Chapter 02 Casing and Tubing
Table of Contents Introduction 2-4 Topic Areas 2-4 Learning Objectives 2-4 Unit A: Casing and Tubing Uses 2-4 Unit A Quiz 2-5 Unit B: Typical Casing Strings 2-5 Conductor Casing 2-5 Surface Casing 2-6 Protective Casing (Intermediate Casing) 2-6 Production Casing 2-7 Liners 2-7 Tubing String 2-9 Unit B Quiz 2-9 Unit C: Casing and Tubing Threads 2-10 Casing Threads 2-10 Tubing Threads 2-11 Thread Selection 2-11 Make-Up Torque Selection 2-12 Thread Care 2-12 Unit C Quiz 2-13 Answers to Unit Quizzes 2-14
Introduction For well operations to take place, lengths of tubular goods are joined together and run down-hole. Then, surface and downhole equipment can be connected so that drilling and cementing operations can proceed. Due to the nature of our work, personnel must be familiar with basic drilling operations. An understanding of the factors involved in making up joints of casing, tubing, and drill pipe will help you work more effectively with customers as well as better understand the ways in which equipment is used with these tubular goods. Topic Areas This section presents the following topics: A. Casing and Tubing Uses B. Couplings and Threads C. Casing and Tubing Threads Learning Objectives Upon completion of this section, you should be familiar with the Purpose and use of tubular goods Types of threads and how to select and care for them Unit A: Casing and Tubing Uses Casing design involves three major steps: 1. Determining the sizes and lengths of casing strings you will run 2. Calculating the type and size of loading conditions 3. Choosing the weights and grades of casing that will not fail when exposed to these loads This section will discuss the basics for developing a casing program. This information should help you specify design criteria to a third party. An ideal casing string design allows you to control common and uncommon well conditions safely and economically. Specifically, the casing program should be appropriate for the geological environment and allow safe well production. Although it would be easy to choose a single casing weight and grade to satisfy most well conditions, you might go through unnecessary expenses depending on the complexity of the well. A casing designer s main job is to select the weight and grades of casing that will be just strong enough to withstand the loading conditions of the well. Since casing is made from steel pipe, cost generally increases with weight, but tensile strength and grade change also affect prices. When selecting casing sizes and final weights and grades, consider the availability of tubular goods. You may not be able to purchase certain types of casing in your area. In extreme cases, you may have to base the casing design on what is available; the main goal is to simply make sure the specific string is suitable for the well. To plan a well, you must first choose a casing/bit system. When choosing this system, you should consider Past experience with the area Geological factors Abnormal pressure Troublesome zones (such as salt) and sloughing shale Lost circulation zones Remember, the casing size and weight chosen will determine casing inside diameter (ID). This, in turn affects maximum bit diameter and limits the size of the next casing string. 2-4
The basic loading conditions on a casing or tubing string that must be considered are collapse, burst, and tension. All pipe designs must carry a safety factor that considers the uncertainty of the magnitude of these forces. The Red Book ( Cementing Tables) lists collapse and burst (internal yield) limitations for common pipe sizes and grades. In addition, the Redbook provides limitations on the tensile force (parallel to the axis of the casing string) that is allowed for different pipe sizes, grades, and coupling types. Tensile force on the casing also has an effect upon the collapse and burst values. You may also encounter compression and bending forces, which often occur in non-vertical holes. The degree to which these forces are exerted will also affect the burst and collapse resistance of the pipe. Another secondary condition is load change during cementing due to the placement of fluids of differing densities. API bulletins, as well as the Redbook, contain minimum burst, collapse, and tension casing values. To use API s monogram, casing manufactures must use minimum standards set by the API. Non-API casing is often manufactured using the same standards, but for critical wells, be sure that the material meets all API standards. Unit A Quiz Fill in the blanks with one or more words to check your progress in Unit A. 1. The casing program should be appropriate for the and allow safe well production. 2. The casing size and weight chosen will determine casing. 3. The basic loading conditions on a casing or tubing string that must be considered are _,, and. Unit B: Typical Casing Strings Conductor Casing In this unit, we will describe the purpose and use of tubular goods used in a typical well. The conductor casing (Fig. 2.1) prevents washouts of poorly consolidated surface soil and rock while drilling the surface hole. Should the surface erode, or become unstable, drilling rig stability is compromised. Conductor casing normally has a large diameter (16 to 30 in.). It is either set with a spud rig or driven to the point of refusal (150 to 250 blows/ft) with a drive or vibration hammer. Setting depths is normally 90 to 150 ft and rarely deeper that 300 ft. Conductor casing allows you to install a diverter system, and provides a flow line high enough to allow mud return to steel mud pits while drilling the surface hole. A blowout preventer (BOP) may sit on the conductor casing above a large-diameter (± 10 in.) vent pipe. Figure 2.1 - Conductor Casing 2-5
