Minimum Wellhead Requirements

Edition 2

Sanction Nov Date 2011

MINIMUM WELLHEAD REQUIREMENTS

AN INDUSTRY RECOMMENDED PRACTICE (IRP) FOR THE CANADIAN OIL AND GAS INDUSTRY

VOLUME 5

COPYRIGHT/RIGHT TO REPRODUCE

Copyright for this Industry Recommended Practice is held by Enform, 2012. All rights reserved. No part of this IRP may be reproduced, republished, redistributed, stored in a retrieval system, or transmitted unless the user references the copyright ownership of Enform.

DISCLAIMER

This IRP 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 IRP are meant to allow flexibility and must be used in conjunction with competent technical judgment. It remains the responsibility of the user of this IRP to judge its suitability for a particular application.

If there is any inconsistency or conflict between any of the recommended practices contained in this IRP 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 IRP. However, DACC, its subcommittees, and individual contributors make no representation, warranty, or guarantee in connection with the publication of the contents of any IRP recommendation, and hereby disclaim liability or responsibility for loss or damage resulting from the use of this IRP, or for any violation of any legislative requirements.

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IRP 05 – November 2011 Page i

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....................... 1

5.1.1 Background on Oil and Gas Wells ................................................... 1

5.1.1.1 Casing ............................................................... 4 5.1.1.2 Tubing ............................................................... 5 5.1.1.3 Instrument and Control Lines ................................ 6 5.1.1.4 Types of Wells ..................................................... 6

5.1.2 Component Requirements Applicable to All Wellheads ....................... 9

5.1.2.1 Manufacturing Requirements (API / ISO compliance)9 5.1.2.2 Salvaged Wellhead Component Requirements ....... 10 5.1.2.3 Pressure Rating Requirements ............................ 10 5.1.2.4 Full Bore Access Requirements ............................ 11 5.1.2.5 Pressure Relief Access on Side Outlets ................. 11

5.1.3 Basic Components of a Wellhead .................................................. 11

5.1.3.1 Casing Head ..................................................... 12 5.1.3.2 Casing Spool ..................................................... 15 5.1.3.3 Casing Hangers ................................................. 17 5.1.3.4 Packoff Flange................................................... 19 5.1.3.5 Tubing Head ..................................................... 20 5.1.3.6 Tubing Hanger .................................................. 24 5.1.3.7 Tubing Head Adaptor ......................................... 28 5.1.3.8 Christmas Tree .................................................. 30 5.1.3.9 Connections ...................................................... 34 5.1.3.10 Seals ............................................................... 46

5.1.4 Sweet Flowing Wells ................................................................... 50

5.1.4.1 Below 13.8 MPa................................................. 51 5.1.4.2 Above 13.8 MPa ................................................ 52 5.1.4.3 Low Pressure / Low Risk Gas Wells ...................... 53

5.1.5 Critical Sour, Sour and Corrosive Wells ......................................... 55

5.1.5.1 Critical Sour Wells ............................................. 55 5.1.5.2 Sour Wells ........................................................ 56 5.1.5.3 Corrosive Flowing Wells ...................................... 58

5.1.6 Artificial Lift Wells ...................................................................... 59

Page ii IRP 05 – November 2011

5.1.6.1 Reciprocating Rod Pump ..................................... 60 5.1.6.2 Progressing Cavity Pump (PCP) ........................... 63 5.1.6.3 Plunger Lift ....................................................... 64 5.1.6.4 Electric Submersible Pump.................................. 66 5.1.6.5 Hydraulic Pump ................................................. 68 5.1.6.6 Gas Lift ............................................................ 68 5.1.6.7 Velocity String .................................................. 69 5.1.6.8 Coiled Tubing .................................................... 69

5.1.7 Other Well Types ........................................................................ 70

5.1.7.1 Injection or Disposal .......................................... 70 5.1.7.2 Thermal Operations ........................................... 73 5.1.7.3 Cavern Storage Well .......................................... 78 5.1.7.4 Observation Well ............................................... 79 5.1.7.5 Other Strings (not part of well flow) ..................... 79 5.1.7.6 Environmentally Sensitive Areas .......................... 80 5.1.7.7 Cold Climate Considerations ............................... 80

