MINIMUM WELLHEAD REQUIREMENTS

Transcription

1 MINIMUM WELLHEAD REQUIREMENTS AN INDUSTRY RECOMMENDED PRACTICE () FOR THE CANADIAN OIL AND GAS INDUSTRY VOLUME 5 Edition 2 Sanction Nov Date 2011

2 COPYRIGHT/RIGHT TO REPRODUCE Copyright for this Industry Recommended Practice is held by Enform, All rights reserved. No part of this may be reproduced, republished, redistributed, stored in a retrieval system, or transmitted unless the user references the copyright ownership of Enform. DISCLAIMER This is a set of best practices and guidelines compiled by knowledgeable and experienced industry and government personnel. It is intended to provide the operator with advice regarding the specific topic. It was developed under the auspices of the Drilling and Completions Committee (DACC). The recommendations set out in this are meant to allow flexibility and must be used in conjunction with competent technical judgment. It remains the responsibility of the user of this to judge its suitability for a particular application. If there is any inconsistency or conflict between any of the recommended practices contained in this and the applicable legislative requirement, the legislative requirement shall prevail. Every effort has been made to ensure the accuracy and reliability of the data and recommendations contained in this. However, DACC, its subcommittees, and individual contributors make no representation, warranty, or guarantee in connection with the publication of the contents of any recommendation, and hereby disclaim liability or responsibility for loss or damage resulting from the use of this, or for any violation of any legislative requirements. AVAILABILITY This document, as well as future revisions and additions, is available from Enform Canada Street NE Calgary, AB T2E 8N4 Phone: Fax: Website:

3 Publication Correction Request form for: all Enform Safety Services published documents Enform welcomes comments at any time on any of these documents. Comments are considered on the basis of clarity, intent, accuracy, or omissions. All comments are passed on to the committee chair or held until the next scheduled review, as appropriate. If you have any comments or suggestions on how we can improve this, please let us know by filling out this form. This form can be submited by or fax. Contact Contact Title Company Address Phone No (no spaces) Fax No (no spaces) If you belong to an Association, please select the appropriate Member Association City Province Postal Code Country Comments Select document Correction type: Correction/administrative Technical Broken link Page #, Section: Description of suggested change: Reasons/rationale for suggestion: Fax Enform Street, Calgary, AB T2E8N

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5 Table of Contents Preface... vii Scope and Forward... vii Revision Process... ix Sanction... ix Acknowledgements... x Copyright Permissions... x 5.1. Wellhead Components and Considerations Background on Oil and Gas Wells Casing Tubing Instrument and Control Lines Types of Wells Component Requirements Applicable to All Wellheads Manufacturing Requirements (API / ISO compliance) Salvaged Wellhead Component Requirements Pressure Rating Requirements Full Bore Access Requirements Pressure Relief Access on Side Outlets Basic Components of a Wellhead Casing Head Casing Spool Casing Hangers Packoff Flange Tubing Head Tubing Hanger Tubing Head Adaptor Christmas Tree Connections Seals Sweet Flowing Wells Below 13.8 MPa Above 13.8 MPa Low Pressure / Low Risk Gas Wells Critical Sour, Sour and Corrosive Wells Critical Sour Wells Sour Wells Corrosive Flowing Wells Artificial Lift Wells November 2011 Page i

6 Reciprocating Rod Pump Progressing Cavity Pump (PCP) Plunger Lift Electric Submersible Pump Hydraulic Pump Gas Lift Velocity String Coiled Tubing Other Well Types Injection or Disposal Thermal Operations Cavern Storage Well Observation Well Other Strings (not part of well flow) Environmentally Sensitive Areas Cold Climate Considerations Wellhead Implementation General Responsibilities in Wellhead Implementation Determining Wellhead Requirements Required Information Gathering Transmitting required data for wellhead design Competency requirements for wellhead design Wellhead Installation Contractor Competency and Compliance Pre-Spud Meeting Installation Personnel Installation Procedures Pressure Testing Connections and Seals Installation Considerations Post-Installation Requirements Wellhead Protection Wellhead Intervention On-Site Audit Intervention Plan Contractor Competency and Compliance Pre-Intervention Meeting Dismantling Procedures Make-up Procedures Shallow Gas Well Intervention Requirements Post-Intervention Requirements Monitoring and Maintenance Documented Maintenance Schedule and Procedure Wellhead Pressure Testing Rod Pumping Well Maintenance Pressure Shut Down System Maintenance Procedure for Closing Gate Valves Page ii 05 November 2011

7 Weld Repair of Threaded Components Wellhead Requirements for Suspended Wells Appendix A - Flange/Ring dimensions Appendix B - Trim Selection Chart Appendix C: API 6A Table 2 - Temperature Ratings Appendix D: Table 1 from ERCB Directive 013: Suspension Requirements for Wells Acronyms References November 2011 Page iii