Figure 2.2 - Surface Casing (Set inside the conductor casing) If shallow hydrocarbons are found, and the well flows, you can close the BOP and divert flow away from the rig. If such a shallow flow is encountered, the well should not be completely shut in. It is likely, in most cases, that insufficient pipe is set to prevent fluids or gas from breaking around the outside of the conductor casing to surface. In other words, the diverter system protects the rig and personnel until the problem can be corrected. Surface Casing The surface casing string (Fig. 2.2) is designed to protect formations near the surface from deeper drilling conditions. The surface casing string has several important functions. First, it protects shallow freshwater sands from contamination by drilling fluids and produced fluids. Surface casing is cemented back to the surface so freshwater zones will have a cement sheath and a steel casing to protect them. Depth and cement requirements are mandated by regulatory agencies. Surface casing allows you to drill to the next casing seat. BOPs are nippled up on the surface casing; the well can be controlled if abnormal conditions cause an inflow of formation fluid to the wellbore. The surface casing is designed so that the casing can be totally shut in using Figure 2.3 - Protective Casing (Set inside the surface casing and extending from total depth to surface) surface equipment. When drilling into abnormal pressure, casing seats must be able to withstand increasing mud weights. Casing should be set deep enough to prevent broaching to the surface. Finally, surface casing supports all casing strings run in the well. Protective Casing (Intermediate Casing) A protective (intermediate) casing string (Fig. 2.3) provides hole integrity during later drilling operations. This intermediate string protects formations behind it from high mud weights. It also prevents drilling fluid contamination during underbalanced drilling. Specifically, it performs the functions covered in the following paragraphs. A protective casing string allows you to control the well when encountering subsurface pressure higher than the mud weight. If this takes place, and fluid (or gas) enters the wellbore, drilling fluid will be forced from the wellbore at surface. The petroleum industry refers to this as a "kick". In order to stop the formation-to-wellbore fluid flow, the surface control equipment must be closed or partially choked off. A positive surface pressure will result. The protective casing is designed to withstand this 2-6
pressure. Since it covers low fracture gradient formations, it maintains wellbore integrity during wellkicking. Protective casing also allows you to control the well if it is swabbed in, or if gas purges all drilling fluids form the well. One major advantage of protective casing is that it allows underbalanced drilling of deeper formations and isolates troublesome ones. It allows you to isolate sloughing shales, abnormally pressured saltwater flows, and formations that contaminate the mud to prevent interference during drilling operations. Production Casing The production casing string (oil string) (Fig. 2.4) is set and cemented through the producing zone and acts as a backup for the tubing string during production. It is the primary string responsible for isolating the desired production interval(s). This string must be able to withstand full wellhead shut-in pressure if the tubing leaks or fails. After cementing the production casing, holes (perforations) are made in the casing (and cement sheath) which allows fluid to enter the wellbore. This is most often accomplished using explosive charges run on wireline units provided by the logging service line. When replacing the tubing or downhole tools during well maintenance operations, you must make sure the production casing will allow you to kill the well (offset bottom hole pressure with fluid hydrostatic head), circulate workover fluids, and conduct some pressure testing. Casing in general and production casing/liners specifically, allow for a wellbore with consistent known internal diameter. This is critical when utilizing special downhole tools that require these conditions. These tools are commonly inserted into the casing during completion and production operations in order to obtain wellbore isolation at desired points. Figure 2.4 - Production casing (Last full string of casing, set from total depth to surface). Liners In the past, it was common to have several strings of casing in a deep well. All these strings extended from the wellhead to different depths. However, another method was devised to accommodate varying well conditions. This time- and money-saving method involves the hanging of a casing string from the bottom of a cemented casing string. These hanging casing strings are called liners and they are used in almost every deep well completion. Four types of liners will be described briefly to begin this section: Drilling (or protective) liners Production liners Stub liners In some areas, conditions may allow you to use small diameter lines; in these instances, production casing is set for well fluid production. In other words, these are tubingless completions there is no backup string. Scab liners 2-7
