Casing and Cement Manual

OGCI Dr. Ted G. Byrom

CASING& CEMENTING

A Course for OGCI/PetroSkills

 Ted G. Byrom 2003

Course Agenda Day 1 Class Preliminaries & Introductions Course Introduction (Chapter 1) Casing Point Determination (Chapter 2) Casing Size Determination (Chapter 3) Casing Load Determination (Chapter 4) Class Project – Planning a Casing & Cementing Program for an Example Well

Day 2 Casing Design (Chapter 5 & 6) Class Project (Continuation)

Day 3 Casing Running & Landing Practices & Special Topics (Chapter 7) Cement Types, Additives & Testing (Chapter 8) Cementing Equipment (Chapter 9) Class Project (Continuation)

Day 4 Primary Cementing (Chapter 10) Stage Cementing (Chapter 10) Class Project (Continuation)

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Day 5 Special Cementing Operations (11) Squeeze Cementing Balanced Plugs Class Project Conclusion

Included with this manual: Each manual has a CD containing the following:

A full color electronic copy of the entire course manual (PDF format) A full color electronic copy of all course slides (PDF format) An Excel spreadsheet to do many of the course calculations An electronic copy of Halliburton’s Cementing Tables and Data (the “Red Book”) An electronic copy of Schlumberger’s i-Handbook

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Table of Contents CHAPTE R

Course Introduction

CHAPTE R

CHAPTE R

CHAPTE R

5-1

CHAPTE R

Running & Landing Casing

CHAPTE R

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13 - 1

14

Slide Handouts (Black & White)

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12 - 1

13

Exercises

7

11 - 1

12

Conversion Factors

6–1

10 - 1

11

Special Cementing Operations

6

Final Casing Design

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9-1

10

Primary Cementing

5

Preliminary Casing Design

CHAPTE R

CHAPTE R

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8-1

9

Cementing Equipment

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4

Casing Load Determination

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CHAPTE R

3

Casing Size Selection

8

Cement Types, Additives & Testing

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2

Casing Point Selection

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Chapter

Course Introduction Who is this course for and what is its purpose?

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his course is a foundation level course designed to give the participant a working knowledge and basic competence in the fundamentals of casing selection, design, and running practice and cement selection, design, and cementing practices. It is assumed that the participant already has such fundamental exposure to the concepts as to know and understand the rudiments of what casing is, what its purpose is, what oilfield cement is and what it is used for.

Course Philosophy and Objective Casing design and cementing are two extremely important topics and skills with which a petroleum engineer involved in drilling and completion must become competent. In fact competence is the base level of skill required because these are two of the most important processes in drilling and completing wells. As important as these two topics are, it seems that no two companies are in complete agreement as to the best methods and practices. That presents something of a problem in a course like this because no matter what you learn here your company or someone in your company will likely have a different approach or different ideas. There is no way that we can cover or even mention in this course all of the variations that different companies use. What we will cover though are the foundation level principles and understanding common to all good practices. When you complete this course you should be able to design a basic casing and cementing program for a normal well almost anywhere in the world. From that point you must continue your education so that you are soon competent to do the same for the unusual and extreme conditions you are surely to encounter in your career.

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How this Manual Is Organized The manual is organized in the logical sequence of the course beginning with casing and then moving to cementing. For a number of reasons the manual contains much more information than will actually be covered in the course. Some information is basic, which the participant should already know, but is included for “memory refreshment”, reference, and review. Other information is advanced beyond the scope of this course, but is included so that the participant may be aware of its existence and importance.

Calculations This manual out of necessity contains numerous equations and computations. We will not devote class time discussing the origin or derivation of formulas, so much of what is contained in the manual is to provide supplementary material for those who are interested in the background and methods involved in the calculations. Most casing design and cementing calculations are now done with some type of software. Blind reliance on computer software without understanding of the assumptions and limitations of the methods involved is an invitation to disaster. Hence, it is essential that an engineer or technician learn how to do the calculations manually in the early stages for an understanding of the process. In this course, the participant will be given a simple, spread sheet software package that will perform some of the basic calculations for use later after the participant understands the process and does some of the calculations manually. Those participants who will eventually rely totally on software in the future should at least spend enough time learning how the software applies the methods taught in this course and what further advanced treatment the software employs.

Units and Measure In this manual we will use typical oilfield units.

Unfortunately the units of measure in the oilfield are not standardized. Most of the world uses some system of the units that evolved from the oilfields of North America in the late nineteenth and early twentieth centuries. In this manual we refer to that system as typical oilfield units or just oilfield units. Even that system is not consistent because typically some units vary even within the borders of the USA. For example, in Texas mud density is typically expressed in pounds per gallon whereas in California it is typically specified in pounds per cubic foot. In some oilfields of the world various sorts of metric systems are in place, but they are seldom a true SI system of units. For example pressure is often measured in bars instead of Pascals. Perhaps most confusing of all are those systems which borrow units from both the SI and the typical oilfield system. It is not unusual to find places where well depth is measured in meters and pressure in psi. It makes sense to those using it, and it is just a fact of life in the oilfield.

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There should be little dispute that the SI system is superior to what we now use, but things are not likely to change any time soon.

A few of the basic measures we will use in this course are listed in the table below. Others will be mentioned when we need them. Quantity

Measure

Oilfield Units

SI Units

length

L

feet (ft)

meter (m)

force

F

Pound force (lbf)

Newton (N)

mass

F L/t2

Pound mass (lbm)

Kilogram (kg)

density

F /(L t2)

Pound mass/gal (ppg)

Kilogram/cubic meter (kg/m3)

pressure

F/L2

Pound force/square inch (psi)

Pascal (Pa) (equivalent to 1 Newton/square meter)

Chapter 12 of this manual has conversion factors for most quantities and operations covered in this course.

Formulas in This Manual Most formulas in this manual do not contain conversion factors.

Because there are so many different types of units used in the oilfield, this manual does not contain conversion factors within most of the formulas. Conversion factors in formulas are a significant source of confusion and error because one cannot see the ideas clearly if the formulas are cluttered with conversion factors. If you are consistent in your usage of units there will not be many places where you will need a conversion factor, but where conversion factors are needed we will point them out and make note of it.

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Review of Casing Basics – What You Should Already Know Purpose of Casing Casing is placed (and usually cemented) in a borehole in order to protect the integrity of the borehole. In other words its primary purpose is to keep the borehole from collapsing or fracturing, to keep unwanted fluids out of the borehole, and to keep the desired fluids from leaving the borehole at undesirable places.

Types of casing Oil well casing comes in a number of different types based on several properties: •

Diameter (e.g. 7 inch, 9-5/8 inch)

•

Weight (Wall Thickness) (e.g.

•

Grade (Yield Strength) (e.g. API K55 – 55,000 psi yield strength)

•

Connection (e.g. API

•

Joint Length (e.g. Range 2, Range 3)

LT&C, API ST&C)

Casing Applications supports the well head, the weight of all subsequent casing strings and tubing in many wells, but there are many other wells where the conductor plays no role as a structural member. It maintains borehole integrity through the usually soft surface formations. It seldom gives us any pressure control though because the formations in which it is set often have very little strength so its role in maintaining borehole integrity is relatively short lived and severely limited.

Conductor casing

is usually the first string of casing in the well that provides significant borehole integrity. It is usually capable of containing well bore pressures that might be encountered before the next casing depth is reached. It also serves the purpose of protecting valuable fresh water supply in formations near the surface. In many wells where the conductor is not a structural support the surface casing serves the role of supporting all subsequent tubular strings. Surface casing

well maintains borehole integrity when the mud density necessary to contain the formation pressures below it exerts more hydrostatic pressure

Intermediate casing

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than the strength of the formations above it. In other words, it allows higher mud densities to contain formation fluids while continuing to drill to deeper depths while protecting the weaker formations above it from failure due to fracture from the hydrostatic pressure of the mud column. Intermediate casing is not required on many wells. Some require more than one string of intermediate casing. is usually the last string of casing run in the well. It maintains borehole integrity for the borehole below the intermediate casing. It also performs another important function in that it serves as a backup to contain the pressures associated with the producing formation should the production tubing ever fail. Production casing

are shorter strings of casing which are not set all the way back to the surface. A liner is usually set from bottom back up inside the previous casing string. In many cases it is possible to set a casing string from bottom only back to the bottom of the previous casing string. The liner usually has a mechanical hanger that attaches it to the casing in which it is set. It is usually cemented all the way to its top and often has a mechanical packer on top to assure a seal where it overlaps into the casing string to which it is attached. Liners

Tie-back casing is a string of pipe that connects to the top of a liner and is usually run

all the way back to the surface. The purpose of the tieback is often to function as production casing once it is tied into the liner. Sometimes tie-back strings are used to isolate the original casing since it may be badly worn during drilling operations below.

Review of Cementing Basics – What You Should Already Know Cement has a number of functions on oil and gas wells. The major categories are: •

Primary cementing

•

Squeeze cementing

•

Cement plugs

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Primary Cementing The purposes of a primary cement job are

•

Seal the wellbore to prevent flow of formation fluids in the annular space outside the casing

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Provide support for the casing

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Protect casing from corrosion (in some cases)

•

Provide thermal insulation (geothermal and steam injection wells)

Primary cementing involves: •

Determining what part of the borehole must be cemented

•

Selection of cement type

•

Selection of casing cementing equipment

•

Determining the need for spacers

•

Calculating volume of cement and spacers required

•

Determining displacement procedures

•

Determining WOC time

Successful primary cementing depends on a number of variables, but two things are worth remembering: 1. The number one cause for poor primary cementing is poor mud displacement. 2. The number one cause for poor mud displacement is poor quality mud Squeeze Cementing

Squeeze Cementing is the process of applying hydraulic pressure to force or squeeze a cement slurry into the desired perforations, fractures, channels, or voids and force filtrate water from the slurry to create a solid mass which will harden to provide the desired seal.

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There are a number of ways to achieve a squeeze. We may classify them by squeeze pressure: •

High pressure squeeze

•

Low pressure squeeze

final

by volume of cement mixed for the squeeze: •

High volume squeeze

•

Low volume squeeze

by method of achieving final pressure: •

Hesitation squeeze

•

Continuous squeeze (“walking squeeze”)

or by method of placement: •

Bradenhead squeeze (bullheading)

•

Retrievable squeeze tool

•

Cement retainer

Despite all the advances in cementing technology, squeeze cementing remains an enigma of sorts. There are so many different opinions and techniques, and most are successful in at least some specific applications and areas. The fact about squeeze cementing is this: Squeeze cementing is more of an art than a science.

Experience is a key factor in successfully performing a squeeze job in a particular application in a specific area. Cement Plugs

Almost every well ever drilled will eventually contain a cement plug. It may be placed during the drilling phase, the producing life, or almost certainly during the abandonment phase. Cement plugs are commonly used in open hole and cased hole for:

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•

Zone abandonment

•

Zone isolation

•

Sidetrack seat

•

Hole abandonment

•

Temporary safety plug

•

Severe well control situations

Typically cement plugs are placed with open ended pipe (sometimes with wall scratchers for open hole) as a balanced plug, i.e. the columns of cement in the pipe and the annulus are the same length as the pipe is pulled out of the plug volume.

The items mentioned in this basic review will be discussed in much more detain in the cementing chapters.

Review of Basic Calculations – What You Should Already Know for casing and cementing are fairly simple for the most part. But for them to be easy one must be familiar with a few basic concepts such as hydrostatics, i.e. the pressures exerted by fluids at rest. Calculations

Hydrostatic Pressure The pressure exerted by a static liquid is called a hydrostatic pressure. The thing that is most important to remember is that at any given point it is the same in all directions and it can only act on a solid in a direction perpendicular to the surface that it contacts. Here is an example to illustrate the nature of a hydrostatic pressure.

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Example: Hydrostatic Pressure

I N T R O D U C T I O N

Suppose we have a continuous, long tube 10,000 feet in length, 2 inches in diameter, and in air it weighs 5 lb/ft. We hang this tube in a perfectly vertical wellbore with a set of seals on the bottom in a packer. The seals are free to move in the packer with no friction. The wellbore on the left is full of air (no perforations) and there is air inside the tube. We record the weight of the tube. Then we fill the annulus with water with a density of 8.5 lb/gal. Again we record the weight of the tube.

Figure 1 - 1. Hydrostatic pressure example.

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Which statement is correct? 1. The tube on the left weighs more than the tube on the right. 2. The tube on the right weighs more than the tube on the left. 3. Both tubes weigh the same in both cases. The correct answer is number 3. The water in this wellbore cannot possibly affect the weight of the tube because it cannot act in any direction but horizontal on the tubes’ surface. If that is not obvious to you, then you need further review of the fundamentals of hydrostatics.

Magnitude of Hydrostatic Pressure at Depth We can calculate the hydrostatic pressure exerted by any liquid at a given depth easily if we know its density. (For the purposes of this course we will consider the density of a liquid is constant under pressure and temperature unless otherwise noted.)

Figure 1 - 2. Hydrostatic pressure example, one tube.

Example: Calculate Pressure at Depth

Suppose a vertical wellbore is full of drilling mud with a density of 12.5 ppg. Assume there is no flow and the well is open at the surface, i.e. no surface pressure. What is the pressure in the wellbore at 10500 feet.

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 psi/ft  p = (12.5 ppg )  0.052  (10500 ft ) = 6825 psi ppg   First we multiplied the mud weight (density) times a conversion factor to get a gradient (psi/ft) then times the depth to get the pressure. That particular conversion factor is one of those unfortunate things about oilfield units that we do not like, but you should memorize it because you will use it over and over again in this course and your career.

Figure 1 - 3. Hydrostatic pressure example with surface pressure added.

Example: Surface Pressure

Now suppose the same well is shut in and the pressure gage on the surface shows that the wellhead pressure is 1100 psi. What is the pressure at 10,500 ft?

 psi/ft  p = (12.5 ppg )  0.052  (10500 ft ) + 1100 psi = 7925 psi ppg   That was easy. Now let us consider a more typical example.

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Figure 1 - 4. Hydrostatic pressure example with two tubes.

Suppose a tube in the well is open on the bottom. Inside the annulus is 12.5 ppg mud, but inside the tubing is 9.0 ppg salt water. The casing has an inside diameter of 4.545 inches and the tubing outside and inside diameters are 2.875 inches and 2.441 inches, respectively. The well is shut in and the gage on the casing reads 1100 psi like before. What is the pressure of the tubing at the surface?

Example: Unbalanced Column

 psi/ft  p = (12.5 ppg )  0.052  (10500 ft ) + (1100 psi ) ppg    psi/ft  − ( 9.0 ppg )  0.052  (10500 ft ) ppg   = 3011psi

Now that was one way of doing it. Why did we give you all the dimensions of the tubes since you do not need them to solve the problem? We added that extraneous data because in real life you always have a lot of information that has nothing to do with the problem at hand. In real life you have to be able to determine what you need. After doing a few of these types of calculations you can easily see that you can minimize your efforts by using a difference in the densities of the two liquids.

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 psi/ft  p = (12.5 ppg − 9.0 ppg )  0.052  (10500 ft ) + (1100 psi ) ppg   = 3011psi We can also understand this example if we visualize it as a U-tube (see next figure).

Figure 1 - 5. A U-tube schematic for resolving hydrostatic pressures.

Whenever you get the least bit confused about hydrostatic pressures in a wellbore, the first thing you should do is draw a U-tube.

Do not be embarrassed at resorting to such a simple tool. The truth is that an enormous amount of money would have been saved over the years if more “experienced” people had done just that. We will use this U-tube configuration for many of our calculations in this course.

Gas Calculations There are a few times in designing casing when we will need to be able to calculate gas pressures at various depths and temperatures. This can be complicated to do manually, but is a little easier if we make certain assumptions. One of the assumptions we typically make when designing casing is to assume that the gas is pure methane. We assume that the molecular weight is 16 and that the compressibility factor, z = 1. That the compressibility is unity is not quite true, but we will assume it is close enough for our purposes.

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p2 = p1 f g (1.1)

fg = e

16 L 1544(460 +T ) z

where

p1 = pressure at top of interval, psia p2 = pressure at bottom of interval, psia L = vertical length of interval, ft T = average temperature of interval, o F z = 1, approximate compressibility of methane

This is satisfactory for most of the applications, but when it is not some other calculation procedure must be employed. A Vacuum This should not have to be mentioned, but there are some really odd notions in the oilfield about the potential power of a vacuum. A vacuum is nothing more than the absence of atmospheric pressure. On the surface of the earth a perfect vacuum is roughly 15 psi less than atmospheric pressure. A vacuum cannot cause casing to collapse nor can it hold a column of mud suspended in an annulus if lost circulation occurs at the bottom of the hole. Think about it – a vacuum is a pressure difference of only 15 psi. Can it possibly have any significant effect in an environment where the pressures are measured in thousands of psi? (There are a few situations where it might be of some consequence, but none that involve casing design or cementing.)

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2

Chapter

Casing Point Selection

B

efore we can look at casing design we must first determine the depths at which the casing must be set. Below is a schematic of a typical well showing four strings of casing: conductor casing, surface casing, intermediate casing, and production casing. Why do we need four strings of casing for this well? How we make that determination? How do we determine the depths at which we set the casing strings? How do we determine what sizes we need? This chapter will attempt to answer those questions.

Determining Parameters Pore Pressures

The pore pressure or formation pressure in a particular well is a given property of the various formations in the well. In other words, it is given data which we cannot change. It is the pressure of the fluids within the pore spaces of the formations. There are various methods for determining or estimating pore pressures in wellbores, and we are not going to go into those methods, but for this course we will assume that we already have access to reasonable pore pressure estimates for our borehole. Frac Pressures

If enough pressure is exerted in a borehole it will cause the rock surrounding the borehole to fail in tension. The fluid in the borehole can be pumped into the fracture causing the fracture to propagate further into the formation. This pressure is a function of the tensile strength of the rock, the pore pressures, and the insitu stresses present in the rock. This pressure is normally determined by some type of fracture test, leak-off test, or some estimation method. Again it is data that is a given value which we cannot change.

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Figure 2 - 1. A typical casing installation.

is determined by the requirements to maintain the integrity of the borehole and protect the environment. Yes, it is that simple. Or perhaps we should say it is that complicated. Casing setting depth

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Figure 2 - 2. Three possible configurations.

The above picture shows three possible configurations for a well similar to the one in the previous illustration. The first shows a production casing string. The second shows a production liner where the intermediate string also serves as part of the production string. The third one shows a tie-back string inside the intermediate string and connected to a liner at the bottom of the intermediate string. One can see that the second option might save the operator money by eliminating a full production string, but why would an operator elect to choose the third option as opposed to the first or the second? One reason might be to reduce the weight of the final string and save money using a lower strength casing. Of course that has to be more saving than the additional cementing and equipment cost and additional rig time required. However, here is a typical situation for choosing the third option. We are drilling a very high pressure well and the intermediate casing is required to contain the high density mud while drilling the lower part of the hole. In this case suppose it takes a few weeks to drill the hole below the intermediate casing so there may be considerable wear from the drill string on the intermediate string. This means we have to rule out option number two because the intermediate casing may not be able to contain the pressures required of a production string due to loss of wall thickness from the wear. In this case the first option is usually cheaper than the third option which requires more time, more cement, and more equipment, so we still see no reason for selecting the third option. Consider two more things. Remember that we said it was a very high pressure well. The operator wants to be assured that the casing above the cement does not leak and the best way to assure this is to hydrostatically test the casing connections as the casing is being run in the hole. This cannot be done with a full string of pipe because the static time required to test each connection will probably allow the casing to get stuck before it gets to bottom. That would then be an extremely costly situation which

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would require another liner of a smaller diameter than the production casing. So, while the third option is not common there are often very good reasons for doing it. Also there are many wells that require two liners instead of one, and the tie-back string is always a preferred option in that case. As you can imagine there are many possibilities. Well conditions and costs dictate the actual choices. We will discuss those choices more later.

Conductor Casing Depth The conductor casing is the largest diameter casing run in the well. As already mentioned it often serves to hold the weight of the subsequent tubes run in the wellbore and also to maintain some minimal amount of borehole integrity while drilling the surface hole for the surface casing. Individual wells may require two conductors, one a structural conductor to support the well head and casing, and another to provide borehole integrity while drilling the surface hole. Conductor casing may require the drilling of a hole in the ground and cementing in place or it may be driven into the ground with a diesel pile driving hammer. The criteria for selecting the depth of the conductor can be very simple or very complicated. On the simple side we want the conductor deep enough so that it will not sink further into the ground once the wellhead is placed on it and the subsequent casing strings are hung in the wellhead. For many shallow wells with hard surface soils the conductor may be set at depths of 50 feet or so, some times 100 feet. On the other hand, in areas where the surface soils (or ocean bottom) are extremely soft it may be necessary to set the conductor 200 feet to 500 feet below the surface (or ocean bottom) just to drill the hole for the surface casing. There are some situations where the surface formations are so incompetent or problematic that two strings of conductor casing may be required. In other cases the conductor casing is also the platform support structure for the well and must additionally support a small platform attached to the wellhead and some minimal amount of production equipment – not as uncommon as many might think, hundreds of these type wells exist in shallow waters. While conductor pipe is usually considered the simplest of the casing strings we will run in our well, it is often the most complicated in terms of both setting depth and design. Determining the setting depth of conductor in many cases must be determined by soil bearing tests and coring. This gets more into the realm of the civil engineer than it does into the petroleum engineer’s domain. Most companies have their own specifications or they rely on the standard practice in the area that has already proved successful. There are unfortunately no handy formulas for determining the setting depth of conductor casing. There are just too many variables and complexities to consider in a foundation level course. That probably sounds like an avoidance of the issue and it is. About the only guide we can offer in the absence of soil bearing tests similar to those performed for foundations of bridges, tall buildings, and similar structures, is to use

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what has proven successful in the area. And as much as we hate to say it that brings us to a rule of thumb. In the absence of soil mechanics data and analysis the only way to reliably select the depth of conductor casing is to use the depth already proven successful in the area. In other words do what everyone else does. The main thing is that if you do not have data to support your choice, do not attempt to set your conductor casing at a lesser depth than is standard in the area.

Surface Casing Depth There are a number of factors affecting the setting depth of surface casing: •

Formation strengths

•

Formation pressures

•

Depth of fresh water bearing zones

•

Legal regulations and requirements

Which of those do we choose? Or which are the most important? The answer is almost always the one that requires the most casing. Strictly from a design point of view the first two are the most important – they are related and are our basis for maintaining borehole integrity. We intend that to include well safety. The last two may also be related. Protecting surface fresh water sands is of extreme importance in populated areas and in truth it should be everywhere. Regulations require this in most areas now. However, it is sometimes possible to obtain a variance from the regulations if the fresh water sands will be protected by the next string of casing.

is not only a bad thing to do, but in some parts of the world it could put your company (and you) out of business! Damaging a fresh water aquifer

The question of regulations as already mentioned is mostly a matter of protecting fresh water aquifers, but in many cases it also regulates the safety aspects of setting sufficient surface casing. Unfortunately regulations do not always take specific situations into account and they may require more casing than is really needed and some times less than what is needed.

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Aside from the regulations, the surface casing must allow us to drill to the next (or final) casing point with the mud density required to contain the formation pressures encountered and not cause fracture failure of the exposed formations near the upper part of the hole. If more than one additional string of casing (an intermediate casing string) is required, then the two become interdependent.

Intermediate Casing Depth The need for intermediate casing is caused by the fact that the borehole below the surface string requires a mud density too high (or sometimes too low) for the formations between the drilling depth and the surface casing depth. When intermediate casing is required, and sometimes even when it is not we really have to start with conditions at total depth to determine proper setting depths for our casing strings. Borehole Parameters for Intermediate Casing

There are two parameters used in selecting casing depths, formation pore pressures and formation fracture pressures. The best way to understand how these two parameters are used is to make a plot of pore pressure and fracture pressure versus depth. Here is a plot of the two parameters for a simple well. Casing Setting Depth Chart Equivalent Mud Density (ppg) 8

9

10

11

12

13

14

15

16

17

18

19

0

Pore Pressure

2000

Frac Press

True Vertical Depth (ft)

4000

6000

8000

10000

12000

14000

Figure 2 - 3. Pore pressure and fracture pressure plot used in selecting casing setting depths.

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It shows a plot of the formation pore pressure versus depth on the left and the fracture pressure on the right. Drillers use plots like this to determine mud densities required at various depths for drilling the well. The mud density must be slightly higher than the formation pressure to prevent formation fluids from entering the well bore and at the same time it the density must be less than the fracture pressure so that the drilling fluid does not fracture and enter the formations. The lines shown in the chart do not include any safety margins. Drillers typically drill with the density slightly higher than that required to balance the formation pressures. This allows some safety margin, especially when making trips because the action of pulling the pipe tends to cause a negative pressure surge or a reduction in the hydrostatic pressure while the pipe is in motion. Likewise the drillers like to keep the maximum slightly lower than the fracture pressure because running the drill string back into the hole causes a positive surge effect, but more importantly the maximum is also considered a “kick margin” so that during a well control event the formation is not fractured in the process of killing the well. Different companies have their own policies on the amount of safety margin required, and it may vary with type and location of individual wells. For this course we will use a typical margin of 0.5 ppg mud density for both fracture and pore pressure. Casing Setting Depth Chart Equivalent Mud Density (ppg) 8

9

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16

17

18

19

20

0 Pore Pressure Mud Density

2000

Frac Press Kick Marg

True Vertical Depth (ft)

4000

6000

8000

10000

12000

14000

Figure 2 - 4. Safety margins added to pore pressure and fracture pressure.

The above figure shows the addition of these two safety margins. We can see that the mud density required to contain the pressure at 12000 ft is 10.8 ppg, but above 1700 ft

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that mud density begins to exceed the kick margin. In other words, we cannot drill safely to 12,000 ft in the well unless the hole is cased down to 1700 ft or more because the mud density required to contain the pore pressure at bottom is greater than the fracture pressures at the surface (including the safety margins). That is exactly how we determine the setting depth of the surface casing in this well. Casing Setting Depth Chart Equivalent Mud Density (ppg) 8

9

10

11

12

13

14

15

16

17

18

19

20

0

2000

Pore Pressure Mud Density Frac Press Kick Marg

b c

True Vertical Depth (ft)

4000

6000

8000

10000

12000

a

14000

Figure 2 - 5. Selection of casing setting depths.

If we start at the mud density at 12,000 ft (point a) and draw a line vertically until it intersects the kick margin line (point b) then horizontally to the vertical axis (point c) we can read the setting depth of the surface casing which in this case is about 1700 ft. That particular well requires only a surface casing string at 1700 ft and a production string at 12,000 ft. If the surface casing depth of 1700 ft meets the regulatory requirements for this well then our setting depth selection is complete. If the regulations require more casing, say 2500 ft we will simply move our surface casing depth to 2500 ft and it will give us more safety margin in our mud densities as far as a kick is concerned. That is a relatively simple well. Now let us look at an example where an intermediate string is required.

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Casing Setting Depth Chart Equivalent Mud Density (ppg) 8

9

10

11

12

13

14

15

16

17

18

19

20

0 Pore Pressure Mud Density Frac Press Kick Marg

2000

True Vertical Depth (ft)

4000

6000 Fracture Pressure 8000

10000 Pore Pressure 12000

14000

16000

Figure 2 - 6. Casing depth selection for example well.

Example: Casing Depths

In this example we see that the mud density of 15.2 ppg required at 14,000 ft will exceed the kick margin at all depths above 10,500 ft. So we must set a string of casing at that depth. Moving horizontally to the left we see that the mud density required at 10,500 ft is 11.8 ppg. This mud density will exceed the kick margin at all depths above 3000 ft. That depth becomes the surface casing depth.

This is a straight forward procedure, but sometimes it can be complicated by depleted zones that have lowered pore pressure and fracture pressure but are located amongst normally pressured zones. In some cases we may have situations that require more than one intermediate casing string in which case we typically would install a liner (usually called a drilling liner) before reaching total depth rather than a second intermediate string. There are many possibilities, but that is the basic procedure.

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3

Chapter

Casing Size Selection What size casing and what size bits do we require?

Size Selection

O

nce the setting depths have been determined the next step is obviously to select the sizes of the casing strings to be set. The sizes will depend on a number of things.

Two important things to know about selection of casing size: •

Hole size determines casing size

•

Hole size at any point in the well except the surface is determined by the previous string of casing

This means one thing to us. In selecting casing size we usually have to start at the bottom of the hole.

The size of the last string of casing run in a well is determined by the type of completion that will be employed. That decision is usually the function of an interdisciplinary team of reservoir, production, and drilling personnel. There are numerous criteria on which this decision is based, so we will assume for our purposes that the size of the last string is predetermined and we will proceed from that point. From the standpoint of drilling our input into that process is to asses the risks and

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allow for alternatives. For example, if we know there are serious hole stability problems in an area and our drilling experience in the area is limited we may be well advised to recommend a final size that is still large enough for us to set an extra string of casing or liner and still reach the objective with a usable size of hole for a good completion. This is a point that is unfortunately too often overlooked in the desire to keep well costs low. Once we know the diameter of the final liner or string of casing the procedure proceeds like this: •

Determine the hole size (bit size) for the final string of casing.

•

Determine what diameter casing will allow that size bit to pass through it. That is the size of the next string of casing.

•

Repeat the procedure until all of the hole sizes and casing sizes have been determined. Precaution: After the casing strings have been designed be sure to check the drift diameters to be certain that the bits will pass through.

Borehole Size Selection What is the proper borehole size for various sizes of casing? What do we require of the borehole size? •

A borehole must be large enough for the casing to pass freely with little chance of getting stuck

•

There should be enough clearance around the casing to allow for a good cement job.

•

In general, the bigger the borehole the more costly it is to drill. There are no formulas for determining the ideal borehole size.

Selecting the borehole size is primarily based on current practices in the area or areas with similar lithologies. There are a number of charts and tables in the literature, some good for some areas, greatly lacking for other areas. The best advice we can offer is to use what is common practice in the area unless there is good reason to do otherwise.

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We will show a case history later in this chapter of an operator who chose to vary from local custom and paid an expensive price for it. No matter what specific charts we suggest here they going to be wrong for some particular locale or application. That notwithstanding, here are two charts that show some typical choices. One chart is for hard rock and the other is for unconsolidated rock.

Figure 3 - 1. Typical bit and casing sizes for hard rock formations.

This chart starts with the last string of casing or liner and works downwards to the first casing string of the well. You can see on this chart there are many options even for those situations where the same size liner or casing is to be run. In general, hard rock offers us more choices and clearance between the casing and borehole wall can be less than for unconsolidated wells.

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Here is a similar chart for unconsolidated formations.

Figure 3 - 2. Typical bit and casing sizes for unconsolidated formations.

You will note in this chart that there are still some options, but not as many. A few may not be available even though shown on the chart. For instance on the fourth row from the top it shows that either an 8 ½ in. or an 8 ¾ in. bit may be used from 9 5/8 in. casing. That may be true in some cases, but if the 9 5/8 in. casing string contains any 40 lb or heavier pipe then the 8 ¾ in. bit cannot be used. What is common practice in one area may not work in another because formation pressures may require a heavier pipe. Example of Casing Size Selection

Continuing with the same example we looked at in the previous chapter, assume the we have determined the following casing depths:

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•

Surface Casing

•

Intermediate Casing

10,500 ft

•

Production Casing

14,000 ft

S I Z E

S E L E C T I O N

3,000 ft

The production engineers tell us they will require a production casing diameter of 7 inches so the production casing size is determined. Assume that the well is in an area of unconsolidated formations. Use the soft formation chart to determine the intermediate casing size, the surface casing size, and the conductor casing size. •

Intermediate Casing 9 5/8”

•

Surface Casing

13 3/8”

•

Conductor Casing

20”

Although not shown in the chart as a possible path, some operators in areas where borehole stability is a serious problem elect an alternative for 7 inch casing as follows: •

Intermediate Casing 10 ¾”

•

Surface Casing

16”

•

Conductor Casing

24”

That choice would be a case of experience in a particular area influencing the decision in order to allow more margin for the effects of anticipated problems.