8 List of Figures Fig ure 1. Simplified Diagram of Casing and Tubing... 2 Fig ure 2. Wellhead Basics... 3 Fig ure 3. Well Types*... 7 Fig ure 4. Casing Heads Fig ure 5. Casing Spool Fig ure 6. Casing Hangers Fig ure 7. Packoff Flanges Fig ure 8. Tubing Head Fig ure 9. Tubing Head Threaded by Threaded or Welded Fig ure 10. Tubing Head Flanged by Threaded or Welded Fig ure 11. Tubing Hangers Fig ure 12. Extended Neck Tubing Hanger Fig ure 13. Back Pressure Valves Fig ure 14. Tubing Head Adaptors Fig ure 15. Christmas Tree for Flowing Well Fig ure 16. Christmas Tree on Rod Pumping Well Fig ure 17. Christmas Tree on Dual Completion Well Fig ure 18. Example of Slip-On Weld (Cross Section) Fig ure 19. Example of Butt Weld (Cross Section) Fig ure 20. Example of Valve Removal Threading on Side Outlet Fig ure 21. Clamp Hub Fig ure 22. Sliplock Casing Head Examples Fig ure 23. Roll-On Coiled Tubing Connection Fig ure 24. API Metal Ring Gasket Styles Fig ure 25. Wellheads for Sweet Flowing Well ( 13.8 MPa) Fig ure 26. Wellhead for High Pressure Sweet Flowing Well Fig ure 27. Simplified Wellhead for Low Pressure / Low Risk Gas Wells Fig ure 28. Non-Critical Sour Well Example Fig ure 29. Integrated Pollution Control Stuffing Box and BOP Fig ure 30. Wellhead for PCP Pump Fig ure 31. Plunger Lift System Fig ure 32. Wellhead for Electric Submersible Pump (ESP) Fig ure 33. Coiled Tubing Hangers Fig ure 34. Basic Injection Wellhead Fig ure 35. Integral Flow-Tee BOP Fig ure 36. Simple Steam Injection Wellhead for SAGD Fig ure 37. Additional Example of SAGD Wellhead for Rod Pumping Fig ure 38. Example of Cyclic Steam (CSS) Wellhead Fig ure 39. Cavern Storage Wellhead Page iv 05 November 2011

9 List of Tables Revision History... ix Range of Obligation... x Table 1: Injection Material November 2011 Page v

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11 PREFACE SCOPE AND FORWARD The s for Minimum Wellhead Requirements have been crafted with one prime goal in mind to ensure safe and successful control and containment of fluids and pressure from drilling to abandonment. This is only possible when wellhead design, installation, operation, and maintenance fit the actual well conditions over the entire life cycle of a well. ISO/FDIS defines a wellhead as all the permanent equipment between the uppermost portion of the surface casing and the tubing head adaptor connection. This, however, will adopt a wider, more generic definition that also includes components attached to the wellhead to meet well control requirements. Hence all components and related equipment from the top of the outermost casing string up to but excluding the flowline valve will be considered part of the "wellhead" in this. This will also, at times, consider components managed through the wellhead to the extent they impact wellhead design and operation. The ultimate function of a wellhead is to contain and control the flow of liquids, gases and solids during the drilling, completion, workover, and ongoing operation of the well. A wellhead needs to provide: A securely sealed surface termination for the various well casing strings. Necessary access to annular spaces. A means of suspending or installing production tubing and other subsurface equipment required to operate the well. A secure platform for installing surface flow control components and other equipment. And easy access for well servicing or other interventions. Well designs and operations continue to evolve and this cannot provide a recommendation for every possible present or future application. Instead, this will approach wellhead requirements from two perspectives. First, it will provide an introduction to wellhead components and major variations in wellhead design that are driven by reservoir and well operating considerations and conditions. Second, it will serve as a guide to wellhead implementation, providing recommendations for: 05 November 2011 Page vii

12 Assigning responsibilities in wellhead installation, intervention, and maintenance Determining wellhead requirements Installing and protecting wellheads Intervention operations Monitoring and maintaining wellheads Maintaining wellheads on suspended wells This document will cover a range of petroleum industry well types including: Flowing wells Artificial lift wells Injection and disposal wells Monitoring and observation wells Other wells that require special considerations with respect to wellhead design or components This document will not include extensive recommendations regarding wellheads for critical sour wells and heavy oil (conventional and thermally stimulated) wells because wellhead requirements for those well types are specifically addressed in Volume 2 Completing and Servicing Critical Sour Wells and Volume 3 In Situ Heavy Oil Operations. The s presented here are based on engineering judgement, accepted good practices and experience. The establishment of these minimum requirements does not preclude the need for industry to exercise sound technical judgement in the application and maintenance of wellheads. Every effort has been made to ensure completeness, accuracy and reliability of the data contained in this publication. The Drilling and Completion Committee (DACC), its subcommittees and individual members make no representations, warranty or guarantee in connection with this publication or any Industry Recommended Practice () herein and hereby disclaim liability of responsibility for loss or damage resulting from the use of this, or for any violation of any statutory or regulatory requirement with which an may conflict. In cases of inconsistency or conflict between any of these s and applicable legislative requirements, the legislative requirements shall prevail. The subcommittee does not endorse the use of any particular manufacturer s product. Any descriptions of product types or any schematics of components which may bear resemblance to a specific manufacturer s product are provided strictly in the generic sense. Page viii 05 November 2011

