# Chapter 17 — Introduction to Casing and Cementing ## Learning Objectives By the end of this chapter, students should be able to: 1. Explain the engineering functions that casing must perform and why it is the critical deliverable of the drilling process. 2. Identify the six standard casing string types and describe the purpose of each. 3. Distinguish between tubing and casing and explain when tubing is required. 4. Describe a typical casing program for a land well and an offshore well, and explain why offshore programs require more strings. 5. Read a casing specification and identify OD, nominal weight, grade, and connection type. 6. List the API casing grades in order of yield strength and identify which grades are designated for sour service. 7. Describe the difference between nominal ID, drift ID, and wall thickness, and explain why each matters. --- ## 17.1 Casing as the Deliverable The drilling engineer's job is not simply to reach total depth — it is to deliver a usable wellbore. A hole drilled through rock and left unlined is nearly worthless: it will slough, collapse, allow pressure zones to communicate, contaminate freshwater, and provide no structure for the completion equipment that must eventually be run. The wellbore becomes an asset only when it is cased and cemented. ```{figure} ../figures/ch17/casing_deliverable.png :name: fig-casing-deliverable :width: 80% Casing is the finished, deliverable product. Without it, the well cannot produce. ``` This perspective has a practical implication: the bit must get the bit there for the casing to count. A string that hangs up 500 ft above bottom because the wellbore is too tight, the mud is wrong, or the string is too heavy does not deliver the well. Every aspect of the casing design, OD selection, grade selection, connection type, centralizer placement, must account for the fact that the string must first get to depth before it can do anything useful. ```{figure} ../figures/ch17/casing_must_get_there.png :name: fig-casing-must-get-there :width: 80% The casing string must reach its setting depth to function. This constraint influences every aspect of casing design. ``` Cementing is equally essential: cementing fills the annular space between the casing and the formation with a solid, low-permeability material that creates the zonal isolation the wellbore needs. Without adequate cement, fluids can migrate between zones behind the casing and bypass the barriers that the casing itself creates. A well with poor cement bond quality may require costly remediation or, in the worst case, may never achieve acceptable isolation and must be abandoned. This chapter introduces the casing and cementing systems that protect the wellbore. Chapters 18 and 19 cover the quantitative design of casing strings (setting depth selection and load calculations), and Chapter 20 covers cementing in detail. --- ## 17.2 Functions of Casing Casing simultaneously performs several engineering functions. No single function can be sacrificed: the design must satisfy all of them at once. ```{figure} ../figures/ch17/casing_functions_1.png :name: fig-casing-functions-1 :width: 80% Primary functions of a casing string. ``` ```{figure} ../figures/ch17/casing_functions_2.png :name: fig-casing-functions-2 :width: 80% Additional casing functions, including structural support and wellbore integrity over the life of the well. ``` **Wellbore stability.** Open-hole sections are vulnerable to collapse, sloughing, and washout. Once cased, that section of hole is mechanically stabilized by the steel casing and surrounded by cement that bonds to the formation. **Freshwater protection.** Surface casing must be set deep enough to protect all potable water aquifers. This is the most heavily regulated aspect of well construction in most jurisdictions. The cement behind surface casing usually must reach surface to seal off the annulus completely and to demonstrate a proper cementing job. **Zonal isolation.** Pressure zones at different depths must be isolated from each other and from the wellbore. Without isolation, oil, gas, or saline formation water could migrate between zones or to the surface. Cement provides this isolation behind the casing. **Pressure containment.** Each casing string is a pressure vessel. It must contain any internal pressure (formation fluid influx, injection pressure, production pressure) and resist any external pressure (formation pressure acting to collapse the pipe). The steel casing carries these loads; the cement transfers them to the formation. **Structural integrity.