5.2. Wellhead Implementation .............................................. 81

5.2.1 General Responsibilities in Wellhead Implementation ...................... 81

5.2.2 Determining Wellhead Requirements ............................................ 82

5.2.2.1 Required Information Gathering .......................... 82 5.2.2.2 Transmitting required data for wellhead design ..... 85 5.2.2.3 Competency requirements for wellhead design ...... 85

5.2.3 Wellhead Installation .................................................................. 85

5.2.3.1 Contractor Competency and Compliance............... 85 5.2.3.2 Pre-Spud Meeting .............................................. 86 5.2.3.3 Installation Personnel ......................................... 86 5.2.3.4 Installation Procedures ....................................... 87 5.2.3.5 Pressure Testing Connections and Seals ............... 90 5.2.3.6 Installation Considerations .................................. 91 5.2.3.7 Post-Installation Requirements ............................ 92

5.2.4 Wellhead Protection .................................................................... 92

5.2.5 Wellhead Intervention ................................................................. 93

5.2.5.1 On-Site Audit .................................................... 93 5.2.5.2 Intervention Plan ............................................... 93 5.2.5.3 Contractor Competency and Compliance............... 93 5.2.5.4 Pre-Intervention Meeting .................................... 94 5.2.5.5 Dismantling Procedures ...................................... 94 5.2.5.6 Make-up Procedures .......................................... 95 5.2.5.7 Shallow Gas Well Intervention Requirements ........ 96 5.2.5.8 Post-Intervention Requirements .......................... 96

5.2.6 Monitoring and Maintenance ........................................................ 96

5.2.6.1 Documented Maintenance Schedule and Procedure 96 5.2.6.2 Wellhead Pressure Testing .................................. 96 5.2.6.3 Rod Pumping Well Maintenance ........................... 97 5.2.6.4 Pressure Shut Down System Maintenance ............ 97 5.2.6.5 Procedure for Closing Gate Valves ....................... 99

IRP 05 – November 2011 Page iii

5.2.6.6 Weld Repair of Threaded Components .................. 99

5.2.7 Wellhead Requirements for Suspended Wells ................................. 99

Appendix A - Flange/Ring dimensions. ................................. 101

Appendix B - Trim Selection Chart ........................................ 105

Appendix C: API 6A Table 2 - Temperature Ratings .............. 107

Appendix D: Table 1 from ERCB Directive 013: Suspension Requirements for Wells ................................................ 109

Acronyms ............................................................................. 113

References ........................................................................... 114

Page iv IRP 05 – November 2011

List of Figures Fig ure 1. Simplified Diagram of Casing and Tubing ............................................... 2Fig ure 2. Wellhead Basics .................................................................................. 3Fig ure 3. Well Types* ....................................................................................... 7Fig ure 4. Casing Heads ................................................................................... 13Fig ure 5. Casing Spool .................................................................................... 16Fig ure 6. Casing Hangers ................................................................................ 18Fig ure 7. Packoff Flanges ................................................................................ 19Fig ure 8. Tubing Head..................................................................................... 21Fig ure 9. Tubing Head Threaded by Threaded or Welded ..................................... 22Fig ure 10. Tubing Head Flanged by Threaded or Welded ..................................... 23Fig ure 11. Tubing Hangers .............................................................................. 25Fig ure 12. Extended Neck Tubing Hanger .......................................................... 27Fig ure 13. Back Pressure Valves ....................................................................... 28Fig ure 14. Tubing Head Adaptors ..................................................................... 29Fig ure 15. Christmas Tree for Flowing Well ........................................................ 30Fig ure 16. Christmas Tree on Rod Pumping Well ................................................ 31Fig ure 17. Christmas Tree on Dual Completion Well ............................................ 32Fig ure 18. Example of Slip-On Weld (Cross Section) ........................................... 36Fig ure 19. Example of Butt Weld (Cross Section) ................................................ 36Fig ure 20. Example of Valve Removal Threading on Side Outlet ........................... 39Fig ure 21. Clamp Hub ..................................................................................... 41Fig ure 22. Sliplock Casing Head Examples ......................................................... 43Fig ure 23. Roll-On Coiled Tubing Connection ...................................................... 45Fig ure 24. API Metal Ring Gasket Styles ............................................................ 48Fig ure 25. Wellheads for Sweet Flowing Well (≤ 13.8 MPa) .................................. 51Fig ure 26. Wellhead for High Pressure Sweet Flowing Well .................................. 52Fig ure 27. Simplified Wellhead for Low Pressure / Low Risk Gas Wells .................. 54Fig ure 28. Non-Critical Sour Well Example ......................................................... 57Fig ure 29. Integrated Pollution Control Stuffing Box and BOP ............................... 61Fig ure 30. Wellhead for PCP Pump .................................................................... 63Fig ure 31. Plunger Lift System ......................................................................... 65Fig ure 32. Wellhead for Electric Submersible Pump (ESP) .................................... 67Fig ure 33. Coiled Tubing Hangers ..................................................................... 70Fig ure 34. Basic Injection Wellhead .................................................................. 71Fig ure 35. Integral Flow-Tee BOP ..................................................................... 74Fig ure 36. Simple Steam Injection Wellhead for SAGD ........................................ 75Fig ure 37. Additional Example of SAGD Wellhead for Rod Pumping ....................... 76Fig ure 38. Example of Cyclic Steam (CSS) Wellhead ........................................... 77Fig ure 39. Cavern Storage Wellhead ................................................................. 78