13 REVISION PROCESS s are developed by the Drilling and Completions Committee (DACC) with the involvement of both the upstream petroleum industry and relevant regulators. s provide a unique resource outside of direct regulatory intervention. This is the second version of 5 (first published in 2002). Technical issues brought forward to the DACC, as well as scheduled review dates, can trigger a reevaluation and review of this, in whole or in part. For details on the specific process for the creation and revision of s, visit the Enform website at Revision History Edition Sanction Date Scheduled Review Date Remarks/Changes 1 June was initially published in June, November was fully revised. It was sanctioned by DACC on November 2011 and published on May SANCTION The following organizations have sanctioned this document: British Columbia Oil and Gas Commission Canadian Association of Oilwell Drilling Contractors Canadian Association of Petroleum Producers Energy Resources Conservation Board (Alberta) International Intervention and Coil Tubing Association (Canada) Petroleum Services Association of Canada Saskatchewan Energy and Resources Small Explorers and Producers Association of Canada 05 November 2011 Page ix

14 ACKNOWLEDGEMENTS This Industry Recommended Practice () is a set of best practices and guidelines, compiled by knowledgeable and experienced industry and government personnel and is intended to provide the operator with recommendations regarding Minimum Wellhead Requirements. Throughout this document the terms must, shall, should, may, and can are used as indicated below: Range of Obligation Term Must Shall Should May Can Usage A specific or general regulatory and /or legal requirement An accepted industry practice or provision that the reader is obliged to satisfy to comply with this A recommendation or action that is advised An option or action that is permissible within the limits of the Possibility or capability COPYRIGHT PERMISSIONS This includes documents or excerpts of documents as follows, for which permission to reproduce has been obtained: Copyrighted Information Used in Permission from API 6A Table 2 Temperature Ratings Appendix D API Page x 05 November 2011

15 5.1. WELLHEAD COMPONENTS AND CONSIDERATIONS BACKGROUND ON OIL AND GAS WELLS The earliest wells dug by hand to access shallow, fresh water sources pre-date 5000 BC. Since water levels were often below surface and the water was withdrawn by hand only as required, the wells were lined with wood, stones or bricks to reduce sloughing and contamination and left open to the environment. Early oil wells date back about 1500 years and many were simple pits or excavations. By 1000 AD, drilled depths of over 200 m were achieved and wood (e.g., bamboo) was being used to cap or contain the fluid and pipeline production to where it was needed. The first "modern" wells were drilled in the mid-late 1800s and although these simple wells still were lined with wood, they now were capped by an assortment of fittings. This progression from "open air" to enclosed wellheads reflected the increased utilization of wells and needs to safely manage the resource and contain fluids which were able to flow to surface. Current-day wells have evolved from these modest beginnings. Today s wells still provide for the unaided (flowing) recovery of fresh water or sweet hydrocarbons from a single, shallow formation. However, they also enable a wide range of operations that include geo-thermal energy, liquid and gas storage, sour production, various types of injections, and enhanced recovery of artificially-lifted reserves. In spite of different well types and operations, some features are common. All wells are lined with steel pipe, known as casing, to allow unobstructed access to the target reservoir. Up to four casing strings may be installed and each string is cemented in place to mechanically support the pipe and hydraulically isolate the target reservoir from groundwater sources and other formations. Most wells also include one or more strings of pipe or tubing to recover or produce the reservoir fluids, to inject fluid into the reservoir, or to allow other well operations. All wells are capped by an assembly of steel pipe and fittings known as the wellhead. The wellhead s function is to contain the reservoir or well fluid and to allow safe access to the casing and tubing for the life of the well. In the following illustrations, it is clear that the function of the wellhead above the wellbore is fundamentally linked to the function of the various strings of casing and tubing that run down inside the wellbore. Each of the components in the following diagram will be explained in greater detail below. 05 November 2011 Page 1

16 Figure 1. Simplified Diagram of Casing and Tubing Production Tubing Production Casing Surface Casing Wellhead seals and isolates each of these, allowing access and controlling flow to and from tubing and casing annulus Ground Level Drilled Wellbore Fresh More complex wells may have additional intermediate casing strings between the surface casing and production casing (which run to surface and are sealed in wellhead) or (which are sealed to previous casing downhole) Production Tubing Cement Cement Oil or Gas in Formation Page 2 05 November 2011

17 Figure 2. Wellhead Basics 05 November 2011 Page 3

18 Casing A "typical" basic well is installed with one or two strings of casing (each cemented into place) plus a short length of conductor pipe (see above, Figure 1). Conductor pipe is set to prevent sloughing and water influx while drilling through the soft and generally weak material near surface. It may also capture and enable the recirculation of drilling mud during subsequent drilling operations. Conductor pipe is: Typically set at a depth of less than 30 metres Cut off at ground level Light weight and is not used to support any permanent wellhead equipment Equipped with a mounted diverter system in the early stages of certain drilling operations that carry a heightened risk of shallow gas kicks Surface casing, where required, is installed to isolate the uppermost part of the well and to ensure the integrity of the wellbore while drilling deeper. Once the surface casing is landed, the casing is cemented to the borehole wall. The first wellhead components are then attached and begin their function as a well control device. Surface casing is: The "foundation" of the well, providing the platform on which the wellhead is mounted and securing the existing hole for subsequent drilling Easily recognizable as the first and outermost casing string More common in deeper or high pressure wells or where there is a requirement to isolate shallower fresh water from deeper salt water sources or hydrocarbons Production Casing is set across or on top of the target formation and, as with all casing strings, it is cemented into place. It is always tied back to surface where wellhead components seal and isolate the annular space between the production casing and the previous casing string. The wellhead also offers outlets to access the inside of the production casing. Production casing is the string through which larger well servicing operations are conducted and the well completion equipment is set. In those instances where surface casing is not installed, the production casing will be cemented from final total depth (FTD) to the surface. Page 4 05 November 2011

