Subsea Engineering Handbook

CHAPTER 22 Subsea Wellheads and Trees Contents 22.1. Introduction 22.2. Subsea Completions Overview 22.3. Subsea Wellhead System 22.3.1. Function Requirements 22.3.2. Operation Requirements 22.3.3. Casing Design Program 22.3.4. Wellhead Components 704 705 705 706 708 709 712 22.3.4.1. Wellhead Housing 22.3.4.2. Intermediate Casing Hanger 22.3.4.3. Production Casing Hanger 22.3.4.4. Lockdown Bushing 22.3.4.5. Metal-to-Metal Annulus Seal Assembly 22.3.4.6. Elastomeric Annulus Seal Assembly 22.3.4.7. Casing Hanger Running Tools 22.3.4.8. BOP Test Tool 22.3.4.9. Isolation Test Tool 22.3.4.10. OD Wear Bushing and OD BOP Test Tool 712 714 714 715 715 716 716 716 717 717 22.3.5. Wellhead System Analysis 22.3.5.1. 22.3.5.2. 22.3.5.3. 22.3.5.4. 717 Basic Theory and Methodology Static Wellhead Loading Thermal Induced Loading Wellhead System Reliability Analysis 718 721 721 723 22.3.6. Guidance System 22.3.6.1. 22.3.6.2. 22.3.6.3. 22.3.6.4. 22.3.6.5. 725 Guide Base Options General Requirements Twin Production Guide Base (Twin-PGB) Template-Mounted Guide Base (TMGB) Single-Well or Cluster Production Guide Base (SWPGB) 22.4. Subsea XMAS Trees 22.4.1. Function Requirements 22.4.2. Types and Configurations of Trees 728 728 728 22.4.2.1. Vertical Xmas Tree 22.4.2.2. Horizontal Xmas Tree 22.4.2.3. Selection Criteria 728 729 731 22.4.3. Design Process 22.4.4. Service Conditions 22.4.5. Main Components of Tree 732 734 735 22.4.5.1. General 22.4.5.2. Tubing Hanger Subsea Engineering Handbook ISBN 978-1-85617-689-7, doi:10.1016/B978-1-85617-689-7.10022-6 725 725 727 727 728 735 739 Ó 2010 Elsevier Inc. All rights reserved. 703 j 704 Y. Bai and Q. Bai 22.4.5.3. 22.4.5.4. 22.4.5.5. 22.4.5.6. 22.4.5.7. 22.4.5.8. 22.4.5.9. Tree Piping Flowline Connector Tree Connectors Tree Valves Production Choke Tree Cap Tree Frame 22.4.6. Tree-Mounted Controls 22.4.6.1. Subsea Control Model (SCM) 22.4.6.2. Pressure and Temperature Transmitters 22.4.7. Tree Running Tools 22.4.8. Subsea Xmas Tree Design and Analysis 22.4.8.1. 22.4.8.2. 22.4.8.3. 22.4.8.4. 22.4.8.5. 742 742 744 744 746 749 749 750 750 751 753 753 Chemical Injection Cathodic Protection Insulation and Coating Structural Loads Thermal Analysis 753 754 755 756 756 22.4.9. Subsea Xmas Tree Installation References 757 761 22.1. INTRODUCTION Subsea wellheads and Xmas trees are one of the most vital pieces of equipment in a subsea production system. The subsea wellhead system performs the same general functions as a conventional surface wellhead. It supports and seals casing strings and also supports the BOP stack during drilling and the subsea tree after completion. A subsea Xmas tree is basically a stack of valves installed on a subsea wellhead to provide a controllable interface between the well and production facilities. It is also called a Christmas tree, cross tree, X-tree, or tree. Subsea Xmas tree contains various valves used for testing, servicing, regulating, or choking the stream of produced oil, gas, and liquids coming up from the well below. The various types of subsea Xmas trees are used for either production or water/gas injection. Configurations of subsea Xmas trees can be different according to the demands of the various projects and field developments. Subsea wellhead systems and Xmas trees are normally designed according to the standards and codes below: • API 6A, Specification for Wellhead and Christmas Trees Equipment; • API 17D, Specification for Subsea Wellhead and Christmas Tree Equipment; Subsea Wellheads and Trees 705 • API RP 17A, Recommended Practice for Design and Operation of Subsea Production Systems; • API RP 17H, Remotely Operated Vehicle (ROV) Interfaces on Subsea Production System; • API RP 17G, Design and Operation of Comlpetion/Workover Risers; • ASME B31.3, Process Piping; • API 5L, Specification for Line Pipe; • ASME B31.8, Gas Transmission and Piping System; • ASME BPVC VIII, Rules for Construction of Pressure Vessels, Divisions 1 and 2; • AWS D1.3, Structural Steel Welding Code; • DNV RP B 401, Cathodic Protection; • NACE MR-0175, Petroleum and Natural Gas IndustriesdMaterial for Use in H2S-Containing Environments in Oil and Gas Production. 22.2. SUBSEA COMPLETIONS OVERVIEW Prior to the start of production, a subsea well is to be completed after drilling and temporarily suspended. Subsea completion is the process of exposing the selected reservoir zones to the wellbore, thus letting the production flow into the well. Two completion methods are commonly and widely used in the industry, as illustrated in Figure 22-1: • Open hole completion: Open hole completions are the most basic type. This method involves simply setting the casing in place and cementing it above the producing formation. Then continue drilling an additional hole beyond the casing and through the productive formation. Because this hole is not cased, the reservoir zone is exposed to the wellbore. • Set-through completion: The final hole is drilled and cemented through the formation. Then the casings are perforated with tiny holes along the wall facing the formations. Thus, the production can flow into the well hole. The completion design includes the tubing size, completion components and equipment, and subsea Xmas tree configuration. Components of subsea completion equipment include the subsea wellheads and the subsea tubing hanger/tree systems, which will be discussed in the following sections. 22.3. SUBSEA WELLHEAD SYSTEM The main function of the subsea wellhead system is to serve as a structural and pressure-containing anchoring point on the seabed for the drilling and 706 Y. Bai and Q. Bai Figure 22-1 Subsea Completion Methods (Courtesy of Dril-Quip) completion systems and for the casing strings in the well. The wellhead system incorporates internal profiles for support of the casing strings and isolation of the annulus. In addition, the system incorporates facilities for guidance, mechanical support, and connection of the systems used to drill and complete the well. Figure 22-2 illustrates the main building blocks of a subsea wellhead system. 22.3.1. Function Requirements The subsea wellhead system should: • Provide orientation of the wellhead and tree system with respect to the tree-to-manifold connection. • Interface with and support the Xmas tree system and blowout preventer (BOP). • Accept all loads imposed on the subsea wellhead system from drilling, completion, and production operations, inclusive of thermal expansion. Particular attention should be given to the horizontal tree concept where the BOP is latched on top of the Xmas tree. • Ensure alignment, concentricity, and verticality of the low-pressure conductor housing and high-pressure wellhead housing. Subsea Wellheads and Trees Figure 22-2 Subsea Wellhead System Building Blocks (Courtesy of API RP17A) 707 708 Y. Bai and Q. Bai • Be of field proven design, as far as possible, and designed to be installed with a minimum sensitivity to water depth and sea conditions. 22.3.2. Operation Requirements The subsea wellhead system should: • Provide the ability to install the following equipment in the same trip: the production guide base (PGB), the 36-in. conductor, and the lowpressure conductor housing. The assembly should be designed to be preinstalled in the moon-pool prior to being run subsea. • Allow for jetting operations for the casing pressure and for the drill and cement as a contingency case. • Include provision for efficient discharge of the drill cuttings/cement returns associated with the drilling operations. • Provide a bore protector and wear bushings to protect the internal bores of the wellhead system components during drilling, completion, and retrieval operations. • Ensure that all seals and locking arrangements can be tested in situ. • Ensure that the complete packoff/seal assembly can be retrieved and replaced in the even of a failed test. • Ensure that all permanent seals are protected during the running phase and remotely energized after landing. • Be designed such that the running string with wellhead tools and components will not snag or be restricted when running in or being pulled out of the hole. • Provide tooling that allows for seal surfaces to be cleaned after cement operation and prior to setting seal assemblies without pulling the running string; that is, the tool should allow cleaning of seal surfaces by circulation prior to pack offsetting. • Be designed to allow for landing of the casing hanger and installation of the seal assembly and removal of the same (in case of failure) in a single trip. Multipurpose tools should as far as possible be used to avoid pulling of the running string for tool change-outs. • Allow for large enough flow-by areas, and particle size, at the casing hanger and casing hanger running tool level (to be compared with the clearance between ID of the previous casing and the OD of the collars of the attached casing). • Be designed to allow for testing of the BOP without having to pull the wear bushing. Subsea Wellheads and Trees 709 • Provide guidance for equipment entering the well during drilling, completion, and subsequent operations. • Allow for safe and efficient retrieval of all installed equipment during permanent abandonment of the well. • Be designed to allow access for both work class and inspection ROVs. ROV grab bars should be included wherever an ROV operation is defined to provide stabilized working conditions for the ROV. 22.3.3. Casing Design Program For subsea wellhead system design, it is imperative to consider casing growth, which will affect the wellhead load intensively. Generally, the casing will connect with a tubing hunger with a screw thread on the top and be fixed with cement. It is a comparatively simple structure. The most important parameters for casing design are wall thickness and length. Based on guaranteeing the intensity and reliability, there is a growing need to consider conversative materials and resources with the increase in operating costs and withstand the cyclic swing of oil prices. Subsea oil development is not significant to survival when oil prices are very low. There are many typical casing design examples to refer to. See Figures 22-3 and 22-4, which are typical wellhead casing schemes used in North Sea. As the oil explorations move into deepwater drilling of high-pressure and hightemperature wells, it has become more and more popular and necessary to increase the scope of the optimization by encompassing more design parameters into the analysis. Consequently, numerous variables can be taken into account within the design spectrum. However, usually it is imperative to integrate all of the subsea components in the analysis of the casing design, which we will elaborate on in wellhead reliability analysis section. Normally, a lot of different design parameters are proposed under the same conditions. To counter this problem, a dimensionless parameter called the wellhead growth index (WHI) has been developed, which greatly aids the ability to determine the severity of the design and a means of describing the severity of wellhead growth, without sacrificing any rigor. WHI encapsulates the annuli fluid expansion and wellhead growth and it provides a simple practical way to view the casing movement and fluid expansion in the annuli during the course of drilling and also during the production phase of the well. It is defined as the ratio of the annulus fluid expansion of the casing to the actual volume of the exposed segment above the top of the cement [1]. 