Drilling Liners A drilling liner (Fig. 2.5) is a string of casing that is hung from another casing of a larger diameter which has already been cemented downhole. It is used to case off open holes so that deeper drilling may be performed. A drilling liner serves to: help control water or gas production isolate lost-circulation zones isolate high-pressure zones. like any other completion string. It provides isolation and support when casing has been set above the production zone. A drilling liner is subject to the same design conditions as protective casing, and it provides the same protections. Multiple drilling liners may be required. As with all liners, the top of the casing does not extend to the surface, but is hung off at some point in the previous casing string. Figure 2.6 Production liner (cemented in place but hangs from the bottom of the intermediate casing rather than extending to the surface. Stub Liners A stub liner (also called a tie-back liner) is usually a short string of casing that provides an upward extension for a drilling liner. It is run when casing above the drilling liner has been damaged in some way (by corrosion, etc.) a liner is leaking Figure 2.5 - Protective or Drilling liner (Set inside protective casing at current hole total depth, but does not extend to surface) Production Liners A production liner is a string of casing that is hung from a drilling liner or casing in the producing formation (Fig. 2.6). This type of liner is then cemented and perforated greater resistance is needed for other reasons (abnormal pressure, etc.). Scab Liners An unusual type of liner, a scab liner (Fig. 2.7) is usually not cemented after it has been run downhole and, therefore, it is retrievable. It has a packoff on both ends and is used under the same conditions as a stub liner. Stub and scab liners can be set with part of their weight on the liner below or hung uphole on existing casing. 2-8
Stub and scab liners can be set with part of their weight on the liner below or hung uphole on existing casing. Tubing String The tubing string gives produced fluids a flow path to the surface and allows you to inject for secondary recovery, storage, and disposal. By increasing the size of this string, you can reduce friction pressure and increase production or injection rates. However, by increasing this diameter, you must increase all other casing sizes in the well. In other words, you must make sure the increased production/injection ratio justifies the higher cost. Figure 2.7 - Scab Liner Unit B Quiz Fill in the blanks with one or more words to check your progress in Unit B. 1. The first string in the well may be _ or _ casing. If the top soil is erodible, then _ casing will be the first type run. 2. The conductor prevents under the rig. 3. Sometimes, conductor casing is set by simply _ it into the ground. However, if the soil is too hard, then the hole will be _ for it. 4. casing supports all casing strings run in the well. 5. Protective casing is also known as _ casing. 6. A hanging casing string is called a. 2-9
Unit C: Casing and Tubing Threads Nearly all tubular goods used in completing a well come in joints that vary from 30 to 40 ft in length. Joints have threads machined into their ends which serve to hold the string together. Different types of tubular goods have threads which differ in size, shape, and in the way they seal and make up to hold pressure. Cut on a taper, the threaded pin end and box end screw together (Fig. 2.8). As the makeup torque increases, the pin threads (which have less metal than the box threads) begin to conform to the box. Continued makeup causes additional yielding until the pin end is wedged tightly into the box. In this way, joints of tubular goods are sealed together. Tensile loads and internal pressures cannot easily force the separation of the joined segments. Casing Threads Tubing Threads Thread Selection Make-Up Torque selection Thread Care. Casing Threads Casing threads appear on both ends on the outside of a joint of casing. Lengths of casing are made up by using a collar (Fig. 2.9). A joint screws into one end of the collar, while the next joint screws into the other end. Most casing threads are not upset, that is flared, as are many tubing threads. Figure 2.9 Casing Joints and Collar Figure 2.8 Pin End and Box End Since 1928, threads have been regulated by the American Petroleum Institute (API). There are five important areas of thread types, selection, and care. The most common threads (Fig. 2.10) in use today for casing connections are: 8 round (8rd) thread has 8 rounded threads per inch Extreme line (Xline) thread has square threads* Buttress thread has square threads. 2-10
Figure 2.10 Comparison of thread types. Tubing Threads The tubing or production string provides a flow path to the surface for produced fluids. Tubing is not cemented into place as is casing. Therefore, the threads on tubing joints and collars (Fig. 2.11) are designed to withstand great tensile loads and internal pressures. Like casing joints, tubing has threads on both ends. Two types of tubing threads (Fig. 2.12) are External Upset (EU) used in most wells for added strength Non-Upset used in shallower wells and on the surface. Figure 2.11 Tubing Joints and Collar Figure 2.12 External and non-upset tubing threads. Thread Selection When working with the customer's casing, tubing or drill pipe, it s up to personnel to be sure that service equipment fits the tubulars. Selection of the proper pin size (changeover from the casing/tubing to discharge piping) can sometimes be difficult for the beginner. In selecting the proper pin for casing, tubing or drill pipe, the following information is needed: What type of thread is on the string? What is the outside diameter (OD) of the pipe on the string? (For drill pipe you would need to know the OD of the tool joint or coupling). The type of thread varies depending upon which type of pipe the customer has in the hole. The OD tells you what size pin you need to connect to the customer s pipe. For example, if you know the customer has 5 ½ inch 8rd casing, your equipment should also have an OD of 5 ½ inches and 8 round threads per inch. On location, check the specifications, which are stenciled on the side of the joints. If the joints are not marked, 2-11