19 Production casing may: Serve as the platform on which the wellhead is mounted when surface casing is not installed. House production tubing or other tubulars and lines run down hole from the wellhead at the surface. This creates an accessible annular space that runs from the wellhead to the target formation. Conduct produced fluid to the surface in some cases (e.g., commonly used as the production string for gas in sweet, shallow wells where production tubing may not be used). Provide an annulus to vent gases in pumping wells. Serve as a conduit for injection purposes in certain cases, most notably steam injections or pressured gas in a gas lift system. Additional Casing Strings may be required to isolate intermediate formations (intermediate casing) or to support or provide additional strength for production operations (production liner). These may be found in deep or complex wells or in shallow horizontal wells where a liner may serve as production casing. These additional strings can be sealed to a previously cemented casing string or cemented and tied back to surface. If tied back to surface, the wellhead is designed to accommodate and support the additional strings Tubing In most wells, a single tubing string is the main conduit for bringing reservoir fluid to the surface or injecting fluid from the surface into the target formation. Additional tubing string(s) may be required if the formation has more than one interval that is being accessed and the fluids from the different intervals need to be kept separate from each other. Multiple tubing strings may also be used in the event a long reservoir section requires access at two or more locations. Special well monitoring needs may also require additional tubing strings. Each tubing string: Is supported from the wellhead May be free hanging, anchored or sealed against the cemented casing string Multiple tubing strings: Can be run concentrically (each inside the previous tubing) Can be in parallel with each string on a separate hanger 05 November 2011 Page 5

20 Instrument and Control Lines Wellheads also provide safe, sealed access for small diameter tubing or electric lines that may be installed to monitor well operating conditions, inject chemicals, operate flow control devices, or power artificial lift equipment. The wellhead serves to suspend, isolate, and support these lines Types of Wells The main types of wells are shown in Figure 3. Each of these well types will create different requirements in terms of wellhead design. Page 6 05 November 2011

21 Figure 3. Well Types* *A full page download of this diagram is available on the 5 landing page 05 November 2011 Page 7

22 Flowing wells rely on reservoir pressure to lift production to surface. Flowing wellheads typically are simple. Some, however, will support multiple tubing strings, monitoring or control lines. Depending on the type of produced fluids and well completion, production can be up the production casing, production tubing, or the tubing-casing annulus. o Sweet, low pressure, low risk wells (e.g., shallow gas) often do not have a tubing string installed. Artificial Lift is used when well conditions are insufficient to lift reservoir fluids to the surface at the rate required. The flowing style of wellhead must be modified to accept equipment specific to each lift system. o o o o Reciprocating rod pump: Requires a polished rod blowout preventer (BOP) and stuffing box. Progressing cavity pump (PCP): Requires a polished rod BOP and stuffing box. The wellhead also provides the platform on which the PCP drivehead and any required electric motors are mounted. Electric submersible pump: Requires a sealed electric line feedthrough. Plunger Lift: Requires a plunger catcher assembly. In other types of lift, the wellhead configuration is identical or very similar to that of the flowing wells. o o Gas lift: High pressure lift gas is injected either into the tubing or the tubing-casing annulus. Hydraulic Jet or Piston Pump: Hydraulic fluid is injected down through a tubing string and a combination of hydraulic and production fluids are produced either through an additional tubing string or the tubingcasing annulus. Injection and disposal wells are often configured like flowing wells. Wellheads in these cases may be configured with a tubing string that is isolated from the casing for the injection of fluids or solids. In other cases, material may be injected via the production casing. Once pressured, injection and disposal wells function as a flowing well and must be configured as such. Cavern or storage wells require a separate spool or tubing head to allow the large diameter tubing string to be raised and lowered, as required, to store or recover fluid. Within these main categories individual wellhead designs can vary significantly based on the types of fluid or other materials handled, the flow velocities, pressures, Page 8 05 November 2011

23 and temperatures encountered. Well production and servicing operations over the entire life cycle of the well also impact design COMPONENT REQUIREMENTS APPLICABLE TO ALL WELLHEADS In North America, the American Petroleum Institute (API) provides key manufacturing standards for wellhead components, and wellhead components that are certified to API standards carry an API stamp. Wellhead equipment that meets API Specification 6A (equivalent to ISO 10423) is available in standard pressure increments: o o o o o o o 13.8 MPa (2000 psi) 20.7 MPa (3000 psi) 34.5 MPa (5000 psi) 69.0 MPa (10,000 psi) MPa (15,000 psi) MPa (20,000 psi) 207 MPa (30,000 psi) Standard temperature ratings are defined by an operating range. o Conventional operations span -60 to 121⁰C in 8 ranges (K, L, P, R, S, T, U, V). K and U are the largest and overlap the other ranges. o Elevated temperature operations span -18 to 345⁰C in 2 ranges (X, Y). Y has the highest temperature rating. Material Class defines the corrosion resistance required by all components wetted by the retained fluid. The seven material classes range from AA (General service: carbon or low alloy steel) to HH (Sour service: corrosion resistant alloys). All sour service materials must conform to ANSI/NACE MR0175/ISO (NACE International provides control standards related to corrosion protection). Product Service Level (PSL) defines the degree of testing applied to the wellhead component. o PSL-1 is the baseline. PSL-2, PSL-3, PSL-3G, and PSL-4 include additional and ever more stringent requirements to confirm component suitability for challenging operations (e.g. high pressure, elevated temperature, sour) Manufacturing Requirements (API / ISO compliance) REG All wellhead and Christmas tree components must be manufactured in compliance with API Specification 6A, latest edition (currently Twentieth Edition; equivalent to ISO 05 November 2011 Page 9