710 Y. Bai and Q. Bai Figure 22-3 Typical Casing Design for Shallow Water The annulus fluid expansion includes the unconstrained volume change and the annulus volume change due to annulus pressures. Wellhead growth gives an estimate of the circumferential and axial strain on the casings. With the circumferential and lateral strain, the total volume of the expansion of all casing string for all casing segments is given by: m X n h i X p Dv ¼ (22-1) ð2dDdl þ d2 DlÞ þ va 4 i; j j1 i1 The total area of the annulus cross section for each casing string is given by X X p  (22-2) D2 ji;j a ¼ 4 where: d D ¼ casing diameter, in ¼ annulus gap between the casings, in Subsea Wellheads and Trees 711 Figure 22-4 Typical Casing Design for Deep Water l ¼ segment length of the exposed casing, ft n ¼ number of exposed casing sections, m ¼ number of casings, v ¼ annulus volume, ft3 v2 ¼ volumetric change due to annulus pressures Dd ¼ change in the casing diameter, in Dl ¼ wellhead growth, in Dv ¼ change in the annulus volume, ft3 WHI ¼ wellhead growth index. Using Equations (22-1) and (22-2) with approximations, the wellhead growth index for multiple casing string is given by i Pm Pn hp ð2dDdl þ d2 DlÞ þ va j1 i1 4 i;j WHI ¼ (22-3) P P p 2  l ðD Þ i; j 4 712 Y. Bai and Q. Bai where: d ¼ casing diameter, in D ¼ annulus gap between the casings, in l ¼ segment length of the exposed casing, ft n ¼ number of exposed casing sections, m ¼ number of casings, v ¼ annulus volume, ft3 v2 ¼ volumetric change due to annulus pressures Dd ¼ change in the casing diameter, in Dl ¼ wellhead growth, in Dv ¼ change in the annulus volume, ft3 WHI ¼ wellhead growth index. WHI gives a quantitative predictive capability for interpreting the calculation results. The higher the value of WHI, the higher the severity of the casing design involved. Calculation of WHI at different stages of the casing design will aid in comparing the relative rigorousness of the overall casing design. 22.3.4. Wellhead Components A subsea wellhead system mainly consists of wellhead housing, conductor housing, casing hungers, annulus seals, and guide base (TGB and PGB). The high-pressure wellhead housing is the primary pressure-containing body for a subsea well, which supports and seals the casing hangers, and also transfers external loads to the conductor housing and pipe, which are eventually transferred to the ground. Figure 22-5 illustrates the typical 183/4-in. subsea wellhead components. 22.3.4.1. Wellhead Housing The wellhead housing is the primary housing supporting both the intermediate and production casing strings. In API 17D [2], very detailed profiles are introduced. Figure 22-6 is a schematic of a typical wellhead housing. Two kinds of subsea analyses are necessary to consider in the wellhead housing design procedure: load stress analysis and thermal analysis. The hanger landing shoulder will sustain loads from the tubing hanger. Normally, a finite element analysis (FEA) and riser fatigue analysis will be performed to verify the design capacities. In addition, thermal analysis is performed to determine the temperature profiles through the system so that temperature derating can be accounted Subsea Wellheads and Trees Figure 22-5 Typical 183/4-in.Subsea Wellhead System (Courtesy of Dril-Quip) Figure 22-6 Schematic of Wellhead Housing 713 714 Y. Bai and Q. Bai for as appropriate. A prototype wellhead should be tested to the test pressure as well as loaded with simulated casing loads and BOP test pressure with hangers in place simulating the real production environment in total without experiencing any permanent deformation. 22.3.4.2. Intermediate Casing Hanger The intermediate casing hanger for the system lands in the first hanger position in the lower portion of the wellhead. Figure 22-7 illustrates the profile for an intermediate casing hanger. The casing hanger can nominally be for either a 16- or 13-5/8-in. casing. The casing hanger features an expanding load ring that lands into the wellhead seat segments to suspend the casing and BOP pressure end loads. The analysis is performed on existing field-proven hangers of similar designs to compare stress levels. Reliability data also will be collected from similar equipment and lessons learned should be incorporated into the design. Further reliability work is performed during FMECAs (Failure Mode effect and Criticality Analysis). Finally, through testing, the hanger is positively proof tested to the design loads, pressures, and combined loads in the exact sequence in which they would be applied in the field, without experiencing any permanent deformation. 22.3.4.3. Production Casing Hanger The production casing hanger for the system lands in the second hanger position. The casing hanger can nominally be either for an 113/4- or 103/4-in. Casing Hanger Figure 22-7 Intermediate Casing Hanger Profile Subsea Wellheads and Trees 715 casing. The casing hanger features an expanding load ring that lands into the second set of wellhead seat segments to support the casing and BOP pressure end loads. Using the approach above, detailed stress analysis and classical calculations should be performed in fashion similar to the analysis performed for the intermediate hanger. 22.3.4.4. Lockdown Bushing The lockdown bushing is used to permanently hold the production casing hanger in place so that the annulus seal assembly locked to the hanger does not move and get damaged during start-up/shutdown operations. This system’s lockdown bushing has a rated lockdown capacity of 3.2 million pounds. It is installed using a related tool using full-open water operations. The design approach for this piece of equipment is handled as same as other components of wellhead. Design calculations and finite element analysis are performed in conjunction with the gathering of reliability lessons learned and FMECA to confirm the integrity of the design up-front. Tests should be performed to confirm that the lockdown bushing and tool can definitely function as designed, and load testing is performed to confirm the load capacity. 22.3.4.5. Metal-to-Metal Annulus Seal Assembly The metal-to-metal annulus seal assembly is used to seal off the casing string annulus pressure from the bore pressure to isolate geological formations from one another. The typical profile is showed in Figure 22-8. Figure 22-8 Intermediate Casing Hanger Profile 716 Y. Bai and Q. Bai The metal-to-metal assembles usually needs practice testing to confirm that it could withstand the high pressure and temperature. 22.3.4.6. Elastomeric Annulus Seal Assembly The elastomer seal assembly is used in an emergency when the primary metal seal fails to function should the bore of the wellhead or casing hanger have a deep scratch. The elastomer seal assembly seals in a different vertical location in the wellhead, which should seal away from the damaged area. 22.3.4.7. Casing Hanger Running Tools The intermediate and production casing hanger running tools run the casing hangers and set the annulus. These tools normally are designed using the same technology, lessons learned, and in many cases the same parts as the standard 15-ksi running tool, as shown in Figure 22-9. 22.3.4.8. BOP Test Tool The BOP test tool is designed with an approach that is similar that for other components and tools in this system. It is used to test the BOP in terms of future formation pressure that the operator is currently drilling into, and is also used to run and retrieve wear bushings, as shown in Figure 22-10. Figure 22-9 Casing Hanger Running Tool (Courtesy of Dril-Quip) Subsea Wellheads and Trees 717 Figure 22-10 BOP Isolation Test Tool (Courtesy of Dril-Quip) 22.3.4.9. Isolation Test Tool The isolation test tool is used to test the pack-off per MMS (Mineral Management Service) requirements while simultaneously isolating the BOP (Blowout Preventer) stack/riser. The tool operates with a simple straightin/straight-out approach. Once set in position with the weight down, drill string pressure is applied up to a target test pressure of 20 ksi. 22.3.4.10. OD Wear Bushing and OD BOP Test Tool The 135/8-in. OD wear bushing and 135/8-in. OD BOP test tool are key tools to expediting completions while the 183/4-in., 20-ksi BOP is being developed for the industry. This wear bushing and running tool combination is run through a 135/8-in., 20-ksi BOP that latches either to the wellhead or 20-ksi tubing head; they allow for BOP tests. The wear bushing protects all seal surfaces including those on the production casing hanger while drilling/logging operations are performed. 