Bit Choices Obviously from the above charts we select the hole size for our particular casing and that automatically sets our bit size too. While that is true, there is another aspect to the bit sizes that should be mentioned. Those charts are based on the most commonly available bit sizes. There are special cases where it will be necessary to use an unusually thick wall casing and you find that the common bit used in that casing will not work – it is too large. There are many other diameters of bits available for special applications. In general they tend to cost more, but the biggest problem is that often there is a limited choice of types when it comes to unusual bit sizes. For instance for one common size we may have a choice of twenty-five different tooth and hardness characteristics just from a single manufacturer, and maybe 50 to 100 choices if we include all manufacturers. However, with some odd size bit we may be limited to six choices and only one manufacturer. That may be acceptable for some special case, but it should always be considered.

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Actual Bit Clearance To determine the bit clearance we look at the casing tables for the internal diameter and see if it is larger than the diameter of the bit. But in the table we see two diameters listed. One is the internal diameter and the other is the internal drift diameter which is slightly smaller than the internal diameter. The internal diameter is the diameter to which the tube is supposedly manufactured. Once it has gone through the milling process it is inspected for final diameter by passing a mandrel through it of the diameter listed as the internal drift diameter. So its internal diameter might be the same as that listed or it might be slightly smaller, but we know for sure (assuming the manufacturer does its job) that it is at least as large as the drift diameter. We normally then assume that the drift diameter is the maximum bit diameter we can be assured will pass through the casing. But in many cases bits greater than the drift diameter have been used. The only thing is that you have to drift the casing with a mandrel the size of the bit first and cull out those joints that are undersized. Some steel mills will actually do this for customers (for extra $$$). An Unfortunate Case History

To illustrate the consequences of making poor choices when it comes to casing selection here is a case history. A well was planned such that an 8 ½ in. hole was drilled below 9 5/8 in. casing set at 10000 ft with 7 in. casing to be set at 14000 ft. A 6 1/8 in. hole would be drilled below that to 14800 ft and a 4 ½ production liner would be cemented in place. At about 13000 ft serious lost circulation and borehole stability problems were encountered. Now the operator had no contingency plan for such an occurrence. It appeared that it would be necessary to set the 7 in. casing at 13000 ft and the 4 ½ in. liner would have to be set at 14000 ft, and now the last 800 ft of hole would have to be drilled with a 3 3/4" in. bit and a 2 7/8 in. liner would be the final string. This was unfortunate, but that was the only good choice the operator had left. But that is not the choice they made. Thinking that the 2 7/8 in. liner would not give acceptable production rates the operator decided to run 7 5/8 in. casing in the 8 ½ in. hole hoping to finish the hole with a 3½ in. liner. That size is not recommended for unconsolidated formations, but the operator had done that many times in hard rock areas where it is common. The reasoning was that in unconsolidated formations the hole is probably over gage anyway so there should be even more clearance than in hard formations. (Don’t ever make this foolish mistake!) So they ran 7 5/8 in. casing in the well and it stuck 600 feet off bottom. There was nothing left to do at that point, so it was cemented in place. They drilled out the shoe and tested it to the equivalent mud density that would be required to drill to the next casing point at 14000 ft. They lost circulation immediately. Two squeeze jobs were performed with no success. Now the situation looked very discouraging. The only choice left was to drill the hole back to 13000 with a 6 3/4 in. bit and set a 5 in. liner. (The operator had earlier thought that they could set a 5 ½ in. liner below the 7 5/8 in. but now they were beginning to believe the charts and tables.) Then they would drill a 3 7/8 in. hole to 14000 ft and set a 2 7/8 liner. Then they would drill a 2 ¼ in. hole to 14800 ft and set a ??? You get the picture now. There were no more options; the well was plugged. Now it may not have been a really bad well plan in the

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beginning because the hole problems at 13000 ft were totally unexpected. There was still a way to reach total depth though not with the size liner the operator wanted. Unfortunately that final liner size became a priority and the operator made a very foolish and uniformed decision. It cost them the well.

Alternative Approaches There are additional approaches to allow for more clearance for the casing. One method is to under ream the open hole below the current casing string. This allows additional clearance and is a proven method where the expense of the extra time and reaming can be justified. A similar result can be obtained with a bi-centered bit for drilling below the current string of casing. Such a bit will drill a larger diameter hole than its nominal diameter. This technique can eliminate the extra expense of under reaming and accomplish the same result. Another option is the use of expandable casing. This is a relatively new technology and has proven itself successful in a number of applications. The hole is typically drilled with a bi-center bit or under-reamed to give more clearance. The casing itself is run just like a conventional liner but with an expander device on bottom. Once in place cement is displaced into the annulus then the expander mandrel is forced through the casing from the bottom up and it expands the casing to its final size. The expander also expands a liner hanger and pack-off. The expandable casing is an ERW tube so as to maintain a constant wall thickness.

Figure 3 - 3. Expandable open hole liner.

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Next is an illustration of a program showing a proposed well plan utilizing expandable casing to optimize the hole size.

Figure 3 - 4. Alternative casing program using expandable casing strings.

There are some potential problems with the process.

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•

The pipe itself or one of its connections can split during the expansion process.

•

The cement must be placed before the expansion operation commences.

•

The expanding tool can get stuck and thus plug the expandable casing.

•

Once expanded the casing has a much lower collapse resistance than conventional casing.

•

The expandable casing is not readily available on short notice as an emergency alternative in a well already drilling.

Because of the limitations it appears that the most appropriate application is for those occasions in which unforeseen well conditions require a change of the program to run an unanticipated string of casing or liner. However, the lack of availability seems to offset that advantage, at least at the present. Despite these limitations this technology has a lot of promise for the future.

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4

Chapter

Casing Load Determination What loads determine our design?

I

n order to determine what strength of casing we will need we must next consider the types and magnitudes of the loads the casing must safely bear. There are a number of different considerations and possibilities with each string of casing run in a well. There are some simple load situations that will suffice for most casing strings, but often there are special conditions that may apply to a specific well or type of well. We are going to look at the types of loads we use for design for each type of casing string. There are three types of loads commonly encountered. •

Collapse loads – those external pressure loads tending to cause the casing to collapse

•

Burst Loads – those internal pressure loads tending to cause the casing to rupture or burst

•

Axial loads – tension or compression loads caused by gravitational and frictional forces on the pipe

The first two of these are dictated by well conditions and anticipated operations in the well. Those are the two we will look at in this chapter. The third type of load, axial, is a function of the casing selection process itself and will be discussed in the next

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chapter. The first two are functions of pore pressures, fracture pressures, and drilling fluid (or cement) pressures.

Surface Casing The collapse load for surface casing depends on the worst case scenario anticipated in which the pressure outside the casing exceeds the internal pressure. There are a number of possibilities, but the most commonly accepted situation assumes that the surface casing is empty inside (possibly due to lost circulation while drilling somewhere below) and has mud pressure on the outside the same as when it was run. We can modify the internal pressure if we have some knowledge of the worst case of lost circulation that could be encountered and how far the drilling fluid would drop in the surface casing should that occur. In the absence of such knowledge however, we should assume it could empty the surface casing. On the outside of the surface casing we know the pressure when the casing is run; it is the hydrostatic pressure of the mud column. If the cement is of greater density than the mud (and it usually is) we can easily calculate the pressure due to the cement. The question is though, what is the pressure after the cement hardens. We can be fairly certain that it will not be as high as the cement pressure before it hardened, but the actual pressure depends on the integrity of the cement job, i.e. whether there are channels in the cement or whether some formations are not cemented properly. Typically, a safe assumption is that the highest pressure outside the casing after cementing is the mud pressure before cementing. It may be less, but it is unlikely to be more. Typical Surface Casing Collapse Design Load

•

Internal pressure – atmospheric pressure or zero

•

External pressure – mud pressure when run

That is the collapse design load we will use in this course, but be aware that there are other possibilities. The burst rating of the surface casing is based on the maximum anticipated internal pressure and the minimum anticipated external pressure. Let us look at the external pressure first. In collapse we were looking for the maximum external pressure, now we are interested in the minimum. The minimum external pressure will likely occur sometime after cementing. It is believed that when cement hardens, the spaces where the cement has channeled or is absent, the fluid in these spaces is usually fresh water. For that reason, many assume that the minimum external pressure will be equivalent to a fresh water gradient. There are some who believe that a fresh water gradient is not really likely and they use the mud pressure on the outside just as we did in collapse. The internal pressure for bust is a little more complicated. If we drill a well some distance below the surface casing, encounter a gas kick, and get a large volume of gas in the casing then the pressures could get quite high. However, if the pressures get very high, the formations at the bottom of the surface casing will fracture and flow will go into those formations. That being the case it does not make sense to design a surface

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casing string to withstand 6000 psi internal pressure if the formation below the surface casing will fracture at 3500 psi. The typical procedure for burst is to assume that the maximum internal pressure will be equivalent to the fracture pressure beneath it, plus some additional pressure for flowing into the formation. We will look at how to determine this shortly. Typical Surface Casing Burst Design Loads

•

Internal pressure – Equivalent of gas kick that fractures and flows into formation(s) below the casing shoe

•

External pressure – Fresh water gradient

Again, we must emphasize there many possibilities, and different companies have a number of varieties. These, however, are simple and should be safe in most cases.

Surface Casing Load Curves One of the easiest ways to work with loads is to construct a set of design load curves. The anticipated loads such as collapse pressures and bust pressures are plotted graphically as pressure versus depth. This makes it very easy to visualize the loading rather than relying on a lot of formulas. (We will still need formulas and calculations to construct the load curves, but it will take very few calculations.) Possibly the best way to present this is with an example. We will use the depth selection curve we used in Chapter 2. Assume that the bottom hole temperature is 326 °F and the average surface temperature is 74 °F.

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Casing Setting Depth Chart Equivalent Mud Density (ppg) 8

9

10

11

12

13

14

15

16

17

18

19

20

0 Pore Pressure Mud Density Frac Press Kick Marg

2000

True Vertical Depth (ft)

4000

6000 Fracture Pressure 8000

10000 Pore Pressure 12000

14000

16000

Figure 4 - 1. Depth selection chart for example well.

In this example we are going to set surface casing at 3000 ft, the mud density is 9.2 ppg, and the fracture gradient is equivalent to 12.3 ppg. First we will plot a collapse curve. Assume the internal casing pressure is 0 psi and the external pressure at 3000 ft is due to the mud pressure. The collapse load at 3000 ft is: ∆pc = po − pi = 0.052 ( 9.2 )( 3000 ) − 0 = 1440 psi

(Note that we are going to round off to the nearest 10 psi to keep these calculations simple – after all it is not rocket science we are doing here). The collapse load at the surface is zero since there is no external pressure. Next we will examine the burst load. At the shoe the burst load will be the frac pressure of the formation below the casing, plus some extra pressure for flow into the formation, less the external pressure which we have said will be equivalent to a fresh water gradient. We will use 500 psi as the incremental injectivity pressure into the fracture. Then we calculate the burst load at the shoe at 3000 ft: ∆pb = p f + ∆pi − pe ∆pb = 0.052 (12.3)( 3000 ) + 500 − 0.052 ( 8.3) 3000 ∆pb = 1120 psi You can see that the burst load at the shoe is quite low.

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Note: Throughout this manual I have used a gas injection pressure of 500 psi where gas is flowing into a fracture below the casing string. That value is strictly arbitrary. Many designers do not add any pressure for injection at all. That is strictly a matter of preference.

Next we need to calculate the burst load at the surface. The worst case scenario here is to have the surface casing full of gas all the way from the shoe to the top – this will give us the maximum possible pressure at the surface and such a pressure is quite possible in a kick situation. We use Equation (1.1) to calculate the gas pressures assuming pure methane. Assume the average temperature in the 3000 ft wellbore is 101 °F. Calculate the pressure at 3000 ft which is the frac pressure plus the 500 psi injectivity pressure. p2 = 0.052 (12.3)( 3000 ) + 500 = 2420 psi

Then the surface gas pressure is:

p1 = 2420 e

−

16(3000) 1544(460 +101)

p1 = 2290 psi (Note that we have done a little algebra on this formula to calculate the surface pressure instead of the down hole pressure as it was set up for in Chapter 1.) Since there is no external pressure at the surface, then that is also the burst load at the surface. We can now plot this on a chart with the collapse load for convenience.

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Surface Casing Load Pressure (psi) 0

500

1000

1500

2000

2500

3000

0

500

1000

Depth (ft)

1500

Burst Load Line Collapse Load Line

2000

2500

3000

3500

Figure 4 - 2. Surface casing load curves for example well.

That constitutes the load curves for the surface casing.

Intermediate Casing The intermediate casing loading is often straight forward like the surface casing, except that the magnitude of the loads is generally greater. And in many cases the surface BOP and wellhead selection limits the burst rating at the surface. In those cases the reason the BOP will not withstand full well pressure is that the formations below the shoe will fracture before the maximum pressure is reached at the surface, so it is common practice to use a BOP stack that will contain the well assuming that the formation below the shoe will fracture before the BOP fails. Otherwise the cost of wellhead equipment and BOP rental becomes exorbitantly high. If that is the case then, the surface pressure is fixed at the maximum service pressure (MSP) rating of the BOP and wellhead, and the pressure at the bottom of the intermediate casing is fixed at the formation fracture pressure plus some differential injection pressure. Given those two pressures, one must then determine the configuration of the mud and gas columns that will impose the highest burst loads on the casing. It seems intuitive that the highest load would be with gas at the surface and mud below, but that is not the

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case. Prentice (1970) showed that the maximum burst load actually occurs with a mud column on top and gas beneath as shown in the next figure. Intermediate Casing Design Maximum Burst Determination Pressure (psi) 0

500

1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000

0

BOP Max Pressure (fixed)

2000

Mud Maximum Burst Load Line

4000

Depth (ft)

After Prentice (1970)

Gas

6000

Gas 8000

Mud Formation Injection Pressure (fixed)

10000

12000

14000

Figure 4 - 3. Maximum burst load (after Prentice, 1970).

This is the procedure we will use in our example.

Intermediate Casing Load Curves We will continue with the same example. It shows that the setting depth of the intermediate casing is 10500 ft, the pore pressure is equivalent to 11.3 ppg, and the fracture pressure 15.7 ppg. Now we must also consider the mud weights and formation pressure while drilling. We will assume that the wellhead and BOP equipment is rated at 5,000 psi. The average borehole temperature (from bottom to surface) is 200 °F. The formation pressure will be 11070 psi. The load curve for collapse is similar to a surface casing load curve. However, there is very little chance the intermediate casing could ever be empty of all fluids like the surface casing, and if we design an intermediate string for collapse with no fluid inside then we will likely have a greatly over-designed and expensive string of casing whose function in the well is only temporary. We will consider that the worst possible case for collapse of the intermediate casing is one in which there is fresh water on the inside and the mud it was run in on the outside.

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Note that some companies would not find this assumption acceptable and would apply a more severe collapse load criterion. That is always dependant on the specific well and the design generally should be for the worst case even if it means a very expensive string of casing. For our case then the net collapse load at the bottom is:

∆pc = 0.052 (11.8 − 8.3)(10500 ) − 0 = 1910 psi This is a very low value for collapse and it will probably not even enter into the design. As for the burst load, there are many possibilities. The typical burst design assumes that the minimum rating of the wellhead equipment is one limiting factor and the injection pressure of gas or liquids into the formation just below the casing shoe is the other. Between the surface and the casing shoe is some combination of gas and mud. It would seem that the worst case would be gas at the surface and mud from some point in the casing down to the shoe such that the surface pressure of the gas is equal to the working pressure of the BOP and the combined column is such that the pressure at the shoe is equal to the injection pressure of the formation at the shoe (or just below). That is not the case, however. Prentice (1969) showed that the worst case is exactly the opposite with the mud on top and the gas below. By knowing the working pressure of the BOP, the fracture pressure of the formation below the shoe, and the density of the mud we can calculate the length of the column of mud and of gas with the following formula. Lm + Lg = L g m Lm + g g Lg = p f + pi − ps

where

Lm = length of mud column, ft Lg = length of gas column, ft L = length of casing, ft g m = mud gradient, psi/ft g g = gas gradient, psi/ft p f = formation fracture pressure, psi pi = differential injection pressure, psi ps = surface equip. pressure rating, psi

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This is an approximation but it will be close enough for our design. Of course it is a system of linear equations with two unknowns. It can be solved by any number of methods, but to make it easy we will show a solution here.

Lm = Lg =

p f + ∆pi − ps − g g L gm − g g p f + ∆pi − ps − g m L

(4.2)

g g − gm

We need not calculate both. If we calculate the length of the mud column we can subtract it from the length of the casing to get the length of the gas column. The biggest problem with this sort of formula is the gas gradient. A gas gradient is not constant; it varies with depth and temperature. Typically in casing design a typical constant is used or it can be calculated by various methods. We could use Equation (1.1), with the bottom hole pressure and calculate a pressure at the surface and use those two to determine an average gradient for our gas assuming the gas goes all the way to the surface. At least this will give us an approximation. p1 = p2 e

−

16 d 1544 z (460 +T )

p1 = 11070e

−

16(14000) 1544(460 + 200)

p1 = 8890 psi 11070 − 8890 14000 g g = 0.16 psi/ft gg =

(There are more accurate ways to do this, but this will serve as an approximation for our design.) The fracture pressure at the intermediate casing shoe is: p f = 0.052 (15.7 )(10500 ) = 8570 psi

Now we can calculate the length of mud column on top.

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Lm =

p f + ∆pi − ps − g g L gm − g g

8570 + 500 − 5000 − 0.16(10500) 0.79 − 0.16 Lm = 3790 ft Lm =

The internal pressure at 3790 will be: pm = 5000 + 0.052 (15.2 )( 3790 ) = 8000 psi

And the injection pressure at the casing shoe is:

pd = p f + ∆pi pd = 8570 + 500 pd = 9070 psi We can now determine the net burst loads by subtracting the supporting pressure on the outside of casing. Recall we elected to use a fresh water gradient just as for the surface casing. So the net burst loads are:

∆po = 0 − 0 = 0 psi

∆pm = 8000 − 0.052 ( 8.3)( 3790 ) = 6360 psi ∆pd = 9070 − 0.052 ( 8.3)(10500 ) = 4540 psi Now we can plot the loads for the intermediate casing:

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Intermediate Casing Design Pressure (psi) 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

8000

8500

9000

0

Burst Load Line 2000

Depth (ft)

4000

6000

8000

10000

Collapse Load Line

12000

Figure 4 - 4. Intermediate casing load curve for example well.

Production Casing There are a number of different ways to consider the loads in the production casing. The most common approach is to assume that the worst collapse scenario is one in which the casing is empty and open to the atmosphere. This is not common, but there are cases where this has happened. Another possibility is to assume that the well will always have some amount of liquid or pressure inside it equal to the formation pressure at the time (usually taken to be the depletion pressure). The situation for each well may be different, and can be complex. One should always keep in mind that what may occur in the future is extremely hard to foresee now. Casing has collapsed during the producing life of the well because later in the life of the well someone attempted some operation that was not foreseen when the well was designed. As far as burst is concerned, the most common procedure is to assume that the casing must withstand the maximum shut in formation pressure in the form of a gas column (for a gas well) from the perforations all the way to the surface. In other words, the production casing is a backup for the tubing as far as burst pressure is concerned. And there are many ways a situation such as that can occur. However, there is one other situation that can be much worse especially with a gas well. Suppose the tubing is set in a packer and a leak develops in the tubing near the surface. There is no problem with casing burst at the surface because it was designed for that pressure. But what

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happens down hole because of the gas pressure on top of the packer fluid? The burst load is much higher in a situation like this than with a pure gas column in the casing. Designing for a case like this can lead to a very expensive casing string and is seldom done, however, this is not at all an uncommon situation in the producing life of many gas wells. (In a case like that you have to assume that a rupture down hole is something that you can deal with.)

Production Casing Load Curves Looking again at our example we see that the production casing will be set at 14000 ft and will be brought all the way to the surface. We will assume a gas well. The bottom hole pressure is equivalent to a 14.7 ppg mud. We do not have to be concerned with the fracture pressures in the production casing loading. The collapse loading we will consider that the casing can possibly be empty and that the pressure on the outside is equivalent to the mud it was run in, 15.2 ppg. For burst we will again assume that the pressure on the outside is equivalent to fresh water (though many use the mud weight it was run in) and on the inside we will consider that the packer might fail during production so that the packer fluid is produced with the gas resulting in a full column of gas in the annulus between the tubing and production casing. For collapse the net load at the surface is zero. The net collapse pressure at the bottom of the production casing at 14,000 ft is: pc = 0.052 (15.2 )(14000 ) − 0 = 11070 psi

For burst the net pressure at the bottom is:

∆pd = 0.052 (15.2 )(14000 ) − 0.052 ( 8.3)(14000 ) = 5020 psi We use the gas equation to calculate the pressure at the top:

∆po = 11070 e

−

16(14000 )

1544( 460 + 200 )

− 0 = 8890 psi

Now we are ready to plot the load curves for the production casing.

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Production Casing Load Pressure (1000 psi) 0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

5.5

6

6.5

7

7.5

8

8.5

9

9.5

10 10.5 11 11.5 12

0

2000

Collapse Load Line

Burst Load Line

4000

Depth (ft)

6000

8000

10000

12000

14000

Figure 4 - 5. Production casing load curve for example well.

Axial Load Curves We have not mentioned any load curves for axial tension yet. That is because the well itself does not impose the axial load (discounting borehole friction for now). The axial load is not determined until we have made our preliminary selection of pipe for the well because it is the function of the weight of the specific pipe and the density of the drilling fluid. We will address the axial load in the next chapter. That completes our load curves. In the next chapter we will use these curves to arrive at a preliminary design for all three strings.

Liners & Tiebacks Liners and tieback strings are special situations, however, the approach is very similar to that of either the intermediate or production casing. The thing that is different in the load curve for a liner or a tieback is that the load curve is not just for the liner or tieback but for the casing in which it is hanging if it is a liner, or for the liner and tieback combination. Sometimes liners must meet the requirements of two functions. In other words a liner or a tieback is never designed by itself, but as a contiguous part of another string of casing. The only thing that really differs as far as the load is concerned is the tension load, since it is a separate part of a longer string.

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Figure 4 - 6. A well with a production liner and two completion options.

In the above figure we see a well with a production liner and two possibilities for final completion. On the left the well could be completed as is with the production liner and the intermediate casing forming the final production string. In this case the intermediate string would be designed to function as both the intermediate string and as the upper portion of the production string. In the second case where a tieback is run the intermediate casing serves only as an intermediate string and the liner and the tieback together serve as the production casing. Here is another common liner situation.

Figure 4 - 7. Example well with a drilling liner and a production liner.

In this case there are two liners, a drilling liner and a production liner. On the left, the intermediate casing serves its normal purpose, but it also serves as a portion of a

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second intermediate string in conjunction with the liner so they have to be designed as one string and it has to satisfy both functions. On the right, the drilling liner is tied back to the surface and a production liner run below it. In a case like this the design depends on when the tieback is run. If the tieback is run immediately after running the drilling liner, the intermediate casing serves as intermediate only until the tieback is run, and the drilling liner and tieback serve as a second intermediate string and then finally in conjunction with the production liner they serve as a production string. If the tieback is run after the production liner is run then the intermediate casing has to be designed to perform its first function as well as a second intermediate string with the drilling liner. And finally like before the tieback, the drilling liner, and the production liner all function as the final production string. It perhaps sounds a little more complex than it actually is, but the only thing to keep straight is to be sure all strings are designed to meet all the required loads that they will be subjected to in their various roles during drilling and production.

References Prentice, Charles M., (1970), Maximum load casing design, SPE 2560, Society of Petroleum Engineers, Richardson, Texas.

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5

Chapter

Casing Design -Preliminary Getting Started

C

asing design is primarily a two-step procedure when done manually. Just like writers make a first draft and then revise it to make it better, we make a preliminary casing design based on published strength properties of the tube and then refine it if necessary to account for the effects of the combined loads. It is very easy to use the published values to get a preliminary design, and when used with appropriate design factors many of these preliminary designs become a final design without need for further refinement. However, those published values are based on tests and formulas that assume there are no other loads on the casing. In other words the collapse rating you see in the tables is the collapse rating with no tension in the tube; the collapse rating is lower if the tube is in tension. We will not consider combination loads until the next chapter.

Design Factors If there is one topic almost no one can agree upon, the issue of design factors is one. There was a time when there were some industry recommended standards that companies seemed to accept, even though almost everyone deviated from them from time to time. Now almost no two companies use exactly the same design factors. Here is a range of the commonly used design factors.

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•

Design Factor, Tension:

1.6 – 2.0

•

Design Factor, Collapse:

1.0 – 1.125

•

Design Factor, Burst:

1..0 – 1.25

We reiterate.

These are not industry standards nor are they necessarily

recommended.

They are merely some industry averages that have been used for over fifty years in many applications. Your company will likely have its own design factors, and usually the design factors will vary depending on the type of well and possibly its proximity to populated areas. It is not necessary, nor always advisable to use the same design factors for each string of casing in a well.

Type of Pipe Seamless or ERW? API casing is made in both seamless and electric resistance welded

(ERW) types. In general ERW is cheaper and is used in shallow applications such as surface casing and conductor. It is manufactured by rolling steel billets into long plates which are cut to exact widths. These plates are then rolled into tubes and welded along a straight seam with an electric resistance process that fuses the seam together without use of a filler material. The seam is then annealed and stress relieved. There has long been a bias against welded pipe because of the perceived problems with welded seams whether founded in truth or not. Some companies will not use welded pipe and others say there is no problem with such pipe. One thing we can say for certain about ERW pipe is that it can be manufactured to very close tolerances in wall thickness, something not possible with seamless pipe. All of the current expandable casing is ERW because of the necessity of maintaining a constant wall thickness. Seamless pipe, which is the preference of most companies, especially for higher pressure applications, is manufactured by forcing a mandrel through a heated solid cylinder of steel to form a tube. The result is a seamless tube, but the wall thickness does vary because of the inaccuracy of the process. API specifications limit the variation in wall thickness to 12.5 % of the nominal published wall thickness. This is a rather large variation compared to ERW pipe.

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Selecting Pipe Weights & Grades In selecting the casing for our string we are often presented with a choice of a particular weight and grade of pipe versus a different weight and grade both of which might satisfy our design. For example we might have a choice between 7” 23# N80 or 7” 26# K55 either of which will work in our string. The most obvious selection criterion might be cost or availability, but what else might enter into the decision? A thicker wall pipe might offer better corrosion or wear life and we might choose the 26# J55. But if it is a directional well where the pipe is below the critical inclination angle (the angle below which nothing will move due to its own weight ~70°), then the heavier it is the more force required to push it in the hole so there the 23# N80 might be a better choice. One thing you must always keep in mind though about different weights and grades of pipe (as well as connections in the next section) is that the fewer types you have in a single string the better it is. The more different types you have the easier it is for there to be a mistake running it in the hole. As most casing is run in most with most rigs of the world it is an intense and continuous operation. To stop in many areas is to stick the string off bottom. Pipe is rolled off pipe racks or off-loaded from barges as it is being run into the wellbore and usually part, if not most, of this operation occurs at night. The simpler is the design, the less the likelihood of a costly mistake. The best way to let people in the field know that you are inexperienced and have never run any casing yourself is to send a casing design and casing string to the field that has a 237 ft section in it that is a different weight or grade or that requires a crossover. And if you have to ask, “Is a 300 ft section OK?”, then you fail the course! Think about it this way; there is seldom, if ever, a justifiable reason to run a different section of casing of less than 500 ft in length in a casing string, and some companies use a minimum of 2000 ft. The only good exceptions might be for shallow strings or in the case where a few thick wall joints are placed at the top for wear, wellhead support, or gauge control.

Connections In the process of selecting casing to meet our load requirements we are confronted with so many different types of connections. What type do I need? For most normal pressure applications we can use standard API couplings, but for higher pressures and temperatures, bending in curved wellbores, rotating torque, high tensile loads, gas containment, and so forth then integral and proprietary connections become necessary. In this course we are going to limit ourselves to standard API connections to keep things manageable, but we will be mentioning other types of connections.

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API 8-rd Connections: The most common type of casing connection in use is the API 8-rd connection in either ST&C (short thread and coupling) or LT&C (long thread and coupling). These two threads are the work horses of the industry and are sufficient for most normal applications. Like most connections these are not as strong in tension as the pipe body itself because of the reduced net cross sectional area of the tube resulting from the threads being cut into the pipe body wall in the absence of an upset. The threads are wedge-shaped, cut on a tapered profile, and are made up until a prescribed torque is attained. At full make up torque the threads do not achieve a pressure seal because the threads do not meet in the base of the groove leaving two small channels at the base of the thread in both pipe and the coupling.. How then do they seal and prevent pressure leaks? They form a pressure seal with the use of thread lubricant that fills the voids between the threads. The gap is very small and its length is quite long due to the number of turns at a pitch of 8 per inch, so the lubricant forms a good seal in most cases. However, one must always use an approved thread lubricant. One that ages and shrinks in time and temperature will eventually leak. Though these connections are often used in gas well applications they are generally not recommended because they rely on the thread lubricant for a seal.

“8-rd” means 8 threads per inch and a slightly rounded profile. The profile is a “V” or wedge shape but slightly rounded. There is also an API 11-1/2-V thread which has 11-1/2 threads per inch and has a very sharp “V” profile. This is typically what is called a line pipe thread and is seldom used in down-hole applications today. Note:

There are a number of other types of threaded and coupled connections that have different profiles from the API 8-rd. Instead of wedge shaped threads, many have a square profile or something similar to give them greater tensile and bending strengths. Examples of this type of thread is the Buttress (now and API thread), 8-Acme, etc. These threads are typically used where higher tensile strengths are needed in the joints. In general they also rely on thread lubricant to form a seal and are prone to leak in high pressure gas applications. Most of these connections have less taper than the API 8-rd connections and require less make up torque. This is an advantage, but can also be a disadvantage because the maximum make up torque is usually less than that required to rotate the casing in the hole. Where rotation is planned for cementing or for orienting precut windows for multilateral wells these types of connections are to be avoided. Also, because the make up torque is relatively low most of these joints have a “make up mark” on the pipe. When the pipe is made up properly the coupling should be aligned with the make up mark. It the maximum torque is attained before the coupling reaches the make up mark it is an indication that the thread lubricant is the wrong type, the connections have not been properly cleaned, or the pipe is not round or has been damaged. If the make up mark is reached before the optimum torque is achieved that is an indication the connections are either worn or the threads were not properly cut. Other Threaded & Coupled Connections:

Another type of connection used for casing is one in which a metal-to-metal seal is achieved that is independent of the threaded area. These are Integral Connections:

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almost always an integral type connection cut into both ends of the pipe with no separate coupling. Some have a smooth tapered seal that seats very tightly when the proper make-up torque is achieved, others have a shoulder type seal, and others have a combination of both. These types of connections give both high tensile strengths (some greater than the pipe body itself), greater bending strengths for curved wellbores, and greater pressure sealing ability for high pressure gas wells. Some of these threads may be cut in non-upset pipe for use as liners – typically called flush-joint connections because both the ID and OD are the same in both the tube and connection. Typical of these types of threads are those made by Hydril, Atlas Bradford, API Extreme Line (X-line), and others. These threads are often referred to as premium threads, but that is often a misnomer. With the exception of X-line these should be referred to as proprietary threads. They are patented and their dimensions and properties are strictly those specified by the manufacturer though they are almost always on API tubes. One should always consult the individual manufacturer for properties such as strengths and make up torque as well as the recommended type of thread lubricant. Always consult them on thread lubricant, as some lubricants used with API 8rd connections can result in loss of pressure seal in some of the proprietary connections. Simplicity is Preferred

One of the problems we often tend towards in casing design is overlooking the concept of simplicity. Every point in our design where we change from one type connection to another, we will require a crossover sub or joint. In fact if we are prudent operators we will require two crossovers on location for each of those points in case one is damaged while running the casing. Not many things can be worse than running a string of 13 3/8” casing to 10,000 ft and damage a crossover joint by crossthreading it when the casing is 2000 feet from bottom. Yes, it does happen! If you do not have a spare then you have to pull 8000 ft of 13 3/8” casing out of the hole laying it down in singles as you pull it. (Another thing you will learn if you ever have to pull casing is that often the mill end of the coupling will back out instead of the field end, and you will also discover that casing made up to maximum recommended make-up torque will often gall the threads when it is backed out and require that a good number of the joints be replaced.