IRP 05 – November 2011 Page v

List of Tables Revision History .............................................................................................. ix Range of Obligation .......................................................................................... x Table 1: Injection Material ............................................................................... 72

Minimum Wellhead Requirements

IRP 05 – November 2011 Page vii

PREFACE SCOPE AND FORWARD The IRPs 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 10423 defines a wellhead as “all the permanent equipment between the uppermost portion of the surface casing and the tubing head adaptor connection”. This IRP, 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 IRP. This IRP 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 IRP cannot provide a recommendation for every possible present or future application. Instead, this IRP 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:


Page viii IRP 05 – November 2011

• 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 IRP Volume 2 Completing and Servicing Critical Sour Wells and IRP Volume 3 In Situ Heavy Oil Operations.

The IRPs 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 (IRP) herein and hereby disclaim liability of responsibility for loss or damage resulting from the use of this IRP, or for any violation of any statutory or regulatory requirement with which an IRP may conflict. In cases of inconsistency or conflict between any of these IRPs 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.

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IRP 05 – November 2011 Page ix

REVISION PROCESS IRPs are developed by the Drilling and Completions Committee (DACC) with the involvement of both the upstream petroleum industry and relevant regulators. IRPs provide a unique resource outside of direct regulatory intervention.

This is the second version of IRP 5 (first published in 2002). Technical issues brought forward to the DACC, as well as scheduled review dates, can trigger a re-evaluation and review of this IRP, in whole or in part. For details on the specific process for the creation and revision of IRPs, visit the Enform website at www.enform.ca.

Revision History

Edition Sanction Date Scheduled Review Date

Remarks/Changes

1 June 2002 2007 IRP 5 was initially published in June, 2002

2 November 2011 2017 IRP was fully revised. It was sanctioned by DACC on November 2011 and published on May 2012.

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

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Page x IRP 05 – November 2011

ACKNOWLEDGEMENTS This Industry Recommended Practice (IRP) 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 Usage Must A specific or general regulatory and /or legal requirement Shall An accepted industry practice or provision that the reader is

obliged to satisfy to comply with this IRP Should A recommendation or action that is advised May An option or action that is permissible within the limits of

the IRP Can Possibility or capability COPYRIGHT PERMISSIONS This IRP 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


IRP 05 – November 2011 Page 1

5.1. WELLHEAD COMPONENTS AND CONSIDERATIONS

5.1.1 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.


Page 2 IRP 05 – November 2011

Figure 1. Simplified Diagram of Casing and Tubing

Oil or Gas in Formation

Wellhead seals and isolates each of these, allowing access and controlling flow to and from tubing and casing annulus

Production Tubing

Surface Casing

Production Casing

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)

Cem

ent

Cem

ent

Dri

lled

Wel

lbor

e Ground Level

Pro

du

ctio

n T

ub

ing



Figure 2. Wellhead Basics



5.1.1.1 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.



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.

5.1.1.2 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



5.1.1.3 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.

5.1.1.4 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.



Figure 3. Well Types*

*A full page download of this diagram is available on the IRP 5 landing page

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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 Reciprocating rod pump: Requires a polished rod blowout preventer (BOP) and stuffing box.

o 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.

o Electric submersible pump: Requires a sealed electric line feedthrough.

o 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 Gas lift: High pressure lift gas is injected either into the tubing or the tubing-casing annulus.

o 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 tubing-casing 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,



and temperatures encountered. Well production and servicing operations over the entire life cycle of the well also impact design.