22.3.5. Wellhead System Analysis An analysis approach based on a simple linear elastic model (SLEM) of multistring wellbore systems is described in this section. This approach can be used to facilitate understanding and analysis of various complex wellhead load events in terms of a simple linear model. Although the simple linear model is limited because nonlinear effects due to buckling are not 718 Y. Bai and Q. Bai considered, wellhead loads and displacement behave as a linear system to a good first-order approximation in many realistic situations. Loads on conductor and surface casings are considered in particular, since many surface/rig events tend to impact these strings more directly. Also, they must bear the primary load burden due to their greater relative stiffness and tendency to displace linearly. 22.3.5.1. Basic Theory and Methodology A brief review is presented of the SLEM for multistring wellhead displacements and loads for a free-standing wellhead system. Use of the SLEM in a systematic analysis of wellhead load events is also discussed. Recall that an OCTG casing or tubing string typically operates within the material’s linearly elastic region. The relation of axial stress strain is governed by Hooke’s law and the string material elastic modulus, E. Since the tubular string functions as a prismatic bar, Hooke’s law can be expressed as follows: d ¼ PL EA (22-4) where d is the resultant displacement subject to an applied axial load P on a string of free length L and cross-sectional area A. This may be expressed in terms of a stiffness or spring constant k as is familiar for linear elastic springs: P ¼ k$d (22-5) EA L (22-6) where stiffness k is given by: k ¼ For an offshore platform or jack-up well with a free-standing wellhead structure, the wellhead is free to move vertically, and all casing and tubing strings landed in the wellhead are subject to uniform wellhead displacement. The system is statically indeterminate and must be analyzed as a composite system. For a wellbore with n strings linked at the wellhead (not including downhole liners or outer casings not in contact with the wellhead), the composite system stiffness ksys is the sum of the stiffness from each string: ksys ¼ n X E1 $A1 E2 $A2 En $An þ þ.þ ¼ kn L1 L2 Ln i¼1 (22-7) Subsea Wellheads and Trees 719 Note that for a casing or tubing string i ¼ q composed of w sections with changes in geometry or material, the composite stiffness of that particular string is given by the following equation: w X 1 1 1 1 1 ¼ þ þ.þ ¼ kq kq;1 kq;2 kq;w k z ¼ 1 q;z (22-8) Each string landed into the wellhead contributes an axial load, Pi. To satisfy mechanical equilibrium, the sum of all axial loads at the wellhead must be zero: n X pi ¼ 0 (22-9) i¼1 If m static wellhead loads W j, such as the weight of the wellhead, BOPs, or Christmas trees and also upward forces applied by rig tension systems, are applied to the system, then the equation of equilibrium now requires that the sum of all string axial loads balance the net static load: n X i¼1 Pi þ m X Wj ¼ 0 (22-10) j¼1 When any load W is applied to the system, the wellhead and all strings landed in the wellhead will undergo a uniform displacement, dsys, which is determined by the system stiffness and the applied load (upward displacement is positive): dsys ¼ W =ksys (22-11) Based on this uniform displacement, the applied load W is thus distributed onto each string in proportion to its relative individual stiffness. As a result, the axial load of each string is changed by an incremental load DPi: DPi ¼ ki $dsys (22-12) To model the change in wellhead displacement and actual wellhead loads for each string throughout the life of the well, the preceding equations and conditions must be applied to each step of the well construction process as well as subsequent states during production operations. The global datum point for wellhead displacement is the flange height of the outer casing string in its initial free-standing state. The methodology is 720 Y. Bai and Q. Bai simplified by utilizing the initial and subsequent load states for each string considered in isolation from the overall wellbore system. An axial load result can be calculated using a single-string model based on a fixed nominal wellhead condition. Each single-string load can then be added to the multistring wellhead system and the appropriate redistribution of axial loads can be determined based on the discussion and equations above. The initial axial load Pi,o contributed by each string added to the system corresponds to the hook load when it is landed in the wellhead. This is calculated from cumulative buoyed weight based on its nominal length, tubular weight, mud and slurry densities, and wellbore deviation. In addition, the landed weight of each string may include overpull or slackoff. For any new load state S such as a well life production operation, each string undergoes a change in axial load DPi,S, When changing in operation conditions such as temperature or pressures. For example, after commencement of production, the wellbore heats up and any given casing will tend to expand axially due to a net increase in temperature relative to the initial state. Similarly, during a cold injection or stimulation operation, each string will tend to go into increased tension due a thermal contraction. The resultant change in axial load and the associated unconstrained axial displacement for each string considered in isolation may be calculated using a standard single-string force/displacement model such as in Mitchell [3] (1996). As each new string is added to the system, the wellhead undergoes a uniform displacement as discussed above and the new string landed weight will be distributed among the outer strings. If the cement has set before the new string is landed, the new string will also “slump” somewhat to bear a portion of its own weight. Likewise, for any changes in the string state during operation, the subsequent changes in axial load are redistributed across the multistring system based on relative stiffness. A procedural method based on the foregoing discussion of simple linear elasticity, the SLEM can be summarized as follows: 1. For operational load step S, identify the strings i ¼ 1 to n already installed or to be landed in the current step and calculate the current composite system stiffness: ks ¼ n X i¼1 kn (22-13) Subsea Wellheads and Trees 721 2. For each string i ¼ 1 to n, determine the load change DP relative to Pi,o based on single-string analysis; for a string to be landed in the current step S, define DPi,S ¼ Pi,o. 3. Identify static wellhead loads j ¼ 1 to m to be applied in the current load step S: W1,S, W2,S, ., Wm,S. 4. Calculate the current incremental wellhead system displacement dS as follows: # " n m X X DPi;s þ Wj;s =ks (22-14) ds ¼ i¼1 j¼1 5. For each string, calculate the final redistributed multistring axial load based on the current load step: Pi;S ¼ Pi;S1 þ DPi;S  ds $ki (22-15) 22.3.5.2. Static Wellhead Loading In the first sensitivity study, incremental wellhead displacements were calculated for a range of arbitrary static wellhead loads using both SLEM Equation (22-11) and also state-of-the-art stress simulation software with advanced numerical modeling of multistring system behavior. There is nearly exact agreement between the SLEM solution and the numerical model, which does account for any nonlinear effects such as buckling. This indicates that the multistring system reacts in an essentially linear fashion to static wellhead loads. This result holds even for loads on the order of the axial rating of the outer casing. This is consistent with the general observations noted above, in that the majority of the load is distributed onto the outer casing, which is either unbuckled or for which buckling strain is negligible relative to elastic strain. Table 22-1 summarizes the system stiffness values used in the SLEM calculation. In this example, the outer surface casing accounts for 92.1% of the composite system stiffness. 22.3.5.3. Thermal Induced Loading A second sensitivity study was carried out to investigate the effects of thermal induced loads. Heating of the wellbore tends to induce buckling of the inner casings and tubing. This is because the outer casing will tend to 722 Y. Bai and Q. Bai Table 22-1 Buckling Sensitivity Example: SLEM Multistring System Values E L_ft K K/Ksys String A (psi) (ft) (lbf/in.) (%) No. Section (in.2) 1 2 3 4 1 1 1 2 1 38.0427 20.7677 31.5342 15.5465 8.4494 30Eþ06 30Eþ06 30Eþ06 30Eþ06 30Eþ06 500 5000 1000 9000 11500 190214 10384 78836 4094 4318 1837 92.1% 5.0% 2.0% Ksys (lbs/in.) 206529 0.9% restrain upward well growth driven primarily by the compressive force of the inner strings; as a consequence it will tend to go into tension. Production and injection operations were defined appropriately to focus on thermal effects as opposed to production pressures. The initial operating state is steady-state production followed by a long duration of shutdown at roughly constant SITHP. After the wellbore returns to geostatic temperatures, kill operations are undertaken that cool the wellbore even more and also reduce wellhead pressure to a minimal value. The kill is then continued as a long-term, low-rate mud injection. Figure 22-11 shows a plot of cumulative wellhead displacement versus time over the duration of the shutdown and injection operations using SLEM and the numerical modeling software. The datum reference point is the as-built wellhead elevation after landing all strings. The SLEM matches the overall trend of wellhead movement, and the difference in magnitude with the numerical model is negligible. If the conductor is added to the system by assuming the wellhead to be fixed to the outer flange, then the overall system becomes stiffer. The increase in system stiffness results in a greatly reduced range of movement and a tighter clustering of the different model results. Figure 22-11 Comparative Sensitivity-Thermal Induced Displacement: Numerical Model versus SLEM Subsea Wellheads and Trees 723 22.3.5.4. Wellhead System Reliability Analysis When drilling a well in deep water, the wellhead will bear the intricate forces from the environment and the drilling operation, which will affect the integral reliability of the wellhead system. Normally an FEA model is built to analyze the wellhead system reliability in terms of taking all factors into consideration, including loading from the marine environment and the drift of a drilling vessel or platform, and nonlinear response between casing string and soil stratum. Figure 22-12 illustrates the scheme of a wellhead system subjected to different loads. Figure 22-13 shows the force diagram for a wellhead during the drilling operation, where Fx is the sum of the external force on the riser in the x direction, Fy is the sum of the external force on the riser in the y direction, Figure 22-12 Wellhead Load Conditions 724 Y. Bai and Q. Bai Figure 22-13 Force Diagram of Wellhead W is the weight of the BOP and wellhead, and Fd is the direct wave force on the BOP and wellhead upper seabed. The casing string’s displacement equation can be explained as follows:     d2 d2y d dy EIðxÞ 2 þ N ðxÞ þ DcðxÞpðx; yÞ ¼ qðxÞ (22-16) d2 x d x dx dx where EI(x): bending stiffness of combination of casing string, cement ring, etc., kNm2; q(x) : unit external force, kN/m; Dc(x) : external diagram of casing string, m; N(x) : axial force, kN; P(x,y) : unit (area) horizontal soil force, which is determined by Equations (22-17) and (22-18) according to Matlock and Reese [4], kN/m2. 