** Casing provides the structural wellbore for the life of the well, including cementing, perforating, completion, stimulation, production, and eventually plugging and abandonment. It must withstand all loads it will experience throughout this lifetime, not just during initial installation. **Support for subsurface equipment.** The wellhead, BOP stack, tubing hangers, and all wellbore equipment ultimately hang off or connect to the surface casing and conductor. Each inner string hangs from the previous outer string through the wellhead stack. --- ## 17.3 Tubing and Its Functions **Tubing** is the innermost pipe in the wellbore. Unlike casing, which is a permanent structural element, tubing is a production conduit, it is the pipe through which hydrocarbons flow from the formation to the surface. Tubing is run after the well is completed and can be pulled and replaced if it wears out, corrodes, leaks, or if the completion needs to be changed. ```{figure} ../figures/ch17/tubing_functions_1.png :name: fig-tubing-functions-1 :width: 80% Tubing functions in production operations. ``` ```{figure} ../figures/ch17/tubing_functions_2.png :name: fig-tubing-functions-2 :width: 80% Tubing provides a separate flow conduit that protects production casing from corrosion and high-velocity erosion. ``` The primary functions of tubing are: **Flow conduit.** Hydrocarbons (and injected fluids for injection wells) travel through the tubing, not through the casing. This protects the casing from flow-induced corrosion and erosion. **Pressure isolation.** A packer is set between the tubing and the production casing above the productive interval. The packer prevents produced fluid from contacting the casing annulus, which protects the casing from corrosion and allows pressure monitoring. **Artificial lift.** Gas lift valves, electric submersible pump (ESP) motor and pump assemblies, and sucker rods for beam pumping are all run in the tubing or in the casing/tubing annulus. The tubing string provides the mechanical structure for these systems. Not all wells use tubing. Some low-pressure, low-volume wells are produced directly through the production casing (casing flow). However, any well with significant reservoir pressure, corrosive fluids, or artificial lift will require tubing. --- ## 17.4 Casing String Types A well typically requires multiple concentric casing strings, each set to a different depth. The strings are named for their function in the well construction sequence. Moving from the outermost to the innermost: ```{figure} ../figures/ch17/casing_program_overview.png :name: fig-casing-program-overview :width: 80% Overview of the bottoms-up casing design process showing how strings are nested from outermost to innermost. ``` ### 17.4.1 Drive Pipe / Conductor Casing The **conductor** (sometimes called **drive pipe**) is the outermost string. It can be literally driven into the ground with a pile driver — hence "drive pipe," and not cemented, or drilled into the ground with a smaller spudding rig. It is typically set to 100–300 ft depth on land, and to 300–500 ft (or deeper in weak formations) offshore. ```{figure} ../figures/ch17/conductor_casing.png :name: fig-conductor-casing :width: 80% Conductor casing (drive pipe): the outermost string, set in the shallowest section of the well. ``` The conductor's primary functions are: - Providing structural support for the wellhead and BOP stack - Preventing shallow formation collapse around the well - Establishing the first seal against shallow groundwater Conductor ODs are typically 18-36 in (inches) onshore and can be as large as 36–42 in for offshore wells where a template or subsea structure must be supported. ### 17.4.2 Surface Casing **Surface casing** is set below the conductor, typically to 1,000–5,000 ft depending on regulatory requirements and local geology. It is the most regulated casing string because its primary function is freshwater protection. ```{figure} ../figures/ch17/surface_casing.png :name: fig-surface-casing :width: 80% Surface casing: set to protect freshwater aquifers and provide the anchor for the BOP stack. ``` Surface casing must: - Be set below all potable water-bearing formations (this depth is often specified by regulation) - Be fully cemented from shoe to surface (or to within a specified distance of surface) - Provide a competent anchor for the BOP stack (BOPs are always installed on the surface casing) - Be strong enough to survive a leak-off test that demonstrates the