5.1.2 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 13.8 MPa (2000 psi)

o 20.7 MPa (3000 psi)

o 34.5 MPa (5000 psi)

o 69.0 MPa (10,000 psi)

o 103.5 MPa (15,000 psi)

o 138.0 MPa (20,000 psi)

o 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 15156 (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).

5.1.2.1 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



10423: 2009) and all current supplements, and shall bear the API monogram.

IRP 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.

5.1.2.2 Salvaged Wellhead Component Requirements

IRP Salvaged wellhead components shall not be reused unless they are restored and certified for the intended service by the Original Equipment Manufacturer (OEM).

Note: There may be occasions where casing heads are reused in drilling operations. This type of reuse shall be subject to the IRPs on re-used casing heads (see 5.1.3.1 Casing Head Assembly).

5.1.2.3 Pressure Rating Requirements

REG 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.

Note: 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.

Note: 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.

Note: 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.



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.

5.1.2.4 Full Bore Access Requirements

IRP 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.

IRP 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.

5.1.2.5 Pressure Relief Access on Side Outlets

IRP 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.

5.1.3 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 IRPs specific to the item under consideration.



5.1.3.1 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 5.1.3.9 Connections and 5.1.3.10 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.



Figure 4. Casing Heads



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 Where surface casing is set, regulations require the installation of a surface casing vent that remains on the well until well abandonment.

Note: Any exemption to this requirement can only be achieved by contacting regulatory bodies. See also 5.1.4.3 Low Pressure / Low Risk Gas Wells.

REG 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], 1.2.4.). British Columbia follows a similar pattern (BC Oil & Gas Commission, Well Drilling Guideline [Version 1.4; 2011], 3.1.1.3). 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.

IRP 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.

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IRP 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.

IRP Any casing head re-used in a drilling operation should be carefully inspected and pressure tested between drilling operations. Note that IRP 5.1.2.2 excludes the use of salvaged or re-used casing heads for permanent use apart from OEM recertification.

IRP 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.

IRP 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.

5.1.3.2 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.



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 5.1.3.10.2 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.

IRP 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.



5.1.3.3 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.



Figure 6. Casing Hangers



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.

IRP 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.

5.1.3.4 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



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”).

IRP A packoff flange shall only provide one jump in API pressure range.

REG Any component providing a jump in API pressure range must provide a primary and secondary seal with test ports.

Note: 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.

5.1.3.5 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.



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.



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

IRP 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.



2. Top connection flanged; bottom connection threaded or welded.

Figure 10. Tubing Head Flanged by Threaded or Welded

IRP 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).

IRP Tubing heads with flanged or clamp hub connections top and bottom may be used in any operation.



IRP 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.

5.1.3.6 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.



Figure 11. Tubing Hangers



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 5.1.5.2 Sour Wells and 5.1.5.3 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 5.1.7.1 Injection or Disposal Considerations, Table 1: Injection Material).



Figure 12. Extended Neck Tubing Hanger



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.

IRP 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.

5.1.3.7 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.



Figure 14. Tubing Head Adaptors



See further 5.1.5.2 Sour Wells and 5.1.5.3 Critical Sour, Sour and Corrosive Wells for recommendations on the use of extended neck tubing hangers.

5.1.3.8 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



Figure 16. Christmas Tree on Rod Pumping Well



Figure 17. Christmas Tree on Dual Completion Well



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.

IRP 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.

Note: 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 IRP 5, when used correctly, they can optimize recovery and minimize tree and flowline damage caused by erosion and cavitation. Good operating and monitoring



procedures are essential. If a choke washes out, the wellhead or flowline can erode quickly to the point of failure.

This type of flow control is most applicable to naturally flowing wells. Higher rate production from wells on artificial lift should be controlled by varying the pumping speed or gas lift gas rate.

IRP If operating conditions suggest high pressure well stimulation may be required, consideration shall be given to isolation devices to protect the Christmas tree from these higher working pressures.

IRP Under more demanding operating conditions (e.g., high pressures or corrosive or erosive fluids), a block cross or tee, in conjunction with a bottom hole test adaptor should be used rather than a combination flow tee and test adapter for the top fitting on the wellhead.

See also 5.2.5.7 Shallow Gas Well Intervention Requirements for bracing requirements for shallow gas well interventions.

See also 5.2.6.5 Procedure for Closing Gate Valves for correct procedures for closing wedge and slab style gate valves.