8 > p > < u > > : 3Cu X ; X < Xr Dc pu ¼ 9Cu ; X  Xr ¼ 3Cu þ gX ¼ Xr ¼ 6Cu Dc gDc þ 3Cu (22-17) Subsea Wellheads and Trees @  1 P y 3 y ¼ 0:5 ; <8 Pu y50 y50 725 (22-18) P y ¼ 1:0; 8 Pu y50 where Pu : critical soil force; x: distance under the seabed; y: horizontal displacement of casing string; Cu : undrained shear strength of soil; 3: a coefficient 0.25 to 0.5 ; g: submerged weight of soil. After obtaining the displacement of the casing string, the bending moment can also be obtained and used to judge the stability of the wellhead. 22.3.6. Guidance System 22.3.6.1. Guide Base Options Guidance onto the wellhead system is dependent on the actual type of development concept (template or satellite well) by means of the following guide base options: • Concept 1: multiwell template with production manifold (integral or modular) and template-mounted production guide base; • Concept 2: individual wells connected to subsea manifold center; • Concept 3: two slots structures; • Concept 4: individual wells in daisy chain configuration. Three different types of guide base are proposed for these four concepts: • Twin production guide base; • Template-mounted guide base; • Single-well or cluster production guide base. 22.3.6.2. General Requirements The production guide base is an element attached to and installed with the low-pressure housing of the wellhead. All guide bases should comply with the following general requirements: • All guide bases should orient and lock to the 30-in. conductor housing incorporating an antirotation device. • In all type of wells, it should provide orientation to the tree to be in the right position for connecting the flowlines and hydraulic and electric lines. 726 Y. Bai and Q. Bai • The ability to reuse some of the existing exploration and appraisal wells is to be included within the design either as part of the overall design or as part of a specific modification. • The guide base and receptacle should be designed to withstand all vertical and horizontal loads associated with deployment, installation and retrieval of all modules including BOPs, without any permanent deformation. The base should tolerate landing and retrieval of modules with angular misalignment relative to the centerline of the wellhead. • The guide base should be designed to prevent snagging of an ROV and associated umbilical. • All guide bases should be designed for a 36-in. conductor pipe to be run through the guide base at the surface. • The production guide base should be installed with the conductor pipe and latched and locked to the 30-in. housing. It should provide an antirotation device. The locking and antirotation mechanism should not be affected by any cutting or cement, during drilling and cementing on the associated two first phases of the well. The PGB and the template, if to be considered, should facilitate the evacuation of cuttings and cement from the next drilling phase, in order to preserve the previously installed equipment. • The orientation device will allow the guide base to be installed in multiple orientation positions. • The configuration should allow retrieving the tree with the jumper connector remaining in place. • The guide base should be designed to accommodate rigs that have a funnel-down guidance arrangement. However, a funnel-up configuration should be proposed as an option. • The guide base and low-pressure housing should be designed to provide a support to suspend the conductor pipe in the moon-pool prior to running. • The conductor pipe should be jetted and the guide base arrangement should allow for installing and retrieving all of the tools used for this purpose. • Drilling and cementing the conductor pipe is part of the contingency plan. The guide base design should cope with such operations. • The structure and the conductor locking mechanism with the antirotation device should accommodate all combined loads resulting from the drilling and production operation such as bending and fatigue loads and thermal and pressure effects. Subsea Wellheads and Trees 727 • A device (bull’s-eye for example) should be installed on the guide base to check the conductor pipe verticality at the installation. • The guide base should include all equipment needed for ROV intervention or connection tools. • The guide base will be equipped with a cathodic system, which should be dimensioned to cater to both the guide base and the well (well drain) for the entire life of the well. • The guide base should be designed to avoid any clash with the different BOP planned to be used in the project in any orientation. • A clump weight should be added to the guide base in order to handle it in a horizontal position. • A dedicated tool, drill pipe should be provided for retrieving/ reorienting/reinstalling the guide base. This system will be equipped with a secondary backup release which is operated by ROVs. • If relevant, the PGB should include retrievable protection caps for vertical mandrels. These should be installable and retrievable by ROV. These caps provide temporary protection of bores, seal areas, and hydraulic couplers against dropped objects and environmental impact, per ISO 13628-4 [5]. The protection caps should be used during transportation and storage on land and offshore. 22.3.6.3. Twin Production Guide Base (Twin-PGB) The twin-PGB should provide a second well slot adjacent to an existing wellhead, by means of a base structure that can be landed and locked to the existing well conductor housing by use of the guide base locking profile. It should satisfy the same functional and design requirements as the PGB defined above, with the following additions/modifications: • The twin-PGB includes a second well slot with the same functionality as a TMGB. • The twin-PGB includes a two-well manifold with piping arrangement, ROV-operable isolation valves, hubs for vertical tree connection, and horizontal inboard tie-in facilities for production lines and service umbilical, as well as an electrical connection system between the inboard hub and the trees. • The twin-PGB will not be installed with the conductor pipe. 22.3.6.4. Template-Mounted Guide Base (TMGB) In a template configuration, the function of the guide base will be limited to the orientation and the elevation of the Xmas tree. Providing all of the 728 Y. Bai and Q. Bai functions listed before are included in the design, the PGB, in that special case could be installed with the template. The TMGB should include the equipment necessary to facilitate the interface between the Xmas tree and the template/manifold, such as: • Equipment for guidance; • Alignment and suspension of the wellhead; • Flowline/service umbilical inboard connection (if relevant). 22.3.6.5. Single-Well or Cluster Production Guide Base (SWPGB) In addition to the above general requirements and the PGB requirements, the SWPGB should satisfy the following: • In a cluster or single-well configuration, the production guide base should orient the tree and support the tree-to-jumper connection. In such a case, the PGB should be designed so that it can be either retrieved to the surface or reoriented. • The PGB should provide a support for deepwater subsea telemetry to perform the measurements needed for the jumper installation. 22.4. SUBSEA XMAS Trees 22.4.1. Function Requirements Typical function requirements for subsea Xmas trees include: • Direct the produced fluid from the well to the flowline (called production tree) or to canalize the injection of water or gas into the formation (called injection tree). • Regulate the fluid flow through a choke (not always mandatory). • Monitor well parameters at the level of the tree, such as well pressure, annulus pressure, temperature, sand detection, etc. • Safely stop the flow of fluid produced or injected by means of valves actuated by a control system. • Inject into the well or the flowline protection fluids, such as inhibitors for corrosion or hydrate prevention. 22.4.2. Types and Configurations of Trees 22.4.2.1. Vertical Xmas Tree The master valves are configured above the tubing hanger in the vertical Xmas tree (VXT). The well is completed before installing the tree. VXTs are applied commonly and widely in subsea fields due to their flexibility of Subsea Wellheads and Trees 729 Figure 22-14 Xmas Vertical Tree (Courtesy of FMC) installation and operation. Figure 22-14 shows a vertical Xmas tree being lowered subsea. Figure 22-15 illustrates the schematic of a typical vertical tree. The production and annulus bore pass vertically through the tree body of the tree. Master valves and swab valves are also stacked vertically. The tubing hanger lands in the wellhead, thus the subsea Xmas tree can be recovered without having to recover the downhole completion. 