Casing Ratings Casing is typically rated in tension, collapse, and burst by the API for API standard tubes and by other manufacturers who make non-API tubes. These values are published in many sources. The primary source for the API tubes is the API Bulletin 5C2, Bulletin on Performance Properties of Casing Tubing, and Drill Pipe. The latest edition is October, 1999. It is available from API by mail or their web site: www.api.org. The values in these tables are calculated from a set of formulas that he API has adopted. Naturally, if you want the formulas you have to purchase a separate publication. It is API Bulletin 5C3, Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties. The latest edition of this bulletin is October 1, 1994.

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Below is a portion of a page of performance properties from 5C2.

That is only half the page. It is continued on the facing page as below.

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Columns 1 – 11 give the casing size and various physical dimensions and descriptions. Column 12 gives the collapse rating. Column 13 gives the tension rating of the tube itself not considering the connection. Columns 14 – 21 give the “burst rating” for plain pipe and for various API connections. And Columns 22 – 29 give the tensile ratings of the various types of API connections. Again we emphasize that these values are valid only if there is no other load other than the one listed.

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The API has recently increased the cost of its bulletins to the point where it is now cost prohibitive to include a complete copy of the Bulletin 5C2 (or 5C3) in this manual. Instead, a copy of Halliburton’s Cementing Tables (“red book”) and Schlumberger’s i-Handbook are both included on your course CD. Either or both of these may be installed on your computer for reference and they both contain the basic properties of API casing that are listed in API Bulletin 5C2. Note:

The API Formulas The strength values listed in API Bulletin 5C2 are calculated from various formulas adopted by the API. We shall wait until the next chapter to look at the API formulas that these tables are based on. The reason for that is that there are a number of things we need to discuss to understand the formulas, and those things are not necessary to understand at this point where our priority is on making a preliminary design.

Surface Casing – Preliminary Design We start the surface casing design with the surface casing load curves. Using the curves developed in the previous chapter as an example we will look at the process for selecting the proper weights, grades, and connections necessary for a preliminary surface casing design. Surface Casing Load Pressure (psi) 0

500

1000

1500

2000

2500

3000

0

500

1000

Depth (ft)

1500

Burst Load Line Collapse Load Line

2000

2500

3000

3500

The first thing we must do with our load curves is to include design factors. We mentioned earlier that we would use the following typical design factors:

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Load Type

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Design Factor for this Example

Collapse

1.125

Burst

1.125

Tension

1.6 or 100,000 lb

After selecting the design factors we incorporate them into the load curves to give us “design lines” for collapse and burst. Surface Casing Load Pressure (psi) 0

500

1000

1500

2000

2500

3000

0

Burst Load Line

500

Collapse Design Line

Depth (ft)

1000

1500

Collapse Load Line

2000

Burst Design Line

2500

3000

3500

With the design lines completed we begin to make our casing selections to fit the design. Since there are so many different types of 13 3/8” casing available we will consider that we have an inventory of the following casing available for our use: Wt

Grade

Connection

lb

ID in.

Joint Collapse Internal Strength Yield Pressure 1000 lb psi psi

54.5

K-55

ST&C

12.615

1130

2730

547

61

K-55

ST&C

12.515

1540

3090

633

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Grade

Connection

Joint Collapse Internal Strength Yield Pressure 1000 lb psi psi

ID

lb

in.

68

K-55

ST&C

12.415

1950

3450

718

68

N-80

ST&C

12.415

2260

5020

963

72

N-80

ST&C

12.347

2670

5380

1040

We could begin with either the burst or collapse design. For many surface casing designs, the collapse is the more critical so we will start with it. We start by plotting the collapse rating of 54.5 lb K55, and seeing that it will not be adequate all the way to bottom we add some alternatives. Surface Casing Collapse Design

Surface Casing Design Pressure (psi) 0

500

1000

1500

2000

2500

3000

3500

0

Collapse Design Line

500

54.5 lb K55 1000

Depth (ft)

1500

Collapse Load Line

61 lb K55

2000

68 lb K55

2500

3000

3500

We can see that the 54.5 lb K55 can be run to 2100 ft and the 61 lb K55 to 2850 ft and the 68 lb can be run all the way to bottom with no problem in collapse. If we try to go with a minimum design we will have a string with three weights of K55 as follows: Type Casing

Interval

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Type Casing

Interval

Section Length

13 3/8” 54.5# K55 ST&C

0 – 2100 ft

2100 ft

13 3/8” 61# K55 ST&C

2100 – 2850 ft

750 ft

13 3/8” 68# K55 ST&C

2850 – 3000 ft

150 ft

Now we have already stated that we want to keep our design simple and that we do not want to run any short sections of pipe. This design has three different types of pipe and one of them is only 150 ft in length. We cannot eliminate the 150 ft of 68 lb pipe unless we relax our design factor. That might be a consideration in some cases, but we are not going to relax our design factor in this example. Another possibility might be to see what a 61 lb N80 section would work since it would have a slightly higher strength that the 61 lb K55. Unfortunately there is no 61 lb N80; the least weight of N80 is 68 lb so there is no alternative there. It looks at this point like the best choice is to select our string as follows:

Surface Casing Burst Design

Type Casing

Interval

Section Length

13 3/8” 54.5# K55 ST&C

0 – 2100 ft

2100 ft

13 3/8” 68# K55 ST&C

2100 – 3000 ft

900 ft

Now let us see how this string works with our burst design line. As can be seen this design works well for burst so there is no adjustment needed at this point.

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Surface Casing Design Pressure (psi) 0

500

1000

1500

2000

2500

3000

3500

0

Collapse Design Line

500

Burst Load Line 54.5 lb K55

54.5 lb K55

1000

Depth (ft)

1500

Burst Design Line

Collapse Load Line

2000

68 lb K55

2500

68 lb K55

3000

3500

Next we consider the tension. We have not prepared a tension load curve nor design line yet, because the tension will depend on the weight of the casing string.

Surface Casing – Axial Load There are three sources of tension (or compression) in a casing string. •

Gravitational forces (weight)

•

Borehole friction

•

Bending

The tension in a casing string at any point due to gravity or weight is a function of the buoyancy of the drilling fluid and by the inclination of the wellbore. The tension due to borehole friction is a function of gravity, buoyancy, wellbore inclination and curvature, and also the tension in the pipe. (In the case of a curved wellbore, the tension is a function of the friction, but the friction itself is also a function of the tension). We are not going to consider directional wells or borehole friction at this time. Here are some of the considerations in designing casing to consider the axial load. •

Weight in air or buoyed weight?

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•

Over pull or design factor?

•

Borehole friction?

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Weight of Pipe

When we work with casing in a wellbore we must consider its weight and the amount of tension in the string due to that weight. What measure we use for the weight? Do we use the weight of the casing in air or do we use the buoyed weight of the casing in the drilling fluid that is in the hole? As hard as it may be to believe, there is no universally accepted answer to that question in oilfield practice in the world today. Many use the weight in air claiming that it gives an extra margin of safety. Others say the buoyed weight is more realistic.

Design Factor

When it comes to the tensile design of casing there are two schools of thought. One is to use a design factor, e.g. 1.6, and the other is to use a specified amount of over pull, say 100,000 lb. It is quite common to use both and say that the design should incorporate whichever one leads to the strongest design. In cases where the design factor is the highest value that is usually the case only near the surface and the over pull will be greater near the bottom.

Axial Load

If we chose to use the weight of the casing in air, the design process is quite simple. The problem is that it can lead to an over design of the string because the casing is almost never actually suspended in air. While this used to be a common practice it is seldom used by many today. The buoyed weight of the casing in the drilling fluid is generally recognized as the standard approach for designing casing to withstand the axial loads in the pipe. There are two ways to go about this. One way is to use the true axial load and the other is to use the effective axial load. •

True axial load comes from the actual hydrostatic forces acting on the tube and is valid for all bodies

•

Effective axial load

comes from Archimedes principle which is only valid for

rigid bodies Let us examine a plot of the axial load of our surface casing string in air (un-buoyed), the true axial load in 9.2 ppg mud, and the effective axial load in 9.2 ppg mud.

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Axial Load Curves Axial Load (1000 lb) -50

0

50

100

150

200

0

500

Axial Load Unbuoyed

Depth (ft)

1000

1500

True Axial Load

2000

Effective Axial Load

2500

3000

3500

Notice the true axial load curve on the left. It is actually in compression at the bottom – because of the hydrostatic pressure on the cross-sectional are of the tube at the bottom. Notice also that at 2100 feet the curve shifts slightly. That is due to the difference in cross-sectional area of the 54.5 lb/ft and the 68 lb/ft casing at that point. The tension increases, meaning that the net hydrostatic force is acting downward because the ID of the 68 lb/ft pipe below is smaller than the ID of the 54.5 lb/ft pipe above. Had the heavier pipe been on top, the curve would have shifted in the opposite direction. Another thing to notice about these curves is that the un-buoyed load curve essentially parallels the true load curve. It is much easier to calculate manually since there are no differences in cross-sectional areas and hydrostatic pressures to calculate. That is why in the past many used this as the basis for their design (along with an appropriate design factor). In fact many still do use it, especially when doing manual calculations for calculating the axial load line. We will now examine the method used for calculating the true axial load. Perhaps it is best to first look at a schematic of a casing string showing the change in cross-sectional areas and hydrostatic forces. True Axial Load

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We can write an equilibrium equation for the hydrostatic and gravitational forces in this diagram. Since the load is discontinuous at each change in cross-sectional are it requires two equations, one for the load just above each change of cross-sectional area and one just below each change. Above each change of area the equation is: k

k

i =1

i =1

Pk = − po A1 + ∑ wi Li + ∑ pi ( Ai +1 − Ai )

for 0 ≤ k < n

(5.1)

Below each change in cross-sectional area and at the very top of the string the true axial load is given by: k

k −1

i =1

i =1

Pk = − po A1 + ∑ wi Li + ∑ pi ( Ai +1 − Ai )

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for 0 ≤ k = n

(5.2)

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where

k = node or section number n = total number of sections in string For example if we desired to obtain the true axial load just above section 2 in the drawing above we would use Equation (5.1) as follows: P2 = − po A1 + w1 L1 + w2 L2 + p1 ( A2 − A1 ) + p2 ( A3 − A2 )

And the true axial load just below the top of section 2 is calculated using Equation (5.2) as follows: P2 = − po A1 + w1 L1 + w2 L2 + p1 ( A2 − A1 )

While that may seem a little complicated, it is very easy to do on a computer spread sheet. Let us see how it works for our surface casing so far selected: Type Casing

Interval

Section Length

13 3/8” 54.5# K55 ST&C

0 – 2100 ft

2100 ft

13 3/8” 68# K55 ST&C

2100 – 3000 ft

900 ft

We will make a table of the variables that go into the equations first to organize things a bit. Section

Weight

Length

Area

Depth at bottom

Pressure at bottom

Lb/ft

ft

in2

ft

psi

2

54.5

2100

15.513

2100

1005

1

68

900

19.445

3000

1435

Calculate the true axial load at the bottom of each section and at the top of the well using Equation (5.2)

5 - 16

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

P0 = − p0 A1 = 1435 (19.445 ) = −27,904 lb P1 = − po A1 + w1 L1 = −27,904 + 68 ( 900 ) = 33, 296 lb P2 = − po A1 + w1 L1 + w2 L2 + p1 ( A2 − A1 ) = 33, 296 + 54.5 ( 2100 ) + 1005 (19.445 − 15.513) = 151, 698 lb

Next we use Equation (5.1) to calculate the true axial load just above the places where the cross-sectional area changes, and in this case there is only one at the top of the first section. P1 = − po A1 + w1 L1 + p1 ( A2 − A1 )

= −27904 + 68 ( 900 ) + 1005 (19.445 − 15.513) = 37, 248 lb Section

Depth

Pressure

CrossSectional Area

True Axial Load

ft

psi

in2

lb

2 (top)

0

0

15.513

151,698

2 (btm)

2,100

1,005

15.513

37,248

1 (top)

2,100

1,005

19.445

33,296

1 (btm)

3,000

1,435

19.445

-27,904

This direct method appears in a number of sources, and is the generally accepted method for calculating the true axial load. We will see later that it has a flaw as it is presented here and in other sources.

Effective Axial Load

Now the question will likely arise, what is the purpose if any of the effective load curve? If it is not the actual load in the casing, why do we even consider it? This load curve requires some discussion even though the load it portrays is strictly fictitious; in other words, except at the top of the string it does not even exist. First, you should be aware of what it is because it makes an appearance in a lot of oilfield applications. As we said before it comes from Archimedes principle, and usually involves the calculation of a buoyancy factor based on the difference between the density of the

5 - 17

C A S I N G

&

C E M E N T I N G

steel and the liquid it is in. It is very easy to calculate and we are going to use it for exactly that reason. Second, you should be aware that it is frequently misused in some oilfield applications. Archimedes principle was intended for use with rigid bodies and not with extensible bodies (things that deform). You can sometimes use it with extensible bodies, but you can also get into a lot of trouble if you are not careful. Third, you should be aware that it does have legitimate uses that are quite important. One legitimate use for the effective load curve is for determining lateral buckling of tubes in a wellbore due to axial loads. Contrary to what you might initially think the hydrostatic force on the end of a tube has no effect whatsoever on the lateral buckling of pipe as long as the density of the pipe is greater than the density of the fluid it is in. Believe it or not, there was a time that some engineers were so confused by this that they thought it would be impossible to run a wire line into a deep well because the hydrostatic force on the bottom of the wire would cause it to buckle and not go below a certain depth. Most of us now know intuitively that such cannot possibly be the case, but there are still many who harbor some notion that it can cause drill pipe, drill collars, or even casing to buckle laterally. A typical misapplication along these lines is in the selection of the number of drill collars required to prevent buckling of the drill pipe. For many years drillers calculated a buoyancy factor for the drill collars and calculated how many would be required to maintain a certain weight on the bit plus a few extras for safety. That was a method based on the effective axial load. Along in the 1970’s someone looked at the true axial load and decided that drillers had been doing it wrong all those years. They showed us all how we should calculate the true axial load as opposed to the effective axial load, and of course the net result was that we were not running enough drill collars. A lot of us affected by that revelation realized we had really been dumb in the past so we all changed our calculation method. Of course the new method always required more drill collars than the old method. Then some began to ask the question, if the old method was so obviously wrong why did it work? Well, it worked because it was correct. A static liquid cannot sustain a shear force or a moment on a buckled tube in a wellbore as long as the density of the tube is greater than the density of the liquid. In other words, the hydrostatic forces acting axially along the tube can neither cause nor sustain a laterally buckled configuration. In fact use of the true axial load leads to the absurd result that you still need drill collars even when there is no weight on the bit. Unfortunately, some are still using the true axial load to determine the number of drill collars required. The rental tool companies love it. Now there is another use of the effective axial load and that is to simplify the manual calculation of the true axial load. We can use it to calculate the true axial load with just a few steps. Some find it easier to calculate the effective load first then the true load from those results, and it has another advantage which we will mention later. Let us see how this procedure works. First we calculate a buoyancy factor.

5 - 18

C A S I N G

fb = 1 −

D E S I G N

–

P R E L I M I N A R Y

ρm

(5.3)

65.43

where

ρ m = mud density, ppg 65.43 = steel density, ppg This formula can be used in any system of units as long as the density of steel is in the same units as the density of the mud. Other units are given in Chapter 12. To illustrate the process we will use our 13 3/8 in. surface casing string we have thus far designed for collapse and burst. So for our casing string the buoyancy factor is:

fb = 1 −

9.2 = 0.8594 65.43

To calculate the buoyed weight of a section of pipe we multiply the weight in air by the buoyancy factor. In our casing string we have: Weight

Section Length

Section Weight Unbuoyed

Axial Load Un-buoyed

lb/ft

ft

lb

lb

Buoyancy Factor, fb

Effective Axial Load lb

54.5

2100

114,450

175,650

0.8594

150,954

68

900

61,200

61,200

0.8594

52,595

Next we calculate the true axial load using the following equation.

P = P′ − pm At where

5 - 19

(5.4)

C A S I N G

&

C E M E N T I N G

P = true axial load, lb P′ = effective axial load, lb pm = 0.052 ρ m D = pressure of the mud, psi

ρ m = density of the mud, ppg D = true vertical depth, ft At =

π

(d 4

2 o

− di2 ) = cross sectional area of tube, in 2

d o = outside diameter of tube, in. di = inside diameter of tube, in.

We will use a table to show the calculations. Section

Effective Load

Depth

Pressure

CrossSectional Area

True Axial Load

lb

ft

psi

in2

lb

2 (top)

150,954

0

0

15.513

150,954

2 (btm)

52,595

2,100

1,005

15.513

37,004

1 (top)

52,595

2,100

1,005

19.445

33,053

1 (btm)

0

3,000

1,435

19.445

-27,904

Whether it is easier to do the calculations this way or directly using Equations (5.1) and (5.2) is a matter of personal preference. However, when designing a casing string for directional wells we find that the axial load has to be calculated by some type of torque and drag software using the pipe weights, mud density, directional surveys, and friction factors. All of the commercial software models give the resulting axial load in the form of the effective axial load. (If your torque and drag software shows a zero axial load at the bottom of the string it is definitely the effective axial load, not the true axial load.) So for casing design in a highly deviated well, it becomes necessary to transform that into a true axial load (though many are not aware of that), and this method is the easiest way to accomplish that manually. You may also notice this last method of calculating the true axial load gives slightly different results from Equations (5.1) and (5.2). This is not the fault of the method, but rather the way that the API specifies its casing weights, and an error on the part of

5 - 20

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

whoever came up with the direct method. When we calculated the true axial load directly we used the dimensions and weights given by API assuming that the hydrostatic forces only acted on changes in the cross-sectional area of the pipe. As it turns out there is a problem with the direct method as given in this manual and other sources. Although it is the recognized industry standard method it does not account for the buoyancy of the couplings. For instance 13 3/8 in. 68 lb/ft casing does not really weigh 68 lb/ft, it weighs 66.1 lb/ft. The extra weight in the API specification is to account for the weight of the couplings. The API calculates the nominal weight by adding the weight of a coupling less the material removed in cutting the threads to the weight of a 20 ft length of pipe. It is then divided by 20 to give the nominal weight per foot. That is obviously not very accurate because a short coupling does not weigh the same as a long coupling and integral joints like API Extreme-line have an upset and an integral connection. Also, almost no one uses casing joints of 20 feet in length; typically casing is run in joints that are range 2 or range 3, which average about 30 ft and 40 ft respectively. The direct method we employed accounts for the weight of the couplings in air because they are approximately included in the 68 lb/ft API nominal weight, but it does not account for any buoyancy of the couplings. In our example the actual buoyant force on the couplings would be about 1042 lb total, assuming 20 ft joints in the string. So the truth should be clear; the method of calculating the true axial load from the effective axial load is actually more accurate than the direct method which appears in many sources, e.g. Bourgoyne, et al. (1991) because the direct method (as published) does not take into account the buoyant effects on the couplings. Of course, the issue is rather trivial on the whole, but you should understand the difference. One of the problems we have had for years in the petroleum industry has been a lack of understanding of simple hydrostatics. Now that we have shown the various methods of calculating the axial load curve let us proceed with the design of the surface casing string. We have already stated that we are going to use a design factor of 1.6 and 100,000 lb over pull, whichever is greater.

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C A S I N G

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C E M E N T I N G

Surface Casing Axial Load Axial Load (1000 lb) -150

-50

50

150

250

350

450

550

650

750

0

500

1000

Safety Factor = 1.6

True Axial Load

Depth (ft)

54.5 lb, K55 ST&C 1500

2000

2500

3000

68 lb, K55 ST&C 100,000 lb over pull

3500

In this case the design factor of 1.6 is less than the 100,000 lb over pull at all points so we use the over pull line as the design line. When we plot the casing we have already selected to meet the collapse and burst requirements we find that it easily exceeds the tension requirements also. This is fairly typical of many surface strings, but the tensile design should always be checked to be certain. Casing Design Summary 13 3/8" Surface Casing Actual Design Factors Section Number 2 1

OD ID Weight Grade Connection 13.375 12.615 54.5 K-55 ST&C 13.375 12.415 68 K-55 ST&C

Bottom 2100 3000

Length 2100 900 0 0 0 0 0 0 3000

Mud Weight:

9.2

Totals: Minimum Safety Factors Collapse: 1.125 Burst: 1.125 Tension: 1.6/100,000

Section Weight 114450 61200 0 0 0 0 0 0 175650

Cum. Weight Collapse 175650 1.125 61200 1.359 0 0 0 0 0 0

Joint Burst Strength 1.128 3.6 1.916 26.135

Intermediate Casing – Preliminary Design The design of the intermediate casing is done exactly as the design of the surface casing except we use the design load curves we made for the 9 5/8 inch intermediate casing.

5 - 22

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

Intermediate Casing Design Pressure (psi) 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

8000

8500

9000

0

Burst Load Line

Burst Design Line

2000

Collapse Design Line

Depth (ft)

4000

6000

8000

10000

Collapse Load Line

12000

The design lines have been added to the chart using the same design factors used for the surface casing. We will assume that we have the following 9 5/8 inch casing available in our inventory for use in this well. Wt

Grade

Connection

lb

ID in.

Joint Collapse Internal Strength Yield Pressure 1000 lb psi psi

36

K-55

ST&C

8.921

2020

3520

423

40

K-55

ST&C

8.835

2570

3950

486

40

K-55

LT&C

8.835

2570

3950

561

40

N-80

LT&C

8.835

3090

5750

737

43.5

N-80

LT&C

8.755

3810

6330

825

47

N-80

LT&C

8.681

4750

6870

905

53.5

N-80

LT&C

8.535*

6620

7930

1062

5 - 23

C A S I N G

Wt

&

C E M E N T I N G

Grade

Connection

lb

ID in.

Joint Collapse Internal Strength Yield Pressure 1000 lb psi psi

58.4

N-80

LT&C

8.435*

7890

8650

1167

43.5

P-110

LT&C

8.755

4420

8700

1105

47

P-110

LT&C

8.681

5300

9440

1213

53.5

P-110

LT&C

8.535*

7950

10900

1422

*Note that since we elected to drill an 8 ½ inch hole from the bottom of the intermediate casing to total depth we may have a problem with some of the casing in this inventory. The 53.5 lb/ft casing will have to be specially drifted for an 8 ½ inch bit. The 58.4 lb/ft casing cannot be used unless we use a smaller bit. A precursory examination of the available pipe and the loads we can see almost immediately that the collapse loading is very small and the weakest pipe in our inventory will easily sustain the maximum collapse load. We also note that the burst load is relatively high and that the first three items in our inventory will not sustain the burst load at the bottom of the string where the burst load is the lowest. It looks like the best place to start on this design is with the burst design curve. Intermediate Casing Burst & Collapse Design

5 - 24

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

Intermediate Casing Design Pressure (psi) 0

500

1000

1500 2000

2500

3000

3500

4000

4500 5000

5500

6000

6500

7000

7500 8000

8500

9000

9500

0

Burst Load Line

43.5 lb, N-80

2000

47 lb, N-80

53.5 lb, N-80

4000

Depth (ft)

Burst Design Line

47 lb, N-80 6000

43.5 lb, N-80

8000

40 lb, N-80

10000

12000

In this design we have used some 53.5 lb/ft N-80 casing in the string. We should recall that the internal diameter of this pipe is 8.535 in. which is large enough for an 8 ½ in. bit. However, the drift diameter is only 8.379 in. which is less than the bit diameter. If we were to select this design we would have to drift this pipe to be sure that an 8 ½ in. bit would pass through it. An alternative would be to use some 43.5 lb/ft P-110. We can easily check to see that all of this casing far exceeds the collapse design load for this well, so we are not going to plot it here. Intermediate Casing Axial Load

Now we look at the axial load. The casing is run in 11.8 ppg mud, and normally we use the true axial load of the casing just as we did for the surface casing, however, for illustration we will use the weight in air. We calculate the weight of the casing string.

5 - 25

C A S I N G

&

C E M E N T I N G

9 5/8" Intermediate Casing Weight in Section Bouyancy Section Air Length Factor Weight fb lb lb/ft ft 43.5 1800 1.00 78300 47 1200 1.00 56400 53.5 1800 1.00 96300 47 1700 1.00 79900 43.5 2000 1.00 87000 40 2000 1.00 80000 Total Length: 10500

Cumm. Safety Weight Factor fs lb 477900 1.8 399600 1.8 343200 1.8 246900 1.8 167000 1.8 80000 1.8

Design Weight lb 860220 719280 617760 444420 300600 144000

The plot below shows us that all of the casing is well above the tensile limit except for the top section of 43.5 lb/ft N-80. Intermediate Casing - Tension Tension (lb) 0

200000

400000

600000

800000

1000000

0 43.5# N-80 LT&C Tension Load 2000

47# N-80 LT&C

Tension Design

53.5# N-80 LT&C

Depth (ft)

4000

47# N-80 LT&C

6000

43.5# N-80 LT&C

8000

40# N-80 LT&C

10000

12000

We must now adjust our design in tension. We can see that the 47 lb/ft N-80 section can be extended to the top, but that will also add weight to the string and we must recalculate and re-plot our load curve. So let us see the effect of extending that section to the top.

5 - 26

C A S I N G

9 5/8" Intermediate Casing Weight in Section Bouyancy Section Air Length Factor Weight fb lb lb/ft ft 47 1800 1.00 84600 47 1200 1.00 56400 53.5 1800 1.00 96300 47 1700 1.00 79900 43.5 2000 1.00 87000 40 2000 1.00 80000 Total Length: 10500

D E S I G N

–

P R E L I M I N A R Y

Cumm. Safety Weight Factor fs lb 484200 1.8 399600 1.8 343200 1.8 246900 1.8 167000 1.8 80000 1.8

Design Weight lb 871560 719280 617760 444420 300600 144000

And we plot the adjusted load curve as below. Intermediate Casing - Tension Tension (lb) 0

200000

400000

600000

800000

1000000

0

47# N-80 LT&C

Tension Load 2000 Tension Design

53.5# N-80 LT&C

Depth (ft)

4000

47# N-80 LT&C

6000

43.5# N-80 LT&C

8000

40# N-80 LT&C

10000

12000

Now the top section works. The preliminary design for the intermediate casing string is complete. This string is obviously over designed as compared to the method we used for the surface casing, but this particular design method has been used for many years in the industry and it is shown here to illustrate how it works.

5 - 27

C A S I N G

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C E M E N T I N G

Casing Design Summary 9 5/8" Intermediate Casing Actual Design Factors Section Number 5 4 3 2 1

OD 9.625 9.625 9.625 9.625 9.625

ID Weight Grade Connection 8.681 47 N-80 LT&C 8.535 53.5 N-80 LT&C 8.681 47 N-80 LT&C 8.755 43.5 N-80 LT&C 8.835 40 N-80 LT&C

Bottom 3000 4800 6500 8500 10500

Length 3000 1800 1700 2000 2000 0 0 0 10500

Mud Weight:

11.8

Totals: Minimum Safety Factors Collapse: 1.125 Burst: 1.125 Tension: 1.8 in air

Section Weight 141000 96300 79900 87000 80000 0 0 0 484200

Cum. Weight Collapse 484200 high 343200 high 246900 high 167000 2.54 80000 1.66 0 0 0

Burst 1.13 1.25 1.13 1.126 1.127

Joint Strength 1.87 3.09 high high high

Production Casing – Preliminary Design Finally we come to the production casing. The production casing is the final string of casing. We expect that it should be capable of containing full well pressure throughout the producing life of the well. It should not collapse should the well be depleted significantly, nor under any operations conducted in the wellbore during workovers or stimulations. Here is the load curve we developed in the previous chapter. Production Casing Load Pressure (1000 psi) 0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

5.5

6

6.5

7

7.5

8

0

2000

Collapse Load Line

Burst Load Line

4000

Depth (ft)

6000

8000

10000

12000

14000

We will use the following design factors:

5 - 28

8.5

9

9.5

10 10.5 11 11.5 12

C A S I N G

•

Collapse – 1.125

•

Burst – 1.2

•

Tension – 1.6 or 100,000 over pull

D E S I G N

–

P R E L I M I N A R Y

Now we look at the 7 inch casing available to us for this production string.

Wt

Grade

Connection

lb

Production Casing Collapse Design

ID in.

Joint Collapse Internal Strength Yield Pressure 1000 lb psi psi

26

N-80

LT&C

6.276

5,410

7,240

519

29

N-80

LT&C

6.184

7,030

8,160

597

32

N-80

LT&C

6.094

8,600

9,060

672

35

N-80

LT&C

6.004

10,180

9,240

746

38

N-80

LT&C

5.920

11,390

9,240

814

26

P-110

LT&C

6.276

6,230

9,960

693

29

P-110

LT&C

6.184

8,530

11,220

797

32

P-110

LT&C

6.094

10,780

12,460

897

35

P-110

LT&C

6.004

13,030

12,700

996

First we take our collapse load curve and plot a design curve on it using the design factor we selected, 1.125.

5 - 29

C A S I N G

&

C E M E N T I N G

7" Collapse Design Collapse Pressure (1000 psi) 0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

13

14

0

2000

4000

Depth (ft)

6000

8000

10000

12000

14000

16000

We then start fitting casing from our inventory onto the collapse design curve. 7" Collapse Design Collapse Pressure (1000 psi) 0

1

2

3

4

5

6

7

8

9

10

11

12

0

2000

4000

32# N-80

Depth (ft)

6000

8000 29# P-110 10000 32# P-110 12000

14000 35# P-110 16000

5 - 30

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

We did not select casing all the way to the top based on collapse because the burst load will require us to change it anyway. Now we will plot these sections on the burst curve, adjust if necessary, and then complete the string to the surface based on the burst design. 7" Burst Design Burst Pressure (1000 psi) 0

2

4

6

8

10

12

0

2000

4000 29# N-80 6000 Depth (ft)

Production Casing Burst Design

8000 32# N-80 10000 32# P-110

12000

14000 35# P-110 16000

We can see on this plot that the 29 lb/ft N-80 will not work at all, so we have gone one step too far in the collapse design. We will go back to the burst design and start with the 32 lb/ft N-80 and design to the top using the burst curve.

5 - 31

C A S I N G

&

C E M E N T I N G

7" Burst Design Burst Pressure (1000 psi) 0

2

4

6

8

10

12

0

2000 29# P-110 4000

Depth (ft)

6000

8000 32# N-80 10000 32# P-110

12000

14000 35# P-110 16000

Now our design is complete for collapse and burst. Next we will look at tension.

Production Casing Axial Load Design We will use the true axial load and a design factor of 1.6 or 100,000 lb over pull. Then we plot these on a chart for designing the tension.