24 10423: 2009) and all current supplements, and shall bear the API monogram. Wellhead equipment not included in the scope of API Specification 6A / ISO 10423, current edition (such as stuffing boxes, rod BOPs, electrical feed through equipment, and coiled tubing components) shall be designed, manufactured and tested in accordance with the same material specifications and quality assurance procedures, including traceability requirements, as API/ISO certified wellhead components Salvaged Wellhead Component Requirements Note: Salvaged wellhead components shall not be reused unless they are restored and certified for the intended service by the Original Equipment Manufacturer (OEM). There may be occasions where casing heads are reused in drilling operations. This type of reuse shall be subject to the s on reused casing heads (see Casing Head Assembly) Pressure Rating Requirements REG Note: Note: Note: The API / ISO rating on all wellhead and Christmas tree components must meet or exceed the maximum anticipated service conditions. Even though the equipment is pressure tested by an OEM beyond its API/ISO rating, the API stamp remains the standard for which the equipment is rated. At new wells, the maximum anticipated bottom hole pressure (BHP) shall be included in these service conditions since well production, injection, or servicing operations could result in a full column of dry gas being present from the (open) formation interval to surface. In this case, the full reservoir pressure could be seen at surface. At existing wells where the operating and servicing conditions are well known and a full column of gas cannot occur (e.g., wells on artificial lift at lower Gas/Oil Ratio [GOR] high Water/Oil Ratio [WOR]) the bottom hole pressure does not need to be included in the anticipated service conditions. In the event that the regulator approved casing of the well has a burst rating that is less than the BHP, operators may consult with their respective regulators regarding requirements. Page November 2011

25 REG In the event maximum anticipated service conditions change or the actual BHP exceeds wellhead and Christmas tree component design, the operator must replace or upgrade the wellhead with appropriate equipment Full Bore Access Requirements Wellhead components shall allow full bore access to the casing to which they are connected. This allows for the setting of permanent and retrievable packers and facilitates well suspension and/or abandonment. Wellhead and Christmas tree components, including the master valve, should allow full bore access to the tubing to which they are connected. This facilitates the running and retrieval of full bore equipment Pressure Relief Access on Side Outlets Side outlets on the wellhead should have pressure relief access, such as tapped bull plugs with needle valves. The blind flange opposite the wing valve on a flow cross or tee and side outlets on the casing head are exempt from this recommendation BASIC COMPONENTS OF A WELLHEAD A wellhead is made up of a series of components that are connected and sealed in various ways. In this section, the following key components of a wellhead (from bottom to top) are covered. Bear in mind not every wellhead requires all of these components since the need for each depends on the type of well, the well completion, and expected operation. Casing Head Casing Spool Casing Hangers Packoff Flange Tubing Head Tubing Hanger Tubing Head Adaptor Christmas Tree This section also covers: Connections (by type) Seals (by composition and type) These key components, connections and seals are described in sub-sections which also note the function and provide s specific to the item under consideration. 05 November 2011 Page 11

26 Casing Head The casing head, also referred to as a casing bowl, is the lowest part of the wellhead assembly. The bottom of the casing head is configured to attach to the casing below (typically, the surface casing). The upper inside of the casing head provides a bowl in which the next casing string can be set and sealed (if required). The top of the casing head then connects to the next wellhead component. The method of connecting the casing head to the surface casing below or the next component above is subject to operational and regulatory considerations and is covered in Connections and Seals. A casing head may also be supplied with a landing base plate that takes the weight load off the surface casing and spreads it over the conductor pipe. Access to the annulus between the surface casing and the next casing string is available through side outlets. Page November 2011