22.4.2.2. Horizontal Xmas Tree Another type of subsea Xmas tree developed rapidly in recent years is the horizontal tree (HXT). Figure 22-16 shows a horizontal tree made by FMC. Figure 22-17 shows the schematic of a horizontal tree. The valves are mounted on the lateral sides, allowing for simple well intervention and tubing recovery. This concept is especially beneficial for wells that need a high number of interventions. Swab valves are not used in the HXT since they have electrical submersible pumps applications. The key feature of the HXT is that the tubing hanger is installed in the tree body instead of the wellhead. This arrangement requires the tree to be installed onto the wellhead before completion of the well. 730 Y. Bai and Q. Bai Figure 22-15 Schematic of Vertical Xmas Tree (Courtesy of API RP 17A) Figure 22-16 Horizontal Xmas Tree (Courtesy of FMC) Subsea Wellheads and Trees 731 Figure 22-17 Schematic of Horizontal Xmas Tree (Courtesy of API RP 17A) 22.4.2.3. Selection Criteria In the selection of a horizontal tree (HXT) or a vertical tree (VXT), the following issues should be considered: • The cost of an HXT is much higher than that of a VXT; typically the purchase price of an HXT is five to seven times more. • A VXT is larger and heavier, which should be considered if the installation area of the rig is limited. • Completion of the well is another factor in selecting an HXTor VXT. If the well is completed but the tree has not yet been prepared, a VXT is needed. Or if an HXT is desired, then the well must be completed after installation of the tree. 732 Y. Bai and Q. Bai • An HXT is applied in complex reservoirs or those needing frequent workovers that require tubing retrieval, whereas a VXT is often chosen for simple reservoirs or when the frequency of tubing retrieval workovers is low. • An HXT is not recommended for use in a gas field because interventions are rarely needed. 22.4.3. Design Process The designs of subsea trees vary in many ways: completion type (simple, diver assist, diverless, or guideline-less), purpose of the tree (production or injection), service conditions (H2S, CO2, or H2S and CO2), and so on. These parameters will affect the selection of the tree type, materials, and component arrangement. A typical design process for a subsea tree is shown in Figure 22-18. The design requirements include the requirements of function, performance, working capabilities, and the cost of the product, which is referred to as its economy. These are basic requirements when designing a product. Design requirements are shown in Figure 22-19. After the functions and requirements are clearly known by the designer, the tree type can be determined and the schematic diagram drawn. Draft structural drawings of the tree are usually done during this phase. Component design is almost the most important point in subsea Xmas tree design. Components of a typical subsea Xmas tree include: • Tubing hanger system; • A tree connector to attach the tree to the subsea wellhead; • The tree body, a heavy forging with production flow paths, designed for pressure containment. Annulus flow paths may also be included in the tree body; • Tree valves for the production bore, the annulus, and ancillary functions. The tree valves may be integral with the tree body or bolted on; • Valve actuators for remotely opening and closing the valves. Some valves may be manual and will include ROV interfaces for deep water; • Control junction plates for umbilical control hook-up; • Control system, including the valve actuator command system and pressure and temperature transducers. The valve actuator command system can be simple tubing or a complex system including a computer and electrical solenoids depending on the application; • Choke (optional) for regulating the production flow rate; Subsea Wellheads and Trees 733 Figure 22-18 Design Process of Subsea Xmas Tree Design Requirements Working Capabilites Functions Performance Requirements Economy Open & Shut down the Production Strength Pressure Integrity Control & Monitor the Flow (speed, pressure, temperature, sand, etc) Rigidity Materials Proper Selection of Raw Materials Thermal Stability Leakage Standardization & Commonality Provide Interfaces to Flowlines …… Reliability Inject Chemical Fluids into the Well or Flowlines Life Cycles Operating Forces/Torques Figure 22-19 Design Requirements Processbility 734 Y. Bai and Q. Bai • Tree piping for conducting production fluids, crossover between the production bore and the annulus, chemical injection, hydraulic controls, etc.; • Tree guide frame for supporting the tree piping and ancillary equipment and for providing guidance for installation and intervention; • External tree cap for protecting the upper tree connector and the tree itself. The tree cap often incorporates dropped object protection or fishing trawler protection. The design should consider the components although some of them may be a system or subassembly. Calculations for, drawings, and reports for the components are completed in this phase. Subassembly and assembly design includes a report that shows the assembly procedures and the assembly drawings. Design procedures are shown in Figure 22-20. 22.4.4. Service Conditions Pressure ratings of subsea Xmas trees are standardized to 5000 psi (34.5 MPa), 10,000 psi (69.0 MPa), and 15,000 psi (103.5 Mpa). Recently 20,000-psi (138-Mpa) subsea Xmas trees have been applied successfully in subsea fields. Table 22-2 shows the standard temperature ratings per API Specification 6A [6]. Subsea equipment should be designed and rated to operate throughout a temperature range of 35 to 250 F (Rating V) according to the API Specification 17D [2]. Choosing materials classes is the responsibility of the user. All pressurecontaining components should be treated as “bodies” for determining material requirements from Table 22-3. However, other wellbore pressure Figure 22-20 Component Design Process Subsea Wellheads and Trees Table 22-2 Standard Temperature Ratings [46] Operating Range Temperature  Maximum ( F) Minimum ( C) Classification Minimum ( C) K L P R S T U V e60 82 e46 82 e29 82 Room temperature e18 66 e18 82 e18 121 2 121 735 Maximum ( F) e75 180 e50 180 e20 180 Room temperature 150 180 250 35 250 boundary penetration equipment, such as grease/bleeder fittings and lockdown screws, should be treated as “stems.” Metal seals should be treated as pressure-controlling parts. Equipment should be designed to use materials based on the material class required, as shown in Table 22-4. If the mechanical properties can be met, stainless steels may be used in place of carbon and low-alloy steels, and corrosion-resistant alloys may be used in place of stainless steels. 22.4.5. Main Components of Tree 22.4.5.1. General Components of a subsea Xmas tree vary according to the specific design requirements of specific subsea fields. However, typical VXT components, as illustrated in Figure 22-21, include the following: • Tree cap; • Upper production master valve (UPMV); Table 22-3 Material Class Rating [2] Relative Corrosivity Retained Fluids of Retained Fluid Partial Pressure of CO2 (psia) (MPa) Recommended Material Class General service General service General service <7 (0.05) 7 to 30 (0.05 to 0.21) >30 (0.21) AA BB CC <7 (0.05) 7 to 30 (0.05 to 0.21) >30 (0.21) DD EE FF >30 (0.21) HH Sour service Sour service Sour service Sour service Noncorrosive Slightly corrosive Moderately to highly corrosive Noncorrosive Slightly corrosive Moderately to highly corrosive Very corrosive 736 Y. Bai and Q. Bai Table 22-4 Material Requirements [6] Minimum Material Requirements Material Class Body, Onnet, End, and Outlet Connections Pressure-Controlling Parts, Stems, and Mandrel Hangers AA e General service BB e General service CC e General service DD e Sour servicea EE e Sour servicea FF e Sour servicea HH e Sour servicea Carbon or low-alloy steel Carbon or low-alloy steel Stainless steel Carbon or low-alloy steela Carbon or low-alloy steela Stainless steela CRAsb Carbon or low-alloy steel Stainless steel Stainless steel Carbon or low-alloy steelb Stainless steelb Stainless steelb CRAsb a As defined by NACE MR 0175 [7]. In compliance with NACE MR 0175 [7]. b Figure 22-21 Typical Components of a VXT (Courtesy of Dril-Quip) • • • • • Lower production master valve (LPMV); Production wing valve (PWV); Production swab valve (PSV) Crossover valve (XOV); Annulus master valve (AMV); Subsea Wellheads and Trees • • • • • 737 Annulus access valve (AAV) or annulus swab valve (ASV); Annulus wing valve (AWV); Pressure and temperature sensors (PT, TT, PTT, etc.); Tree connector; Conventional tubing hanger system. Typical components of a horizontal Xmas tree, as illustrated in Figure 22-22, are as follows: • Tree debris cap; • Tree body; • Internal tree cap (or upper crown plug); • Crown plug (or lower crown plug); • Production master valve (PMV); • Production wing valve (PWV); • Annulus access valve (AAV); • Annulus master valve (AMV); • Annulus wing valve (AWV); • Crossover valve (XOV); • Sensors (PT, TT, PTT, etc.); • Tree connector; • Tubing hanger system. Figure 22-22 Typical Components of an HXT 738 Y. Bai and Q. Bai The main components that vary between VXT and HXT are as follows: • Tree body: The tree body in a HXT is normally designed to be an integrated spool. The PMV is located in this tree body, as well as the annulus valves. The PWV is usually designed to be integrated into a production wing block, which can be easily connected to the tree body by flange methods. This design results in components that are interchangeable between the HXTs in the industry. In addition, the tubing hanger system is located in the tree body. • Tubing hanger system: A VXTutilizes a conventional tubing hanger, which has a main production bore and an annulus bore. The tubing hanger is located in the wellhead. However, in an HXT, the tubing hanger is a monobore tubing hanger with a side outlet through which the production flow will pass into the PWV. Because the TH in the HXT is located in the tree body, it needs the crown plugs as the barrier method. An internal tree cap is the second barrier located above the crown plug. If dual crown plugs are designed in a TH system, an internal tree cap is not used. • Tree cap: The tree cap in a VXT system has the functions of providing the control interfaces during workover and sealing the tree from seawater ingress. An HXT, in contrast, has internal tree caps and tree debris caps. These differences are illustrated in Figure 22-23. Figure 22-23 Differences between VXTs and HXTs (Courtesy of Vetco Gray) Subsea Wellheads and Trees 739 22.4.5.2. Tubing Hanger In a subsea well, production tubing is supported and sealed