5 - 32

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

7" Casing True Axial Load Design Axial Load (1000 lb) -200

0

200

400

600

800

1000

0 True Axial Load 2000

29# P-110 Safety Factor = 1.6

4000

6000 Depth (ft)

32# N-80 8000

10000 32# P-110 12000 Over Pull 100,000 lb 14000

35# P-110

16000

As can be seen we got a bit lucky because the string we designed for collapse and burst meets the design load for tension too. This completes our production casing preliminary design. Casing Design Summary 7" Production Casing Actual Design Factors Section Number 4 3 2 1

OD

ID 7 7 7 7

Weight 29 32 32 35

Grade Connection P-110 LT&C N-80 LT&C P-110 LT&C P-110 LT&C

Bottom 4800 9600 12100 14000

Length 4800 4800 2500 1900 0 0 0 0 14000

Mud Weight:

15.2

Totals: Minimum Safety Factors Collapse: 1.125 Burst: 1.2 Tension: 1.6/100,000lb buoyed

Section Weight 139200 153600 80000 66500 0 0 0 0 439300

Cum. Weight Collapse 439300 2.25 300100 1.33 146500 1.127 66500 1.177 0 0 0 0

Burst 1.275 1.2 high high

Joint Strength 2.34 3.36 high high

Closing Comments In the preliminary designs for surface casing, intermediate casing, and production casing that we just examined we used a variety of design factors. In two cases we considered the buoyed weight of the casing in the tension design; in the other we did

5 - 33

C A S I N G

&

C E M E N T I N G

not. We did that primarily to illustrate the different approaches. Typically a company will have a set of design criteria for a specific area or field or even company wide and will stay with those same criteria for all designs. Another point we should make is that we selected from our inventory of pipe without explanation as to why we chose one as opposed to another. There are many possible combinations that would work just as well if not better than the selections we made. In general the choice between two different types of casing for a particular section would be based on:

•

Cost

•

Availability

•

Simplicity of design

•

Minimum number of crossovers

•

Corrosion considerations

•

Wear considerations

•

Many more

Generally cost is the over riding factor in deciding which particular type of casing to select when several types of casing will satisfy the load requirements of the design. Obviously we could select a string of some weight of P-110 grade pipe that would meet all of our design criteria easily. However, the cost of such a string would far exceed that of a string made up of several weights of N-80, K-55, and even some P-110 if required. In the designs in this chapter our basic premise was to try to select the lowest grade first then the lowest weight because that is how costs tend to run. We also tended to stay away from the heaviest weight in any grade since that is usually a special item not readily available and often with too small an internal diameter to use common bits and tools. Costs vary considerably and we do not attempt to put casing costs into our examples here, but in general the lower the grade the lower the cost. However, it is possible a joint of heavy N-80 may cost less than a joint of light P-110. The other thing that complicates the cost picture is the inventory status within a company and the availability of certain weights and grades. It may be more costly to purchase some K-55 casing than to use some N-80 that is already owned by the company or the companies partners in some venture. Costs

We have not mentioned corrosion here because this is a complex issue beyond a foundation level course. But when hydrogen sulfide (H2S) is present our selection process would be quite different. We would have

Corrosion

5 - 34

C A S I N G

D E S I G N

–

P R E L I M I N A R Y

to stay away from the more brittle steels like P-110 and even N-80. In those cases we would select grades with controlled hardness such as L-80 and C-90 which are much less susceptible to hydrogen embrittlement. Preliminary Design?

We have repeatedly referred to our design procedures in this chapter as preliminary steps in a design. In fact, many operators go no further than what we have done here. That is their final design, and in many cases that is sufficient. In the next chapter we are going to look at the effects of combined loading and how these loads may require adjustments and tuning of our preliminary design.

References Bourgoyne Jr., A.T., Chenevert, M.E., Millheim, K.K., and Young Jr., F.S., (1991), Applied Drilling Engineering, Society of Petroleum Engineers, Dallas, Texas Prentice, Charles M.., (1969), Maximum load casing design, SPE Paper Number 2560. API Bulletin 5C2, (1999, Oct), Bulletin on the Performance Properties of Casing, Tubing, and Drill Pipe, American Petroleum Institute, Washington, D.C.

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6

Chapter

Casing Design – Combined Loads How do we do it?

U

sing the depths, sizes, and casing loads we learned how to select a preliminary design in the preceding chapter. Our preliminary design was based on the strength values from tables published by the API (similar tables are available for non-API tubes), and are based on formulas developed by the API. The API formulas and methods have been used successfully for many years. But there are limitations to the API methods. In the presence of some combined load situations, the API method fails even though it has ways to consider some combined loads. Another big problem with the API approach is that it involves a virtual morass of formulas and can be very confusing. A much more elegant method based on the yield stress of the metal, considered more advanced by many, actually gives us a very easy method that is well founded in mechanics and does not rely on empirical formulas. Its limitation, though, is the fact that some tubes collapse before the pipe reaches the yield stress, and also the joint connections do not perform like the body of the pipe. So in one sense we are still stuck with some vestiges of the API methods. What we now seek to do is to refine our preliminary design so that it will safely sustain the combined loads within some predetermined design limits. We will use what is called a deterministic design method which will be explained later. Even after stating that we will use a deterministic method there are still some alternatives. The problem is that no one method will give us satisfactory results in every case. Contrary to the conventional approach to casing design we will look at the more advanced yield based method first. It is very easy to understand and has only one

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essential formula, plus a few additional formulas to convert tension and pressure loads into stresses. After that we will look at the API based method and formulas. The API formulas and methods will actually be easier to understand after learning the yield method rather than before. Before getting into the details of specific methods we should address some general considerations about designs and loading.

General Structural Design Methods There are two general approaches to designing casing or any type of structure. One is a deterministic design method, and it is the process we are most familiar with. We use published values for the minimum strengths and performance properties of the materials, hypothetical load scenarios based on observed and hypothetical criteria, and a set of formulas to calculate and then specify the types and sizes of structural materials required to safely sustain those loads. This is the method for the design of most common static structures such as bridges, skyscrapers, television transmission towers, drilling rig masts, and even oilfield casing strings. The other general approach is a probability-based design method in which we use statistical test data for the strengths and properties of actual materials and probabilistic loading scenarios. This approach is often used in the design of structures subject to dynamic and cyclic loading such as airframes, turbine blades, and so forth where fatigue failure is a significant or dominant factor. The probabilistic design criteria in these types of structures may also be weighted on the consequences of structural failure. In other words, the critical strengths and loads are often based on things like risk to human life, property value, the environment, and so forth. An example would be the blade of a gas turbine operating in some remote oilfield location as opposed to a jet engine turbine blade on an aircraft flying human passengers across a continent, in other words a 0.01% probability of failure may be acceptable for the remote oilfield gas turbine, but that same failure probability in an aircraft engine design would likely have aircraft falling out of the sky almost daily and that is not acceptable. This method can also be applied to static type structures, and an example we see of this in the oilfield is in part of the design of pipelines where the published standard for strength is based on the human population density in the vicinity of the pipeline. A common mistake is to think that a deterministic design gives us a 100% safe structure at a higher cost, and a probabilistic design gives us a more cost effective structure but at a slightly greater risk. While that may be true in many cases it is not true in general. Both methods have their place and applications. Some companies are now using probabilistic methods in casing design. However, we are going to use the deterministic method in this course as it is still the industry standard, but you should be aware that there are other legitimate approaches.

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One last comment about probability based methods. When we speak here of probabilistic methods the probabilities arise from our lack of information or knowledge. This should not be confused with the probabilistic workings of nature on an atomic scale – the two are totally different concepts.

Design Limits One thing you must get very clear in your head is that when we design casing (or any other type of structure) we are not attempting to predict failure. Predicting actual failure is near impossible even when you have the most complete data you can imagine, and in the case of oilfield tubes and borehole conditions predicting failure is impossible. So our goal is to calculate some design limits and select our casing such that the anticipated loads do not exceed those limits. Calculating design limits and predicting failure are separate and distinct processes. Engineers have no idea how to predict failure accurately.

A design limit should naturally be linked to some strength property of the structural member which is a tube in our case. Since we have already stated that we cannot predict actual failure of the tube there must be some other strength property of the tube that we can reliably predict. And in fact there is and it is the yield stress of the metal from which the tube is made. The yield stress (sometimes referred to as the yield strength) of a metal such as steel is well defined and relatively easy to determine experimentally. A piece of the metal is cut into the shape of a test sample and it is placed in a device that pulls tension on it (or applies compression). In a simplified version of this test we can mark off a distance on the sample before the test is begun and call it L. As tension is applied to the sample it begins to stretch slightly and the original length we delineated as L gets longer. It increases by some amount we will call ∆L. We can then define the uniaxial strain in the direction of the load as ε = ∆L L so that it is simply the change in length divided by the original length. We can also measure the cross-sectional area of the sample and call it A. If the tensile load of the machine at any time is P then we can define the uniaxial stress in the sample as σ = P A .

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Figure 6 - 1. Test specimen for uniaxial stress test.

Then if we record the uniaxial stress and strain as the test is being conducted it would give us a plot similar to this one.

Figure 6 - 2. Simple stress-strain relationship for uniaxial test of carbon steel.

This simple uniaxial test is quite easy to do and gives us some very useful results. The point where the slope goes from linear to nonlinear is called the elastic limit or yield point. Up to that point the material behaves elastically. At any point below the elastic limit the load can be removed (returned to zero) and the strain will also return to zero. That is what we call elastic behavior. But once the sample is deformed beyond that point the material enters a plastic region and when the load is removed and reduced to zero the strain will not go back to zero. It has undergone some permanent deformation or plastic deformation.

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In many cases the behavior of the metal at the yield point is somewhat more complicated than that in the above illustration. Sometimes the behavior becomes nonlinear before the yield stress is reached and that point is called the proportional limit. Ductile steels often exhibit this behavior and materials like cast iron seldom exhibit a distinctive yield point. There are other cases where the stress actually decreases slightly after the yield stress is reached and hence there is an upper yield stress and a lower yield stress. This is typical of some steel alloys. In many cases the yield point is indistinct and the yield point is defined as some arbitrary point offset from the proportional limit by a specified amount of strain (API does this). We are not going to concern ourselves with those details, but rather assume that as long as we do not exceed the published yield stress for the casing material that its behavior is linear and elastic. The behavior of the metal in the elastic range is easy to measure and predict. And as long as the load on the metal does not exceed the yield point the metal will behave exactly the same every day with every load. Once the metal goes into the plastic region, however, things get considerably more complicated. The stress-strain relationship becomes nonlinear and the yield point is no longer a constant; it changes and becomes a history dependent property of the metal. It is no longer possible to predict the behavior of the metal without new tests or a record of its load history plus some additional properties not revealed by the simple uniaxial tensile test. The design limit we will use is the yield stress of the material.

The yield stress or some fraction of it is the design limit of almost every structure designed and built in the world. There are very few exceptions. The only equipment in the oilfield that is designed to operate in the plastic region is coiled tubing when it is cyclically bent over the reel, guide arch, and injector. Typically it may experience strains an order of magnitude greater than at the yield stress of the tube. Now that we have established what will constitute our design limit, the yield stress, we must look at the various ways in which loads affect the casing. Several distinct types of loading are possible, either singly or in combination.

• Tensile • Burst • Collapse These are the items we used in our preliminary design and the allowable values based on the yield stress of the materials are published in API Bulletin 5C2 for API standard

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tubes as well as many other places. In the previous chapters we explored various ways to determine the loads that we would encounter in various wells. In the last chapter we looked up the allowable values of the tubes in the tables and selected the casing whose strength would exceed our predicted loads in collapse and burst, and then made certain that it was strong enough in tension so that it would support its own weight. It is a simple and straight forward procedure. Though that is the method often used for many years and still used in some areas, it does not account for one critical fact. If a tube is subjected to a combination of tension or compression plus an internal or external pressure then the values in those tables are meaningless. In our simple uniaxial test we loaded the sample in only one direction, but most casing is not loaded in only one direction. The next step of the process is to determine how to apply the results of the uniaxial test in a three dimensional loading situation. That brings us to combined loading and how we account for the ways in which it affects our design.

Combined Loads Almost always casing is subjected to some type of combined loading. Here are the possibilities: •

Tensile and compressive loads

•

Collapse and burst loads due to hydrostatic forces

•

Torsion loads due to borehole friction

due to gravitational forces, borehole friction, hydrostatic forces, and bending forces

There are various ways to calculate a design limit for combined loading. Most of them work, but some are quite misleading and can cause serious problems if one does not understand the limitations. We are going to look at a simple method that has been around for more than 150 years and in publication for almost 100 years. It has been proven effective throughout all those years in all engineering design applications.

THE YIELD BASED APPROACH

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The Yield Criterion What we would like to have is some method of quantifying the combined loads into a single value to compare with some simple strength or stress value for the material of the tube. For example, if Y is the yield stress determined from a uniaxial test and Ψ is the combined load, we might compare them thusly:

Y > Ψ → no yield Y ≤ Ψ → yield

(6.1)

The only problem we face is how to convert the combined loads on the casing into a single value like Ψ. Fortunately this is what a yield criterion allows us to do, and for this course we will use a yield criterion called the von Mises yield criterion which works very well with metals such as steel. When we plot the von Mises criterion in principal stress space (a three dimensional plot where the coordinate axes are the principal stress components rather than a direction measure) it plots as a cylinder. The surface of the cylinder is called a yield surface. The central axis of the cylinder is along a line where all three principal stress components are equal, in other words a hydrostatic pressure or spherical stress. The radius of the cylinder is the value yield stress of the metal. Any value of Ψ that plots within the cylinder will not cause yield, but any value that plots on the surface or outside the surface of the cylinder will cause the metal to yield.

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Figure 6 - 3. A von Mises yield surface in principal stress space.

The von Mises yield surface is a mathematical cylinder; it is not a tube or portion of a casing joint. This is not a picture of a tube. Do not confuse the von Mises yield surface with a tube.

That is straight forward enough. Now the only remaining question is how do we calculate Ψ ? Here is the formula in terms of principal stress components. 1

2 2 2 2 1 Ψ =   ( σ 1 − σ 2 ) + (σ 2 − σ 3 ) + (σ 3 − σ 1 )    2 

(6.2)

Now what is Ψ called? Here we get into a technicality that deserves a little explanation. I use the symbol Ψ and call it the yield indicator because that is as good a name and description for it as I know. In petroleum engineering applications it is often and called the “von Mises stress”. This is a somewhat unfortunate misnomer, because it is not a stress and calling it a stress can lead to a lot of confusion because the actual stresses can never cause the actual von Mises quantity to exceed the yield stress. We will save those technicalities for later, but for now we will just call it a yield indicator, but if you want to call it the von Mises stress then you are welcome to do so, but that term will not be

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used in this manual and it never appears in any text on plasticity or continuum mechanics. Here is another picture of a von Mises yield surface with the three principal stress components for a particular combined load plotted as point a .

Figure 6 - 4. A load that falls outside the yield surface.

Notice point a , which represents the combined load, is outside the yield surface. The yield indicator Ψ then is the scalar magnitude of a radius vector from the central axis of the yield surface to the load point. Remember that Y is the yield stress of the material and is the magnitude of the radius of the yield cylinder. So all we have to do is compare the magnitudes of Y and Ψ, and in this case it is easy to see that

Y Ψ 55000 > 22152 → no yield This is a fairly simple example. In a later example we will look at more complex loading.

Change in Pressure In the above example we considered axial and pressure loads on the tube. Now we must examine something else that can happen to our casing during or after cementing. What happens if we change the internal and/or external pressures during or after cementing operations. Consider three scenarios where the internal and external pressures may differ.

•

Running the casing into the hole, the internal pressure is different from the external pressure due to different fluid densities.

•

After the casing is on bottom and prior to or during cementing we change either the internal or external pressure or both due to differences in fluid densities.

•

After the casing is cemented and landed, we change the internal or external pressure or both due to changes in fluid densities and/or changes in applied pressure. How do those three things affect the axial stress in the pipe?

In the first case there is no actual change in the axial stress due to having different pressures inside and outside the pipe. Assuming we are able to calculate the axial load correctly by taking into account the weight, buoyancy, and friction, the pressure

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differences are not going to cause us to make any further adjustments once we reach bottom. The second case where we change the pressures after reaching bottom could be a different situation. If the casing is totally free to move in the wellbore (which is not the usual case) changing the internal and external pressures and/or the densities of the fluids will cause changes that we can calculate just as in the first example. However, if the casing is not free to move because of friction or it is stuck, any change in the internal or external pressure will change the axial stress and we cannot calculate the changes based on weight buoyancy considerations alone. In the third case we assume the pipe is not free to move where it is cemented so we must assume that the uncemented portion of the pipe is anchored at the top of the cement. Likewise a change in pressures will change the axial stress component in ways that we cannot account for by considering the weight and buoyant forces alone. When the pipe is not free to move we can calculate the change in axial stress due to the change in pressure. Here is the formula for calculating the change in axial stress due to changes in the internal and/or external pressures after the pipe is in place and cannot be moved.

∆σ z = ν ( ∆σ θ + ∆σ r )

(6.10)

In this equation is the original axial stress calculated from the axial load and ν is Poisson’s ratio which is 0.3 for steel. Note that the sum of the tangential and radial stress components is an invariant quantity within the pipe wall and does not depend on whether is was calculated at the inner or outer wall of the pipe. This is the formula often associated with the so-called “ballooning” effect caused by changes in pressure. By itself it will calculate the change in axial stress in the portion of the pipe that is not free to move. In the portion of the pipe that is still free this formula can be applied in conjunction with the changes in buoyancy calculations to determine the changes in axial load in the free portion of the pipe.

Bending Stresses The effect of curved wellbores on the design of casing went without consideration until fairly recent times. We now recognize that a casing joint that is bent in a curved wellbore necessarily has stresses in it that are not accounted for in conventional design procedures of the past. We will examine a simple version of bending, and mention some more complicated issues. Simple beam bending assumptions for a tube state:

•

The cross-section of the tube remains round

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•

Cross-sections perpendicular to the central longitudinal axis before bending remain perpendicular after bending

•

The amount of bending is small compared to the dimensions of the tube

This all works well enough for most borehole situations we encounter.

In the figure above the length of the central axis of the tube remains the same, the concave side compresses and the convex side stretches. The amount of stretch in the convex side is identical to the amount of compression in the concave side. Without going into details we can use the simple beam bending equation to determine the maximum stress due to bending.

σb = ± E

ro R

(6.11)

In that equation the plus-or-minus means tension (+) on the convex side or compression (–) on the concave side, E , is Young’s modulus (elastic modulus, 30×106 psi for steel), ro is the outside radius of the tube, and R is the radius of curvature of the borehole. Now it is important to note that the bending stress predicted by this equation is the stress along a line along the outside of the tube at the convex side and also the concave side. It is not the stress anywhere else in the body of the tube. Another important point is that to use this formula you should be aware

that the radius of the pipe and the radius of curvature of the borehole must be in the same units. It does not matter if you use inches, feet, millimeters, centimeters, or meters, as long as they both use the same units. The radius of curvature of the borehole is a familiar term to those working with directional wells, but may not be understood by those who do not. The assumption made by our current directional calculation method (minimum curvature method) is that the wellbore path between two directional surveys is in the form of a segment of a circle with radius, R . What most engineers are accustomed to working with is a build rate commonly expressed in degrees per 100 foot or degrees per 30 meters. Build rate and radius of curvature are equivalent ways to express the curvature of a borehole. Here are the formulas to go from one to the other.

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θ=

18000 πR

or

R=

18000

πθ

(6.12)

The build rate, θ , is in degrees/100 ft and the radius of curvature, R , is in feet. In the SI system the formulas are

θ=

5400 πR

or

R=

5400

πθ

(6.13)

where the build rate is in degrees/30 m and the radius of curvature is in meters. You will often see Equation (6.11) written in terms of the build rate with conversion factors already inserted. That is fine for those who only want the simple answer, but it is near impossible to understand what it means when written in that form. As presented here one can (or should) see that equation is Hooke’s law ( σ = Eε ) and the ratio of radii in the equation is simply the strain at that point. Example of Bending Stress

A wellbore has a build rate of 15 °/100 ft. If 7 in. diameter casing is placed in this curved borehole, what is the bending stress? Solution:

Get the borehole radius of curvature:

R=

18000 = 382 ft π 15

Then the bending stress is

σb = ±

30 × 106 ( 7.0 2 ) 382 (12 )

= ±22,906 psi

Notice two things in that calculation. In the numerator we changed the diameter of the pipe to the radius by dividing it by two. The second thing is the radius of curvature of the wellbore was in feet so we multiplied it by 12 to get it into inches, the same units as the pipe radius. Also anther point of interest is to notice how much stress a medium radius wellbore can put on a joint of 7 in. casing! Bending stresses can be significant. Advanced Bending That simple bending formulation assumes that the wellbore is smooth and that the pipe is in contact with the wellbore all along Considerations

its length. Now in reality our casing has couplings on it. The couplings are not as flexible as the casing body and all of the casing body does not touch the wellbore wall because of the standoff provided by the larger diameter couplings. In these cases the bending stress may be greater in the casing near the couplings if the pipe is in tension or greater somewhere else if it is in compression. There are formulas to make these calculations and they are adequate as far as they go.

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They are limited in that they assume the casing does not touch the borehole wall except at the couplings. The problem with them is that they provide no way to determine if the equation has reached that limit or not. And once that limit is reached the predicted stress is much higher than the actual stress. One text book uses one of these equations to show that the simple bending equation given here gives a maximum bending stress of 6500 psi in an example. Then they calculate the bending stress using one of the formulas mentioned and it gives a bending stress of 20,000 psi. That is a terrific difference! In fact it is so alarming that you would think the simple formula we are using must be very poor. However, if you do some analysis with the equations that text uses you discover that such a stress requires a lateral displacement of close to 14 inches, yet the borehole curvature in the example will only allow a deflection of 1.25 inches. Clearly the pipe is in contact with the borehole wall and the formula they use is well beyond its limits. So for our purposes we are going to say that the simple beam bending formula is adequate, and the advanced formulas are for those who know how to use them, and apparently not many do.

Summary of the Yield Based Approach We covered a lot of material on the yield based method and it may seem a little confusing at this point. We can summarize the method in a few steps.

•

Calculate the axial stress component from the tension or compression load

•

Calculate the radial stress component from the hydrostatic pressure

•

Calculate the tangential stress component from the internal and external pressures

•

Calculate the torsional stress component from the torque if rotation is employed

•

Calculate the bending stress component if there is curvature in the wellbore, and add this to the axial stress component

•

Put these values into the yield equation and calculate the yield indicator

•

Compare the yield indicator to the yield stress of the pipe

•

Adjust the casing design if necessary

•

Check the collapse and connections using the API methods It may be necessary to recheck the yield in the free pipe if the pressures are changed significantly during or after cementing.

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Another consideration that must be mentioned about calculations based on the yield approach is that different types of loading may be a maximum at the inner pipe wall or the outer pipe wall.

•

Internal and external pressure always causes yielding at the inner wall first

•

Torsion always causes yielding at the outer wall first

•

Bending always causes yielding at the outer wall first

To be accurate we should check for yield at both the inner and outer wall. However, from a practical standpoint with casing the difference is not that significant. There are rare cases where combined loading might cause yielding at one wall and not the other, but the wall where yielding does not occur will be so close to yield that the design will still have to be changed. Another approach is to calculate the radial and tangential stress components at the inner wall, the torsion and bending stress components at the outer wall and combine them in the yield equation. This gives a larger yield indicator than is present at either wall, but the difference is relatively insignificant. In fact, some commercial software does it that way (unfortunately because the authors did not know the difference). However, you choose to handle that is your choice as long as you understand what you are doing. Here are summaries of the important equations of the yield based approach.

Summary of Equations for Stress at the Inner Pipe Wall σz =

P π ( r − ri 2 ) 2 o

σ r = − pi σθ = σ rθ =

pi ( ro2 + ri 2 ) − 2 po ro2

(r

2 o

− ri 2 )

2ri τ π ( ro4 − ri 4 )

Eri R ∆σ z = ν ( ∆σ θ + ∆σ r )

σb = ±

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Summary of Equations for Stress at the Outer Pipe Wall

σz =

P π ( r − ri 2 ) 2 o

σ r = − po σθ = σ rθ =

− po ( ro2 + ri 2 ) + 2 pi ri 2

(r

2 o

− ri 2 )

(6.15)

2ro τ π ( ro4 − ri 4 )

Ero R ∆σ z = ν ( ∆σ θ + ∆σ r )

σb = ±

Summary of Yield Equations Principal Stress Components

σ1 = σ2 =

σθ + σ z 2

σθ + σ z 2

2

 σ −σ z  +  θ + σ θ2z   2  2

 σ −σ z  2 −  θ  + σθ z  2 

σ3 = σr Yield Indicator

(6.16) 1

2 2 2 2 1 Ψ =   ( σ 1 − σ 2 ) + (σ 2 − σ 3 ) + (σ 3 − σ 1 )    2 

Yield Condition Y > Ψ → no yield Y ≤ Ψ → yield

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Example Using Yield Approach

Here is an example of a problem that has occurred on several occasions to various operators. Here is the situation:

An operator is running 7 inch casing into a horizontal well. The casing will be run to the bottom of the build section of the well and will serve as an intermediate string while drilling the horizontal section, but will also serve as the production casing for the open hole completion of the horizontal lateral. As that casing is going in the hole and is about halfway through the build section it stops. This is not uncommon in a horizontal well if the hole is not thoroughly cleaned of cuttings before running the casing – they tend to accumulate in the hole where the inclination angle is between 45° and 60°. The operator was not aware of this. Rather than pull the casing and clean the hole the operator set weight on the casing and attempted to push it further in the hole. He also turned on the pumps to circulate. The driller had set down the entire weight of the string (so the weight indicator went to zero). The float shoe was plugged and the pump pressure went to 2000 psi at the surface. The operator was unsuccessful in getting the pipe to go any further and pulled the casing out of the hole. When he got it to the surface he found that it had buckled and collapsed at a point that was just down inside the build section. The operator was confused as to what had happened since they never exceeded the design limits of the casing. (Other operators have had this same experience and were not lucky enough to get the casing out of the hole.) Let us see if we can determine what happened. Data at 6000 ft (just inside build section): Csg OD:

7.0 in

Csg ID:

6.366 in

Csg Grade:

K55 (55,000 psi yield)

Elastic Modulus:

30×106 psi

Poisson’s ratio

0.3

Axial Compression:

-122,000 lb (from torque & drag software)

Radius of Curvature:

300 ft

External Pressure:

3000 psi

Internal Pressure:

5000 psi

Determine if combined Loads will yield pipe. Since the bending stress will likely play a large role in the combined loading we will calculate the stresses at the outer wall where the bending stress is a maximum using Equations (6.15) 1. Find the axial stress The axial stress is calculated

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σz =

π 4

−122, 000

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–

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= −18331 psi

(7.0 − 6.366 ) 2

2

2. Find the bending stress

σb =−

30 × 106 (7.0 / 2) = −29167 psi 12(300)

Note that we had to get the radius of curvature into the same units as the pipe radius so we multiplied by 12 in/ft to change it to inces. 3. Find the pressure effect

σ r = −3000 psi σθ =

−3000(3.52 + 3.1832 ) + 2(5000)(3.183) 2 = 16129 psi 3.52 − 3.1832

4. The total axial stress at the external wall is the axial stress from the last equation plus the bending stress

σ z = −18331 − 29167 = −47498 psi 5. Check the combined loading against the yield using the von Mises criterion in terms of principal stresses

1 (−3000 − 16129) 2 + (16129 + 47498) 2 + (−47498 + 3000) 2  2 Ψ = 56543 psi Ψ=

Y = 55000 psi ∴ Ψ > Y → yield We see that none of the separate loads was near the yield value of the pipe yet the combined loading definitely exceeds the yield of the casing.

This particular example illustrates one of the ways the yield approach may be used to check existing designs in anticipation of unusual loading conditions.

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THE API BASED APPROACH The API method is based on formulas developed by the API over many years. Some are founded in physics and others are empirical formulas based on testing of actual casing. Despite some of them being cumbersome to use they work. In the absence of combined loads they are the best way to select a casing string, because the values are published in tables and few calculations are actually necessary. Even when we use the yield approach for combined loading, we generally begin with a preliminary design based on the API published values for single loads as we did in the previous chapter. And as we have stated before, the yield approach does not account for connection performance nor does it account for those tubes that collapse before they reach the yield point.

The Collapse Problem It would be good if all we had to do was check the yield of our design using the yield formulas given above and adjust the design accordingly. Unfortunately, there is a problem in that collapse of casing often takes place at pressures less than the yield pressure. And to further complicate the situation the collapse pressures are also dependent on the axial stress in the tube. There is not a really good way to account for this, however, the API has a recommended procedure and we will look at that now. The von Mises yield surface we just examined accounts for the effects of axial stress, radial stress, tangential stress, and torsional stress components as far as yield of the material is concerned. In the plot of the yield surface in a principal stress space it plots as a cylinder. If we were to set one of those principal stresses, say σ 3 to zero, the cylinder would plot as an ellipse on the σ 1 – σ 2 plane. This is essentially what API has done for their biaxial procedure for a computing a revised collapse strength due to tensile stress in the pipe. Here is how they arrived at that. Look first at Equation (6.2) again. If we assume that the stresses are just at the yield point and there is no torsion in the pipe then we may write it as below. 1

2 2 2 2 1 Y =   (σ θ − σ r ) + (σ r − σ z ) + (σ z − σ θ )    2 

(6.17)

We can expand and rearrange the equation in the following form.

Y 2 = (σ θ − σ r ) − (σ θ − σ r )(σ z − σ r ) + (σ z − σ r ) 2

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2

(6.18)

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This equation is an ellipse if we view it as

r 2 = x 2 − xy + y 2

(6.19)

It is a quadratic equation. We cannot solve it for individual stress components, but we can solve it for stress differences, in other words we can solve for x or y . Solving for x gives us:

x=

y 3y2 ± r2 − 2 4

(6.20)

or in a more useful form (to us) as

x 1y 3 y2 = ± 1− r 2r 4 r2

(6.21)

So that now we can write this as either

σ z −σr Y

=

σθ − σ r

=

σ z −σr

2Y

3 (σ θ − σ r ) ± 1− 4Y 2

2

(6.22)

or equivalently

σθ − σ r Y

2Y

3 (σ z − σ r ) ± 1− 4Y 2

2

And we can plot these equations as an ellipse in two dimensions.

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(6.23)

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Biaxial Stress Chart 1.4 1.2

Burst

1

-1.4

-1.2

-1

σθ − σ r

0.6

Y

0.4

σ z −σr

0.2

Y

Compression

0.8

Tension

0 -0.8

-0.6

-0.4

-0.2-0.2 0

0.2

0.4

0.6

0.8

1

1.2

1.4

-0.4 -0.6 -0.8 -1 -1.2

Collapse

-1.4

Figure 6 - 11. A two-dimensional representation of the von Mises yield surface.

But the question you might ask at this point is what have we accomplished? We have taken a three dimensional yield surface and found a way to plot it in two dimensions, but it is still the same thing. That in itself is of no importance, but what if we now say (as the API does) that the radial stress component is negligible and we set it to zero. Now Equation (6.23) becomes

3 (σ z ) = ± 1− Y 2Y 4Y 2

σθ

σz

2

(6.24)

and we could do similarly with Equation (6.22), but we only need one of them. The plot of this equation is exactly the same as the previous figure. Now here is how API uses this two-dimensional, or biaxial formulation. API assumes that the tangential stress becomes an effective yield stress for collapse in Equation (6.24). So we define an effective yield stress in collapse as

Ye ≡ −σ θ

(6.25)

We may rewrite the equation adjusting the signs to account for the fact that the tangential stress is compressive (negative) in a collapse situation.

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2

3σ  σ Ye = Y 1 −  z  − z 4 Y  2

(6.26)

Then the API procedure uses this effective yield stress in the calculation of collapse using the standard API collapse formulas.