5.1.3.9 Connections

Connections provide a secure, leak free joint between wellhead components. There are five basic connection types commonly used in wellhead design.

• Threaded • Welded • Flanged • Studded • Clamp hub

There are also other connection types that are less common, such as sliplock connections, and connections unique to coiled tubing.

Each connection type will be introduced below, their typical usage described, and any relevant IRPs or additional resources pertinent to that connection type included or referenced.



5.1.3.9.1. Threaded

With a threaded connection, components are directly threaded onto the previous component.

Threaded connections are used with, but not limited to:

• Casing head to surface casing connections • Casing head to upper wellhead components • Side outlets • Tubing hangers • Tubing heads • Adaptors • Valves • Flow tees • Pipe nipples • Bull plugs • Pressure and temperature gauges • Needle valves • Bottom hole test adapter or fluid sampling port • Polished Rod BOPs • Polished Rod Stuffing boxes • Plunger lift lubricator • Back pressure valve • Erosion (e.g. sand) or corrosion monitoring probes

Typical usage and/or limitations:

• Typically used only in lower pressures, sweet operations and for smaller diameter pipe or fittings.

Relevant IRPs, Resources or Regulations:

IRP Flanges that are threaded on, even if back welded, shall not be considered an integral flange connection.

• See 5.1.4 Sweet Flowing Wells for a description of conditions under which threaded wellhead components are acceptable.

• See Threaded Connections under 5.2.3.4 Installation Procedures for requirements related to threading procedures.

• See 5.2.6.6 Weld Repair of Threaded Components.

• In Alberta see ERCB Directive 036: Drilling Blowout Prevention Requirements and Procedures (February 2006), 1.2 Casing Bowls.

• API Spec 6A: Specifications for Wellhead and Christmas Tree Equipment

• API RP 5C1: Care and Use of Casing and Tubing

• API RP 5A3: Thread Compounds for Casing, Tubing, Line Pipe, and Drill Stem Elements





5.1.3.9.2. Welded

In a welded connection it is the weld itself that provides both a solid connection and sealing between components. With wellheads, fillet welds often are used to connect pipes or fittings of dissimilar diameters in a socket or slip-on configuration.

• A socket weld involves fillet welding the exterior surface of one component to another. For example, when connecting a section of pipe to a flange or tee fitting the pipe is recessed into the flange or tee opening and the components are welded together at the external joint. Socket welds typically are used for smaller diameter pipe and fittings.

• A slip-on weld is used for joining larger components such as the casing to the casing head. In this application a fillet weld is applied to the lower, outside connection where the casing head slips over the surface casing, and to the upper, inside connection where the surface casing terminates in the casing head. This allows for a test port between the welds to pressure test the integrity of the seals.

Figure 18. Example of Slip-On Weld (Cross Section)

A butt weld is used in most other welding applications such as connecting two lengths of pipe of the same unit weight (kg/m) and diameter. Two common uses are in joining different lengths of wellhead piping or where a casing extension or repair is required at surface, joining one length of casing to another.

Figure 19. Example of Butt Weld (Cross Section)

Piping/Casing Wall

Butt Weld

Casing Head

Fillet Welds

Casing



Welded connections are used with:

• Casing Head to Surface Casing connections • Casing Head to Upper Wellhead Components • Side Outlets • Tubing Heads • Adaptors • Valves • Flow Tees or Crosses


• This is the most common means of attaching the casing head to the casing. Depending on the type of well and regulatory requirements, the casing head might be welded to the surface, intermediate or production casing.

• This is the connection type used to attach the casing head to the surface casing if there are any concerns such as pressure rating, fluid conditions (e.g., sour gas) or environmental exposure (e.g., near a population center).

• This connection type is used extensively in thermal operations. In Cyclic Steam Stimulation (CSS) operations, for example, the entire wellhead is prefabricated in sections using socket welds at the main fittings and valves are bevelled (for welding later), flanged, or clamped-hub ends for the final assembly in the field. In the field, the casing head is welded onto the casing. Connecting steam and production lines are also welded to the wellhead piping.


• See 5.1.4.2 Above 13.8 MPa and 5.1.5.2 Sour/Corrosive Flowing Wells for a description of conditions under which welded casing heads are required.

• See 5.2.3.3 Installation Personnel for requirements related to welding personnel.

• See Welded Connections under 5.2.3.4 Installation Procedures for requirements related to welding procedures.