integrity of the formation below the shoe The leak-off test (LOT) is always conducted at the surface casing shoe before drilling ahead. The result establishes the maximum allowable annular surface pressure (MAASP) for the next open-hole section below the shoe. If the shoe is weak, the drilling window below is limited. ### 17.4.3 Intermediate Casing **Intermediate casing** is set between the surface casing and the production string. Some wells will have a single intermediate casing, others may have multiple intermediate casing strings. It is the "problem solver" in the casing program: its depth is frequently determined by whatever formation problem is encountered before the production interval. ```{figure} ../figures/ch17/intermediate_casing.png :name: fig-intermediate-casing :width: 80% Intermediate casing isolates problem formations and extends the drilling window for the next string below. ``` Common reasons for setting intermediate casing: - Isolating an abnormally pressured zone (e.g., overpressured sandstone) that would require a mud weight increase which might fracture a shallower formation - Isolating a lost circulation zone or fractured formation - Isolating mechanically unstable shale (e.g., reactive shales that swell and cause breakouts in water-based mud) - Sealing off a depleted reservoir that could not withstand the mud weight needed to drill deeper - Extending the drilling window by isolating the weakest zone above the next objective A complex well may require multiple intermediate strings. Each one "erases" a constraint that was limiting the drilling operation below the previous shoe. ### 17.4.4 Production Casing **Production casing** is the last full-length string run in most wells. It is set through the productive formation and must: - Withstand the full reservoir pressure during production, shut-in, and injection operations - Survive perforation and hydraulic fracturing loads - Provide a platform for the completion (packer, tubing hanger, subsurface safety valve) - Serve as the primary pressure barrier for the life of the well ```{figure} ../figures/ch17/production_casing.png :name: fig-production-casing :width: 80% Production casing runs through the reservoir and is designed for the full range of production and completion loads. ``` Production casing is typically the most demanding string to design because it must handle simultaneous burst (formation pressure pushing out), collapse (mud or cement squeeze pushing in), and tension (weight of the string) loads under the highest pressure conditions the well will experience. ### 17.4.5 Liners and Tie-backs A **liner** is a casing string that does not extend back to surface. Instead, it is hung from a **liner hanger** set inside the bottom of the previous casing string, with a short overlap of 200–500 ft. The liner extends from the overlap depth to the new total depth. ```{figure} ../figures/ch17/drilling_liner.png :name: fig-drilling-liner :width: 80% A drilling liner extends from a hanger inside the previous casing string to the new total depth, saving the steel cost of a full string. ``` Liners are used when: - The well is deep and the cost of a full string (from TD back to surface) is prohibitive - The wellbore trajectory makes running a full string impractical - The operator needs an intermediate point of isolation but does not want to run full steel to surface The **critical limitation** of a liner: it does not provide a direct pressure barrier to the wellhead. The liner hanger must be trusted to maintain seal integrity. For wells that need full pressure containment from TD to surface, a **tie-back string** is required. ### 17.4.6 Production Liner A **production liner** is a liner run through the productive formation, analogous to production casing but without extending to surface. It is commonly used in long-reach horizontal wells where running full production casing back to surface would create excessive drag and buckling forces. ### 17.4.7 Tie-Back String A **tie-back** is a string run from the liner hanger back to the wellhead, converting the liner into the equivalent of a full-length string. The tie-back "lands" in the liner hanger and extends upward through all intermediate strings to surface. ```{figure} ../figures/ch17/tieback.png :name: fig-tieback :width: 80% A tie-back string extends from the liner hanger to the wellhead, providing a full-length pressure barrier from total depth to surface. ``` Tie-backs are used when: 1. A liner was run originally but the well later requires a