Casing and Cement Manual

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(1)OGCI Dr. Ted G. Byrom. CASING& CEMENTING.

(2) A Course for OGCI/PetroSkills.  Ted G. Byrom 2003.

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(4) 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). i.

(5) 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. ii.

(6) Table of Contents CHAPTE R. Course Introduction. CHAPTE R. CHAPTE R. CHAPTE R. 5-1. CHAPTE R. Running & Landing Casing. CHAPTE R. 7-1. 13 - 1. 14. Slide Handouts (Black & White). iii. 12 - 1. 13. Exercises. 7. 11 - 1. 12. Conversion Factors. 6–1. 10 - 1. 11. Special Cementing Operations. 6. Final Casing Design. CHAPTE R. CHAPTE R. 4-1. 9-1. 10. Primary Cementing. 5. Preliminary Casing Design. CHAPTE R. CHAPTE R. 3-1. 8-1. 9. Cementing Equipment. 2-1. 4. Casing Load Determination. CHAPTE R. CHAPTE R. 3. Casing Size Selection. 8. Cement Types, Additives & Testing. 1-1. 2. Casing Point Selection. CHAPTE R. CHAPTE R. 1.

(7) C O U R S E. I N T R O D U C T I O N. 1. Chapter. Course Introduction Who is this course for and what is its purpose?. T. 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.. 1-1.

(8) C A S I N G. &. C E M E N T I N G. 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.. 1-2.

(9) C O U R S E. I N T R O D U C T I O N. 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.. 1-3.

(10) C A S I N G. &. C E M E N T I N G. 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. 1-4.

(11) C O U R S E. I N T R O D U C T I O N. 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. 1-5.

(12) C A S I N G. &. C E M E N T I N G. 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. •. Provide support for the casing. •. 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.. 1-6.

(13) C O U R S E. I N T R O D U C T I O N. 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:. 1-7.

(14) C A S I N G. &. C E M E N T I N G. •. 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.. 1-8.

(15) C O U R S E. 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.. 1-9.

(16) C A S I N G. &. C E M E N T I N G. 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.. 1 - 10.

(17) C O U R S E. I N T R O D U C T I O N.  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.. 1 - 11.

(18) C A S I N G. &. C E M E N T I N G. 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.. 1 - 12.

(19) C O U R S E. I N T R O D U C T I O N.  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.. 1 - 13.

(20) C A S I N G. &. C E M E N T I N G. 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.). 1 - 14.

(21) C A S I N G. P O I N T. S E L E C T I O N. 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.. 2-1.

(22) C A S I N G. &. C E M E N T I N G. 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. 2-2.

(23) C A S I N G. P O I N T. S E L E C T I O N. 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. 2-3.

(24) C A S I N G. &. C E M E N T I N G. 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. 2-4.

(25) C A S I N G. P O I N T. S E L E C T I O N. 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.. 2-5.

(26) C A S I N G. &. C E M E N T I N G. 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.. 2-6. 20.

(27) C A S I N G. P O I N T. S E L E C T I O N. 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. 10. 11. 12. 13. 14. 15. 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. 2-7.

(28) C A S I N G. &. C E M E N T I N G. 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.. 2-8.

(29) C A S I N G. P O I N T. S E L E C T I O N. 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.. 2-9.

(30) C A S I N G. &. C E M E N T I N G. 2 - 10.

(31) C A S I N G. S I Z E. S E L E C T I O N. 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. 3-1.

(32) C A S I N G. &. C E M E N T I N G. 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.. 3-2.

(33) C A S I N G. S I Z E. S E L E C T I O N. 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.. 3-3.

(34) C A S I N G. &. C E M E N T I N G. 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:. 3-4.

(35) C A S I N G. •. 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.. 3-5.

(36) C A S I N G. &. C E M E N T I N G. 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. 3-6.

(37) C A S I N G. S I Z E. S E L E C T I O N. 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.. 3-7.

(38) C A S I N G. &. C E M E N T I N G. 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.. 3-8.

(39) C A S I N G. S I Z E. S E L E C T I O N. •. 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.. 3-9.


(41) C A S I N G. L O A D. D E T E R M I N A T I O N. 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. 4-1.

(42) C A S I N G. &. C E M E N T I N G. 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. 4-2.

(43) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4-3.

(44) C A S I N G. &. C E M E N T I N G. 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.. 4-4.

(45) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4-5.

(46) C A S I N G. &. C E M E N T I N G. 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. 4-6.

(47) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4-7.

(48) C A S I N G. &. C E M E N T I N G. 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. 4-8. (4.1).

(49) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4-9.

(50) C A S I N G. &. C E M E N T I N G. 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:. 4 - 10.

(51) C A S I N G. L O A D. D E T E R M I N A T I O N. 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. 4 - 11.

(52) C A S I N G. &. C E M E N T I N G. 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.. 4 - 12.

(53) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4 - 13.

(54) C A S I N G. &. C E M E N T I N G. 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. 4 - 14.

(55) C A S I N G. L O A D. D E T E R M I N A T I O N. 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.. 4 - 15.


(57) C A S I N G. D E S I G N. –. P R E L I M I N A R Y. 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.. 5-1.

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