off inside the subsea wellhead housing. The tubing hanger and the running tool necessary to install it comprise a tubing hanger system. On wells with subsea wellheads, the subsea tubing hangers are run and landed through the marine riser and the subsea BOP stack with a full drilling fluid/completion fluid column in place. On wells that have been mudline suspended, the subsea tubing hangers are landed in a tubing head through a casing riser and a surface BOP stack. The basic functions of a tubing hanger are as follows: • Suspend the tubing string(s) at the mudline level. • Seal the annulus between the tubing and casing. • Provide access to the annulus. • Provide a through conduit(s) for SCSSV control, chemical injection, and monitoring. • Provide an interface with the subsea tree. Three factors characterize the basic tubing hanger system for a subsea well: • Location: wellhead/tubing hanger spool/tree body; • Size and designation: nominal wellhead size: 183/4, 163/4, or 135/8 in.; production casing size: 103/4, 95/8 , 75/8, or 7 in.; tubing string size: 23/8 , 31/2 , 41/2 , and 51/2 in. are typical; • Lockdown method: The mechanical set tubing hanger is run on a drill pipe tool and set by rotation. The hydraulic set tubing hanger, run on a completion riser, is set by a hydraulic tool driving a lock ring into a lockdown groove. Tubing Hanger Types All tubing hanger systems can be summarized into two categories: • Concentric bore or nonorienting tubing hanger; • Multibore or orienting type of tubing hanger system. Concentric tubing hanger has a single central bore, threaded box down to make up to a single tubing string. The upper part of the tubing hanger body will have a central seal pocket to receive the mating male stab sub from the subsea production tree. The tubing hanger is lowered into position with a running tool that is connected mechanically or hydraulically to the tubing hanger body ID. The running string may be the drill pipe, tubing, or a custom-designed completion string with integral tubing strings and control lines. See the left side o Figure 22-24. 740 Y. Bai and Q. Bai Figure 22-24 Concentric and Multibore Tubing Hangers (Courtesy of Dril-Quip) The multibore, or orienting, tubing hanger incorporates the bore tubing hanger system. It also incorporates two or more pockets in the tubing hanger body for communications to multiple tubing strings and multiple stab receptacles, to maintain control over downhole equipment. The multibore tubing hanger allows the operator to enter the annulus from directly overhead, through an annulus bore in the tree, to the tubing hanger and tubing/ equipment downhole. This capability makes the tubing hanger orientation specific with respect to the tree. See the right side of Figure 22-24. In a horizontal tree system, the tubing hanger configuration is normally of the concentric type, with a production outlet beside (see Figure 22-25). The tubing hanger assembly consists of the hanger body, lockdown sleeve, locking dogs, gallery seals, pump down seal, electrical penetrator receptacle, bottom dry mate connector, and pup joint. There are four basic sizes of tubing hanger: 31/2, 4, 5, and 7 in. nominal. Penetration Configuration Figure 22-26 shows a typical tubing hanger penetration configuration. The number of control ports through the tubing hanger depends on: • How many SCSSV there are and whether they are balanced or unbalanced. A balanced SCSSV requires two control lines, whereas an unbalanced valve needs only one. • Downhole pressure/temperature monitors (electric connector at the tubing hanger/tree extension sub interface). An electric cable extends Subsea Wellheads and Trees 741 Figure 22-25 Horizontal Tubing Hanger Section View Figure 22-26 Typical Tubing Hanger Penetration Configurations below to the bottom of the tubing string where a sensing device is located. For example, a typical configuration would include: • Downhole injection: 1 Hyd. • SCSSV: 2 Hyd. • Smart well hydraulics: 2 Hyd. 742 Y. Bai and Q. Bai • Soft landing: 1 Hyd. • Downhole gauges: 1 or 2 Elec. Tubing Hanger Running Tool The tubing hanger running tool (THRT) is used to run the tubing hanger (TH) into the tree body. The THRT should have a balanced piston design with equivalent cross-sectional areas to prevent annulus pressure from acting to unlock the THRT from the TH and to ensure that the THRT remains locked even upon loss of hydraulic pressure during installation or workover operations. The system design should be configured to prevent hydraulic locking of the seals during installation/retrieval of the THRT to/from the TH and slick joint. A THRT is illustrated in Figure 22-27. 22.4.5.3. Tree Piping Tree piping is defined as all pipe, fittings, or pressure conduits, excluding valves and chokes, from the vertical bores of the tree to the flowline connections. The piping may be used for production, pigging, monitoring, injection, servicing, or testing of the subsea tree. Inboard tree piping is upstream of the first tree wing valves. Outboard tree piping is downstream of the first tree wing valve and upstream of the flowline connector. Tree piping is normally designed in accordance with ASME B31.3 [8]. The guidelines in the API specifications are general and in many case open to interpretation. It is up to the manufacturer to apply the engineering judgment. 22.4.5.4. Flowline Connector A flowline connector is used to connect subsea flowlines and umbilicals via a jumper to the subsea Xmas tree. In some cases, the flowline connector also provides the means for disconnecting and removing the tree without retrieving the subsea flowline or umbilical to the surface. Figure 22-28 shows a horizontal flowline connector system. Flowline connectors generally come in three types: manual connectors operated by divers or ROVs, hydraulic connectors with integral hydraulics, or mechanical connectors with the hydraulic actuators contained in a separate running tool. The flowline connector system may utilize various installation methods, such as first-end or second-end connection methods. It may be either diverless or diver assisted and may utilize guidelines/guideposts to provide guidance and alignment of the equipment during installation. Subsea Wellheads and Trees 743 Figure 22-27 Tubing Hanger Running Tool (THRT) (Courtesy of Dril-Quip) The flowline connector support frame reacts to all loads imparted by the flowline and umbilical. Tree valves and tree piping are protected from flowline/umbilical loads, which could damage these components. Alignment of critical mating components is provided and maintained during installation. Trees can be removed and replaced without damage to critical mating components. The flowline connector support frame is designed to 744 Y. Bai and Q. Bai Figure 22-28 Flowline Connector (Courtesy of FMC) allow landing a BOP stack on the wellhead housing after the flowline connector support frame is installed. 22.4.5.5. Tree Connectors Tree connectors are used to land and lock the subsea Xmas tree to a subsea wellhead. They provide mechanical and pressure connections as well as orientation between the tree assembly and the wellhead. Mechanical tree connectors are generally diver actuated using a series of screws to energize a locking mechanism. Connectors of this type are suitable for type S (simple) and DA (diver assist) trees run from jack-ups and not recommended for trees run from floaters. Hydraulic tree connectors were originally designed as modified hydraulic drilling BOP connectors. However, current tree designs utilize a connector that is specifically designed for subsea applications. The connector offers additional features not normally present on the BOP H-4 style connector, such as a mechanical override for release and a backup mechanical lock. Hydraulic connectors are the most common type of tree connector. They are suitable for all tree types. Figure 22-29 illustrates the H4 hydraulic connector from Vetco Gray. 22.4.5.6. Tree Valves Subsea Xmas tree contains various valves used for testing, servicing, regulating, or choking the stream of produced oil, gas, and liquids coming up from the well below. Figure 22-30 shows a typical tree valve arrangement and configuration. Subsea Wellheads and Trees 745 Figure 22-29 Hydraulic Tree Connector (Courtesy of Vetco Gray) The production flow coming from the well below passes through the downhole safety valve (DHSV), which will shut down if it detects an accident, leak, or overpressure occurring. Production master valves (PMVs) provide full opening during normal production. Usually these valves are high-quality gate valves. They must be capable of holding the full pressure of the well safely for all anticipated purposes, because they represents the second pressure barrier (the first is the DHSV). A production choke is used to control the flow rate and reduce the flow pressure. The annulus master valve (AMV) and annulus access valve (AAV) are used to equalize the pressure between the upper space and lower space of the tubing hanger during the normal production (i.e., when the DHSV is open). Located in the crossover loop, a crossover valve (XOV) is an optional valve that, when opened, allows communication between the annulus and production tree paths, which are normally isolated. An XOV can be used to allow fluid passage for well kill operations or to overcome obstructions caused by hydrate formation. The production swab valve (PSV) and annulus swab valve (ASV) are open when interventions in the well are necessary. 