full-length pressure barrier (e.g., for high-pressure production or injection) 2. The liner hanger does not have adequate pressure rating for the completion 3. The well requires a secondary barrier to the wellhead for regulatory or safety purposes Of note, a tie-back is not cemented in place, so there is not additional barriers in place. The annular space between the tie-back and the previous casing is an open conduit, and can be a pathway for an influx to reach the surface. --- ## 17.5 Typical Casing Programs ### 17.5.1 Land Well (West Texas Example) A typical West Texas well drilled to moderate depth with relatively predictable pore pressures might use three to four strings: ```{figure} ../figures/ch17/w_texas_program.png :name: fig-w-texas-program :width: 80% Typical casing program for a West Texas land well. The relatively stable pore pressure gradient allows a simpler program than offshore. ``` A representative design might be: - **Conductor:** 20 in, driven to 50 ft - **Surface casing:** 13⅜ in, cemented to 2,500 ft (below all freshwater) - **Intermediate casing:** 9⅝ in, cemented to 10,000 ft, frequently set at the kick-off point (KOP) - **Production casing:** 7 in, cemented to 14,000 ft TD ### 17.5.2 Offshore Well Offshore wells typically require more strings than comparable land wells. The reasons are both geological and regulatory: ```{figure} ../figures/ch17/offshore_program.png :name: fig-offshore-program :width: 80% Offshore casing programs require more strings due to narrower drilling windows, greater geological uncertainty, and more stringent regulatory requirements. ``` - **Narrow drilling window.** The fracture gradient at the seafloor is close to the hydrostatic pressure of seawater, leaving almost no margin between pore pressure and fracture gradient in the shallow section. Strings must be set frequently to manage the window. - **Regulatory requirements.** Deepwater regulators (e.g., BSEE in the US) require additional strings and deeper setting depths for freshwater protection and BOP placement. - **Geological uncertainty.** Deepwater provinces are often frontier areas with limited nearby well control, so additional contingency strings are designed to handle unexpected pressure surprises. - **Well depth and complexity.** Deepwater wells routinely exceed 20,000–25,000 ft MD (with 5,000–7,000 ft of water), requiring more strings simply because of the range of pressures encountered. A deepwater well might use five to seven strings: 36 in drive pipe, 26 in, 20 in, 16 in, 13⅜ in, 9⅝ in, and 7 in production casing — sometimes with a 5½ in liner at total depth. --- ## 17.6 Casing Properties Every casing string is specified by four properties: outside diameter, nominal weight (pounds per foot), grade, and connection type. These four properties completely define a casing joint's mechanical capabilities and clearance constraints. ```{figure} ../figures/ch17/casing_properties.png :name: fig-casing-properties :width: 80% Casing is fully specified by its outside diameter, nominal weight, grade, and connection type. ``` ### 17.6.1 Outside Diameter (OD) The **outside diameter** is the nominal OD of the pipe body, measured in inches. Common production-string and liner ODs include: 4½, 5, 5½, 6⅝, 7, 7⅝, 9⅝, 10¾, 11¾, 13⅜, 16, 18⅝, 20, 24, 30, and 36 in. Larger ODs are used for conductors and outer strings; smaller ODs for production strings and liners. The OD constrains what bit size can be run through the casing. If a 7 in casing has an ID of 6.276 in, the next bit can be no larger than about 6 in to pass through it. This is the **bit/casing compatibility** constraint that drives hole-size selection from the inside out. ### 17.6.2 Nominal Weight The **nominal weight** (in $lb/ft$) is the approximate weight of one foot of casing, including the connection. The word "nominal" is important: it is a label, not an exact number. The actual weight per foot can differ slightly from the nominal value. Nominal weight is a function of wall thickness and OD: heavier weight per foot means thicker walls. Thicker walls mean greater burst and collapse resistance but also greater weight, which increases tension loads and may complicate running in highly deviated wells. The **inside diameter (ID)** is not standardized across weights of the same OD — it depends on wall thickness. Always calculate or look up the actual ID for the specific weight being evaluated, based on the grade, OD and weight per foot. For steel casing, the following relation may be used: $$W [lb/ft] = 2.67 (OD [in]^2 - ID [in]^2)$$ ### 17.6.3 Nominal ID vs. Drift ID Two different IDs appear in casing tables: - **Nominal ID:** The calculated inside diameter based on the nominal OD and wall thickness. Used for volume calculations (capacity in bbl/ft). - **Drift ID:** A smaller ID that accounts for manufacturing tolerances. The **drift diameter** is the minimum guaranteed ID through which a drift (a test mandrel of defined diameter) will pass. The drift ID is used for tool clearance — if you intend to run a 6-in tool inside 7-in casing, you must check that the tool OD is less than the drift ID of that casing. Similarly, if you are pumping balls to activate or deactive tools, ensure the ball is smaller than the drift ID. ```{admonition} Key Term :class: tip **Drift diameter** is the minimum guaranteed inside diameter of a casing string, used to determine whether tools can pass through the casing. The nominal ID is slightly larger and is used for volume calculations. ``` ### 17.6.4 Wall Thickness Wall thickness $t$ is the difference between OD and nominal ID divided by 2: $$t = \frac{\text{OD} - \text{ID}}{2}$$ Wall thickness determines both the mechanical strength of the casing (burst, collapse, tension capacity) and the nominal weight per foot. Casing with a larger OD but the same weight per foot as a smaller-OD string will have thinner walls and lower pressure ratings. --- ## 17.7 Casing Grades **Casing grade** is the designation for the steel's mechanical properties: primarily its minimum yield strength and tensile strength. The API (American Petroleum Institute) developed a standardized grade system that allows engineers worldwide to specify and procure casing with known mechanical properties. ```{figure} ../figures/ch17/casing_grade.png :name: fig-casing-grade :width: 80% API casing grade designations. The number in the grade name represents the minimum yield strength in thousands of psi. ``` The grade designation consists of a letter prefix and a number: | Grade | Min. Yield Strength (psi) | Application | |-------|--------------------------|-------------| | H40 | 40,000 | Very shallow, low-pressure applications | | J55 | 55,000 | Common surface casing; standard workhorse | | K55 | 55,000 | Same yield as J55; slightly different chemistry | | N80 | 80,000 | Standard intermediate and production casing | | L80 | 80,000 | Sour service (H₂S environments); controlled hardness | | C90 | 90,000 | Sour service | | T95 | 95,000 | Sour service | | P110 | 110,000 | High-strength; not H₂S rated | | Q125 | 125,000 | Highest standard API grade; proprietary steels exist above this | ```{admonition} Key Term :class: tip **Casing grade** specifies the minimum yield strength of the steel. The number in grades like N80, P110, or Q125 gives the minimum yield strength in thousands of psi. Letter prefixes differentiate grades with the same yield strength that have different chemical compositions, hardness requirements, or sour-service applicability. ``` **Sour service grades** (L80, C90, T95) are required when hydrogen sulfide (H₂S) is present in the produced fluids or formation gas. H₂S causes **sulfide stress cracking (SSC)**, a form of stress corrosion cracking that can cause sudden, catastrophic failure of high-strength steels at stress levels well below their nominal yield strength. Sour-service grades have controlled hardness (hardness ≤ 22 HRC for L80 and C90) that makes them resistant to SSC. High-strength grades like P110 and Q125 are not approved for sour service because their hardness makes them susceptible. ```{admonition} Warning :class: warning Never use P110 or Q125 casing in wells with significant H₂S concentration. Always consult NACE MR0175/ISO 15156 (the standard for materials for H₂S service) and classify the well before selecting casing grade. ``` The **letter prefix** has no consistent physical meaning — it is largely a historical artifact of the API standardization process. Grade J55 and K55 have the same yield strength but different chemistries; L80 and N80 have the same yield strength but different hardness requirements and sour-service applicability. --- ## 17.8 Casing Connections A casing joint is typically 40–45 ft long. To form a string hundreds or thousands of feet long, joints must be connected end to end. The **connection** (or "coupling") is the threaded interface between joints. Connection selection is nearly as important as grade selection: a strong pipe with a weak or leaking connection does not meet design requirements. ### 17.8.1 Threaded and Coupled (T&C) The