find the chart for casing and your thread size. The first column of this chart is labeled Size: Outside Diameter. Find the column for 5 ½ in. OD casing. Columns 2 and 3 are labeled Nominal Weight, Threads and Coupling lb per ft and Grade. Find the row for the casing you re working with (15.5 lb/ft and Grade J-55). Columns 7, 8 and 9 are labeled Long Thread, and Optimum, Minimum, and Maximum torque levels. For the casing you re working with, these levels are 2170, 1630, 2710 ft-lb, respectively. Thus, proper torque for this casing is between 1630 and 2710 ft-lb, and 2170 ft-lb is the best torque to apply. Figure 2.13- Caliper and ruler you ll need a caliper tool (Fig. 2.13) and ruler to identify pin dimensions. Make - Up Torque Selection To avoid stripping threads by applying too much torque and to avoid loose connections by applying too little torque, it is necessary to be aware of optimum torque levels for the type of tubular goods with which you re working. Charts, published by the API, are available to help you. As an example, let s assume that you want to make up a float collar on the customer s casing. The casing has this stamp: 5 ½ in. casing, 15.5 lb/ft, J-55, grade, 8rd, long thread. To use the make-up torque charts, you need to know all the information provided by this stamp. The stamp tells you that the casing has: An outside diameter (OD) of 5 ½ inches 15.5 lb/ft nominal weight, threads and coupling J-55 grade 8 round threads per inch long thread. Using this information, you can look up the optimum, minimum, and maximum torque to be applied when making connections with this casing. To do this, Thread Care When working with both surfaces and down-hole equipment, you should be careful to protect the threads. Because of the tremendous pressure this equipment is designed to withstand, taking care of threads could mean the prevention of a serious accident and injury. Before taking a piece of equipment to location, you should Carefully remove the thread protectors. Inspect the threads for damage (sometimes diesel fuel or a solvent will be needed to remove grease to inspect for damage). Look for galling, cracking, or cross-threading. If you re not sure, check with your supervisor. Put on safety glasses and clean the threads using a wire brush. If the threads will be chemically welded (with Weld-A), bentonite gel will be needed along with a wire brush to remove all grease from the threads on the equipment as well as on the casing. Check to see that all welds have met established API codes. After a piece of equipment has been inspected, equal care should be taken in its use: Never allow threads to hit metal or hard objects. Never drop or throw equipment. 2-12
Be aware of proper torque when making up a piece of equipment. Place wrenches close to the threads but not on them. Remember, if you have a question about the condition of a thread, ask a supervisor. One blown out pin could not only cause an accident, but could also leave you with a workstring full of cement. After you ve finished using the equipment, re-inspect it for damage. Be sure to clean the thread protectors and carefully re-attach them to the equipment. Size Outside Diameter in. Nominal Weight, Threads and Coupling lb per ft Grade Short Thread Torque, ft-lb Long Thread Optimum Minimum Maximum Optimum Minimum Maximum 5 ½ 14.00 H-40 1300 980 1630 14.00 15.50 17.00 J-55 J-55 J-55 1720 2020 2290 1290 1520 1720 2150 2530 2860 2170 2470 1630 1850 2710 3090 14.00 15.50 17.00 6 5/8 20.00 K-55 K-55 K-55 H-40 1890 2220 2520 1840 1420 1670 1890 1380 2360 2780 3150 2390 2720 1790 2040 2990 3400 20.00 24.00 J-55 J-55 2450 3140 1840 2360 3060 3930 2660 3400 2000 2550 3330 4250 Table 2.1 20.00 24.00 K-55 K-55 2670 3420 2000 2570 3340 4280 2900 3720 2180 2790 3630 4650 Unit C Quiz Fill in the blanks with one or more words to check your progress in Unit C. 1. Threads have been regulated by the _ for over 50 years. 2. As a connection is screwed together, the pin threads begin to to the box threads. Eventually, the pin end is tightly into the box, which produces a against internal pressure. 3. Both the and types of casing threads are square-shaped. 4. The two main questions you need to answer when choosing the proper pin size for casing or tubing are: What is the type of on the string, and what is the of the pipe on the string? 5. When inspecting threads, you should look for _,, and _. 2-13
Answers to Unit Quizzes Items from Unit A Quiz Refer to Page 1. Geological environment 2. Inside diameter (ID) 3. Collapse, burst, tension 2-4 2-4 2-5 Items from Unit B Quiz 1. Conductor, surface, conductor 2. Washout (or erosion) 3. Driven, drilled 4. Surface 5. Intermediate 6. Liner 2-5,6 2-5 2-5 2-6 2-6 2-8 Items from Unit C Quiz 1. API 2. Conform, wedged, seal 3. Buttress, extreme line 4. Thread, outside diameter 5. Galling, cracking, cross-threading 2-10 2-10 2-10 2-11 2-12 2-14
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