746 Y. Bai and Q. Bai Figure 22-30 Configuration of Tree Valves Subsea Xmas tree valves should be designed, fabricated, and tested in accordance with API 17D [2], API 6A [6], and API 6D [9]. The valves can be both bolted on or built in. 22.4.5.7. Production Choke A production choke is a flow control device that causes pressure drop or reduces the flow rate through an orifice. It is usually mounted downstream of the PWV in a subsea Xmas tree in order to regular the flow from the well to the manifold. It can also be mounted on the manifold. Figure 22-31 shows the subsea choke in a subsea Xmas tree. The two most widely used choke types are positive chokes and adjustable chokes. The adjustable choke can be locally adjusted by a diver or adjusted remotely from a surface control console. They normally have a rotary stepping hydraulic actuator, mounted on the choke body. This adjusts the size of orifice at the preferred value. Chokes have also been developed to be installed and retrieved by ROV tools without using a diver. Subsea Wellheads and Trees 747 Figure 22-31 Subsea Choke (Courtesy of Cameron and MasterFlo) In addition, the insert-retrievable choke leaves the housing in place, while the internals and the actuator are replaceable units. Trims/Orifices Types Typical orifices used are of the disk type or needle/plug type. The disk type acts by rotating one disk and having one fixed. This will ensure the necessary choking effect. The needle/plug type regulates the flow by moving the insert and thereby providing a gap with the body. The movement is axial. Figure 22-32 shows all of the trim/orifice types per ISO 13628-4 [5]. Choke Design Parameters Several measurements must be known in order to select the proper choke for a subsea production system: how fast the flow is coming into the choke, the inlet pressure P1 of the flow, the pressure drop that occurs crossing the orifice, and the outlet or downstream pressure P2 of the flow, as shown in Figure 22-33. Figure 22-32 Trim Types 748 Y. Bai and Q. Bai Figure 22-33 Choke Schematic (Courtesy of Cameron) Choke sizing is determined by coefficient value (Cv), which takes into account all dimensions as well as other factors, including size and direction changes, that affect fluid flow in a choke. The Cv equals number of gallons of per minute that will pass through a restriction (orifice) with a pressure drop of 1 psi at 60C. This Cv calculation normally follows Instrument Society of America (ISA) guidelines. Pressure is maintained through the tree piping as P1. When the flow crosses the orifice of the choke, the pressure drops. But soon the pressure will recover to a level (P2). The process is illustrated in the Figure 22-34. The pressure drop is determined by the equation DP ¼ P1 – P2 (inlet pressure minus outlet pressure). The DP ratio, DPR, is considered the most important parameter for evaluating and ensuring the success of the subsea field development project. This ratio is determined as DPR ¼ DP/P1, which used to measure the capacity and recovery of the choke. The higher the value of DPR, the higher the potential damage to the choke trim or body. Normally a special review of the trim is required if DPR is beyond 0.6. Figure 22-34 Pressure Drop in a Choke (Courtesy of Cameron) Subsea Wellheads and Trees 749 22.4.5.8. Tree Cap Tree caps are designed to both prevent fluid from leaking from the wellbore into the environment and small dropped objects from getting into the mandrel. Designs are very different between HXTs and VXTs. Tree caps are usually designed to be recoverable for easy maintenance. The debris cap covers the top of the tree spool. It is installed, locked, unlocked, released, and recovered via ROV-assisted operations. See Figure 22-35. An internal tree cap is designed to latch onto the spool body above the tubing hanger and seal off the area above the tubing hanger to the maximum rated working pressure. It is installed through the marine riser and latches full within the bore of the horizontal tree and should provide primary metal-to-metal and secondary elastomeric seals to isolate the internal tree from the environment. Figure 22-36 illustrates a configuration for an ROVoperated internal tree cap. 22.4.5.9. Tree Frame The tree frame is designed to protect critical components on the tree from objects falling from the surface. It also provides structural mounting for: • Tree body; • Tree valves; • Subsea control module (SCM); • Choke; • Tree piping; Figure 22-35 Tree Debris Cap 750 Y. Bai and Q. Bai Figure 22-36 ROV-Operated Tree Cap (Courtesy of FMC) • • • • • Flowline connectors; Tree connector; Flying leads and connections; ROV panel; Anodes. Guidance and orientation systems are designed for the tree frame in order to land the tree on the production guide base or a template. The tree frame is designed to protect the tree components during handling on the surface and subsea running and retrieving operations. Its strength and entire weight are calculated and checked to ensure these operations can be completed successfully. The subsea tree frame must be designed with no snag points or sharp edges that may cut or entangle the ROV tether or control umbilical. 22.4.6. Tree-Mounted Controls 22.4.6.1. Subsea Control Model (SCM) The subsea control module is the interface between the control system and the tree. It is the main component of the tree-mounted control system. The Subsea Wellheads and Trees 751 SCM contains electronics, instrumentation, and hydraulics for safe and efficient operation of subsea tree valves, chokes, and downhole valves. Other tree-mounted equipment includes various sensors and electrical and hydraulic connectors. The SCM consists of a rectangular housing containing control valves, sensors, and electronic models. The lower base plate is integral with the tree frame, providing the interface with all of the hydraulic functions. The SCM is usually filled with a dielectric fluid that acts as a second barrier against ingress of seawater. Figure 22-37 shows a configuration for a typical SCM. Within a project, it is best to standardize on one SCM design for all trees. For more information about SCMs, see Chapter 7. 22.4.6.2. Pressure and Temperature Transmitters Tree-mounted sensors include pressure and temperature sensors (or combined), which are placed in the annulus and production bore and upstream and downstream of the choke. Figure 22-37 SCM Configuration 752 Y. Bai and Q. Bai A pressure transmitter (PT) is normally used for a force-balanced technique, in which the current required by a coil resists the movement of the detecting diaphragm, giving a measure of applied pressure. The accuracy of 0.15% can be achieved. Usually a redundant PT is provided as it is flange mounted, which is impossible to replace if it fails. A temperature transmitter (TT) is normally operated by measuring the output of the thermocouple, which is a simple device whose output is proportional to the difference in temperature between a hot and a cold junction. The hot junction is the one measuring itself and the cold one is at the head itself. A pressure and temperature transmitter (PTT), as shown in Figure 22-38, is designed to combine the pressure and temperature element into one package. The temperature sensor is in a probe, which is designed to be flush mounted into the process pipe. This also helps reduce errors due to hydrate formation. The two devices are electrically independent. Figure 22-38 PTT Located on a Subsea Xmas Tree Subsea Wellheads and Trees 753 22.4.7. Tree Running Tools Running tools for subsea Xmas trees should be designed according to the tree configuration, depending on the project. The function of a hydraulic or mechanical subsea Xmas tree running tool (TRT) is to support the tree during installation and/or retrieval from the subsea wellhead. It may also be used to connect the completion riser to the tree during installation, testing, or workover operations. Figure 22-39 shows a TRT being tested onshore. Subsea Xmas tree running tools are normally hydraulically actuated if they cannot be weight or tension activated. Hydraulic tools can have hydraulic signals designed to satisfy the function. The theory is that no pressure loss will occur or leak will be detected if reaching the running tool function. 22.4.8. Subsea Xmas Tree Design and Analysis 22.4.8.1. Chemical Injection Chemical injection and MeOH injection requirements should be determined by flow assurance, in order to provide hydrate remediation. If the production tubing uses CRA material and HH trim material was used in the tree, then downhole chemical injection may not be necessary. If tree chemical injection is necessary to prevent corrosion from the tree and downstream, then an injection point downstream of the production master valve should be provided. Chemical injection valves are small-sized hydraulic-actuated gate valves with a check. Figure 22-39 Tree Running Tool (Courtesy of Dril-Quip) 754 Y. Bai and Q. Bai Typical chemical injection points in subsea Xmas tree systems are as follows: • One into production bore upstream of production wing valve; • One into production bore downstream of production wing valve; • One into production bore downstream of production choke; • One into annulus bore downstream of annulus master valve. Figure 22-40 shows an example of subsea Xmas tree chemical injection design. 22.4.8.2. Cathodic Protection Cathodic protection is electrochemical protection that functions by making the metal surface of an electrochemical cell into a cathode that can decrease the corrosion potential to an acceptable level. The corrosion rate of the metal is also significantly reduced. Corrosion control of subsea Xmas tree systems should be achieved through the application of CP in conjunction with coatings. Selection of the CP type is influenced by considerations of availability of electrical power, dependability of the overall system, and the total protective current required. Generally the galvanic anode system is more widely used in subsea Xmas tree systems. Figure 22-40 Example of Chemical Injection Design for Subsea Xmas Tree Subsea Wellheads and Trees 755 To apply CP to subsea Xmas tree systems, the following design features are recommended: • All submerged metallic components are connected electrically to the base housing to ensure cathodic protection of the complete assembly. Items such as pressure caps that cannot be fully or easily connected electrically should be analyzed individually and have independent protection. The surface areas of all submerged components are calculated and input into the sacrificial anode calculations. • All submerged components exposed to seawater, except for the stainless steel control tubing, junction plates, control couplers, etc., are coated with a subsea three-coat epoxy system. • To achieve a cost-effective corrosion control program for each subsea structure, it may be beneficial to allow a certain amount of the structure to remain uncoated. The repair of minor coating damage may be eliminated if the cathodic protection system design accounts for the additional bare surface area. The bare or uncoated area should be protected by the inclusion of additional galvanic anodes. Detailed design and calculation of current demand, selection of anodes, and anode mass and number are designed according to DNV RP B401 [10]. 