27 Figure 4. Casing Heads 05 November 2011 Page 13

28 The function of the casing head is to: Isolate the inside of the surface casing from the outside environment. Provide a platform for and a means to test the rig BOP stack during drilling and well servicing operations. Support or transfer the weight of drilling and workover equipment during drilling and well servicing operations. Allow for suspending and packing off the next casing string (i.e., intermediate or production casing). This is accomplished by setting a casing hanger and seal against the recessed profile machined into the upper inside surface (bowl). The hanger often is held in place by lockdown screws and the seal thus formed against the casing string is called the primary seal. Provide access to the surface inner casing annulus for monitoring and fluid return purposes. Access to the annulus is available through side outlets drilled through the casing head. After the well is completed, one of the side outlets may be converted to a surface casing vent. This can then be used to monitor any flows or pressure build up of gas, water or hydrocarbon liquids within the surface casing annulus. These can indicate a failure in the integrity of the inner casing cement, production casing, or annular seals that may present an environmental hazard. REG Note: REG Where surface casing is set, regulations require the installation of a surface casing vent that remains on the well until well abandonment. Any exemption to this requirement can only be achieved by contacting regulatory bodies. See also Low Pressure / Low Risk Gas Wells. A casing head must have at least one threaded, flanged, or studded side outlet with a valve. In certain operations, regulators may require two outlets with a valve. In Alberta, Class I-IV wells require one outlet, while Class V-VI require two (ERCB Directive 036: Drilling Blowout Prevention Requirements and Procedures [February 2006], ). British Columbia follows a similar pattern (BC Oil & Gas Commission, Well Drilling Guideline [Version 1.4; 2011], ). In Saskatchewan, two side outlets are mandatory (The Oil and Gas Conservation Regulations, 1985, 60.1.c-d.). Check with the appropriate regulatory bodies for mandated requirements on the number of side outlets. In drilling operations in which wear is a concern, a wear bushing and sleeve should be inserted into the casing head to protect its inner surfaces from damage from the drill string. Page November 2011

29 The casing head shall be equipped with a landing base plate that spreads the weight load to the conductor pipe whenever the weight load created by the inner casing string(s), the tubing string(s), and the wellhead could cause the surface casing to collapse. Any casing head re-used in a drilling operation should be carefully inspected and pressure tested between drilling operations. Note that excludes the use of salvaged or re-used casing heads for permanent use apart from OEM recertification. Welded casing heads that are re-used for temporary operations shall be subjected to a hardness check between each operation to ensure ongoing materials integrity and compatibility for additional welding. Operators re-using casing heads in temporary operations shall have a written procedure for the tracking and qualified inspection of all used casing heads in order to verify they are fit for purpose Casing Spool If a well includes one or more intermediate casing strings between the surface and production casing, the next component required after the casing head is the casing spool. The bottom of the casing spool mounts on top of a casing head or previous spool, and the top connects to the next spool or tubing head assembly. The spool is designed so the bottom bowl or counterbore will allow a secondary seal to be set on the previous casing string, while the top bowl will hold a casing hanger to suspend and allow a primary seal around the next string of casing. Multiple casing spools may be used, one on top of the other, to hang intermediate casing strings and the final production casing string. 05 November 2011 Page 15

30 Figure 5. Casing Spool The function of the casing spool assembly is to: Allow for a secondary seal on the previous casing string in the counterbore. With a secondary seal in place, flange or hub seals and casing hanger seals are isolated from internal casing pressure. Provide a port for pressure testing primary and secondary casing seals and flange connections (see below Primary and Secondary Seals in Seal Types). Provide a platform to support, seal and pressure test the BOP during drilling and well servicing operations. Provide a load shoulder and controlled bore in the top bowl to support the next casing hanger and enable a primary seal for the next intermediate or production casing. Provide annular access for fluid returns or fluid injections and pressure monitoring, through side outlets drilled in the spool assembly. Casing spools with a flanged connection shall provide a test port to enable a pressure test between the primary and secondary seal. This test will determine if the seals are holding pressure and that the annulus remains isolated. Page November 2011

31 Casing Hangers Both casing heads and casing spool assemblies may require the use of casing hangers. Casing hangers attach to the end of a given casing string and suspend and seal the casing string in the top bowl of a casing head or spool. Casing hangers come in two main varieties: Slip type hangers that are installed around the casing after it is run, either before or after the casing is cemented into place. o Slip type casing hangers are used as a contingency when pipe is stuck, allowing the casing to be cut off and set where it sits. Mandrel type hangers that are threaded onto the casing. o Mandrel type casing hangers provide superior well control when landing the hanger and improve the annular seal. When a casing hanger is used, shallow intermediate strings are usually suspended from the hanger and then cemented to surface. Longer intermediate and production strings that are not cemented to surface are usually cemented while the casing is suspended in tension from the rig traveling block. After the cement has set for a few hours, the traveling block pulls a calculated tension on the casing above the cement and it is at this point the hanger is set in the bowl. Casing hangers are often called slips or seals as they are designed with built-in seals. Slips may occasionally be run without seals in shallow wells where a primary seal is then installed whenever the BOP or Christmas tree is removed. A hanger may also be held in-place in the upper bowl of a casing head or spool assembly by the use of lock-down (also called hold-down) screws. 05 November 2011 Page 17

32 Figure 6. Casing Hangers Page November 2011

33 The function of the casing hanger is: To suspend the load of the casing string from the casing head or spool. To center the casing in the head. To provide a primary seal against the inside of the casing head and isolate the casing annulus pressure from upper wellhead components. Slip type casing hangers should be available in operations that are designed for mandrel type casing hangers. In the event of a stuck pipe, the slip type casing hanger may be required to land the stuck pipe Packoff Flange A packoff flange is rarely used. It is set above a casing head or spool assembly and also sealed against the intermediate or production casing to enable a safe increase in pressure rating between the casing head or spool and any wellhead equipment above the flange, for example, a tubing head. It is also known as a restricted packoff flange or crossover flange. Figure 7. Packoff Flanges As wellheads are now typically initially designed for the life of the well, packoff flanges are not commonly used. Wells are designed such that all components are rated to bottom hole pressure (BHP). However, in certain operations, such as well re-entry for drilling purposes, a new, unanticipated level of pressure may be 05 November 2011 Page 19

