently sufficient to restore production. Organic deposits, such as asphalt and paraffin, can be removed with organic solvents or heated-oil treatments. Such procedures are generally referred to as tubing or casing washes.

12.6

DAMAGE PREVENTION

12.6.1

Drilling Fluid Selection Although drilling fluids are generally selected for their drilling properties, a consideration of formation damage sensitivity should also guide mud selection. For example, formations known to be sensitive to low salinity brine can be drilled with a NaCI brine mud or KCIpolymer mud. Experience has shown that these muds can be less damaging to formations with sensitive clays, leading to easier production testing and well completion. Although approach to minimizing mud damage involves maintaining low fluid loss properties in the mud, thereby confining the invaded zone close to the wellbore. Low filtration characteristics require careful monitoring of the mud system, with the addition of

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additive and deflocculants as necessary. Maintaining the clays in a deflocculated state increases their effectiveness at building thin, impermeable filter cakes. If this can be accomplished, routine perforating may be sufficient to penetrate the shallow damage zone.

12.6.2

Workover Fluid Salinity Formation damage from clay swelling and migration can be avoided during workovers by exploiting some established properties of clays. Clays will tend to resist changing from their native geologic equilibrium state, providing that external disturbances are not too severe. This applies to both swelling and dispersing, where it has been shown in core tests that gradual reductions in salinity are less damaging than abruptly imposed decreases (see Figure 20). General experience suggests that clays which formed in high salinity connate brines (50,000 ppm +) can withstand decreases in salinity of 50% or more, and even greater final reductions can be tolerated if taken stepwise. However, general experience also suggests that some clay disturbance will result in high salinity formations exposed to NaCI brines lower than about 4000 ppm in salinity regardless of how slowly salinity is lowered. Factors such as maximum tolerable salinity drop per step and damage threshold salinity are certainly dependent upon the rock and the formation brine. Nevertheless, they provide us with general guidelines for field application. For example, based on the above observations it is recommended that workover fluid salinity not be sharply different from salinity. This guideline permits us some leeway, in the sense that 50% reductions are often tolerable, whereas a 95% reduction is usually too drastic. Fresher water formations, characterized by 5000 ppm salinity or lower, generally are not even sensitive to fresh water.

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Figure 20. Effect of Gradual Salinity Reduction on Permeability

12.6.3

Brines To Stabilize Clays Clays can be stabilized against low salinity swelling by exposure to calcium brine. Core material pretreated with calcium brines is typically insensitive to fresh water damage. Other ions such as NH4+ and K+ may also be somewhat effective at preventing fresh water damage, but this has not been conclusively demonstrated. Damage from dispersion of non-swelling clays by fresh water can also be prevented by treating these clays with calcium brine. As in the case of swelling, there is evidence that NH4+ and K+ also help to inhibit dispersion. Although there are a variety of theories and observations concerning clay sensitivity, it seems clear that most damage can be avoided by preventing drastic decreases in salinity. It is also well established that calcium brines will desensitize clays against swelling and dispersal damage. These observations are the basis for establishing field guidelines governing compatibility of workover fluids with formation clays.

12.6.4

Clay Stabilizers Clay stabilizers are chemicals designed to eliminate the tendency of clays to swell and disperse when exposed to low-salinity brine. These molecules function by adsorbing tightly onto the clays, thus preventing the expansion of the ionic layer upon introduction of fresh water. Experiments confirm that some clay stabilizers are effective at preventing low-salinity damage. However, experiments also show that currently available clay stabilizers are not effective at preventing fines migration caused by fluid flow. Figure 21 shows the effect of a clay stabilizer on a laboratory core under two flow rate conditions for the case of fresh water exposure. At the lower velocity, the clay stabilizer prevented clay damage and the core retained 100% of its permeability, even after exposure to fresh water. However, above a critical flow velocity, the permeability declined in spite of the presence of stabilizers. Thus, clay

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stabilizers should only be used where formations will unavoidably be exposed to fresh water.

Figure 21. Pretreatment with a Clay Stabilizer Prevents Only Fresh Water Damage

12.6.5

Avoid Incompatible Brines

12.6.6

As discussed earlier, some combinations of calcium workover fluid and formation brine can lead to scale damage in the formation. Where possible, a water analysis should be obtained to determine this tendency. Specifically, there are methods to predict whether the HCO3 content of a reservoir brine will scale if exposed to calcium workover fluid. Surfactant Selection The use of surfactants which will not cause adverse wettability changes is also important. Specifically, sandstone formations, which normally are negatively charged, should not be exposed to positively charged cationic surfactants. Carbonate formations are positively charged and therefore should not be treated with negatively charged anionic surfactants.

12.6.7

Drawdown The drawdown, or pressure differential from the formation into the wellbore, can be responsible for causing mechanical fines migration, especially in poorly consolidated formations. This type of fines and clay migration cannot be prevented through the uses of clay stabilizers. It may be necessary to limit drawdown and fluid production if finesmigration damage and sand production is a severe problem.

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12.6.8

FORMATION DAMAGE

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Fluid Loss Control The ideal approach to workover fluid quality is to maintain well filtered fluids to prevent damage from fines introduction into the formation. However, under realistic field conditions, it is not often possible to achieve a high level of fluid cleanliness. This problem is compounded if permeable zones are being exposed to the fluid. An approach to this problem is to intentionally add acid-soluble fluid loss control particles to the fluid to minimize leakoff and damage. These particles can then easily be removed with acid. This procedure will be discussed in more detail in the workover fluids section.

12.6.9

Injection Water Quality Formation damage in injection wells is often characterized by recurring injectivity declines requiring periodic treatment. This is usually attributable to solid particle or oil injection, which ultimately leads to plugged perforations and/or creation of a near wellbore oil saturation. Although it is not practically possible to remove all solids and oil from injection water, maximizing water quality within economic constraints will significantly reduce the frequency of cleanout and damage removal operations. The cost of frequent treatments must therefore be balanced against the cost of improved facilities.

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