API Collapse Formulas The API collapse formulas are published in API Bulletin 5C3, Bulletin on Formulas and Calculations for Casing Tubing, Drill Pipe, and Line Pipe Properties. (See reference API, 1994) There is not one API collapse formula; there are four. 1. Yield Pressure Collapse Formula 2. Plastic Collapse Formula 3. Transition Collapse Formula 4. Elastic Collapse Formula The first three collapse formulas depend on the yield stress of the metal and the ratio of the outside diameter of the pipe to the wall thickness of the pipe. This ratio is referred to as the “D over t” ratio. (The API uses the notation, D t , but we will use d o t in this manual to distinguish that it is the outside diameter, since there are a number of formulas where we also use the internal diameter.) The last formula for collapse, elastic collapse, does not depend on the yield of the material but only on the d o t ratio. The API formulas are: Yield Pressure Collapse Formula

 ( d t ) − 1 pYP = 2Y  o 2   ( d o t ) 

(6.27)

Yield Pressure Formula Valid Range

( do t ) ≤

Plastic Collapse Formula

A−2+

( A − 2) + 8 ( B + C Y ) 2(B + C Y ) 2

 A  pP = Y  − B − C  ( do t ) 

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(6.28)

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Plastic Collapse Formula Valid Range

A−2+

( A − 2) + 8 ( B + C Y ) Y (A− F) < ( do t ) ≤ C +Y (B − G) 2(B + C Y ) 2

Transition Collapse Formula

 F  − G pT = Y   ( do t ) 

(6.29)

Transition Collapse Valid Range

Y (A− F) 2+ B A < ( do t ) ≤ C + Y (B − G) 3B A

Elastic Collapse Formula

pE =

Elastic Collapse Formula Valid Range

( do t ) >

2+ B A 3B A

where

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46.95 × 106

( do t ) ( do t ) − 1

2

(6.30)

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d o = outside diameter, in. t = nominal wall thickness, in. Y = yield stress of pipe, psi pYP = collapse pressure, yield pressure formula, psi pP = collapse pressure, plastic formula, psi pT = collapse pressure, transition formula, psi pE = collapse pressure, elastic formula, psi A = 2.8762 + 0.10679 × 10−5 Y + 0.21301×10−10 Y 2 − 0.53132 × 10−16 Y 3 B = 0.026233 + 0.50609 × 10−6 Y C = −465.93 + 0.030867Y − 0.10483 ×10−7 Y 2 + 0.36989 × 10−13 Y 3 3

 3B A  46.95 × 10   2 + ( B A)   F= 2  3B A  3B A  Y − ( B A )  1 −   2 + ( B A)   2 + ( B A)  G=FB A 6

What a nightmare! Unfortunately there is no simpler way to do it. In this course you will be given a computer spreadsheet to do these calculations. There are tables we can use to find values for the API constants, A, B, C, F, G, for standard API yield stress values, e.g. 80,000 psi, so the last three formulas do not have to be employed for determining collapse pressures in the absence of combined loading. Of course, in that case we do not have to even use the formulas because the results are in the published tables also. However, when we are considering combined loads and use Equation (6.26) to calculate effective yield strength, then we must use these formulas and we must also calculate the API constants. It is a tedious procedure to do manually. Note: The above formulas are something of a mix between phenomenology and curve fitting for experimentally derived collapse data. It is not what we would call good or consistent science. Currently the API is working on revisions to Bulletin 5C3 and they expect to publish a more consistent set of formulas for collapse in the near future.

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The Connection Problem In addition to the collapse situation, there is the problem of joint connection performance and how that affects the final design.

•

The tensile strength of connections is in general less than the pipe body

(this is true of all API connections and most other connections, but the reverse is true of a few proprietary connections) •

Many connections will leak before the pipe body reaches to burst yield

By now you may guess what that means – more formulas! These formulas are presented in API Bulletin 5C3 and will not be presented here because the values in the tables of API Bulletin 5C2 are calculated from those formulas. We used these table values in our minimum design so there is no need to calculate them here. However, there are two other formulas that bear notice. Coupling Performance with Tension and Internal Pressure

In the presence of internal pressure the performance of API couplings in tension is reduced. Here is the formula for the tensile strength when there is internal pressure.

Y (1 + 0.5 K )   0.74d o−0.59U Pj = 0.95 Ajp L  +   0.5 L + 0.14d o L + 0.14d o 

(6.31)

In addition there are two formulas that account for failure of API couplings due to bending whose results are not included in the tables of API Bulletin 5C2. Though we will not use these formulas they are presented here for your information. The first formula is Coupling Bending Performance

5   140.5θ d    o Pb = 0.95 Ajp U −  0.8    (U − Y )    

which is valid for Pb Ajp ≥ Y or

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(6.32)

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U −Y  Pb = 0.95 Ajp  + Y − 218.15θ d o   0.644 

L O A D S

(6.33)

which is valid for Pb Ajp < Y Pj = jumpout strength of coupling, lb

Variables for Formulas

Pb = bending load failure strength of coupling, lb Ajp = cross-sectional area under last perfect thread, in.2 =

π 2 2 ( do − 0.1425) − ( di ) 

=

pi d o Y ( do − di )

 4 K = internal pressure to yield ratio

d o = outside diameter, in. di = inside diameter, in. pi = internal pressure, psi L = length of engaged thread, in.

θ = build rate or curvature of wellbore, degrees/100 ft Y = yield stress of pipe, psi U = minimum tensile strength of pipe, psi

These formulas contain a value for the minimum tensile strength of the pipe. These values are not published in most casing tables. However, they do appear in API Specification 5CT in Table E.6. We include them below. API Grade

Minimum Tensile Strength, psi

H-40

60,000

J-55

75,000

K-55

95,000

N-80

100,000

M-65

85,000

L-80

95,000

C-90

100,000

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API Grade

Minimum Tensile Strength, psi

C-95

105,000

T-95

105,000

P-110

125,000

Q-125

135,000

Unfortunately API does not seem to have a formula for both bending and internal pressure.

Burst Pressures The API has established an approximate formula for calculating the internal yield pressure which we often refer to (erroneously) as burst. We do not often use the formula because the value is available in many tables. In addition, some API couplings will leak at pressures lower than the internal yield pressure of the pipe and there are formulas for calculating those pressures too. Again we do not normally need those equations either if we have API Bulletin 5C2, but some of the other published tables do not list the reduced internal yield pressure of the couplings and that is an important item in casing design. Another point is we seldom consider the effect of tension on the burst since it actually increases the burst rating rather than decrease it as in collapse. The API internal yield pressure equation is derived for a very thin wall tube and it gives a conservative result when considering a thicker wall tube. It also has a built in safety factor to account for variations of up to 12.5% in the wall thickness. Internal Yield Pressure

 2t Y  pb = 0.875    do 

(6.34)

The internal pressure formulas for couplings are given in API Bulletin 5C3 and require several coupling and thread dimensions from API Specification 5B. It is too much material to include in this manual, and anyone interested in the details should refer to those publications. For our purposes you should be aware that the coupling performance in internal yield or leaks for some tubes is less than that for the pipe body, but the tables in API Bulletin 5C2 show those reduced values and that is what we will rely on for this course.

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Final Casing Design It is now time to finalize the preliminary designs we made in the previous chapter. In other words we are going to consider the effects of tension on the collapse.

Surface Casing Here is the preliminary surface casing design we made in the last chapter. Casing Design Summary 13 3/8" Surface Casing Actual Design Factors Section Number 2 1

OD ID Weight Grade Connection 13.375 12.615 54.5 K-55 ST&C 13.375 12.415 68 K-55 ST&C

Bottom 2100 3000

Length 2100 900 0 0 0 0 0 0 3000

Mud Weight:

9.2

Totals: Minimum Design Factors Collapse: 1.125 Burst: 1.125 Tension: 1.6/100,000

Section Weight 114450 61200 0 0 0 0 0 0 175650

Cum. Weight Collapse 175650 1.125 61200 1.359 0 0 0 0 0 0

Joint Burst Strength 1.192 3.6 2.413 26.135

Since there is no tension at the bottom of the string, there is only one point where we need to check the collapse in this string for the effects of tension. That is at the bottom of Section 2 at 2100 ft. Referring back to the axial load curve for this string we see that the axial tension at this point is 37,000 psi. We calculate the axial stress with Equation (6.3)

σz =

4 ( 37000 ) P = = 2385 psi A π (13.3752 − 12.6152 )

That is an almost insignificant amount of tensile stress, but we will continue the calculations just to illustrate the procedure. Next we use Equation (6.26) to determine the reduced yield for the collapse formulas. 2

2

3σ  σ 3  2385  2385 = 53, 769 psi Ye = Y 1 −  z  − z = 55000 1 −   − 4 Y  2 4  55000  2 Next we must calculate the constants for the API formulas using the equations given earlier.

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A = 2.98643 B = 0.053445 C = 1169.191 F = 1.992004 G = 0.035643

And we calculate d 0 t ratio. do t =

13.375 = 35.2 0.5 (13.375 − 12.615 )

This ratio is a little on the high side so it does not look like it will be in the yield pressure range. Look first at the formula for the upper end of the plastic collapse region.

Y (A− F) 53769 ( 2.986943 − 1.992004 ) = = 25.2 C + Y ( B − G ) 1169.191 + 53769 ( 0.053445 − 0.035643) So our ratio is greater than that. Next check the upper end of the transition collapse range.

2 + B A 2 + ( 0.053445 2.986943) = = 37.6 3B A 3 ( 0.053445 2.986943) This establishes that the ratio is in the transition collapse formula range. Now we use the transition collapse formula (Equation (6.29) to calculate the new collapse value.

 F   1.992004  pT = Y  − G  = 53769  − 0.035643  = 1126 psi  35.2   ( do t )  The published API collapse value without tension is 1130 psi and since API rounds off the collapse values to the nearest 10 psi then these two are essentially the same. There is no significant effect of tension on the collapse value that would require us to change the design of this string. That was a lot of calculation for such meager results, but it illustrates the process. You will be furnished a spreadsheet in this course so that you do not have to repeat a lot of these types of calculations.

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Intermediate Casing Here is the preliminary intermediate casing design we made in the previous chapter. Casing Design Summary 9 5/8" Intermediate Casing Actual Design Factors Section Number 5 4 3 2 1

OD 9.625 9.625 9.625 9.625 9.625

ID Weight Grade Connection 8.681 47 N-80 LT&C 8.535 53.5 N-80 LT&C 8.681 47 N-80 LT&C 8.755 43.5 N-80 LT&C 8.835 40 N-80 LT&C

Bottom 3000 4800 6500 8500 10500

Length 3000 1800 1700 2000 2000 0 0 0 10500

Mud Weight:

11.8

Totals: Minimum Safety Factors Collapse: 1.125 Burst: 1.125 Tension: 1.8 in air

Section Weight 141000 96300 79900 87000 80000 0 0 0 484200

Cum. Weight Collapse 484200 high 343200 high 246900 high 167000 2.54 80000 1.66 0 0 0

Burst 1.13 1.25 1.13 1.126 1.127

Joint Strength 1.87 3.09 high high high

In this example the collapse resistance is well within the safety factors, so there is no need to check this design for the effects of tension on the collapse.

Production Casing Here is the preliminary production casing design we made in the previous chapter. Casing Design Summary 7" Production Casing Actual Design Factors Section Number 4 3 2 1

OD

ID 7 7 7 7

Weight 29 32 32 35

Grade Connection P-110 LT&C N-80 LT&C P-110 LT&C P-110 LT&C

Bottom 4800 9600 12100 14000

Length 4800 4800 2500 1900 0 0 0 0 14000

Mud Weight:

15.2

Totals: Minimum Safety Factors Collapse: 1.125 Burst: 1.2 Tension: 1.6/100,000lb buoyed

Section Weight 139200 153600 80000 66500 0 0 0 0 439300

Cum. Weight Collapse 439300 2.25 300100 1.133 146500 1.127 66500 1.177 0 0 0 0

Burst 1.275 1.2 high high

Joint Strength 2.34 3.36 high high

Here we might check the design at the bottom of section 2 at 12,100 ft, but upon examining the axial load at that point we see that it is in compression. We will do a quick check at the bottom of Section 3 at 9600 ft using a spreadsheet to do the calculations. It shows a safety factor of 1.33 without tension, but that may not be enough if we include the tension.

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API Biaxial Collapse and Burst Calculations Diameter, outside (inches) Diameter, inside (inches) Yield stress (psi) Tension, (lb)

7 6.094 80000 42000

Biaxial Yield for Burst (psi) Biaxial Yield for Collapse (psi) API Constants for Downrated Yield: A B C F G API Collapse Formula: Biaxial Collapse Pressure:

82158.56 77650.82 3.062684 0.065531 1885.028 1.993731 0.042659 Plastic 8417

The new collapse pressure is 8417 psi and the collapse pressure in the absence of tension is 8600 psi. That is a relatively small difference, but let us see what the actual design factor is now. fs =

8417 = 1.109 0.052 (15.2 )( 9600 )

This is slightly lower than our minimum safety factor of 1.125. As a practical matter this may not be worth changing the design, however, we must all be aware of the consequences of such a decision. In the world today if there were to be an accident involving this well and this string of casing the fact that would carry a lot of weight in a courtroom or other litigation procedure would be the fact that we did not design the string to meet our minimum safety factor. So practical matters aside, we will change the design to be sure it is within our minimum design requirements. The easiest way to deal with this one would be to possibly raise the bottom of section 3 up to 9500 ft, i.e. reduce its length by 100 ft. Since both Section 2 and Section 3 are 32 lb/ft pipe this will not change the tension curve at all but it will change the tension at the bottom of Section 3 which we can still read from the same curve. The tension at 9500 ft is about 45,000 lb. So let us calculate the effect of this change.

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API Biaxial Collapse and Burst Calculations Diameter, outside (inches) Diameter, inside (inches) Yield stress (psi) Tension, (lb)

7 6.094 80000 45000

Biaxial Yield for Burst (psi) Biaxial Yield for Collapse (psi) API Constants for Downrated Yield: A B C F G API Collapse Formula: Biaxial Collapse Pressure:

82305.44 77475.72 3.062086 0.065443 1879.791 1.993463 0.042604 Plastic 8403

Then calculate the safety factor at 9500 with a new collapse pressure of 8403 psi. fs =

8403 = 1.119 0.052 (15.2 )( 9500 )

Obviously 100 ft was not enough. One of the problems is that when we raise the top of the section we lower the hydrostatic collapse load, but we also find the tension is greater at the shallower depth. We could continue to try another 100 ft or so, but that is a waste of time. We will resort to an iterative technique which we will do graphically. Here is how the technique works.

f ( D ) = 1.125 or y = f ( D ) − 1.125 = 0 We assume that all the calculations we do are lumped into something we will call a function of the depth, D, and if we select the correct depth it will give us the safety factor we want, 1.125 in this case. So if we select the correct value for the depth y = 0 and if our guess is not correct then y ≠ 0 , which we have already done. Let us see what we have done so far.

D = 9600 → y = 1.109 − 1.125 = −0.016 D = 9500 → y = 1.119 − 1.125 = −0.006

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Now we can plot a quick graph to predict what value of depth should give us a zero value of y. Collapse/Depth Interpolation 0.015

0.01

0.005 D = 9440 ft

9050

9100

9150

9200

9250

9300

9350

9400

9450

9500

9550

9600

9650

9700

Y

0 9000

-0.005 D = 9500 ft

-0.01

-0.015

D = 9600 ft

-0.02 Depth

After plotting the two points we draw a line through them to the axis where y = 0 . We see at this point that the depth that would give us the correct safety factor is 9440 ft (assuming subsequent points plot as a straight line). We will check the design at 9440. API Biaxial Collapse and Burst Calculations Diameter, outside (inches) Diameter, inside (inches) Yield stress (psi) Tension, (lb)

7 6.094 80000 47000

Biaxial Yield for Burst (psi) Biaxial Yield for Collapse (psi) API Constants for Downrated Yield: A B C F G API Collapse Formula: Biaxial Collapse Pressure:

82402.82 77358.45 3.061686 0.065383 1876.283 1.993284 0.042567 Plastic 8393

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We then check our safety factor with a collapse value of 8393 psi at 9440 ft. fs =

8393 = 1.125 0.052 (15.2 )( 9440 )

Now we are within our required safety factor. And our final design for the production string is: Casing Design Summary 7" Production Casing Actual Design Factors Section Number 4 3 2 1

OD

ID 7 7 7 7

Weight 29 32 32 35

Grade Connection P-110 LT&C N-80 LT&C P-110 LT&C P-110 LT&C

Bottom 4800 9440 12100 14000

Length 4800 4640 2660 1900 0 0 0 0 14000

Mud Weight:

15.2

Totals:

Section Weight 139200 148480 85120 66500 0 0 0 0 439300

Cum. Weight Collapse 439300 2.25 300100 1.125* 151620 1.127 66500 1.177 0 0 0 0

Burst 1.275 1.2 high high

Joint Strength 2.34 3.36 high high

* includes biaxial effects Minimum Safety Factors Collapse: 1.125 Burst: 1.2 Tension: 1.6/100,000lb buoyed

This concludes our casing design process. The remainder of this chapter includes some additional information on yield criteria for anyone who might be interested. We will not discuss it in the course.

Advanced Discussion of Yield Criteria (Optional) The following information is optional and intended only to clarify some of the concepts with more advanced material for those who might be interested.

There are a number of different yield criteria that have been around for many years as has already been stated, but the one that has proven most successful for our purposes

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is the one most often attributed to Richard von Mises in 1911, and typically called the von Mises yield criterion. In truth the same idea was proposed by James Clerc Maxwell in 1858 but never published except in his private letters, and again by Huber in 1905. Huber did publish his result, but it went unnoticed because he published it in a journal that was not widely read outside his home country. A few years later Hencky did some work with plasticity in the range beyond the yield point and his name became associated with it also. So variously you will hear it referred to as the von Mises yield criterion, the Maxwell-Huber-Mises yield criterion, the Huber-Mises yield criterion, or the Hencky-Mises yield criterion. I think that gives fair due to all those who contributed their skills to the idea, so we will call it the Mises yield criterion for the sake of brevity. The criterion was proposed in a somewhat different form by von Mises than we will use here, but for our purposes it looks like this:

Y ≥ 3J 2

(6.35)

where J 2 is the second deviatoric stress invariant. Don’t be concerned about that for now, we will come back to it later. For now just think of it as a value attributable to the combined load that we can compare with the yield strength of the material. Now what this means is this:

Y > 3 J 2 → no yield Y = 3 J 2 → yield

(6.36)

Y < 3 J 2 → not possible The first two equations are easy enough to understand, but the third one may raise questions. The answer we already alluded to earlier. The yield point always changes with the stress in the plastic region, so for a simple material like steel the yield point changes so that the stress can never exceed it. Also if it is higher than the initial value of the yield stress, then the Lamé equations we used to calculate the radial and tangential stress components are no longer valid. It is a far more complicated situation than that, but that gives you the idea. The reason we used the symbol Ψ earlier and called it the yield indicator is to skirt this issue and still have something that is valid to work with. As long as we do not call Ψ a stress we can never be wrong. Now what is J 2 or this deviatoric stress invariant? There is a mathematical formula which we will see soon, but a more simple explanation goes something like this. A metal such as steel cannot be yielded by a hydrostatic pressure no matter what its magnitude. In the simple uniaxial test we applied a stress in only one direction and the material reached its yield point along the elastic load line. Had we applied that same stress equally in all three directions rather than one the metal would have never reached a yield point. In other words if we have a sample of steel that has a yield point of

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50,000 psi, we can apply a uniaxial compressive load and it will yield at 50,000 psi. But if we put that same sample in a pressure cell and apply a hydrostatic pressure of 100,000 psi it will not yield. In fact we could apply a pressure of 1.0 x 106 psi and it still will not yield. There are some limits to how far we can go with a hydrostatic stress and not cause yielding, but they are well beyond anything we might encounter in oilfield work. In this example we used compression because it is easier to visualize loading a material three dimensionally in compression than tension, but the same thing applies to tension were we able to create hydrostatic type tensile stresses. So we now know that the hydrostatic stress does not cause yield, and if we remove the contribution of hydrostatic stress from consideration then we are left with the stresses that cause distortion in various directions. This stress is called the deviatoric stress and beyond knowing that fact our primary interest is in how it is calculated. (If you are interested in learning more about this most any good text on continuum mechanics goes into more detail). It can be fairly easy if we know all the principal stress components. Here is a simple version for calculating the principal deviatoric stress components if we know the principal stress components.

σ 1′ = σ 1 −

σ1 + σ 2 + σ 3

σ 2′ = σ 2 − σ 3′ = σ 3 −

3

σ1 + σ 2 + σ 3 3

(6.37)

σ1 + σ 2 + σ 3 3

There are other formulas for calculating the deviatoric stress components when the stress components are not in terms of principal stress, but we are going to limit our discussion to principal stress to keep the formulas simple. You can always use Equation (6.9) to get the principal stress components. Next we look at a formula for J2 in terms of the principal deviatoric stress components.

J2 =

1 2 2 2 (σ 1′ ) + (σ 2′ ) + (σ 3′ )   2

(6.38)

When we say that this is a stress invariant, what we mean is that no matter what coordinate system we choose for our reference this stress invariant will always be the same as long as the actual stress is the same. In other words for a given stress, the individual components will vary depending on the coordinate system selected, but the stress invariants are independent of the coordinate system. We are often accustomed to referring to the individual stress components as a “stress”, and some even refer to the components as “stress vectors”. Neither is true. Stress is a second order tensor and consequently cannot be expressed in terms of a magnitude other than in terms of

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its invariants which are not coordinate system dependent or its individual components which can only exist in some coordinate system. Suppose a block of steel having a yield stress of 40,000 psi is subjected to tensile stress components in three directions such that each of them is in excess of the yield stress of the metal, σ 1 = 80, 000 psi, σ 2 = 50, 000 psi, σ 3 = 50, 000 psi . Each

Example of Deviatoric Stress and Yield

of these principal stress components is definitely greater than the yield stress of the material. Does the material yield? How close is it to the yield stress of the metal? This one is very easy to do even without any formulas. Since

σ2

and

σ 3 are

both

equal and less than the other principal stress component it is simple to notice that the hydrostatic stress must be 50,000 psi. If we subtract that value from the 80,000 psi of the first principal stress component it tells us that the maximum stress leading to yield is 30,000 psi and that value is below the yield stress of the metal which is 40,000 psi. This may at first appear surprising since each principal stress component taken separately is greater than the yield stress of the material. Let us now use the formulas to verify our reasoning. Substitute into Equation (6.37) to get the deviatoric stresses.

80000 + 50000 + 50000 = 20000 3 80000 + 50000 + 50000 σ 2′ = 50000 − = −10000 3 80000 + 50000 + 50000 σ 3′ = 50000 − = −10000 3

σ 1′ = 80000 −

Then calculate J2

1 2 2 2 (σ 1′ ) + (σ 2′ ) + (σ 3′ )   2 1 2 2 2 = ( 20000 ) + ( −10000 ) + ( −10000 )    2 = 300 × 106

J2 =

And substitute into the yield formula

Y ≥ 3J 2 Y ≥ 3 ( 300 × 106 ) Y ≥ 30000 40000 ≥ 30000

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What this example demonstrates is that once we remove the hydrostatic stress components the actual distortional or deviatoric stress equivalent that tends to cause yield is only 30,000 psi which is less than the yield stress of this metal. For those interested in the yield criteria and related topics there are a number of good texts on solid mechanics or continuum mechanics that should contain ample information, e.g., Fung, (1965) and Malvern (1969).

References API, (2001, Oct), API Specification 5CT, Seventh Edition, Specification for Casing and Tubing, American Petroleum Institute, Washington, D.C. API, (1994, Oct), API Bulletin 5C3, Bulletin on Formulas and Calculations for Casing Tubing, Drill Pipe, and Line Pipe Properties, American Petroleum Institute, Washington, D.C. Fung, Y.C., (1965), Foundations of Solid Mechanics, Prentice-Hall, New York. Malvern, L.E., (1969), Introduction to the Mechanics of a Continuous Medium, PrenticeHall, New York.

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7

Chapter

Running & Landing Casing How to get it to bottom? Casing wellheads

M

any of the problems that occur with casing are not a problem with design, but a problem with the running practices. Most companies have specific running practices, but they do not vary that much from the basics. Several things must be kept in mind as to getting the casing to location and running

in the hole.

Transport to the Location Some casing gets damaged on the way to the location. It is something that could almost always be avoided, but it still happens from time to time. Whether it is loaded on trucks, boats, or barges, it must be adequately protected. This means not only care in handling while transferring from racks to trucks, to boat, to rig. All joints should have thread protectors in place and no cables or hooks should be used that can cause damage to the protectors or the pipe. On racks, trucks, or boats the casing should be placed carefully with wood stripping between rows. The casing should be secured so that it cannot move during transport.

On Location Whether or not a company requires some type of electromagnetic inspection on location is a matter of policy that depends on the type of well is being drilled. There are some things that are essential though: •

Casing should be drifted on location to be sure that no damage has caused a reduction of the internal diameter, and also to be sure that nothing is lodged in the pipe.

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•

The thread protectors should be removed and the threads cleaned with a solvent such as diesel to remove the unknown type of lubricant on the threads.

•

The cleaned threads should be visually inspected.

•

In offshore locations where metal rusts in a matter of minutes the threads should be lubricated as soon as they are inspected with the same lubricant that will be used when the string is run in the hole.

•

In most cases the protectors on the pin end should be cleaned and reinstalled.

•

Do not place any type of equipment such as casing spiders, tongs, etc. on the casing that is on the pipe rack no matter how much stripping or pads may be used.

Pipe Measurements One of the most critical aspects of running casing is the pipe tally or measurement. There are many variations on how and when to do it. Most of the time it is done when the pipe is off loaded at the rig onto the rig pipe racks. The best methods involve removing the protectors (from both ends) and numbering each joint with a paint type marker (not chalk) that will remain on the pipe until it goes in the hole. Most systems involve recording the joints in a tally book or form that lists the joints in groups of ten. As the total length of each group is added is totaled the sum will be ten times the average length of joint in that group. If a mistake has been made in the measurements or in the addition it is very easy to spot using that method. Accuracy is essential, but it is unbelievable how many operators pay little attention to this phase of the process. The final responsibility for an accurate tally lies with the company representative on the location – not the roughnecks or roustabouts.

Crossover Joints and Subs When the pipe is measured that is the time to check all of the crossover joints and be sure they are placed correctly in the string on the racks or placed in a separate location where they can be added to the string when required. There should be at least one spare for each different type of crossover used. Crossovers for proprietary connections should be cut only by a machine shop or manufacturer licensed to cut that specific thread. The legal issue is one thing, but an improperly cut thread can cause failure of the string. Crossover subs or couplings for API ST&C and LT&C threads need special comment. A short pin will make up into a long collar so no crossover is normally required when ST&C is run above LT&C. The reverse is not true though because a long pin will not make up into a short coupling. Some operators get around the crossover issue by purchasing an LT&C coupling and send it to the rig as a crossover. The idea is to take

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that when it comes time to make up the LT&C pipe into the top of the ST&C that the short coupling will be removed and the long coupling installed at the point it is run into the hole. That sounds easy, but it is a bad practice. It often comes as a big surprise when it happens, but the short collar may not back off easily and sometimes not at all. We cannot predict the torque required to remove a coupling installed at the mill. It may come off easily if the pipe is relatively new, but if the pipe has been sitting on a rack in the hot sun for two or three years it might require so much torque that the threads are galled and ruined in the process. This is not uncommon. So it is far better to have a dedicated crossover joint or sub (and a spare) for each place it is needed. The cost saved by purchasing a long coupling for a crossover is miniscule compared to the potential cost if something goes wrong.

Getting the Casing to the Rig Floor Usually the pin protectors are removed before the pipe is picked up to the V-door of the rig. The pin should be protected with a quick-release type rubber protector during this time and until it is up on the rig floor ready to stab.

Stabbing The stabbing process is critical to prevent damage and the rig floor and stabbing board should be set up and sheltered from wind to facilitate this process. (Those of you who work on automated rigs are blessed, but you still need to know all this in case you ever find yourself on a “common rig” like most of us work with.)

Filling Casing In general the casing should be filled with mud as it is being run into the well. An adequate fill line should be rigged up to assure that the filling operation will not slow the running process. In any event you should visually assure the casing is full at least every few joints even if it means slowing the running process until you see the mud at the surface inside the casing. Some companies use differential or some type of automatic fill type float equipment to aid or replace the surface fill procedure. Where it works it is fine, but when it does fail (and it often does) it can cause serious problems. Another objection that many operators have with this type of equipment is that is may allow hole debris to enter the casing at the bottom. If it remains in the casing after circulation and is pushed down to the float collar with the bottom cement wiper plug and bridges and plugs the float, then one is left in the precarious position of having all the cement inside the casing and no way to pump it in either direction. Where this type of equipment has been successful is in some hard rock areas, and where it has failed has mostly been in unconsolidated drilling areas. If your company uses it, just be aware of the possibilities for failure – it is much safer to fill from the surface.

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Makeup Torque All connections should be made up to the proper torque while running. Most casing crews have all the necessary values, but it is good to check and be sure that everyone is in agreement. Correct type of thread lubricant and clean threads are essential for getting the correct amount of torque. For critical applications there are special services that measure both torque and the number of revolutions of the pipe to be sure that the maximum torque did not occur before the coupling was fully made up. Another point about proper torque is its measurement. The torque on the typical casing tong is measured with a hydraulic transducer in the tong line. In other words it actually measures tension in the tong line and not torque. The torque gage is calibrated such that it multiplies the length of the tong arm times the tension in the tong line to give the torque. That only works if the tong line is perpendicular to the tong arm when the torque measurement is made. If the angle is more or less than 90° then the actual torque will be less than that shown on the gage. A few degrees is not going to make an appreciable difference, but it is not uncommon to see casing tongs rigged up with a considerable deviation from the proper 90°.

Thread Locking One of the true disasters associated with casing is the disengagement of the bottom joint (or several joints) after the casing has been cemented and operations have begun to drill out the cement inside the casing. The torque from the rotating bit drilling out the cement and float equipment in the bottom two joints starts to turn the casing and the bottom joint or so backs out at the coupling. Once this happens there is usually no remedy. The hole has been junked and must be abandoned. The reason that this sort of thing happens is that the cement around the bottom joints is incompetent usually because has not reached a satisfactory strength. It most often happens on surface casing where the temperatures at the shoe are relatively low and the cement does not set as fast as expected or the operator is in a hurry to start drilling and does not allow sufficient time for the cement to settle. While those are cementing issues which we will cover in later chapters, there is something often done in the running process of the casing to prevent such an event. Most operators secure the connections on the bottom joints up to and usually one joint above the float collar to prevent accidental back off of the casing while drilling out cement. There are chemical kits consisting primarily of a thermoset polymer used to “glue” the connections. It is applied instead of thread lubricant to the cleaned connections on the float equipment and bottom joints. There are a couple of problems associated with such a practice. One is that most only use the compound on the field make up part of the connection. They figure the mill end will not back out. This is a poor practice. If you are going to use the locking compound you should remove the couplings and “lock” all the threads, not just the field threads. The second problem is that if something goes wrong and the casing string has to be pulled back

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out of the hole before reaching bottom, those connections cannot be broken out. That presents something of a dilemma in that if you do it you are safe from backing off the pipe, but if you have to pull the pipe you cannot easily undo it. You can actually heat the pipe with a welding torch to a temperature where the polymer will break down and the pipe can be backed out. Those joints should be replaced and not run back in the hole though. Another procedure is that of tack welding the couplings on the lower joints. This was common practice for many years before the polymer compounds were available and is still common in some areas. However, welding on casing couplings can lead to serious problems and should be avoided at least for couplings with higher yield strengths than K-55. When is thread locking necessary?

The cause of casing back-off while drilling float equipment and cement joints is almost always caused by drilling out before the cement has had sufficient time to harden. Typically the risk of a joint backing off is most acute on the surface casing or even a cemented string of conductor casing. This is usually because the temperatures are relatively low and the cement has not set sufficiently before drilling is resumed. One should always lock the threads of at least one joint above the float shoe and all joints below the float shoe. In the case of deeper strings the issue is less critical because the temperatures are higher and it often takes much longer to change out BOP’s, drill strings, and other equipment in order to resume drilling. In the case of stage cementing equipment there is little need to lock the threads because for a joint to backoff all the joints below it must also rotate and this is almost impossible in the case of a stage tool that is a few thousand feet above the bottom of the hole.