• In Alberta see ERCB Directive 036: Drilling Blowout Prevention Requirements and Procedures (February 2006), 1.2.

• API Spec 6A: Specification for Wellhead and Christmas Tree Equipment

• American Society of Mechanical Engineers (ASME): Boiler and Pressure Vessel Code, Section IX – Welding and Brazing Qualifications

• Canadian Standards Association (CSA) Z662 – 94 Oil & Gas Pipeline Systems

• ANSI/NACE MR0175 / ISO 15156





5.1.3.9.3. Flanged

Flanged connections involve two flanges bolted together on the exterior of the component housing. Each flange has a ring groove and the connection is made up with a ring gasket to enable a seal between the flanges.

Flanged connections may be used with:

• Casing Head to Casing Spool or BOP stack connections • Side Outlets • Casing Spools • Spacer Spools • Tubing Heads • Adaptors • Valves • Flow tees or crosses • Bottom Hole Test Adaptors • BOPs • Polished Rod Stuffing boxes • Plunger lift lubricators • Back pressure valves

Typical usage and/or limitation:

• Typically used in any high pressure (i.e., 13.8 MPa [2000 psi] to 103.5 MPa [15,000 psi]) or higher risk operations.

• Along with studded connections, flanged connections allow for the installation of a test port to meet requirements of pressure testing between primary and secondary seals.


IRP All flanged or studded side outlets on casing heads, casing spools, and tubing heads must be complete with valve removal threading to enable the installation and removal of a valve removal plug.



Figure 20. Example of Valve Removal Threading on Side Outlet

• See 5.1.4.2 Above 13.8 MPa and 5.1.5.2 Sour/Corrosive Flowing Wells for a description of conditions under which flanged, studded, or clamp hub connections are recommended.

• See Flanged, Studded, and Clamp hub Connections under 5.2.3.4 Installation Procedures for requirements related to making up flanged connections.

5.1.3.9.4. Studded

Studded connections involve one component that has studs threaded into its housing and a second component with a flange bolted to the studs. Like flanged connections, studded connections include a ring groove and are made up with a ring gasket to create a seal between the components.



Studded connections may be used with:

• Casing Head to Casing Spool or BOP stack connections • Side Outlets • Casing Spools • Spacer spools • Tubing Heads • Adaptors • Valves • Flow Tees or Crosses • BOPs • Stuffing Boxes


• Typically used in any high pressure (i.e., 13.8 MPa [2000 psi] to 207 MPa [30,000 psi]) or higher risk operations.

• Used in any operations where there are requirements to shorten the height or length of the wellhead components.

• Used in any operations where there is a need to reduce the bending moment on equipment.

• Along with flanged connections, studded connections allow for the installation of a test port to meet requirements of pressure testing between primary and secondary seals.


• See "Flanged" above for an IRP on valve removal threading applicable to both flanged and studded connections.

• See 5.1.4.2 Above 13.8 MPa and 5.1.5.2 Sour/Corrosive Flowing Wells for a description of conditions under which flanged, studded, or clamp hub connections are required.

• See Flanged, Studded, and Clamp hub Connections under 5.2.3.4 Installation Procedures for requirements related to making up studded connections.

5.1.3.9.5. Clamp Hub

A hub is the enlarged end of a wellhead component that will be used to make a connection. With a clamp hub connection, the hubs of the two components being joined are squeezed together over a seal ring or ring gasket and held in-place by a clamp. The two clamp halves wrap around the hub and are bolted to each other to a specified torque to provide the required connection strength and seal rating.



Figure 21. Clamp Hub

Clamp hub connections may be used with most wellhead components such as:

• Casing Heads • BOP Stacks • Side Outlets • Casing Spools • Tubing Heads • Adaptors • Valves • Chokes • Flow Tees or Crosses • Swivel Joints




• Typically used in any high pressure (i.e., 13.8 MPa [2000 psi] to 207 MPa [30,000 psi]) or higher risk operations.

• Most commonly found in thermal operations.

• Provides a superior ability to align and seal wellhead components and piping modules as compared to flanged or studded connections, as small differences in alignment are more easily “absorbed” by this type of connection.

• Provides a higher fatigue resistance than flanged or studded connections.

• Offers a faster make up time versus flanged or studded connections.

• Since any damage to the face of the hub may compromise the metal to metal seal, special care must be taken in any operation where there is potential for this type of damage.