traditional casing connection uses a separate threaded **coupling** that screws onto pin threads machined onto the ends of each pipe joint. Each joint has a "pin end" at each end; the coupling that connects two joints is a "box" (female thread). **API threaded connections** are the most widely used and least expensive: - **STC (Short Thread Coupling):** A basic tapered thread with 8 threads per inch. Lower engagement length and lower pressure rating than LTC. Used for low-pressure applications. - **LTC (Long Thread Coupling):** The same thread form but longer engagement. Better leak resistance and higher axial load capacity than STC. The standard choice for most casing applications. - **BTC (Buttress Thread Coupling):** A modified buttress thread form with better axial load capacity than LTC. Preferred for production casing under high tension loads and for long horizontal sections. API connections rely on thread compound (pipe dope) applied to the threads before makeup to achieve their pressure seal. They are cost-effective but may not achieve a reliable gas-tight seal on their own, especially after repeated make-and-break cycles. ### 17.8.2 Premium Connections **Premium connections** (non-API) are proprietary designs that offer one or more of the following advantages over API T&C: - **Metal-to-metal seal:** A secondary seal between a machined shoulder on the pin and a corresponding surface on the box, independent of the thread compound. Provides reliable gas-tight sealing even at high pressures. - **Higher torque capacity:** Proprietary thread forms that resist over-torque and under-torque failure. Critical in highly deviated and horizontal wells where the top-drive must apply high torque to rotate the casing. - **Flush or near-flush OD:** Some premium connections eliminate or reduce the OD of the coupling, reducing clearance requirements. Widely used premium connections include: - **Tenaris Blue:** Metal-to-metal seal, flush joint option, widely used for production strings - **Hydril 511 (Wedge 511):** Wedge-thread design providing excellent torque capacity and gas-tight seal - **VAM TOP:** Popular in deepwater and HP/HT applications Premium connections cost significantly more than API T&C — sometimes 3–5× the connection cost — but the cost is justified when a gas-tight seal is required, when the string must survive high torque during rotation, or when running in a tight wellbore that cannot accommodate a standard coupling OD. ```{admonition} Key Term :class: tip A **premium connection** is a proprietary, non-API casing connection that uses a metal-to-metal seal (in addition to or instead of thread compound) to achieve reliable gas-tight performance. Premium connections are specified when API T&C connections cannot meet pressure, torque, or clearance requirements. ``` --- ## 17.9 The Role of Cementing Cementing is inseparable from casing: one without the other does not deliver a wellbore. The cement fills the annular space between the casing OD and the borehole wall (or the previous casing ID for liner jobs), bonding the casing to the formation and creating hydraulic isolation between zones. The engineering objectives of primary cementing are: 1. **Zone isolation.** Prevent fluid migration between permeable zones of different pressure. The primary purpose and the one hardest to retrofit if it fails. 2. **Casing support.** The cement column carries compressive load from the formation, reducing the axial and lateral loading on the casing steel. 3. **Corrosion protection.** Cement surrounds and protects the casing OD from corrosive formation fluids. 4. **Casing centering.** Good cement requires that the casing be centered in the wellbore (controlled by centralizers). Eccentricity leads to channeling and poor cement coverage on the narrow side. Cementing failures are the leading cause of casing integrity issues over the life of a well. Because cement cannot be directly inspected, its quality is inferred from pressure tests (lift pressure), temperature surveys (to locate the top of cement), and acoustic bond logs (CBL — cement bond log). Chapter 20 covers cementing design, operations, and evaluation in detail. --- ## Chapter Summary Casing is the engineered steel lining that transforms a drilled hole into a functional wellbore. A typical well requires multiple concentric casing strings, conductor, surface casing, one or more intermediate strings, and production casing, each set to a depth determined by geological, engineering, and regulatory constraints. Liners