Casing Handling Tools There is a wide variety in the elevator and spider assemblies (slips) available to run casing. Some elevators are what is called “square shouldered”. They have no slip elements. Instead, they have an internal diameter that will fit around the casing body but is too small for a coupling to pass through; they are hinge opening. The spider may be similar to the elevator and hinged or large enough for the coupling to pass through with some type of slip assembly built in or there may be just a simple set of manual slips.

Figure 7 - 1. A square shouldered or wrap around type elevator or spider.

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Figure 7 - 2. A wrap around or square shouldered spider.

Figure 7 - 3. Casing slips for use in a conventional rotary.

They increase in sophistication from there. We assume that anyone who runs casing knows to select an elevator and spider combination of sufficient strength to hold the casing safely. There is one important point to make in this regard though. The elevator and spiders normally used to run heavy casing strings are rated at 500 tons (1,000,000 lb) or even 1000 tons (2,000,000 lb) and have an internal slip assembly that is manually activated by an external lever or air actuated.

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Figure 7 - 4. A 500 ton elevator.

Figure 7 - 5. A 1000 ton elevator.

Figure 7 - 6. A 1000 ton spider.

These are very good tools for the purpose of running heavy strings of casing. The problem is that even a heavy string of casing is not “heavy” when it starts in the hole.

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The efficiency and ease with which the manual lever operates the slips is such that it is possible for someone on the rig floor to easily open the slips even with 1000 ft or more of casing suspended in the spider. A similar problem can occur when the pipe is in the elevator and an obstruction is hit causing the load on the elevator to be momentarily released so that the slips jump open. The result in either case is a portion of a casing string dropping in the hole and going to bottom. For this reason it is often preferred to start a long string of casing in the hole with lower rated tools then switching over to the 500 ton tools when the casing is at the bottom of the surface casing or some other point where the running process can be paused to switch elevator and spider. That may sound remote, but there are a number of these instances in many companies’ annals of bad events. In one case a casing crew member fell on the lever and dropped 500 ft of 13 3/8” casing to 5000 ft in a well. In another case, the crew was not filling the 9 5/” casing properly and as the driller lowered the casing it was buoyed enough so that it did not descend at the same rate as the elevator; the elevator slips opened. No one realized the elevator slips were open until the driller stopped the elevator above the spider and the casing kept on going right through the spider before anyone had time to react. Approximately 1500 ft of 9 5/8” casing fell 12000 ft before it stopped. One other thing to mention about casing tools is that a spare elevator/spider combination should be on the rig in case there is a problem with the primary tools.

Figure 7 - 7. A casing spider and casing tongs.

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Getting Casing to Bottom What should we do if the casing will not go to bottom? When this happens (and it sometimes does) there is a tough decision to make. Should we rig up to circulate and try to wash past the obstruction or should we start out of the hole immediately. There are no firm rules on this because there are so many variables. In many places it is possible to install a circulating head (or top drive) and wash through the obstruction. In other situations where differential sticking is prevalent the act of turning on the pump to circulate is the equivalent of saying this is where I want to stick my casing string. One should always decide before starting in the hole what the risks are and what the decision will be should something stop the casing from going to bottom. It is much easier to make the decision then rather than when it happens. Another point we hate to admit happens, but sometimes we find that the casing stops 34 ft from bottom or maybe 63 ft or some such. This sort of thing happens too often, and the embarrassment of having made a mistake in the tally or joint count is only secondary to the reality that that it could also end your current employment. Check your records quickly and make your decision because the cost of trying to wash pipe to bottom that is already on bottom only compounds your problems.

Highly Deviated Wells Directional and highly deviated wells pose a special set of conditions. Borehole friction may be quite high and borehole stability problems may complicate the situation even further. Unlike most near vertical wells, the hook load does not always increase as the casing nears bottom. It often decreases as more casing enters the highly deviated portion and must be pushed in the hole.

Figure 7 - 8. Decreasing hook load in highly deviated well.

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Obviously if the hook load goes to zero we have nothing more to push the casing with and the casing will go no further. (A top drive rig will allow us to add additional force, but it may not be enough either.) If it is not on bottom, then our only hope is to be able to pull it out of the hole. Will our design allow the casing to be pulled out of the hole with all the borehole friction that is in this well? It is essential in highly deviated wells to incorporate borehole friction into our design and running procedures. We cannot go into that here, but the subject is well covered in courses on directional and horizontal drilling.

Landing Practices Again there is no standard practice for landing casing after it has been cemented. It is assumed that the casing is now fixed at the top of the cement. (The fixed point is often referred to as the freeze point). The casing above the freeze point can actually buckle into a spiral or helix due to its weight, the weight of the fluids inside, and a change in temperature. In rare cases would this buckling actually result in damage to the casing, but it could cause wear problems in intermediate casing strings. The severity of the buckled deformation is limited by the clearance between the casing and wellbore wall which is normally relatively small but could be considerable in a washed out are. Four landing procedures are common and were once recommended by the API (but no longer). Roughly they are as follows: •

Land the casing with the same load on the wellhead as the hook load after cementing.

•

Land the casing with tension at the top of the cement which is assumed to be the freeze point.

•

Land the casing with the neutral point (axial tension/compression) at the freeze point.

•

Land the casing with compression at the freeze point.

You can see that some of those are the opposite of each other (the second and last), and none are in agreement. There are operating companies that have selected one of these (with possible variations) and are adamant that theirs is the only good method to use. The problem with all this is that once the casing is on bottom and cemented we are not really certain what happens down hole when we land the casing at the surface. In other cases there is a limitation on what the wellhead equipment can support. There is also the question of the type of hanger used – a slip type hanger gives us considerable

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flexibility (if we can get it down into the casing head properly) whereas a mandrel type hanger cannot be adjusted once the pipe is on bottom or cemented. We are not going to get into the complexities of casing buckling in this course. However, you should be aware that it is all extremely approximate at best, and some of it is totally erroneous. Your company probably already has some landing procedure and you should follow it unless you can think of a good reason why it should be changed. What most companies do is the first of the four and it has worked for years for them. The real enemy as far as casing buckling is concerned is hole washout and bad cement or no cement in those washed out intervals.

Maximum Hanging Weight There are limits on the amount of weight that may be hung on the hanger: •

Tensile strength of the casing string

•

Maximum support strength of wellhead and support casing

•

Support rating of the casing hanger

•

Collapse rating of casing when using slip type hanger

The first limitation in the above list is a matter of proper casing design such that if tension above the string weight is to be applied (e.g. preventing thermal buckling) such additional tension is included in the design loads. The second item is a matter of structural integrity of the supporting casings or platform and is beyond the content of this course. The third item applies primarily to slip type hangers and one need refer to the hanger manufacturers rating for the particular hanger to be used. There is also the case of weight and wellhead pressures exceeding the rating of the casing head such that the hanger actually causes the head to expand, but that is rare and most wellhead manufacturers have eliminated those problems from their equipment. The last item concerning the collapse load of a slip-type hanger on casing can be a serious problem however. The weight of the casing forces the slip segments downward which in turn imposes a radial, compressive force on the casing. Such a force can exceed the collapse resistance of the casing.

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Figure 7 - 9. Slip type casing hanger.

The collapse pressure load on the casing is given by the formula:

ph = f s W

tan α As

where

ph = external radial pressure on casing due to hanging weight (psi) f s = safety factor W = hanging weight of casing (lb) As = gross area of slip contact (in 2 )

α = inclinationangle of casing head/slips (measured from horizontal)

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To be as consistent as possible, the pressure load from this equation should be compared to the biaxial collapse pressure rating of the casing. As to the safety factor it is a matter of company policy, but a commonly used safety factor is 2.0. Example

From our continuing example the 7” production casing has the following data: Buoyed casing string weight at surface: 338,000 lb Type of 7” casing at surface: 29 lb/ft, P-110 Collapse rating: 8530 psi Hanger taper: 65° Hanger slip length: 10 in. Using a safety factor of 2.0, determine if the entire buoyed weight of the string can be hung on the hanger. The biaxial collapse rating of the casing with 338,000 lb tension is calculated from the formulas of the previous chapter and is: 7276 psi ph = f s W

tan α tan 65 = 2.0 ( 338, 000 ) = 6592 psi π 7 (10 ) As

In this case the casing may be hung safely with the full buoyed weight on the hanger without danger of collapse. Whenever doing this type of calculation it is important to know whether the angle of the slip segments is measured from the horizontal or vertical. If the angle is measured from the vertical it must be subtracted from 90° before using in this formula. It is also important to compare to the biaxial collapse rating of the casing (though many assume the safety factor of 2.0 is sufficient to ignore the combined collapse/tension effect and that may be acceptable for many companies).

Wellhead Equipment for Casing While wellhead selection is primarily a function of the completions discipline a good deal of the selection parameters for the lower portion of the wellhead equipment are based on the casing and drilling operations. In this section we will discuss some of the aspects that are related to the casing and cementing practices. We will look at the portion of the wellhead that is directly related to the cased portion of the well since the remainder of the wellhead equipment is the tubing head and Christmas tree and is entirely in the realm of completions and production. As far as drilling and casing is concerned there may be only one or two sections of wellhead involved (sometimes more). These sections are generally referred to as casing heads and casing spools.

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The first head installed is usually called a casing head and subsequent sections are referred to as casing spools (you may also hear the terms A-section and B-section). The casing head is of two types, a slip-on welded head or a threaded head. The figure below shows typical casing heads of these two types. Casing Heads

Figure 7 - 10. Typical welded and threaded casing heads.

The slip-on welded head requires that the casing on which it is installed be cut with a cutting torch; then the head is slipped on and welded in place. It has the advantage of

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allowing the casing to be landed at any depth and is the only possibility if the casing should become stuck off bottom or while reciprocating during cementing operations. This type of head is usually the preferred choice of most operators. Most of these casing heads are installed on the surface casing after the conductor casing is cut off. But some of these heads have a large base plate flange that is welded to the conductor instead of the surface casing, and the surface casing is then hung inside the conductor casing head. The threaded casing head has the advantage that no cutting or welding is required and it generally installs much faster. There are disadvantages:

•

It requires precise landing of the casing string so that a coupling is at the proper distance in relation to the ground level which cannot be visually verified since it is landed below the conductor bell nipple and/or diverter.

•

A casing coupling must be removed for installing the casing head. It may be difficult or impossible to back off the coupling under the rig floor and often the coupling has to be cut off with a torch at the risk of damaging the casing threads to which the head will be attached. Typically the initial loosening of the coupling is done on the rig floor before the landing joint is installed.

•

The casing may be some distance (up to 40 ft ±) off bottom as determined by the top coupling location.

•

The casing must be cemented all the way to the surface.

•

If the casing is not adequately cemented at the surface, the casing may slump down into the hole and the connection for the head may be too low to attach the head.

This type of head is usually selected for very shallow surface casing applications. Casing Spools

The next casing related section of the wellhead is a casing spool and is required if more than one additional string of casing is to be run. After the initial casing head is installed drilling resumes then the next string of casing is hung in the initial casing head. Then a casing spool is installed on top of that which will serve to hang the next string of casing.

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Figure 7 - 11. A typical casing spool with threaded outlets.

A spool of this sort is flanged on top and bottom, has a bowl in the top for the casing hanger for the next casing string and two outlets to install valves that allow fluid access to the casing string hung in the previous spool or head. The illustration above shows threaded outlets which are typical for low pressure applications on land wells. However, higher pressure wells and those on inland waters and offshore typically have flanged outlets. The top and bottom flanges on casing heads and spools are selected so that the bottom connection and the side outlet connections all have the same pressure rating of the casing string below it and the top flange has the pressure rating of the casing string that will be hung in it. For example, a spool may have a 3000 psi flange on bottom and 3000 psi flange outlets, but a 5000 psi flange on top. There are two general types of casing hangers available for hanging casing. The most commonly used is a slip type hanger similar to those shown in the figures below. The slip type hanger is almost always installed after the casing has been cemented and the cement has been allowed time to set. Casing Hangers

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Figure 7 - 12. A two piece slip type hanger.

Figure 7 - 13. A one piece slip type casing hanger.

These types of hangers are usually installed by removing the BOP bolts and raising the BOP assembly to install the hanger around the pipe while it is still supported by the landing joint(s) and elevators. Once the hanger is seated in the casing head or spool

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the casing string is then pulled with the landing joint(s) to the desired tension then lowered slightly to allow the slips hold the casing in place. With a slip type hanger you can always increase the tension in the pipe once the slips hold, but you cannot reduce it.

An alternative and much safer procedure is to install the slips on the landing joint above the rotary and let it slide down the pipe and into the head. This procedure requires though that the landing joint be long enough that its lower coupling be below the casing head or spool. There is also the problem that if the pipe is not perfectly concentric in the BOP and well head that the hanger will not slide all the way to or into the head. Attempts to push it down manually with small diameter pipe or other devices are usually not very successful. The other type of hanger commonly used is a one-piece mandrel type that is threaded on top and bottom and had a sealing element for the spool bowl. A coupling is removed on the top joint and the hanger is threaded onto that joint. A landing joint is threaded into the top of the hanger and the casing is lowered into place. This type of hanger is simple, the safest to use, and results in very few problems. However, there are a few considerations to note.

•

This type of hanger is always installed before cementing so the return flow during cementing operations must be routed through the side outlets of the casing head or spool on which it is hung.

•

It is not advisable to reciprocate the pipe while cementing with this type of hanger because if the pipe should stick while reciprocating it may not be possible to seat the hanger in the head.

•

It is not possible to select the landing weight since the hanger is installed prior to cementing.

•

The casing shoe will be off bottom by a distance determined by the coupling location at the top of the string.

All side outlets on casing heads and spools should have valves of the proper type (i.e., no blind flanges or bull plugs). A bull plug or blind flange may be installed outside the valve for protection of desired. At least one valve on each head should have a good working pressure gage so that the casing pressure may be monitored. Casing heads, casing spools, and valves like all wellhead equipment have a rated working pressure or maximum service pressure (MSP) as it is sometimes called. It also has a test pressure which is often higher than the MSP by 50% or more. It has become an all too common practice for some operators to rely on the test pressure rather than the MSP when the actual well pressure is slightly above Precautions

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the MSP of the wellhead. This condemnable practice does result in a significant cost savings, but at a considerable risk to the field people who are the ones exposed to the risk. One should always use only the MSP rating in selecting equipment. If the well pressure expected is 3050 psi, then the only choice for a wellhead is 5000 psi, not 3000 psi. It is unconscionable to choose otherwise.

Casing Wear If we have time there will be a short slide presentation on casing wear. That material has not been added to this manual yet. In the meantime some things you should be aware of are these:

•

Casing wear is a function of contact force between the tool joints and the casing

•

Most severe casing wear occurs near the surface

•

There is no direct correlation between casing wear and the magnitude of the dogleg severity

•

The best protection against wear once the casing is in place is non-rotating drill pipe protectors installed in areas of highest potential wear

•

Sand in the mud accelerates wear in all conditions

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8

Chapter

Cement Types, Additives & Testing What we need to know about cement

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he amount of cement used in oilfield applications may seem enormous, but the fact is that cement used for oilfield applications constitutes only a small fraction of total cement used in construction applications. Because of that, the cement manufacturing companies were not always attentive to the needs of the petroleum industry. The situation was so critical in the early days that Earl Halliburton built a cement plant to make cement specifically for oilfield applications. Subsequent to that time the cement companies have been more accommodating and we now have relatively good quality cement tailored specifically for our needs. A great deal could be said about cements. In fact books have been written on the topic. But our primary concern in this course is that of application so we will not devote much time to the manufacture and chemistry of cements. We will discuss in this chapter some of the properties and tests that affect oilfield applications.

Brief History of Cements Cements have been used in building construction since the earliest civilizations. In Egypt they used gypsum cement, in Greece calcined cement, and in Italy pozzolaniclime cement. Cementing technology developed little from those early times until the early 19th century when Portland cement was discovered by a stone mason. This cement was a hydraulic cent in that it would harden under water, and it is the basis for the cements used today.

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Chemistry and Manufacture of Cement Oilfield portland cements are composed primarily of silicon dioxide, SiO2, and calcium oxide, CaO, along with some minor constituents such as the oxides of iron, magnesium, sulfur, and potassium prior to hydration with water. They are manufactured by adding clay or shale to limestone and possibly some amounts of iron and alumina, blending, and heating from 2600 ─ 3000° F in a kiln. The resulting product is a course material called a clinker. The clinker is then reduced in size by grinding and pulverizing. Finally some amount of gypsum is added to control hardening time. Once cement is set it contains compounds of calcium, aluminum, and silica as in the table below. Table 8 - 1. Chemical compounds in set portland cement ( ASTM,III, 1970).

Compound

Formula

Standard Designation

Tricalcium aluminate

3CaO⋅Al2O3

C3A

Tricalcium silicate

3CaO⋅SiO2

C3S

B-dicalcium silicate

2CaO⋅SiO2

C2S

Tetracalcium aluminoferrite

4CaO⋅Al2O3⋅Fe2O3

C4AF

API Cement Classifications The API has classified cements for oilfield use as published in API Standards 10A, Specifications for Oil-Well Cements and Cement Additives”. Currently the following cements are listed: Class A: Intended for use from the surface to a depth of 6000 ft when special properties are not required. Class B: Intended for use from the surface to a depth of 6000 ft when conditions require moderate to high sulfate resistance. Available in both moderate and high sulfate resistant types. Class C: Intended for use from surface to 6000 ft when conditions require high early strength. Available in ordinary type and moderate and high sulfate resistant types. Class D: Intended for use at depths of 6000 to 10,000 ft and at moderately high temperatures and pressures. Available in both moderate and high sulfate resistanct types.

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Class E: Intended for use at depths of 10,000 to 14,000 ft at high temperatures and pressures. Available in moderate and high sulfate resistant types. Class F: Intended for use at depths of 10,000 to 16,000 ft and at extremely high temperatures and pressures. Available in high sulfate resistant type. Class G: Intended for use as a basic cement from surface to a depth of 8,000 ft as manufactured. With accelerators and retarders it can be used for a wide range of depths and temperatures. It is available in both moderate and high sulfate resistant types. Class H: Intended for use as a basic cement from surface to a depth of 8,000 ft as manufactured. With accelerators and retarders it can be used for a wide range of depths and temperatures. It is available in both moderate and high sulfate resistant types. Of these eight cement types only five are currently manufactured; Class D, E, and F have been discontinued. Class G and H are the most widely used, and the specific choice between the two depends primarily on geographic location and availability.

Some Specialty Cements There are a number of popular cements that have general use and also special uses. are manufactured with siliceous materials either manufactured or natural. The primary use of pozzolanic cement is for applications where lower densities are required, such as primary cementing of surface casing. Pozzolanic cements

is usually mixed with API Class A, G, or H used for remedial cementing to provide quick setting times and thixotropic properties to hold the cement in place once pumping has stopped. Gypsum cement

is a slurry of Class A, B, G, or H cement mixed with diesel oil or kerosene with a surfactant and is used primarily to shut off water production. The cement sets on contact with salt water but will not set in the presence of hydrocarbons. Unfortunately the setting times are on the order of 30 seconds to 3 minutes and their use can be problematic. Newer cements and chemicals accomplish this goal with much less hazard.

Diesel oil cement

are supposed to expand when setting as opposed to shrinking as most cements do. The purpose of the expansion is to prevent micro-channels from forming between the pipe and the borehole wall.

Expanding cements

with particle size in the range of 10 microns is used for remedial cementing operations where the cement must pass through very small openings. Fine particle cement

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Examples are repairing cracks or coupling leaks in casing. Another application is those where cement must be pumped through sand screens. are cements to which latex powder has been added. The cement has good bonding properties is slightly ductile when compared to conventional cements. It has been used successfully for cementing junctions of multilateral wells.

Latex cements

is cement mixed with nitrogen to form a foam slurry. It can be mixed as low as 4.0 ppg and obviously has a lot of low pressure applications. Also it tends to displace mud better than other slurries and has expanding properties. Currently it is being used successfully for cementing junctions in multilateral wells. Foam cement

There are a number of additional specialty cements for particular applications, but these are the most common.

Cement Additives There are many hundreds of cementing additives, some general and some proprietary. Obviously, there are far too many to cover here, but we will list the general categories. For now the slide presentation will give additional details not listed in the manual. •

Accelerators – decrease setting time

o Sodium chloride (can also become a retarder in higher concentrations) o Calcium chloride o Densified cement o Sea water o Proprietary products •

Retarders – increase setting time

o Lignosulfonates o CMHEC o Synthetic retarders (often polymers) •

Light Weight Additives – reduce slurry density

o Swelling clays (bentonite/attapulgite) o Anhydrous sodium metasilicate

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o Pozzolanic materials o Fumed silica o Foam cement o Amorphous silica o Hollow spheres •

Fluid Loss Control

o Bentonite o Organic polymers o Latex additives •

Dispersants – friction reducers

o Proprietary products •

Heavy Weight – increasing density

o Barite o Sand o Hematite o Some dispersants •

Defoamers – reduce and release entrained air when mixing

o Salts o Surfactants o Lignin retarders o Bentonite o Various proprietary products •

Lost Circulation

o Granular materials

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o Fibrous materials o Lamellated materials o Gelling and flash setting materials •

Gas Migration – preventing gas migration and channeling in the annulus

•

Expansion – increased bonding and channel reduction

o Aluminate-sulfate additives o Polyvalent metal oxides o In-situ gas generators o Compressible cements

Cement Testing There are a number of tests that can be performed on cement slurries and set cement. Whenever we do a cement job there are a number of questions we need to answer before we start the job: •

Will the cement remain fluid for the time necessary to put it in place

•

Will the cement set to an adequate strength within a reasonable time?

•

Is the cement compatible with the mud in the hole?

•

Will the cement cause damage to the producing formation?

To answer these questions there are some standard API tests to measure some of these properties. Thickening Time Tests

Thickening time tests measure the resistance to pumping (viscosity) of the slurry under pressure and temperature conditions that are expected in the actual well. It is the time required to reach certain consistency levels. It is measured with a special instrument called a HTHP Consistometer. Rheology Tests

Primarily these are viscosity and gel strength tests measured with a conventional Fann viscometer or a HTHP rheometer.

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Fluid Loss Tests

Water loss of cement slurries is measured similar to the API water loss test for drilling fluids except at a higher pressure. Typically the loss is measured at 1000 psi through a 325 mesh screen for 30 minutes. Compressive Strength

Compressive strength is determined by subjecting 2in. x 2 in. samples to a compressive or crushing test. Samples are cured under well pressures and temperatures and are tested at various times, typically 8 hours and 24 hours. Free Water Test

The free water test measures the free fluid in the slurry after 2 hours of static time.

Closure There are many cements and additives available almost any where in the world. Few operating companies now have their own cementing experts, and it is very difficult for most engineers to know all of the possibilities and options. It is essential that there is a close relationship of information sharing and trust between operating companies and service companies when it comes to cement selection for particular applications. Many other tests can be run on cement, cement slurries, and set cement than are mentioned in this chapter. The important thing to remember is that general or published test results are not a substitute for actual testing of cements, mixing water, temperature, and pressures for the actual well.

References API, (1991) Worldwide Cementing Practices, American Petroleum Institute, Washinton, D.C. API, API Standards 10A, Specifications for Oil-Well Cements and Cementing Additives, API, Washington, D.C. Smith, Dwight K., 1976, Cementing, SPE, Dallas, Texas

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9

Chapter

Cementing Equipment The hardware that we use.

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his chapter will describe the equipment used in cementing. It will focus primarily on the equipment run down hole in the casing strings and the surface equipment attached to the casing during the cementing process. The coverage of the pumping, mixing, and transport equipment will be brief as much of that equipment varies with service companies and detailed knowledge is not essential to learning about cementing casing. In this chapter we will confine the discussion to describing the various types equipment. In the following chapters we will discuss the proper uses.

We will cover the following types of equipment in this chapter. •

Float Equipment

•

Centralizers

•

Scratchers

•

Wiper plugs & Containers

•

Stage tools

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Mixing & Pumping Equipment

Float Equipment The device that is run on the bottom of the casing for primary cementing is called a “shoe”. There four basic types of shoes run on casing, a guide shoe, a float shoe, an automatic fill float shoe, and a differential fill float shoe. Guide Shoe & Float Shoe

The guide shoe is simply a plain end device run on the bottom of the casing with a cement or composite bottom and a restricted hole through the center. It is rounded on bottom so it will pass easily into the well. The restricted hole size allows a wiper plug to seat (though it seldom is used for that) and also to increase the velocity of the flow out of the shoe to remove mud and allow for better cementing around the shoe. The cement or composite material in the shoe is easily drilled once the cement has hardened sufficiently for the drilling operations to resume.

Figure 9 - 1. A guide shoe.

The float shoe is similar to the guide shoe except it has a check valve to keep fluids from entering the casing from the bottom. The primary purpose is to hold the cement column in place in the annulus since the density of the cement is usually greater than that of the mud and it would tend to equalize the hydrostatic pressure difference by flowing back into the casing were it not for the check valve. There are three types of check valves used. One is a ball type check valve using a low density ball that floats in the drilling mud or cement. Another is a spring actuated flapper type check valve. And a third type uses a spring actuated poppet type valve. Of the three the ball type is the simplest and considered the more reliable by many because it has no spring like the other two.

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Figure 9 - 2. A float shoe with ball check valve.

Figure 9 - 3. A float shoe with flapper check valve.

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Figure 9 - 4. A float shoe with poppet check valve.

An automatic fill float shoe has a check valve in bottom that is held off its seat by various means until the casing is circulated. Once circulation has been established the check valve actuated, no fluids can enter the casing from the shoe after circulation ceases. The purpose of such a shoe is to allow fill of the casing from the wellbore as the casing is being run into the well.

Figure 9 - 5. An automatic fill valve, shown here on a float collar, but can also be run on a float shoe.

A differential fill type shoe has a check valve and also a spring loaded valve to allow fill from the bottom after a predetermined differential pressure is reached. The purpose of this device is to fill the casing from the shoe in the event that the filling operation at the surface falls to far behind to the point where there is too little mud in the casing.

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Figure 9 - 6. A differential fill valve (shown here on a float collar, but can also be in a float shoe.)

Some float shoes also have some type of outlet other than the down-facing center hole. They also have holes in the side that aid in removing mud from the hole near the shoe. Some of these holes direct the flow upwards, some to the side, and some downward.

Figure 9 - 7. A poppet type float shoe with "jets" on the side to direct some of the flow upward in a spiraling flow.

Float Collars

Float collars serve the same purpose as a float shoe, i.e. to prevent cement from reentering the casing once it has been pumped into place. The float collars are made with various types of valves the same as the float shoes. There are also automatic fill and differential fill collars. The purpose of the float collar is primarily to provide a landing seat for the wiper plugs some distance above the float shoe so that good some quality cement is inside and outside the casing around the shoe. In other words if we displaced a wiper plug all the way down to the shoe there would certainly be some contaminated cement ahead of the wiper plug and it would be around the outside of the shoe. The check valve in the float collar serves as a redundant back up of the

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check valve in the shoe. Float collars are run at least one joint above the float shoe and most operators run them two joints above the shoe. Those who run them only one joint above the shoe feel that they are saving money by having less cement to drill out of the casing. The truth is that bad cement around the shoe will cost a lot more to remedy than a little extra time drilling thirty to forty feet of cement. You should always run the float collar at least two joints above the float shoe. There is also another type of float used in place of a float collar called a float insert. It is a threaded piece of metal with a flapper valve that is run in a casing coupling. It is cheap and that seems to be its only advantage because they can fail easily. It is false economy, or as one old timer once said, “If you can’t afford a real float collar then you should not be drilling a well.”

Centralizers The subject of centralizers seems to be slightly controversial in the oilfields of the world. It should not be. The simple truth is that if the casing is not reasonably centralized in the hole you cannot expect to get a good primary cement job. That is a fact not a theory or speculation. There are three keys to successful use of centralizers. •

Adequate number of centralizers to assure proper standoff

•

Good quality centralizers

•

A clean wellbore (especially in highly deviated wellbores)

We will discuss those items in the next chapter on primary cementing, but for now we will look at some different types.

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Bow Type Centralizers

E Q U I P M E N T

The most common type centralizer in the oilfield is the bow type. It has metal bands bent in a bow type configuration that act as springs to keep the casing centralized. Despite their popularity and long standing dominance in the market, they are not very good at doing what they are supposed to do. Many are cheaply made, do not meet API specifications, and often come apart in the well. The high quality ones are much better, but do not give good standoff in most deviated wells unless a large number of them are run on the casing. Drilling people seem to like them because the think they are flexible and they are easy to run if there are crooked hole problems. Even at their worst they do provide at minimum the standoff equal to the thickness of the ring and blade and they do create some disturbance in the annular flow pattern especially if they have some type of turbulence inducing blades on them. They are manufactured with welded blades or non-welded blades, i.e. mechanically attached. Though there is not total agreement the non-welded blades are rated as better by most companies.

Figure 9 - 8. Bow type centralizer (non-welded).

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Figure 9 - 9. Bow type centralizer with blades to induce turbulence.

In recent years there has been another type of bow type centralizers that have a double curvature in the blade. Some call it a double bow and some call it a semi-rigid centralizer. Whatever name it goes by it provides a better standoff than the common bow type and is still flexible enough to run in unstable boreholes. If one is insistent upon using a flexible centralizer this is a much better choice than the conventional bow type. Modified Bow Type Centralizers

Figure 9 - 10. A double-bow or sem-rigid centralizer.

Rigid and Integral Type Centralizers

Rigid centralizers are the best possible type of centralizer for obtaining a good primary cement job. They provide a positive standoff because there is no flex. The downside is that they are

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generally more expensive. For some reason many drillers think they are too risky to run in a well since they do not flex. This has not been proven to anyone’s satisfaction, but it is a widely held opinion. Like the bow type there are many different variations. Some are welded contrivances often of rather poor quality and some are manufactured as integral one-piece devices. Many have a spiral configuration of the blades to affect the annular flow patterns and that is a good thing. In recent times some have been manufactured of special alloys (e.g. zinc) that reduce friction while running in the hole and also provide cathodic protection from corrosion to the casing.

Figure 9 - 11. A rigid centralizer with hinges.

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Figure 9 - 12. An integral type rigid centralizer.

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Figure 9 - 13. A welded rigid centralizer with spiral blades to induce spiral flow.

Scratchers Scratchers and hole wipers are another subject of controversy amongst drillers. There are various types that require reciprocation or rotation of the casing string. As originally conceived they were supposed to remove wall cake from the wellbore to allow good bonding of the cement to the wellbore wall. Probably no one still believes that anymore because the wall cake reforms almost immediately, but they do definitely free up large accumulations of mud that has gelled and will not move under normal circulation conditions. For that reason alone, they are quite useful and should be run except in horizontal wells or highly deviated wells where pipe movement is not possible.

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Figure 9 - 14. Scratchers for reciprocation.

Figure 9 - 15. Scratchers for rotation.

Wiper Plugs & Containers Wiper plugs are used to protect the cement from contamination and to remove the wet cement from along the inner wall of the casing as it is being displaced. There are two separate wipers. The first wiper in the hole is a bottom wiper. It is pumped ahead of the cement and separates the cement from the fluid already in the casing. When it reaches the float collar it has a shear disk that ruptures to allow the cement to pass through it (Some have weak rubber seals that fail instead of a rupture disk). The top plug flows the cement and prevents contamination of the cement with the displacing fluid. It also wipes the wet cement from the wall of the casing during displacement.

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Figure 9 - 16. Top and bottom wiper plugs.

Some wiper plugs have a feature that prevents them from rotation while being drilled. This is especially important when using a PDC bit to drill out the cement and float equipment.