34 introduced to the production casing. In some cases it is advantageous to leave the original casing head assembly in place. There are two methods of dealing with this scenario. API standards allow for a single jump in pressure increments between components. Technically, given proper isolation and casing strength, one could mount a 20.7 MPa Tubing Head assembly on a 13.8 MPa Casing Head or Casing Spool. The other device for managing increased pressures in a re-entry is with a packoff flange which can be placed between wellhead components. A packoff flange may also be used in temporary operations such as pressure testing primary seals or as a safety device when drilling out the cement that remains in the shoe joint (or float collar ). REG Note: A packoff flange shall only provide one jump in API pressure range. Any component providing a jump in API pressure range must provide a primary and secondary seal with test ports. Here are two examples of how a pressure jump can be accomplished: 1. The new pressure in the production casing is expected to jump from 10 MPa to 30 MPa on a well with a 13.8 MPa Casing Head and Tubing Head. Solution: A packoff flange on the casing head that provides a transition from 13.8 MPa to 20.7 MPa. The tubing head is upgraded to 34.5 MPa. 2. The new pressure in the production casing is expected to jump from 10 MPa to 40 MPa on a well with a 13.8 MPa Casing Head and Tubing Head. Solution: A packoff flange on the casing head that provides a transition from 13.8 MPa to 20.7 MPa. Another packoff flange on top of the previous that provides a transition from 20.7 MPa to 34.5 MPa. The tubing head is upgraded to 69.0 MPa Tubing Head The tubing head assembly provides a means to suspend and seal the production tubing in the wellhead. The tubing head is the top spool in the wellhead assembly and is installed after the last casing string is set. The bottom of the tubing spool includes a counterbore that can be used to set a seal against the production casing. The top of the tubing head provides a landing shoulder and a seal bore for landing and enabling a seal to the tubing hanger. Above the tubing head is the tubing head adaptor which provides a transition to the Christmas tree. Page November 2011

35 Figure 8. Tubing Head The function of the tubing head assembly is to: Enable the suspension of the tubing. Allow for sealing the annulus between the tubing and the production casing. Allow access to the annulus between the tubing and production casing, through side outlets. Provide a means to support and test the service rig BOP during well completions. Provide a bit guide for running the tubing without causing damage to the production casing. With certain varieties of tubing heads, it also functions to: Allow a secondary annulus seal to be set around the top of the production casing. Provide access for a test port to test primary and secondary seals. Ensure safe running and retrieving of tubing hangers in high pressure operations (e.g., snubbing operations). Allow for correct orientation of equipment to enable running multiple tubing strings. 05 November 2011 Page 21

36 Tubing heads come in three basic connection configurations. Well type and conditions are used to determine which type of tubing head is most appropriate for the operation. 1. Top connection threaded; bottom connection threaded or welded. Figure 9. Tubing Head Threaded by Threaded or Welded The use of thread on by thread on, or thread on by weld on tubing heads should be limited to low pressure gas or oil wells. With this type of configuration, the tubing hanger is typically held in by a hammer cup and, as such, it does not offer lock screws for tubing hanger retention. As a result it offers no secondary seal and the tubing cannot be landed under pressure. Furthermore, a workover flange needs to be installed in order to install a BOP stack. Page November 2011

37 2. Top connection flanged; bottom connection threaded or welded. Figure 10. Tubing Head Flanged by Threaded or Welded Flanged top by thread on or weld on tubing heads may be used for re-entry operations, new shallow gas or oil wells, and thermal operations such as cyclic steam injection (CSS/"huff and puff") and steam assisted gravity drainage (SAGD). The flanged top in this configuration offers advantages over threaded configurations, including lock screws for tubing hanger retention, that allow tubing to be run under pressure. It also provides an annulus between production casing and tubing with outlets that can be line piped, clamped, flanged or studded. However, its limitations also need to be considered. It does not provide a secondary seal on the production casing and hence no ability to pressure test between the production casing and the previous casings string (typically surface casing). 3. Top and bottom connection flanged or clamp hub (see above Figure 10. Tubing Head). Tubing heads with flanged or clamp hub connections top and bottom may be used in any operation. 05 November 2011 Page 23

38 Tubing heads with flanged or clamp hub connections top and bottom should be used in any operations in which there are requirements to pressure test the annulus between production casing and the previous casing string, and the need to run multiple tubing strings. This is the best configuration whenever there is a requirement to safely run operations in full pressure situations. It is also the only configuration that is supplied to meet API PSL 1 through PSL 4 requirements Tubing Hanger A tubing hanger is also commonly known as a dog nut. A tubing hanger typically is threaded onto the top of a tubing string and is designed to sit and seal in the tubing head. Usually the tubing hanger is run through the BOP and landed in the top bowl of the tubing head. The top of the tubing hanger provides a profile necessary for the lock screws that will secure the hanger in the tubing head. In a simple, single string completion the hanger carries the weight of the tubing and the tubing is hung in neutral. In other completions where the tubing casing annulus must be isolated from the fluid handled (e.g., produced water injection or disposal wells), different intervals must be isolated from each other, or gas will be injected to enhance fluid production (i.e., in a gas lift well), hanger design must also consider the use of a downhole packer where the tubing may be set in compression, tension or neutral, and upward (compression) forces may be placed on the tubing string during production or injection operations. Tubing hanger design / hold downs also should consider the dynamic loads that can be applied in artificial lift wells by the reciprocating motion of a rod string and torque induced at the start-up and shut-down of ESPs and PCPs. Page November 2011