22.4.8.3. Insulation and Coating The trees and wellhead, as well as well jumpers, manifolds, flowline jumpers, and associated equipment, require corrosion coatings and thermal insulation to enable sufficient cooldown time in the event of a production stoppage. The main objectives of thermal insulation are: • Have sufficient time to confidently perform the preservation sequence at any operation condition. • Avoid dramatic consequences of hydrate formation with associated production losses. • Solve the shutdown problem and avoid the burden of the launching preservation sequence with associated production losses The insulation system includes a layer of corrosion coating suitable for working temperature on the steel surface. This corrosion coating is applied in accordance with the manufacturer’s specifications. Areas that require insulation are specified in the engineering drawings. Areas that are not to be insulated because insulation will be detrimental to the function of the components are marked or adequately protected during installation process. 756 Y. Bai and Q. Bai 22.4.8.4. Structural Loads The tree connector, tree body, tree guide frame, and tree piping must be designed to withstand internal and external structural loads imposed during installation and operation. The following are some tree and tree component load considerations: • Riser and BOP loads; • Flowline connection loads; • Snagged tree frame, umbilicals or flowlines; • Thermal stresses (trapped fluids, component expansion, pipeline growth); • Lifting loads; • Dropped objects; • Pressure-induced loads, both external and internal. Non-pressure-containing structural components should be designed in accordance with AWS D1.3 [11]. The tree framework is usually designed around standard API post centers (API RP 17A [12]). This is typically, but not always true, even if the tree is designed to be guideline-less. API defines the position of four guideposts evenly spaced around the well centerline at a 6-ft radius. This equates to 101.82 in. between the posts on any side of the square corners that they form. 22.4.8.5. Thermal Analysis The thermal behavior of subsea Xmas trees in a subsea production system is important because it is necessary to: • Avoid hydrate formation both in transient states (shutdown/restart) and flowing conditions; • Improve productivity, because a lower temperature implies higher viscosity, which jeopardizes well productivity. Cold spots could be defined as system components in which insulation is difficult to implement resulting in an insulation discontinuity that creates, by nature, a thermal bridge. Industry experiences have highlighted difficulties in properly modeling the effect of cold spots. Their impact is often underestimated, which can have major impact on the thermal performance of subsea equipment. A thermal leak is the result of heat transfer by a conduction mechanism (i.e., reduced insulation thickness, hydraulic or chemical injection line penetration through insulation, pipe support, valve actuator, sensor), convection mechanism (applies to a design where a volume of water is enclosed inside the insulation, mainly connectors), or both. Subsea Wellheads and Trees 757 Figure 22-41 Subsea Xmas Tree Thermal Analysis Using FEA [13] FEA is typically used to analyze the insulated components to illustrate that they meet the thermal insulation criteria. The components can be analyzed individually or together in a system model. Adjacent effects from neighboring components must be considered with care if two or more components are analyzed together. Figure 22-41 show the thermal analysis using FEA. 22.4.9. Subsea Xmas Tree Installation Subsea Xmas trees can be installed either with a drill pipe or with the cable of a crane/winch, as shown in Figure 22-42. The typical size of a tree is 12 ft  12 ft  12 ft and typical weight is 20 to 50 tonne. This size allows trees to be installed through a moon-pool if the tree is already on the deck of a drilling vessel. Otherwise the tree will be transported by a transportation barge. The tree is lifted with the deck crane and lowered subsea. Because the cable of 758 Y. Bai and Q. Bai Figure 22-42 Tree Installation by Drill Pipe (Left) and Rig Winch (Right) a crane is normally 200 to 300 m long, for deep water, the tree will be transferred to a rig winch, which has wire lengths of up to 1000 m. As introduced in Chapter 5, the installation vessel for a subsea Xmas tree can be a jack-up, semisubmersible, or drill ship, based on the water depth of the system, as illustrated in Figure 22-43. In a VXT configuration, the tubing hanger and downhole tubing are run prior to installing the tree, whereas for an HXT the tubing hanger is typically landed in the tree, and hence the tubing hanger and downhole tubing can be retrieved and replaced without requiring removal of the tree. By the same token, removal of an HXT normally requires prior removal of the tubing hanger and completion string. Figure 22-43 Installation Vessels Subsea Wellheads and Trees 759 VXT systems are run on a dual-bore completion riser (or a monobore riser with bore selector located above the LRP and a means to circulate the annulus, usually via a flex hose from the surface). The TH of an HXT is run on casing tubular joints, thereby saving the cost of a dual-bore completion riser; however, a complex landing string is required to run the TH. The landing string is equipped with isolation ball valves and a disconnect package made especially to suit the ram and annular BOP elevations of a particular BOP. Guidance of trees onto the subsea wellhead is usually performed by guidelines that go from the surface to the PGB of wellhead. Guide wires are pushed into the guideposts of the tree and the tree is then lowered subsea. However, the guidelines are usually used in water depths of less than 500 m, because of the limit of wire length on the rig. For deeper water depths, a DP vessel, which uses thrusters to keep the vessel in location, may be needed to land and lock the tree onto the wellhead. Typical procedures for installing a vertical Xmas tree via a drill pipe through a moon-pool are as follows (see Figure 22-44): • Perform preinstallation tree tests. • Skid tree to moon-pool. • Push guide wires into tree guide arms. • Install lower riser package and emergency disconnect package (EDP) on tree at moon-pool area. • Connect the installation and workover control system (IWOCS). • Lower the tree to the guide base with tubing risers, as shown in sequence 1 of Figure 22-44. • Lock the tree onto the guide base. Test the seal gasket. • Perform tree valve function tests with the IWOCS. • Retrieve the tree running tool. Figure 22-44 Vertical Xmas Tree Installation by Drill Pipe 760 Y. Bai and Q. Bai • • • • Run the tree cap on the drill pipe with the utility running tool system. Lower the tree cap to the subsea tree, as shown in sequence 2. Land and lock the tree cap onto the tree mandrel, as shown in sequence 3. Lower the corrosion cap onto the tree cap with a drill pipe (or lifting wires). Some suppliers have developed ROV-installed corrosion caps (see sequence 4). Typical procedures for installing a horizontal Xmas are given next. As the tubing hanger is installed in the tree, subsea completions are performed during tree installation (see Figure 22-45): • Complete drilling. • Retrieve the drilling riser and BOP stack; move the rig off. • Retrieve drilling guide base. • Run the PGB and latch onto the wellhead. • Run the subsea HXT. Figure 22-45 Horizontal Xmas Tree Installation Process (Courtesy of Schlumberger) Subsea Wellheads and Trees 761 • Land the tree, lock the connector, test seal function valves with an ROV, release tree running tool (TRT). • Run the BOP stack onto the HXT; lock the connector. • Run the tubing hanger; perform subsea well completion; unlatch the THRT. • Run the internal tree cap by wireline through the riser and BOP; retrieve THRT. • Retrieve BOP stack. • Install debris cap. • Prepare to start the well. REFERENCES [1] G.R. Samuel, G. Adolfo, Optimization of Multistring Casing Design with Wellhead Growth, Landmark Drilling & Well Services, SPE Paper 56762 (1999). [2] American Petroleum Institute, Specification for Subsea Wellhead and Christmas Tree Equipment, first ed., API Specification 17D, 1992. [3] A.S. Halal, R.F. Mitchell, Casing Design for Trapped Annulus Pressure Buildup, Drilling and Completion Journal (June 1994) 107. [4] H. Matlock, L.C. Reese, Generalized Solutions for Laterally Loaded Piles, Journal of the Soil Mechanics and Foundations Division, ASCE, Vol. 86, No SM5, pp. 63–91, (1960). [5] International Standards Organization, Design and Operation of Subsea Production System - Subsea Wellhead and Tree Equipment, ISO, 13628–4, (2007). [6] American Petroleum Institute, Petroleum and Natural Gas Industries d Drilling and Production Equipment d Wellhead and Christmas Tree Equipment, nineteenth ed., API, 6A, (2004). [7] National Association of Corrosion Engineers, Petroleum and Natural Gas Industries Material for Use in H2S-Containing Environments in Oil and Gas Production, NACE MR0175 (2002). [8] American Society of Mechanical Engineers, Process Piping, ASME, B31.3, (2008). [9] American Petroleum Institute, Specification for Pipeline Valves, API, 6D, (2008). [10] DNV Recommend Practice, Cathodic Protection Design, DNV, RP B401, (2005). [11] American Welding Society, Structural Welding Code – Sheet Steel, AWS, D1.3, (2008). [12] American Petroleum Institute, Recommended Practice for Design and Operation of Subsea Production Systems, API, 17A, (2002). [13] K.A. Aarnes, J. Lesgent, J.C. Hubert, Thermal Design of Dalia SPS Deepwater Christmas Tree – Verified by Use of Full – Scale Testing and Numerical Simulations, OTC 17090, Offshore Technology Conference, Houston, Texas, 2005.