One of the hazards of the two plugs is that if they get mixed up and the top plug is run on bottom it will seal the casing with all the cement inside and it cannot be reversed out because of the check valve in the float shoe and collar. For that reason, the two plugs are a different color and clearly marked. A double plug container holds both plugs at the beginning of the job. There are threaded rods that hold each plug on place and a valve manifold that can direct flow to pump above each plug once it has been released. Operation of this device should be carefully monitored to be sure that it is loaded correctly and that the plugs are released correctly. Failure to operate this device

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correctly could result in an unsuccessful cement job or even a casing string full of hardened cement.

Figure 9 - 17. A two plug container.

Stage Cementing Tools A stage cementing tool is run some distance above the bottom in order to place additional cement at a higher depth than could be placed from the bottom. There are a number of reasons for doing this, and they will be discussed in the next chapter. The tool is run in the hole as part of the casing string and is in a closed position to allow the cementing at the shoe to be done in a conventional manner (though some equipment requires special wiper plugs). Once the top plug has been landed at the float collar a device is dropped in the casing that opened the port in the stage tool. Circulation is established through the stage tool then cement is pumped through the stage tool. The top wiper plug for the stage tool closes the port on the tool when it lands and is pressured. Stage tools are in common use in many parts of the world. Two problems can occur, one is that the tool will not open and the other is that it will not close. If it does not open it is often possible to run small diameter pipe inside the casing to open the stage tool. The problem of the tool not closing is more common though and more serious. There is usually noting that can be done to close the tool if it does not close normally or if it closes only partially. In those cases a squeeze job is necessary and in some cases of high pressure it might be necessary to insert a smaller casing string inside the one with the open stage tool port.

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Figure 9 - 18. A typical stage tool with operating sequence: running position, bottom cement in place and opening tool dropped, port open and top cement being displaced, top cement displaced and tool closed.

Surface Mixing & Pumping Equipment The mixing of cement on the surface is accomplished in three general ways. One is a jet hopper in which the bulk cement is mixed with the mixing water as the water flows through an orifice and the cement is fed into the jet stream by gravity or air pressure. Another method is a batch mixing device that mixes a larger volume of cement in a tank with stirring paddles or blades. The third type of device is a re-circulating system in which the cement is mixed by a jet hopper and re-circulated through a tank to allow time to get the mixture more uniform.

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Figure 9 - 19. A low pressure jet hopper mixing system.

Figure 9 - 20. A batch mixing system.

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Figure 9 - 21. A re-circulating mixing system.

There is a considerable amount of additional surface equipment required for a cement job. There are the pumps, cement handling equipment, water handling equipment bulk cement containers, etc. Onshore this equipment is highly portable and mounted on trucks. Offshore much of the equipment, especially the pumps and mixing equipment is permanently installed on the rig. In some places there are cementing boats that have all the cementing equipment and cement storage onboard. These vessels are like floating cementing facilities that tie up to the rig, do the cement job, then leave for another job at another rig.

Closure In this chapter we have examined some of the more common cementing equipment for cementing casing. We did not go into many details about the selection and operations procedures of the equipment. What we did not discuss in this chapter we will discuss in the chapter on primary cementing where such information will be more meaningful. There is much other equipment we did not cover such as squeeze packers and retainers, liner equipment, etc. Those items will be discussed later when we cover squeeze cementing, liner cementing, etc.

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10 Chapter

Primary Cementing Primary cementing is one of the most important aspects of drilling a well.

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he importance of primary cementing cannot be overemphasized. A good primary cement job can save untold time and money over the life of a well. And likewise, a poor primary cement job can cause enormous expenditures and problems throughout the life of a well.

Primary cementing is a core process used throughout the world. The purpose of primary cementing is to seal the annular space between the wellbore and the casing so as to: •

isolate and contain productive, problematic, and weak formations

•

support and protect casing

•

provide insulation in geothermal wells

In this chapter we will look at primary cementing as it applies to various types of casing then at some of the details as to what is necessary to achieve a good primary cement job. Here is how we will cover this important topic in this chapter. •

Types of Primary Cementing Jobs o Conductor Casing

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o Surface Casing o Intermediate Casing o Production Casing o Liners – Drilling & Production o Tie-back Casing o Horizontal Wells o Multilateral Wells •

Cement Displacement

•

Spacers & Pre-flushes

•

Centralization

•

Rotation & Reciprocation

•

Multi-stage cementing

•

Primary Cementing Calculations

Types of Primary Cementing Jobs

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Conductor Casing The purpose of conductor casing is to: •

Confine circulating fluids while drilling surface hole

•

Prevent washout under the rig

•

Provide elevation for getting circulating fluid back to pits

•

Provide a base for the wellhead (on some wells)

•

Provide a place to attach a diverter (on some wells)

Equipment •

Guide Shoe (with inner string seal on some wells)

•

Centralizers

•

Inner string for displacement in cases of large diameter

Cement •

Fast setting

•

High strength

•

Accelerated

•

Increased density (in some cases)

Pumping Rates •

High

•

Continuous, some problems if pumps stop

Slurry Volumes •

Large volumes due to hole erosion

•

100% to 300% excess of hole volume calculated with bit diameter

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Special Considerations •

Need large capacity mud pit to contain mud displaced by cement

•

Care must be exercised to not pump conductor out of hole (may require anchoring the conductor)

Surface Casing The purpose of surface casing is to: •

Protect fresh water sands

•

Seal off unconsolidated formations

•

Seal off lost circulation zones

•

Provide for initial pressure control

•

Support wellhead and additional casing strings (on many wells)

Equipment •

Guide shoe (or float shoe), float collar

•

Centralizers

•

Thread lock compound for bottom joints

•

Bottom and top plugs

•

Possible stage tool, cement basket or ECP

Cement •

Filler slurry in upper hole, high strength at bottom

Pump Rates •

High

Slurry Volume •

Bring cement to surface

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•

Large volume because of hole erosion

•

Typically 80% to 120% excess of nominal hole volume calculated from bit diameter

Special Considerations •

Multi-stage cementing often required to prevent collapse of casing, or to protect weak formations

•

May require a top job if cement does not reach surface

•

Casing may stick

•

Reciprocation is seldom attempted because of weak formations

Intermediate Casing The purpose of intermediate casing is to: •

Seals off lost circulations zones, water flows, etc.

•

Isolates salt sections

•

Protects open hole from increasing mud densities

•

Protects from flow if mud densities must be reduced

Equipment •

Float Shoe, Float Collar

•

Centralizers

•

Bottom & top plugs

•

Thread lock compound for bottom joints

•

Stage tool may be required, cement basket or ECP

Cement •

High densities usually required because of high mud densities

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Pumping Rates •

Moderate to high

Slurry Volumes •

30% to 50% excess in the absence of a caliper measurement

Special Considerations •

Fracture gradients

•

Displacement rates

•

Density of pre-flushes

•

Temperature and thickening time

•

Multistage might be an option

Production Casing The purpose of production casing is to: •

Conduit for completion string

•

Provides pressure control for full well pressure

•

Covers worn or damaged intermediate casing

Equipment •

Float Shoe, Float Collar

•

Centralizers

•

Bottom & top plugs

•

Thread lock compound for bottom joints

•

Stage tool may be required, cement basket or ECP

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Cement •

Producing formation compatibility

•

High strength for perforating

•

Good bonding across producing intervals essential

•

Prevent gas migration

Pumping Rates •

Moderate to high, avoid exceeding maximum ECD

Slurry Volumes •

Caliper volume plus 15% to 25%

Special Considerations •

Rotate/reciprocate

•

Weighted or reactive spacers

•

Water displacement when possible

•

No pipe motion while slurry is setting

Drilling Liner The purpose of drilling liner is to: •

Cover weak zones

•

Cover high pressure zones

Equipment •

Float Shoe, Float Collar

•

Centralizers

•

Special latch-in liner plugs

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•

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C E M E N T I N G

Liner hanger

Cement •

High strength

Pumping Rates •

Slow to moderate

Slurry Volumes •

Caliper volume plus 15%

Special Considerations •

Batch mix cement if possible

•

Hang liner and be certain running tool has disconnected before starting cement

•

Circulate 1.5 well volumes before starting cement in hole

•

Reverse circulate after cement is in place – annulus

•

Rotate liner while cementing if possible

•

Watch ECD carefully while cementing

•

Differentially test liner lap before drilling out shoe

•

Tack and squeeze method often used

never

Production Liner The purpose of production liner is to: •

Serve as the lower portion of the production casing

•

Isolate and contain the producing intervals

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circulate cement up the

P R I M A R Y

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Equipment •

Float Shoe, Float Collar

•

Centralizers

•

Special liner latch-in plugs

•

Rotating scratchers

•

Liner hanger (with tie-back receptacle if needed)

Cement •

High strength

•

Usually densified

•

Compatible with producing formation

Pumping Rates •

Slow to moderate

•

Use spacers

Slurry Volumes •

Small volume

•

Caliper volume plus 15%

•

Batch mix if possible

Special Considerations •

Hang liner and be certain running tool has disconnected before starting cement

•

Circulate 1.5 well volumes before starting cement in hole

•

Reverse circulate after cement is in place – annulus

•

Do not stop circulation prior to pumping cement

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never

circulate cement up the

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•

Rotate liner while cementing if possible

•

Watch ECD carefully while cementing

•

Differentially test liner lap before cleaning out liner

•

Tack and squeeze method should not be used

Tie-back Casing The purpose of tie-back casing is to: •

Extend production liner to surface (or in some cases a drilling liner)

•

Serves as part of the production casing string

•

Covers damaged or worn intermediate casing

•

Cases off exposed liner tops

•

Can be pressure tested while running for high pressure applications

Equipment •

Float Collar (the shoe is a seal assembly)

•

Centralizers

•

Bottom & top plugs

Cement •

High strength

Pumping Rates •

Moderate

Slurry Volumes •

As little or as much as needed, volume is easily calculated since hole is cased

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Special Considerations The tieback has a seal assembly that fits into a receptacle on to of the liner hanger. The system below the float collar is closed so the seal assembly may not go all the way into the receptacle because the mud will not compress. Many operators use a flapper type float collar with a 3/8” hole drilled in the flapper to allow for the seals to seat fully without the mud compression problem. Once the seal is seated, the float collar has no pressure on it from below so the hole in the flapper has no detrimental effects. There have been cases where the seal did not hold. In that situation it is necessary to hold pressure on the plug until the cement sets.

Horizontal Well Considerations Horizontal wells require special considerations. Currently most horizontal wells are completed as open hole completions and the cementing requirements are for a production string that is cemented into the top of the producing interval vertically in which case it is identical to a vertical well production casing string. In some cases the casing is set all the way through the build section so that the bottom is at a 90° inclination. A relatively few horizontal wells have a casing string cemented along the entire length of the horizontal lateral. The second and third cases here require special attention. Typically what happens in a horizontal well is a bad primary cement job that looks like the figure below.

Figure 10 - 1. Typical poor cement job in horizontal wellbore.

There is a bed of cuttings along the bottom of the borehole and the casing is in contact with it. There is cement around the rest of the casing, but there is a large mud or water channel along the high side of the borehole. How do we do better? There are several requirements.

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•

Get all cuttings out of the wellbore. This may be difficult in a horizontal well and may require extra trips, rotation of the drill string, densified mud sweeps, etc. The point is that it must be done. It is not a matter of some standard or routine circulating time. Whatever it takes to get the cuttings out must be done if one expects to get a good primary cement job.

•

The slurry must be stable from settling and have 0% free water at a 90° inclination angle. A cement slurry with 0% free water in a vertical wellbore will not necessarily have 0% free water in an inclined wellbore. It must be tested.

•

Adequate centralizers are a must. Rigid centralizers that give a minimum of 70% standoff are necessary. (More about centralization in a later section).

•

Reciprocation is not feasible in most cases. Rotation is also not possible in many cases because the torque required to rotate the casing in the presence of the friction in a horizontal wellbore usually exceeds the maximum makeup torque of the casing connections. Rotation is highly desirable, however, and casing with high torque connections and liners may be rotated. It is worth considering.

•

In recent times work is being done with foam cement in horizontal and multilateral wells. It can be mixed at densities as low as 4.0 ppg, has excellent hole cleaning properties, stays in place in horizontal wellbores, and has some expansion characteristics.

•

A good mud is essential for displacement. This may be a different mud than the drilling mud.

Multilateral Well Considerations The most critical part of a multilateral well is the junction, the point where a lateral intersects the main wellbore, or trunk as it is called. Open hole junctions are not a concern here, but where it is necessary to cement a junction we must also look at special considerations. Typically a cemented junction means a liner in the lateral that is cemented back into the trunk. The difference between a liner in one of these wells and a conventional liner is that the liner must be hung or cut flush with the wall of the trunk to allow access to other laterals below the junction. Since there is no overlap of the liner, the cement must provide all of the structural integrity at the junction. In the early multilaterals it was thought that the best cement would be the strongest, hardest cement available. That proved a fallacy. The hard cement proved brittle. It fractured and fell apart at the junction during subsequent operations. The next phase was to add some type of fiber reinforcement to the strong cement. The idea was that if the cement cracked the fibers would hold it in place. That was a little more successful, but still not very good. Finally it was decided that ductile cement that had a

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little flexibility was a better solution. It proved to be successful and most junctions today are cemented with a latex type cement. Now, in the last two years there has been a trend toward foam cement. It seems to have all the ductile qualities of the latex cement plus it cleans the borehole better and has some expanding properties. In some areas most operators have switched over to foam cement for cementing multilateral junctions.

Figure 10 - 2. A liner installation procedure in multilateral well.

Figure 10 - 3. Junction problems caused by bad cement job.

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Displacement Procedures The number one cause of poor primary cement jobs is poor mud removal.

The number one cause of poor mud removal is poor mud.

With those two things said we now turn to the displacement of the cement into the annulus of the casing and wellbore in such a way as to achieve a good primary cement job. Several things aid us in mud removal. •

Mud conditioning

•

Fluid Velocity

•

Flushes and spacers

•

Centralizers

•

Mechanical aids o Pipe movement o Scratchers o Turbulence inducers

Displacement Efficiency

We measure the quality of displacement as a percentage of the total annular volume displaced with cement. Two measures can be used. The first is for the volumetric displacement efficiency.

Ve =

Vc (100 ) Va

where Ve = volumetric displacement efficiency, % Vc = volume of cement, bbl (or any consistent volume unit) Va = volume of annulus, bbl (or any consistent volume unit)

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(10.1)

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The second is a measure of the cross-sectional area displacement efficiency.

Ae =

Ac (100 ) Aa

(10.2)

where

Ae = area displacement efficiency, % Ac = area of cement, in 2 (or any consistent area unit) Aa = area of annulus, in 2 (or any consistent area unit) When we talk about displacement efficiency we generally think in terms of volumetric efficiency, but in practical terms we usually consider the area displacement efficiency at a particular point or points. The figure below illustrates a cross-sectional area with an area displacement efficiency considerably less than 100%.

Figure 10 - 4. Cross section showing area displacement efficiency.

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Figure 10 - 5. A cement dislacement efficiency of 61%.

Figure 10 - 6. A cement displacement efficiency of 97%.

Mud Conditioning Circulating Time

In conditioning the mud and hole the question is how long should the hole be circulated? The answer is that the longer it is

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circulated (at a given rate) then the greater the percentage of mud that is actually moving.

Figure 10 - 7. Effect of circulating time.

The above figure shows a typical example, and we could use it as a rule of thumb. In other words we should circulate the hole for at least three annular volumes before we start the cement in the hole. But is there any other way that we can apply in general since we have no way of measuring the hole cleaning percentage? There is a method that is relatively simple and it involves an accurate measure of the surface circulating pressure while circulating at a constant rate.

Figure 10 - 8. Decline of surface circulating pressure at constant circulating rate.

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We can see that the pumping rate remains constant but the surface circulating pressure decreases and after a period of time begins to become constant. In terms of hole cleaning that same data can be correlated in another chart.

Figure 10 - 9. Circulation effect correlation with declining surface pressure at constant circulating rate.

This chart shows that 60% of the annular space (called the “circulatable hole” in the chart) is being circulated. The chart shows that once the surface circulating pressure becomes constant, then continued circulation at that same rate will not accomplish anything any additional benefit. These charts are from full scale lab tests, but the same apply in an actual well. Accurate measurements of the circulating pressure is necessary though. One of the things that really causes a loss in displacement efficiency after conditioning the mud is stopping the pumps and circulation prior to pumping the cement. This is especially true in a well with a highly thixotropic mud with a high yield strength. Once the mud stops flowing it gels quickly and the displacement efficiency is quickly lost.

Stopping Pumps

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Figure 10 - 10. Effect of static time between conditioning and pumping cement on displacement efficiency.

In the above chart for a highly thixotropic mud, you can see that the displacement efficiency is about 98% while circulation is maintained. When circulation is stopped for 5 minutes and resumed the displacement efficiency has dropped to about 83%. A two hour stop drops the displacement efficiency to 61%. It is apparent that stopping the pumps prior to pumping the cement is detrimental to good displacement efficiency. Mud Properties

We can conclude from the above charts and other lab tests that the drilling mud should ideally have the following properties to assure good displacement efficiency.

•

Yield point less than 10, and ideally it should be 2 or less.

•

The plastic viscosity should be less than 20.

•

The fluid loss should be less than 15

•

The 10 s gel and the 10 min gel should be close in value, e.g. 2/3 and not 2/10.

Of course these properties are not the ideal properties of a drilling fluid for drilling operations.. Once the hole is drilled and the cuttings have been removed the properties should be changed accordingly to promote good cement displacement efficiency. Circulating Rate

The circulating rate is also important in obtaining good displacement efficiency. There are three flow regimes for displacing cement.

•

Plug flow – slow flow with equal velocity across the wellbore, only possible with high viscosity fluids or some interface between the cement and mud.

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•

Laminar flow – medium flow rate, smooth flow, velocity profile is maximum in the center of flow channel and minimum at the boundaries.

•

Turbulent flow – velocities at any point may be in any direction, but general flow is always in the direction if the circulation.

Figure 10 - 11. Three flow regimes.

There is no doubt that turbulent flow is the best for displacement efficiency. However, it is not often possible to achieve turbulent flow while displacing cement because the flow rates and consequent pressures required often exceed the fracture pressures of the formations. The general rule on flow rates is the highest rate possible while not exceeding the fracture pressures in the wellbore.

Figure 10 - 12. Effect of velocity on displacement efficiency.

The above chart shows the correlation between velocity and displacement efficiency in a number of tests.

Flushes and Spacers Spacers and flushes do two things:

•

Aid in the displacement of the mud ahead of the cement

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P R I M A R Y

•

Displacement Aid

C E M E N T I N G

Separate the cement from the mud to prevent contamination

In order to assure adequate displacement the spacer or flush should do one of the following:

•

Fill at least 800 to 100 ft of annular space

•

Remain in contact with the formation for at least 10 minutes.

Those are rules of thumb and will vary depending on the type of mud and spacer or flush fluids used. The type of spacer or flush used makes a considerable difference in how much is required. Here are some examples. Flush/Cement Volumes

Displacement Efficiency

(bbl/bbl)

(%)

none

0/20

64

water

10/10

82

water

50/10

94

commercial flush

10/10

98

Type Flush

Again we should mention that these data are from full scale lab tests because it is not possible to determine displacement efficiency in an actual well. Separate Fluids

The spacer or flush also separates the cement from the mud to prevent contamination. In order to do so it must be compatible with both the mud and the cement. By compatible we mean both chemically and rheologically. So for separation a good spacer must have:

•

Non-reactive properties o Neither retard not accelerate the cement thickening time o Neither increase or decrease the cement strength

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o No effect on cement fluid loss o No effect on cement rheology

•

Easily adjustable rheology o Viscosity o density o etc.

Other Spacer Requirements

The spacers and flushes must also have additional properties that affect the producing formations as well as other borehole stability problems. They must also prevent the dynamic settling of solids

in the wellbore.

•

Non-damaging to formations o No invasion of producing zones o No reaction with formation clays o No change of rock wetting characteristics (especially with oil base mud)

•

Suspend solids

Centralization Centralization is important to aid in removal of mud from the wellbore and to get a good cement sheath all around the pipe. Failure to centralize the pipe can lead to poor mud removal, poor bonding and channels along side the pipe. The important questions about centralizers are how many and where? As always different companies have different procedures and requirements. If centralizers are to be of any use they must keep the casing away from the borehole wall. The question then is how far away from the borehole wall? The consensus of most cementing companies is currently about 70% of the theoretical standoff.

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Figure 10 - 13. Casing standoff.

The above figure illustrates the measure of standoff. We could write a formula as follows: ∆Sc = S=

dh − d p 2

∆S (100 ) ∆Sc

(10.3)

S min ≥ 70%

where ∆Sc = concentric clearance, in ∆S = actual clearance, in S = actual standoff, % S min = minimum standoff, % d h = diameter of hole, in d p = outside diameter of pipe, in

Of course all that is easy to say, but how is the clearance actually determined. The clearance is a function of the contact force of the casing towards the borehole wall and the force of the centralizer to keep it away from the borehole wall. Obviously the

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greater the contact force the greater the force required to centralize the casing. The contact force is a function of gravitational forces and hole geometry. It is easy to calculate for a straight hole slightly inclined, but no hole is straight. The calculations can be done manually (Juvkam-Wold & Wu, 1992), but that would be a tedious process and there are several software packages that calculate the contact force, the resistance force of the centralizers and the number and spacing of centralizers required. Most companies that make and sell centralizers have this software available to their customers. A few operating companies have their own software. Perhaps one of the reservations that some have about the software is that the company that is selling you the centralizers is also the company that is telling you how many you need. And if the centralizers are spaced properly it usually means more centralizers than many operators think they need. Despite the reservations, the software is good and the results should be considered as a guide which may be adjusted if some areas are not considered critical. But in the critical areas one should never run fewer than the recommended number. The other question in addition to how many and where is what kind? We discussed a number of different types in the previous chapter, the bow type, the double bow type, and the rigid type. As to efficient centralization the rigid type far exceeds the other two in performance. If the cost were the same there would be few reasons to run any but the integral rigid type centralizers with a spiral pattern to affect the annular flow pattern. That type gives 100% standoff where it is placed and it generally takes fewer of them to give 70% standoff in the rest of the pipe. Other than cost there is no real disadvantage. However, for some reason there are a lot of drillers and engineers who feel they must have a flexible centralizer to get the casing string in the hole. And there are cases where severe borehole stability problems may be present that requires some flexibility. That should be a rarity though and much of the prejudice against rigid centralizers is ill based. The real problem is that many drillers do not like to run any centralizers at all. They see it as some kind of waste of money. Back some 30 years ago the State of Texas passed regulations requiring that several thousand existing reserve pits be dried and backfilled over a period of years. In the process of bulldozing these pits thousands of centralizers were found buried in the old drilling mud. Instead of being run on the casing the drillers had thrown them in the reserve pits. While not so many are guilty of this now, there is still too much resistance to adequately centralize casing. Good centralization is a proven benefit to good primary cementing and it should not be slighted.

Pipe Movement Rotation is good. Reciprocation is good. When should you consider which? The key question is which one can we actually do in a given situation?

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In many near vertical wells the casing can be reciprocated or rotated with no problem. The more common practice is reciprocation. However, reciprocation can cause pressure surges that can cause lost circulation to occur. There are some operators that believe rotation is by far better and can quote some evidence to support their claim. Rotation of an entire casing string even in a vertical well is not without hazard. The torque to rotate casing is often high, and possibly too high for the couplings in the string. It is a matter of wellbore friction and the maximum makeup torque ratings of the couplings. The friction depends on how straight the hole is and what kind of fluid is in the hole. If the hole has an oil base mud in it then the rotating friction may be half that if the same hole contained water base mud. But even then one has to account for the change in friction once the annulus begins to be displaced by cement. So while rotation, may give better results for some, reciprocation is usually much easier to do safely. Liners are almost always rotated because reciprocation is not possible if a liner hanger is used. In deviated wells the torque required to rotate a string of casing almost always exceeds the maximum recommended makeup torque of the casing couplings. In those cases it is not possible to rotate the casing unless some type of high torque proprietary connection is used and that can be very expensive. About the only rotation used in these type wells is a liner that is short enough that the frictional torque does not exceed the coupling torque rating. While reciprocation can be done in many deviated wells, one has to be sure that the casing design is such that will allow the reciprocation in the presence of increased borehole friction. One of the serious considerations in reciprocating a casing string in a deviated well is that all casing below the point below an inclination angle of 70° must be pushed in the hole. It might be possible in some instances to pick the casing up, but if the fluids in the wellbore have changed from what was in the casing as it was being run, it may not be possible to set it back down to bottom. How long should pipe movement continue? Many stop too soon. Pipe movement should continue until the last plug is landed. Pipe movement is beneficial to good primary cementing, but there are problems that one should be aware of before initiating rotation or reciprocation.

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Gas Migration (To be added – see slides)

Multi-stage Cementing Multistage cementing is often necessary in cases where:

•

Large volumes of cement are required in the annulus

•

Lost circulation zones that require a cement column above

•

Prevent collapse of lower portion of casing due to hydrostatic head of long cement column in annulus

•

Protect casing or formations at remote intervals far above the top of the bottom slurry

•

Reduce some gas migration problems

Stage cementing requires additional tools in the casing, additional time, and additional cement. The stage tool itself is a tool that has a port to the annulus that is run closed. The tool allows passage of the bottom and top plugs for cementing the lower portion of the casing. Once the first stage of cement is in place and pressure is released to ascertain that the float equipment check valves arte holding the cement in place, the stage tool port is opened. Some tools open with a heavy device that is dropped into the casing and shears and shifts a sleeve that opens the port. (We cannot use a pumpdown plug to open the port because the casing is sealed at the shoe with the plugs from the first stage.) An alternative procedure is to run wire line tools or even pipe conveyed tools to open the port. Once the port is open the second stage cement is pumped followed buy a top plug that seats in the stage tool and closes the port. Once the port is closed pressure is usually released and there is no flow-back because the port is closed.

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Figure 10 - 14. Typical stage tool and operation sequence.

In the case where the stage job is being used to protect a lost circulation zone, some means of keeping the cement hydrostatic head off the lost circulation zone. Two procedures are common.

•

Open the stage tool and circulate drilling fluid (or lighter weight fluid) above the lost circulation zone to be sure there is no cement opposite or above the stage tool. Wait until the first stage sets across the lost circulation zone. Cement the second stage.

•

Run an external inflatable casing packer (ECP) in the casing string below the stage tool and above the lost circulation zone. After the first stage is complete, set the ECP. Open the stage tool and begin the second stage cementing. (The ECP must be set in a gauge hole to be effective.)

In the absence of lost circulation zones and if the second stage is at some distance above the top of the first stage cement column, it is often desirable to run some type of

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device like a cement basket below the stage tool to hold the slurry in place if it is more dense that the mud below it in the annulus. The success of these baskets is limited to holes that are relatively close to gauge. Problems with Stage Cementing

There are a number of problems that can arise from stage cementing, and many operators avoid stage cementing when possible because of the consequences. Here are a few of the

possibilities.

•

Stage tool will not open

•

Stage tool opens, but cement in annulus at or above the tool has already set

•

Stage tool will not close

•

Stage tool closes partially and leaks slowly

In the first instance it may be possible to run wire line or pipe conveyed tools to open the stage tool. If the first stage slurry top is above the stage tool it may open, but pumping cement would only result in fracturing the formations near the stage tool which is the second problem in the list. If cement has set above the stage tool it will not be possible to do the second stage through the stage tool because the cement will pump into some formation rather than circulate up the hole. The top of the cement could be located above the stage tool with a temperature survey or bond log. Once located a decision to perforate the casing above the top of the cement and circulate the second stage through the perforation might be considered. If such a decision is made it leads to an equivalent situation as in the last two items on the list above. If the stage tool will not close or will not seal totally when it does close, there will be a permanent hole in the casing. Unfortunately this does happen on occasion. Typically the procedure is to hold the cement in place until it sets then drill out the stage tool. The casing is then pressure tested with both positive and negative pressure tests. If there is no leak operations resume normally. If the port does leak then most operators try a squeeze. At deeper depths these squeezes are often successful. At shallower depths (where most stage tools are run) the results are not very good – especially if the casing must sustain higher pressures as is the case in many production strings. If squeezing is not successful (at least two attempts should be tried) then the only other resort is some mechanical means like a casing patch or scab liner is necessary if pressure integrity is essential. The number one consideration in determining whether or not to use a stage tool is evaluating the possible consequences of the stage tool failing to close or seal.

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Additional Liner Considerations Cementing liners is one of the more difficult of the primary cementing jobs and requires some additional comments. There are potential problems with the liner and its associated equipment as well as with the cementing operation. The liner is generally run on the bottom of drill pipe which must be released from the liner before cementing begins and then retrieved from the hole after the cement is in place. Here are some comments and tips on how to run and cement a liner successfully.

•

The latch-in liner plugs will not function if there is any debris in the liner. o Drift the liner as it is picked up onto the rig floor – there have been countless examples of someone placing a wood strip from the pipe rack in a joint and it stuck inside the joint with mud o Before installing the liner hangar and running tool, be sure that the liner is full of drilling fluid – it is often surprising how much small debris can float to the surface from a clean liner

•

Verify that the liner stage of the latch-in plug is properly placed in the hanger assembly.

•

If the liner will not go to bottom there is a dilemma. If it is close to bottom the tally should be checked immediately to be sure it is not already on bottom. The tendency is to attempt to circulate it to wash it to bottom. There is a problem if it is a rotary rig where circulation is accomplished with a kelly. If the liner starts to wash down it will be necessary to pick it back up to remove the kelly. If it sticks with the kelly below the rotary table then there is a difficult operation involved to remove it. Always use drill pipe with some type of flexible connection on top to try to circulate and or rotate. Another point is that in many areas where differential sticking is a problem circulation can cause a liner to stick immediately. In such an area it is always advisable to pull the liner and clean the hole with drill pipe and then run the liner. A liner stuck off bottom is useless and an impediment to further operations.

•

Once the liner is in place it is hung and the running tool is released. The drill pipe is picked up enough to ascertain that the weight has been released, but not far enough to pull the seals out of the mandrel. The drill pipe is then set back down on the liner. There is always a possibility that the liner hanger could slip during this process and the liner actually fall to bottom. For that reason it is never a good idea to set a liner so far from bottom so that the hanger will be below the casing shoe should it fall. One can always perforate the bottom of a liner sitting on bottom to cement it, but it is almost never

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possible to do anything if the top of the hanger is below the bottom of the casing. In no case should one ever wait until after the cement is in place to release the running tool. If it does not release then the drill pipe becomes a tieback string and it has a smaller ID than the liner.

•

The liner lap should be a minimum of 300 ft if possible. The longer the lap the better the chance of getting a good cement job in the lap. An absolute minimum lap is 150 ft. Centralizers are essential in the lap. When a liner is cemented the most contaminated cement in the entire slurry is the cement that comes back up into the liner lap, so the longer the lap the better the chance of getting enough good cement in the lap to affect a good bond.

•

Circulate the hole thoroughly before pumping the cement. At least circulate bottoms up. Better is to circulate at least 1.5 times the hole volume. Do not stop the pumps before starting the cement displacement. It should be a continuous operation, because once the mud stops moving in the liner annulus it is very hard to get it moving again without channeling.

•

Liner latch-in plugs are notorious for failing to work properly. The drill pipe plug latches into the liner plug and they both seat and latch into the float collar. There should be a pressure increase when the drill pipe plug shears the liner plug out of its container and of course another increase when they contact the float collar. Too many times the sequence does not work. So it is essential that the displacements be carefully calculated and observed. If there is no indication that the drill pipe plug contacted the liner wiper plug then there is a good chance that there will be no seal when they contact the float collar and the pumping should stop immediately when the calculated displacement has been reached. It is much more preferable to drill additional cement out of the liner than to over displace the cement waiting for the plugs to seat then have to squeeze the liner at the producing interval.