39 Figure 11. Tubing Hangers 05 November 2011 Page 25

40 Standard, single or dual tubing hangers with seal rings or elastomers provide a seal between the tubing hanger and tubing head below the lock down screws. Extended neck tubing hangers allow for a primary and secondary seal on the tubing hanger. In this configuration, a secondary seal packs off inside the tubing head adaptor. As a result, the lock down screws are isolated from the well bore fluids and the primary and secondary seals can be pressure tested. Extended neck tubing hangers are required for sour wells and possibly corrosive wells (see below Sour Wells and Critical Sour, Sour and Corrosive Wells). Because tubing head components and seals are uniquely exposed to production and injection fluids, special consideration needs to be given to the metallurgy and elastomer seal selection (see below Injection or Disposal Considerations, Table 1: Injection Material). Page November 2011

41 Figure 12. Extended Neck Tubing Hanger 05 November 2011 Page 27

42 Figure 13. Back Pressure Valves Tubing hangers may come with a back pressure thread profile that enables the operator to lubricate an isolation plug into the tubing hanger. With an isolation plug in place, pressure testing can now be carried out above the tubing head. It also provides well control for installing and removing the BOP or Christmas Tree, and for temporary well suspensions. Slip type tubing hangers still exist in the field. However, these should not be used in new or retrofit installations as slips do not provide a seal or allow adequate well control Tubing Head Adaptor The tubing head adaptor provides a transition from the tubing head to the Christmas tree. With a basic tubing head configuration where the tubing hanger is seated in the top of the tubing head, the bottom of the tubing head adaptor will seal against the tubing head and contain reservoir or injection fluids moving through the top of the tubing. With an extended neck tubing hanger, the adaptor will provide a secondary seal against the hanger, isolating the seal between tubing head and adaptor and any lock screws holding the tubing hanger in place. As such, this configuration provides a means to test the primary and secondary seals on the tubing hanger. Page November 2011

43 Figure 14. Tubing Head Adaptors 05 November 2011 Page 29

44 See further Sour Wells and Critical Sour, Sour and Corrosive Wells for recommendations on the use of extended neck tubing hangers Christmas Tree A Christmas tree is an assembly of gate valves, chokes and fittings included with the wellhead during well completion. The Christmas tree provides a means to control the flow of fluids produced from or fluids injected into the well, at surface. While Christmas trees come in a variety of configurations based on a number of well design and operating considerations, typically the bottom connection of the tree matches the top connection of the tubing head adaptor and these are generally installed as a unit, immediately after production tubing is suspended. Figure 15. Christmas Tree for Flowing Well Page November 2011

45 Figure 16. Christmas Tree on Rod Pumping Well 05 November 2011 Page 31

46 Figure 17. Christmas Tree on Dual Completion Well Page November 2011

47 Typical Christmas tree components on a flowing, gas lift, or injector well can be seen in Figure 15. These components include: A minimum of one master valve that will control all flows to and from each tubing string. Under certain service conditions and well pressures, additional master valves. o The upper valve is typically used in routine operations while the lower valve provides backup and the ability to service the upper valve as the need arises. A tee or cross leading to control valves such as production gate valves, surface safety valves, flow control valves or chokes Potentially a swab valve above the tee that permits vertical access to the wellbore. A tree cap that might be fitted with a pressure gauge. The tree cap provides quick access to the tubing bore for bottom hole testing, installing down hole equipment, swabbing, paraffin scraping, and other thru-tubing well work. A Christmas tree may be modified based on well operating conditions, fluids produced and recovery methods. In the case of an assisted lift well that requires a rod string to run through the Christmas tree (e.g., reciprocating rod pumping or PCP, see Figure 16), the configuration is adjusted as follows: The master valve is either removed or incapacitated to prevent accidental closure. The addition of a polished rod BOP that can be closed around the polished rod to seal fluid and pressure in the wellhead if required. The polished rod BOP may be activated either manually or hydraulically. The addition of a stuffing box that provides a seal around the moving polished rod during operations. The inclusion of an environmental BOP that seals across the tubing bore in the event a polished rod breaks and is pulled or ejected out of the stuffing box. It may be integrated into the stuffing box itself or be installed as a separate component above or below the stuffing box. Note: Gate valves, such as the master valves and swab valves of the Christmas tree or annulus valves attached to the side outlets of the casing head, casing spools or tubing head, are on/off control devices designed to be operated in either the fully open or fully closed position. These gate valves shall not be used as throttle devices. Flow control valves or chokes can be used to regulate the flow of liquids and gas into or out of a well. While technically these components lie outside the scope of 5, when used correctly, they can optimize recovery and minimize tree and flowline damage caused by erosion and cavitation. Good operating and monitoring 05 November 2011 Page 33