and tie-backs extend this system to manage steel costs and reach. Each string is fully defined by its OD, nominal weight (lb/ft), grade, and connection. The OD establishes wellbore clearance constraints that drive hole-size selection from the inside out. Grade specifies yield strength; sour-service grades (L80, C90, T95) are required in H₂S environments. Connections range from economical API threaded couplings (STC, LTC, BTC) to premium metal-to-metal seal designs required for gas-tight service. Cementing fills the annulus and creates the zonal isolation that makes the casing string a real pressure barrier. Chapter 18 addresses how casing setting depths are selected; Chapter 19 covers the load calculations used to select grade and weight; Chapter 20 covers cementing design and operations. --- ## Key Terms | Term | Definition | |------|-----------| | Conductor | Outermost casing string; driven, drilled, or jetted to shallow depth; supports wellhead and BOP | | Surface casing | Protects freshwater; anchors BOP; setting depth often regulated | | Intermediate casing | Isolates problem formations; extends drilling window | | Production casing | Last full string; set through reservoir; designed for production loads | | Liner | Casing string that does not extend to surface; hung off inside previous string | | Tie-back | String that extends a liner to the wellhead, providing a full-length pressure barrier | | Tubing | Innermost pipe; production flow conduit; can be pulled and replaced | | OD | Outside diameter, in inches; determines clearance with adjacent strings | | Nominal weight | Approximate weight in lb/ft; proxy for wall thickness and strength | | Nominal ID | Calculated inside diameter; used for volume calculations | | Drift ID | Minimum guaranteed ID; used for tool clearance | | Casing grade | Steel designation specifying minimum yield strength; higher number = stronger | | Sour service | H₂S environment requiring controlled-hardness grades (L80, C90, T95) | | STC / LTC / BTC | API threaded connections from weakest to strongest; rely on pipe dope for seal | | Premium connection | Proprietary connection with metal-to-metal seal; required for gas-tight applications | | Primary cementing | Initial cementation of casing annulus to achieve zonal isolation | --- ## Practice Problems **17.1.** A well will be drilled in an area with a freshwater table extending to 1,800 ft and abnormal pore pressures beginning at 12,000 ft. The deepest productive formation is at 16,000 ft. (a) Identify which casing strings are needed for this well. (b) Describe the primary function of each string and what would happen if that string were omitted. (c) Explain why an intermediate string is required in this design. --- **17.2.** Casing specification: **7 in × 23 lb/ft × N80 × LTC** (a) What is the OD? (b) What is the nominal weight, and what does it imply about wall thickness relative to lighter-weight 7 in casing? (c) What is the minimum yield strength of the steel? (d) Is this connection suitable for gas-tight service? Explain. (e) Could this casing be used in a well with 150 ppm H₂S in the produced gas? Why or why not? --- **17.3.** An operator is planning a deepwater well in the Gulf of Mexico at 8,000 ft water depth with a planned TD of 25,000 ft MD / 22,000 ft TVD. The pore pressure gradient is normal to 12,000 ft TVD, then increases to 16 ppg equivalent at the objective. (a) Explain why this well likely requires more casing strings than a comparable land well. (b) A production liner is planned rather than full production casing to TD. What is the engineering advantage of the liner? (c) If the operator later decides that a full pressure barrier from TD to surface is needed for well integrity, what additional string would be required? --- **17.4.** A well penetrates a formation with 200 ppm H₂S in the produced gas. The production casing must withstand a collapse pressure of 12,400 psi and a burst pressure of 14,200 psi. Two candidate casing specifications are being considered: - **Option A:** 5½ in × 20 lb/ft × P110 × Premium - **Option B:** 5½ in × 20 lb/ft × L80 × Premium (a) Both options have identical physical dimensions. What is the key difference? (b) Which option is required for this well? Explain the reason. (c) Would your answer change if the H₂S concentration were only 15 ppm? Explain. --- **17.5.** Explain the difference between nominal ID and drift ID, and give an example of a situation where using nominal ID instead of drift ID could cause a problem during well operations.