•

If at all possible, rotate the liner while the cementing is being displaced. Rotation is exceedingly important for a good primary cement job with a liner.

•

The most hazardous part of the liner cementing operation is immediately after the cement is in place. Pick up the seals out of the liner and begin reverse circulating immediately. Everything should be rigged up to do this so that there is nothing to do but close the annular BOP and switch two valves. Never try to pull several joints out of the hole before reversing and never, ever try to pump out through the annulus. The problem is that the cement that comes up into the casing through the liner lap has been exposed to the open hole. It is contaminated to some extent, and it has been exposed to formations where it may have lost a considerable amount of filtrate. There is no way to predict the properties and performance of this cement – it may be retarded or it may be accelerated. In any case we have to get it out of the hole

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as quickly and as safely as possible. The only safe way is reverse circulation. If it should set up in the drill pipe it will cost a few joints of drill pipe. If it sets up in the annulus then the drill pipe becomes a permanent part of the well. Those who believe that if they rotate the drill pipe or move it while circulating out through the annulus are only going to believe in that method for some short time until they discover that cement can set even when the pipe is moving. It has happened and will continue to happen as long as there are those foolish enough to try to circulate cement up the annulus. (The exception is coiled tubing where reverse circulation is not possible, but those cases are not comparable to this one because specific design factors are in place that are not possible in a conventional liner cementing operation.)

•

The tack and squeeze method is sometimes used with drilling liners. It is a method in which a small amount of cement is pumped around the lower portion of the liner, then the liner lap is squeezed later. This is an acceptable practice for many companies. The biggest problem with the method is that a squeeze job on a liner lap is historically unsuccessful on the first attempt. So there can be considerable cost to squeezing, drilling out, testing, re-squeezing, etc.

Primary Cementing Calculations The calculations for primary cementing are fairly simple. They use values from tables for capacity of pipe and hole, capacity of annular spaces, and displacement of pipe. These are values that can be calculated easily without the use of tables as long as we have the dimensions of the hole and the pipe. The other types of calculations, reviewed in Chapter 1, are simple hydrostatic pressure calculations requiring only knowledge of the fluid densities and depths.

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Figure 10 - 15. Cementing table handbooks.

Some of the more important formulas will be listed here with some example calculations. Cross sectional area of pipe:

Ai = π ri 2 = Ao = π ro2 =

π 4

π

4

di2 ≈ 0.7854 di2 d o2 ≈ 0.7854 d o2

At = π ( ro2 − ri 2 ) =

π

(d 4

2 o

+ d i2 ) ≈ 0.7854 ( d o2 + di2 )

where

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(10.4)

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C E M E N T I N G

Ai = cross-sectional area inside tube, in 2 Ao = cross-sectional area outside (entire) tube, in 2 At = cross-sectional area of tube, in 2 ro = outside radius of tube, in ri = inside radius of tube, in d o = outside diameter of tube, in di = inside diameter of tube, in

Buoyancy Factor:

fb = 1 −

ρm 65.43

(10.5)

where

fb = buoyancy factor, dimensionless

ρ m = density of mud or cement, ppg Weight of pipe in fluid (vertical well):

P = fb w L

(10.6)

where

P = weight, lb fb = buoyancy factor w = nominal pipe weight, lb/ft L = length of pipe, ft

Spacer/Flush Contact Time

tc =

V Q

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(10.7)

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where tc = contact time (min) Q = displacement rate (bbl/min) V = volume of spacer (bbl) Volume of Cement

Assuming we have determined the length of a column of cement needed to cover all zones that we require then we want to calculate the total volume of cement slurry required.

Vc = Lc v

(10.8)

where Vc = volume of cement slurry (bbl) Lc = length of cement column (ft) v = volume/height annulus (bbl/ft) Displacement Volume

The amount of mud that must be pumped to displace the wiper plug to the float collar is given by: n

Vd = ∑ Li vi

(10.9)

i =1

where Vd = displacement volume (bbl) Li = length of section i (ft) vi = volume/height of casing in section i (bbl/ft) i = section number of casing n = total sections of casing fromn surface to top of float collar Displacement Pressure

The internal pressure at the top of the casing when the wiper plug reaches bottom is:

 psi / ft  pd =  Lc ρc + Ls ρ s + ( L f − Lc − Ls ) ρ m − L f ρ d   0.052  lb / gal  

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(10.10)

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where

pd = final displacement pressure (psi) L f = depth to float collar (ft) Lc = length of cement column in annulus (ft) Ls = length of spacer column in annulus (ft)

ρc = ρs = ρm = ρd =

denstity of cement (lb/gal) density of spacer (lb/gal) density of mud in annulus (lb/gal) density of displacement fluid (lb/gal)

Sample Calculations Suppose we are going to set intermediate casing in a well with the following data. Total depth:

12,000 ft

Hole size:

10 ¾”

Casing Size:

7 5/8” (7000 ft of 26.4 lb/ft & 5000 ft of 29.7 lb/ft)

Required cement column:

3000 ft

Cement Density:

16.5 ppg

Mud Density:

13.2 ppg

Spacer/flush Density:

14.0 ppg

Displacement fluid:

13.2 ppg (mud)

Displacement Rate:

10 bbl/min

Required spacer/flush contact time: Float Collar Depth:

5 minutes

11920 ft

Calculate Amount of Spacer:

V = tc Q = 5(10) = 50 bbl

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Calculate Amount of Cement Slurry:

Vc = 3000 (.0558 ) = 167.4 bbl Calculate Displacement Volume:

Vd = 7000 ( 0.0471) + 5000 ( 0.0459 ) = 559 bbl Calculate Final Displacement Pressure:

We need the length of the spacer column which we can calculate by rearranging Equation (10.8):

Ls =

50 = 896 ft .0558

Then pd = [3000(16.5) + 896(14.0) + (11920 − 3000 − 896)13.2 − 11920(13.2] 0.052 = 552 psi Comments on Sample Calculations:

We did not take into account any hole enlargement or excess cement in these calculations. In actual practice we would have used hole volumes calculated from logs to determine the volume of cement required. We could average those volumes over a distance to get an average capacity of the annulus or average hole diameter for other calculations. In any event the calculations for column length of the cement and spacer will be only an approximation. Then so too would be the final displacement pressure. In the displacement calculation we assumed the float collar was 80 feet from the bottom of the hole, but we did not take into account that some of the cement would be below the float rather than all above it as in our calculation. Since the length of the cement column and spacer column are only known approximately this assumption should be of little consequence. Of course it is easy to do the additional calculations if one is inclined to do so.

References Juvkam-Wold, H.C. and Wu, Jiang, (1992, Dec), Casing deflection and centralizer spacing calculations, SPE Drilling Engineering, p. 268—264.

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11 Chapter

Special Cementing Operations Squeezes, Plugs, P&A

T

here are a number of special operations using cement in addition to the primary cementing that we have just covered in the last chapter. The most common of those special applications are squeezing, setting cement plugs, and P&A.. We will cover those operations in this chapter.

Squeezing Definition

is the process of applying hydraulic pressure to force or squeeze a cement slurry into the desired perforations, fractures, channels, or voids and force filtrate water from the slurry to create a solid mass which will harden to provide the desired seal. Squeeze Cementing

While we would like to say that we can set out here a set of procedures and practices that will fully prepare you to do any squeeze operation anywhere in the world, that is simply not possible. Of all the operations done with cement, squeezing is the most dependent on experience and locale. Squeeze cementing always has been and still is as much an art as it is a science. Why Squeeze?

There are a number of reasons for squeezing a well. Here are some of the most common reasons. •

Shut off unwanted water or gas production

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•

Abandonment of non-productive zone

•

Seal off troublesome zone during drilling

•

Injection profile modification in injection wells

•

Repair mud or gas channeling on primary cement job

•

Isolate a formation prior to perforating

•

Insufficient top of cement on primary job

•

Repair casing leak

Those are just some of most common of the possible applications. While there are a number of reasons to squeeze, there is also a question as to when to squeeze. Do we squeeze before we perforate for production or do we wait until after production is initiated and the problems become manifest? Of course that is all a matter of why we are squeezing in the first place, but often the question arises before the well is perforated for production. I some cases a bond log may indicate a channel between the planned production interval and some water or gas zone. In some areas we have experience that shows we often get unwanted water or gas production even when the bond log looks good. There are two schools of thought on this. Determining Whether to Squeeze

One school of thought is that squeezes will be performed above and below all potential producing zones and at water contacts before the well is perforated for production. This is an ultraconservative approach. It costs a lot of time money on the initial completion and many would say it is unnecessary. The advantages are that it is usually very successful, it never requires squeezing directly into the production perforations and risking damage of the producing formation, it greatly reduces the cost and mechanics of recompletion in additional zones since all the squeezes are done initially. Most would consider this an extreme approach, but a number of companies used to proscribe this method and they had good success with it. Another approach is to perforate and produce the well before squeezing even where bond logs show possible channels. The thinking in this approach is that all channels are full of drilling mud which may not flow except at very high pressure differentials. In other words there is a good chance flow in the channel may not take place and hence a squeeze is unnecessary. Also it is considered impossible to get cement into the channel before the mud can flow out of it, and if the mud will not flow then it will not be possible to get cement into the channel. This approach is obviously more realistic than the former, but it has some obvious disadvantages. If a squeeze does become necessary it usually requires a well kill and a workover rig. It also requires that the

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cement be pumped into the producing formation perforations. Squeezing a larger interval of producing perforations is seldom successful in one stage. The cement is drilled out after the first stage, the perforations tested for flow, and then the interval must be squeezed again if there is any flow. The risk of formation damage is high and often stimulation is required to remedy the damage. Despite its disadvantages a number of large operating companies subscribe to this approach. Myths of Squeezing

For many years people thought that if one perforated a small interval and squeezed it with cement that a horizontal fracture would be formed and filled with cement. There would be a “pancake barrier of cement formed around the casing at that point. We learned that is not true except in some unusual stress regimes and in some very shallow applications. In most areas the three principal insitu stress components are such that the fracture will be vertical because it will always be perpendicular to the least of the three principal insitu stress components which is usually horizontal. Another misconception is that the cement goes up the hole, down the hole, into a water sand before an oil sand, into a shale, etc. If there is no cement or solidified mud in the annulus and we have good rock property data and insitu stress data we can reasonably predict where the cement will go such as into a sand before a shale, and generally upward instead of down. In a real situation we do not have such data nor a knowledge of the condition of the annulus so the truth is we do not have any idea where the cement will go. Back in the 1950’s, Stanolind (which later became Pan American Petroleum, then Amoco, then BP) ran some tracer tests in South Louisiana and concluded that we have no idea where the cement will go. The best that we hope for is that all of the perforations are filled with cement and we fill any voids in the cement sheath at the perforations with new cement. We mentioned formation damage as a possible consequence of squeezing in actual producing perforations. The damage, if it occurs is , are from the filtrate not the cement particles entering the formation pore spaces and reducing the permeability. Cement particles are on average about 50 µm (microns) and cannot enter formations with permeability less that about 2 Darcies.

Types of Squeezes

We may classify squeezes by a number of criteria. We will discuss these types with their advantages and disadvantages. Then we will look at some typical procedures. Here are some of the common classification points: •

Final pressure

•

Volume of cement

•

Injection method

•

Placement method

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The final pressure of the squeeze is one of the things we often specify when we plan a squeeze. One school of thought recommends a high pressure final squeeze pressure and the opposite recommends a low final squeeze pressure. High Pressure Squeeze Pressure

Proponents of the high pressure squeeze suggest that the final squeeze pressure should exceed the initial breakdown (or fracture pressure) of the formation. The thinking is that this gives a high pressure integrity greater than that of the formation itself. Of course that is not true, the cement has not begun to set and achieve its compressive strength when these pressures are achieved. In truth the cement forms a solid pressure barrier mostly inside the casing and its pressure capacity has no relation to the strength in the perforations or outside the casing. The only real advantage to a high pressure squeeze might be in a case where some of the perforations are partially plugged and the higher pressures might cause additional perforations to open after some have been squeezed. Of course this only works where the plugged perforations are above those that become squeezed off earlier in the process. The high pressure squeeze is seldom used today. Low Pressure Squeeze

The proponents of the low pressure squeeze argue that there is no reason to attempt high pressures because it does not accomplish anything that a low pressure squeeze will not accomplish. Normally a low pressure squeeze requires a final pressure at some fraction of the initial fracture pressure, typically 75% of the initial fracture pressure. Most squeezes currently are low pressure squeezes. Volume of Cement

The general consensus now is that a relatively low volume of cement is adequate for most squeezes. The amount of cement should be enough to fill the perforations, the annulus near the perforation, and no more. In past times a lot of cement was used in squeezes (150 to 250 sacks) on the theory that more is better. Someone once said they could squeeze a well with only one gallon of cement if they could get it into the right place. That is likely a true statement and the only problem is getting that small volume into the right place. So now, we use only what is needed to fill the voids plus a little additional to compensate for contamination during the pumping operations. Injection Methods

There are basically two methods employed for injecting or pumping the cement. •

Continuous method (“walking squeeze”)

•

Hesitation method

Proponents of the continuous method say that this is by far the best method of obtaining a squeeze because the pressure builds up while the cement is flowing and the cement gets into places it would not if the pumps are periodically stopped. They

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believe the hesitation method often allows cement to set or bridge in some places and that the squeeze is not uniform. Proponents of the hesitation method, say that there is no proof that the continuous method gives better results, the hesitation method takes less time, and there are situations where a continuous method may not achieve a squeeze. There is good argument for both sides but the truth is this. There is no proof that one method is better than the other, the hesitation method is generally faster, and there are places in the world where the amount of cement required to obtain a continuous squeeze would number into the tens of thousands of sacks. Most operators use the hesitation squeeze method. Placement Method

There are basically three methods used to place the cement for a squeeze. •

Braden head squeeze

•

Retrievable squeeze tool

•

Drillable cement retainer

The Braden head squeeze (or bullhead squeeze) is accomplished by pumping the cement down the production tubing, coiled tubing, or even casing directly into the perforations without benefit of a cementing packer or circulation. The advantages of this method are: •

No special tools required

•

Quick

•

Often used in emergency situations where it is not possible to kill the well or where the squeeze is necessary to kill the well safely

There are a number of disadvantages to the Braden head squeeze. •

Production tubing or casing experiences full squeeze pressure

•

All fluids ahead of cement go into perforations

•

No way to pre-treat perforations prior to squeeze (except with CT)

•

Must leave cement in place to drill out later (except with CT)

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The retrievable squeeze packer is the most popular method of placing cement for a squeeze. It is a specially designed packer for well testing and squeezing. It is mechanically set (usually rotation and set down weight) and may be set, moved, and reset many times on one trip. The advantages of the retrievable squeeze tool are: •

Designed specifically for squeeze cementing

•

Isolates casing from squeeze pressures

•

Can cement multiple times on one trip in hole

•

Can also be used for testing

It does have some serious disadvantages: •

Poor choice and possibly hazardous for cementing lost circulation or low pressure zones

•

Can be accidentally cemented in hole

•

Takes about 7 days to mill out if accidentally cemented in hole

The possibility of cementing one of these tools in the hole is quite real and the consequences are very costly. However, if proper procedures are strictly followed there is no reason to ever cement one in the hole. In almost all cases where one of these tools has been cemented in a well, it because of human error, ignorance, or carelessness. The drillable cement retainer is a one-time cementing packer made of drillable metals and more recently composite materials. It has advantages. •

It keeps hydrostatic pressure from above off squeeze once the squeeze is completed

•

Easy to drill out

•

Additional safety over retrievable tool in cases where casing above the tool may leak or possible collapse

The disadvantages are: •

One time use

•

Cannot be moved and reset once it is set

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•

C E M E N T I N G

O P E R A T I O N S

If squeeze is not accomplished on first try then it may have to be drilled out before a second attempt is made

The best applications for the drillable retainer are those cases where it is necessary to squeeze a lost circulation zone or low pressure zone that will not sustain the hydrostatic pressure of a full column of workover fluid and an actual squeeze pressure cannot be achieved. In those cases the cement is displaced down the work string through the retainer and into the formation, but before the top of the cement reaches the retainer the work string is pulled out of the retainer, the valve in the retainer closes and the hydrostatic pressure is removed from the formation so the cement is not flushed out of the perforations. The cement left in the work string is reversed out easily and the formulation is isolated from the circulating pressure.

Squeeze Procedures There are many variations on squeeze procedures but we will list a couple of generic procedures that are safe in most cases. Retrievable Squeeze Tool Procedure

The one thing to remember about using a squeeze tool is that there is always the chance of cementing the tool in the hole which will lead to a very expensive milling operation and possibly even junking the hole. Always err on the side of caution and you will never cement one of these tools in the hole. Remember this motto: When in doubt, reverse out!

Don’t ever forget that one thing. •

Set tool at least 60 feet above the perforations, 120 feet is better

•

Breakdown the formation and establish injection into the formation.

•

Open the bypass on the tool and pump the cement down the work string to about 5 bbl above the tool.

•

Close the bypass.

•

Apply pressure to the annulus (~2000 psi depending on application)

•

Monitor the pressure gage on the annulus throughout the job. This is the most important gage reading in the squeeze process because it can keep you from cementing the tool in the hole.

•

Pump a predetermined volume of cement into the perforations.

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•

Begin the hesitation process.

•

Experience in the area dictates the hesitation times. Typically one or two minutes of hesitation followed by two or three barrels of pumping.

•

Once final squeeze pressure is achieved release pressure to be sure the cement does not flow back. If it flows back, the squeeze has not been achieved. Try pressuring the squeeze again and hold the pressure longer before releasing it.

•

Release the pressure on the annulus.

•

Release the squeeze tool and begin reverse circulation immediately. Do not try to reverse circulate through the tool bypass; release the packer and reverse circulate around the bottom of the packer.

•

Monitor the returns at the shaker until the cement is all out of the mud and another 20 to 50 bbl of clean mud has been circulated to the surface.

•

If another squeeze is planned, pull the tool at least 1000 ft above the squeeze and monitor the well for flow back.

This is a safe procedure for almost all cases. There are some things that can go wrong. Emphasis should be placed again on the annulus pressure gage. It is the most important indicator during any squeeze job, always monitor this gage closely. The pressure on that gage should never increase. If it increases even 1 psi it means that there is a leak in the work string or packer. It only takes about 100 ml of cement to stick a retrievable squeeze tool in a well! If the pressure on the annulus gage increases by any amount at all, stop and reverse out immediately! Now, in a normal squeeze operation below 10,000 feet in most areas the pressure on the annulus gage will actually decrease slowly during the squeeze operation. This is because the cement and displacement fluid are cooling the fluid in the annulus. Where that is the norm, and if the annulus pressure does not actually decrease during the squeeze, but remains steady, it is an indication that there is a leak. Any leak, no matter how small, should be cause for aborting the squeeze and reversing out. Remember, if in doubt reverse out. A second, and even a third attempt at a squeeze is still far cheaper than milling out a retrievable squeeze tool.

Squeeze Calculations The calculations for a squeeze are nothing more than calculating the volume of cement, spacer, and displacement. One should also calculate the pressure required to reverse circulate and be sure that the pressure required is less than the squeeze pressure.

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Cement Plugs In the life of almost every well there will be need to set one or more cement plugs. There are many reasons for setting cement plugs in wells. •

Plugs for sidetracking

•

Profile modification

•

Zone abandonment

•

Well abandonment

Setting plugs is a relatively easy process, yet it is often difficult to achieve a good plug. The main reasons for not getting a good plug are usually •

Inadequate cement volume

•

Poor mud removal

•

Not allowing for adequate setting time

In order to obtain a good cement plug it should be a minimum of 150 feet and longer is better. The reason seems to be a matter of contamination. For that reason it is often desirable to pump a wiper plug both ahead and behind the plug to prevent contamination from the mud. As far as mud removal is concerned the mud in the hole should be in good condition and everything that applies to mud displacement in primary cementing applies here. But since the cement volumes are so much less than in primary cementing it becomes more critical in setting plugs. One aid to mud removal for plugs is one or more lengths of pipe on bottom to which are welded strips of wall scratchers. The pipe is rotated as the plug is displaced and the scratchers break up the mud around the outside of the pipe so that it is more easily removed by the cement. On many rigs these special joints are kept on location for the specific purpose of setting cement plugs in open hole when ever it might become necessary. There are also tools now available that pump down the drill pipe and form a barrier below the pipe to keep the plug from falling down hole or mixing with the mud once it is placed.

Setting a Balanced Plug The calculations for setting a balanced plug are simple and straightforward. The easiest way to understand to procedure is to visualize it as a U-tube where one leg is the annulus and the other is the drill pipe.

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Volume of Cement

The volume of cement required to set a specific length plug is calculated using the capacity of the pipe and the capacity of the annulus, and knowing that a balanced plug will be the same length inside the pipe and annulus.

Vc = Lp ( vdp + va )

(11.1)

where

Vc = volume of cement for plug (bbl) L p = length of plug (ft) vdp = volume/height capacity of drill pipe (bbl/ft) va = volume/height capacity of the annulus (bbl/ft)

Displacement Volume

The volume of the displacement fluid required to spot the plug is calculated by subtracting the volume of cement in the drill pipe when the plug is balanced from the total volume of the drill pipe.

Vd = ( D p − Lp ) vdp where

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(11.2)

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O P E R A T I O N S

Vd = volume of displacement fluid (bbl) D p = depth of bottom of plug (ft) L p = length of plug (ft) vdp = volume/height capacity of drill pipe (bbl/ft)

Typically when a balanced cement plug is set it is not fully displaced before pulling the pipe out of the plug. Often the displacement is stopped ½ bbl or so before the plug is completely displaced to leave the column of cement unbalanced. The cement density is greater than that of the drilling mud so if the column of cement in the drill pipe is slightly higher than that in the annulus it will cause the plug to fall out of the drill pipe as it is withdrawn. This is a practical matter to prevent contamination of the plug. Of course it depends on the density of the cement being greater than that of the mud; if it is not then it should not be done in that manner. In addition to the standard method of displacement it is also possible to use both a top and bottom wiper plug in the displacement procedure. This often helps to prevent cement contamination and assure a better quality plug as a result. The calculations are the same if wiper plugs are used.

Plug and Abandonment Plugging and abandonment (P&A) operations are often considered to be simply a matter of setting a few balanced plugs as required by regulations and little more. Quite the reverse is true. P&A operations require careful consideration and execution. There are many instances around the world where so called “plugged and abandoned” wells have started to leak, flow, and even blowout years after abandonment and resulting in pollution and sometimes hazard to human life. In other cases cross flows between reservoirs have occurred as well as pollution of fresh water sources. Unfortunately in many cases the original operating company no longer exists and it falls upon the current lease operator or the state to remedy the problem. The point to P&A operations is not to set a required number of plugs, but to assure that the well can never cause problems in the future.

P&A Requirements

P&A requirements are usually set and enforced by some regulatory agency that has jurisdiction in an area. It is that agency’s mandate to assure that once a well is plugged and abandoned that it never poses a hazard or problem in the future. Typically the

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agency will require cement plugs and or mechanical bridge plugs to isolate open producing perforations, isolate formations where casing is cut and removed, and plug the casing near the surface and at the surface. Below is an illustration of typical P&A requirements.

Figure 11 - 1. A minimum P&A plan.

Remember, regulatory agencies specify the minimum P&A requirements, not the optimum requirements.

What would constitute the best P&A procedure? Without a doubt the most secure P&A procedure is to fill all casing and uncemented annular spaces with cement from bottom all the way to the surface. That is not practical; though it certainly is possible. What everyone should consider however, is not the minimum requirements, but what is adequate and reliable. Too often cement plugs are too short and/or contaminated to the point where gas, oil, or saltwater can migrate through them within days, hours, or even minutes. Some agencies require 100 ft cement plugs, but the truth is that a 100 ft plug is too short to assure a good plug and true isolation. If one is relying totally on cement plugs for abandonment they should be a minimum of 200 ft in length and longer would be even better. Mechanical bridge plugs are inexpensive and provide considerable additional safety to the use of cement plugs. Here is a much better alternative to the minimum procedure illustrated in Figure 11 - 1.

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Figure 11 - 2. A better P&A plan.

The last illustration adds the safety of a cement retainer to squeeze the production perforations and bridge plugs to give additional sealing capability. There is no one correct way to P&A a well. One should always keep in mind that cement plugs alone are subject to failure. An ideal P&A procedure must

•

Insure against future flow of the well to the surface

•

Prevent contamination of fresh water formations

•

Prevent cross flow between formations

And finally the procedure should be adequate for how long? 100 years? 1000 years? Forever? Something to think about.

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12 Chapter

Conversion Factors & Tables Units and Measure In this manual we use typical oilfield units.

Unfortunately the units of measure in the oilfield are not standardized. Most of the world uses some system of the units that evolved from the oilfields of North America in the late nineteenth and early twentieth centuries. In this manual we refer to that system as typical oilfield units or just oilfield units. Even that system is not consistent because typically some units vary even within the borders of the USA. For example in Texas mud density is typically expressed in pounds per gallon whereas in California it is typically specified in pounds per cubic foot. In some oilfields of the world various sorts of metric systems are in place, but they are seldom a true SI system of units. For example pressure is often measured in bars instead of Pascals. Perhaps most confusing of all are those systems which borrow units from both the SI and the typical oilfield system. It is not unusual to find places where well depth is measured in meters and pressure in psi. It makes sense to those using it, and it is just a fact of life in the oilfield. There should be little dispute that the SI system is superior to what we now use, but things are not likely to change any time soon.

A few of the basic measures we will use in this course are listed in the table below. Others will be mentioned when we need them.

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Quantity

Measure

Oilfield Units

SI Units

length

L

feet (ft)

meter (m)

force

F

Pound force (lbf)

Newton (N)

mass

F L/t2

Pound mass (lbm)

Kilogram (kg)

density

F /(L t2)

Pound mass/gal (ppg)

Kilogram/cubic meter (kg/m3)

pressure

F/L2

Pound force/square inch (psi)

Pascal (Pa) (equivalent to 1 Newton/square meter)

Conversion Factors Length Conversion Method: A × B = C

or

A

C÷B= A

B

C

ft

0.304 8 *

m

in

2.54 ×10-2 *

m

yard

0.914 4 *

m

mile, statute, U.S.

1.609 344 *

km

* Conversion factor is exact.

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C O N V E R S I O N

F A C T O R S

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Area Conversion Method: A × B = C

C÷B= A

or

A

B

C

in2

6.541 6 ×10-4 *

m2

ft2

9.290 304 ×10-2 *

m2

mile2

2.589 988

km2

acre (43560 ft2)

4.046 86 ×103

m2

acre (43560 ft2)

4.046 86 ×10-1

ha (10 000 m2)

* Conversion factor is exact.

Volume Conversion Method: A × B = C

C÷B= A

or

A

B

C

gal( liquid, U.S. )

3.785 411 784 ×10-3 *

m3

ft3

2.831 684 6592 ×10-2 *

m3

bbl (42 gal)

0.158 987 3

m3

* Conversion factor is exact.

Mass Conversion Method: A × B = C

C÷B= A

or

A

B

C

lbm

4.535 923 7 ×10-1 *

kg

slug

14.593 902 9

kg

* Conversion factor is exact.

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C A S I N G

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Force Conversion Method: A × B = C

C÷B= A

or

A

B

C

lbf

4.448 221 615 260 5 *

N

kgf

9.806 65 *

N

* Conversion factor is exact.

Energy and torque Conversion Method: A × B = C

C÷B= A

or

A

B

C

lbf · ft (torque)

1.355 817 9

N·m

lbf · ft (energy)

1.355 817 9

J (joule)

Pressure Conversion Method: A × B = C

C÷B= A

or

A

B

C

lbf/inch2 (psi)

6.894 757

kPa (1000 N/m2)

atmosphere

101.325 *

kPa (1000 N/m2)

bar

100 *

kPa (1000 N/m2)

* Conversion factor is exact

Density Conversion Method: A × B = C

A

or

B

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C÷B= A

C

C O N V E R S I O N

A

F A C T O R S

B

C

lbm/gal (ppg)

119.826 4

kg/m3

lbm/gal

0.119 826 4

g/cm3 or kg/l

lbm/ft3

16.018 463

kg/m3

lbm/gal (ppg)

7.480 5

lbm/ft3

Specific Gravity Conversion Method: A × B = C

or

A

C÷B= A

B

C

or 998‡

kg/m3

specific gravity

1000†

specific gravity

8.345† or 8.33‡

specific gravity

62.43† or 62.32‡ lbm/ft3

lbm/gal (ppg)

† assumes water density is 1.0 g/cm3 at 4ºC ‡ assumes water density is 0.998 g/cm at 20ºC

Density / Gradient Conversion Method: A × B = C

or

A

C÷B= A

B

C

lbm/gal (ppg)

0.052 †

psi/ft

lbm/gal (ppg)

1.175 †

kPa/m

lbm/ft3

6.944 ×10-3 †

psi/ft

lbm/ft3

0.157 1 †

kPa/m

kg/m3

4.335 ×10-4 †

psi/ft

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T A B L E S

C A S I N G

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C E M E N T I N G

A

B

C

kg/m3

9.806 65 ×10-3 †

kPa/m

g/cm3

0.433 5 †

psi/ft

g/cm3

9.806 65 †

kPa/m

* Conversion factor is exact. † Conversions from density to gradient assume a standard gravitational acceleration of 32.174 ft/s2 or 9.80665 m/s2 and that the fluid densities are determined from a mass type balance.

Gradient Conversion Method: A × B = C

or

A

C÷B= A

B

C

psi/ft

22.62

kPa/m

psi/ft

0.226 2

bar/m

bar/m

100 *

kPa/m

* Conversion factor is exact.

Weight and Mass per Unit Length Conversion Method: A × B = C

or

A

C÷B= A

B

C

lbf/ft

14.593 903

N/m

lbm/ft

1.488 164

kg/m

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C O N V E R S I O N

F A C T O R S

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T A B L E S

Temperature D

F = 18 . DC + 32

D

R = D F + 459.67 ≈ D F + 460

F − 32 18 . D D K = C + 273.15 ≈ DC + 273 D

C=

D

Buoyancy Factors for Steel Calculation Method: Buoyancy Factor: FB = 1 −

ρf ρs

Density of Fluid

Density of Steel

ρf

ρs

lbm/gal (ppg)

65.43 ppg

lbm/ft3

489 lbm/ft3

kg/m3

7530 kg/m3

g/cm3

7.53 g/cm3

Assuming density of 7.53 g/cm3 for steel (Note: This is an average value for API carbon steels. Martensitic chromium steels have a slightly lower densities.

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Casing Performance Tables & Cementing Tables Because of copyright laws it is not possible to include API published tables in this manual. There are tables for casing dimensions and performance properties as well as cementing tables on the CD included in this course. Please refer to the CD for any information required for the exercises.

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13 Chapter

Class Project & Exercises

T

he class project for this course consists of planning a casing program and cementing program for a hypothetical well that uses data from an actual oilfield somewhere in the world. The actual project is on a CD furnished to the participant and is in MS Excel format. The specifics of each project vary depending on the location of the class so as to use representative data for that part of the world. The participant will be required to do the following: •

Plot pore pressure and frac gradient curves and determine casing setting depths

•

Determine casing sizes

•

Make preliminary casing design for o Surface casing o Intermediate casing o Production casing

•

Refine casing design for combined loading

•

Determine amounts of cement required

•

Determine contact time and volume of spacer/flushes

•

Calculate displacement volumes and displacement pressures

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C A S I N G

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Calculate volume of cement and displacement for a balanced plug

Additional example exercises may be added to illustrate certain important points.

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C L A S S

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P R O J E C T

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E X E R C I S E S

C A S I N G

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C E M E N T I N G

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C L A S S

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P R O J E C T

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E X E R C I S E S

C A S I N G

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C E M E N T I N G

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