• See Protecting Wellhead Equipment in Transport and On Site under 5.2.3.4 Installation Procedures for requirements on protecting clamp hub components during transport and while on the lease site.

• See "Flanged" above for an IRP on valve removal threading applicable to both flanged and studded connections.

• See 5.1.4.2 Above 13.8 MPa and 5.1.5.2 Sour/Corrosive Flowing Wells for a description of conditions under which flanged, studded, or clamp hub connections are required.

• See Flanged, Studded, and Clamp hub Connections under 5.2.3.4 Installation Procedures for requirements related to making up studded connections.



5.1.3.9.6. Sliplock

With a sliplock connection, the components are attached by sliding one over the other and engaging slips and seals. Slip segments on the inner diameter of the sliplock hold the casing tight. Seals provide isolation. Both slips and seals typically are energized by studs which are torqued to a prescribed setting provided by the OEM.

Figure 22. Sliplock Casing Head Examples



Sliplock connections may be used with:

• Casing head to casing connections


• Typically used in drilling or other temporary operations in place of welded or threaded connections as the sliplock provides a faster connection time than either of these other methods.

• May be used in observation style wells where the well bore is not exposed to formation conditions.


REG If an operator wishes to use a casing head with a sliplock connection for high pressure servicing operations or an extended period of time (e.g., production operations), they must provide documentation and seek regulatory approval.

Note: One of the key concerns that must be addressed is the resiliency of the sliplock seals to all conditions that might be encountered such as formation and drilling pressures, temperatures and fluids, cyclic loading or fatigue, adverse conditions such as fire, and extreme (i.e. very hot or cold) climates.

• In Alberta see ERCB Directive 036: Drilling Blowout Prevention Requirements and Procedures (February 2006), 1.2.1.

5.1.3.9.7. Coil Tubing Connection Types

Roll-on connectors may be found in wellheads completed with coiled tubing. The end of the coiled tubing and inner diameter are prepared to ensure a good fit and O-rings might be included to help provide a tight seal. The connector body, with its outer diameter grooves and O-rings, is inserted into the coiled tubing. An installation tool is then applied to crimp the coiled tubing into the connector body grooves. A sleeve may then be slipped over the coiled tubing and threaded onto the connector body. The threaded connector is then attached to the tubing hanger, suspending the coiled tubing in the well bore.





Figure 23. Roll-On Coiled Tubing Connection

In shallow gas operations, roll-on connectors are preferred. In conventional and in situ heavy oil operations, the most common means of landing coiled tubing strings in a wellhead involves slips and seals.

Coiled tubing may also be attached to a connector body with a welded connection. Other less common means of attaching coiled tubing include screw-on, thread-on, and grapple connections.


• See further 5.1.7.3 Coiled Tubing Considerations

• For welded coiled tubing connections see 5.2.3.3 Installation Personnel for requirements related to welding personnel and see Welded Connections under 5.2.3.4 Installation Procedures for requirements related to welding procedures.



5.1.3.10 Seals

Seals provide isolation from one casing to the next, between casing and tubing, possibly between tubing strings, and between tubing and tubing head adaptor.

5.1.3.10.1. Seal Composition

Elastomer and Graphite / Carbon Seals

Sealing components in conventional wells and some (lower temperature) Steam Assisted Gravity Drainage (SAGD) wells are typically made from elastomers. Elastomers are designed to operate within a specified temperature range and offer resistance to a specific set of chemical conditions. Common compound or elastomer brand names include Buna-N [or Nitrile], Highly Saturated Nitrile [HSN], Kalrez, Peek, Teflon, Viton, and Aflas. When operating temperatures exceed the service limits of elastomers, graphite or carbon fibre seals may be used.

The seal elements or rings often are installed into recesses or grooves machined into the outer surface of the component or a bushing that seats into the housing (e.g., as for secondary seals, tubing or casing hangers, or adaptors). These seals are then energized through the application of pressure—either by setting weight or mechanically applying pressure or wellhead pressure energizing the seals. The seal might also be enhanced by the application of a higher temperature.

Metal Seals

Sealing rings or elements may also be made from metals. Since it can be difficult to achieve a metal to metal seal which maintains the required performance through the full range of the well operating conditions, good design and installation practices are essential. The metal of these sealing components must have sufficient ductility and elasticity to deform under the setting conditions and flex under changing operating conditions to maintain the required sealing stress throughout all well operations. As such, the metal seal must be softer than the housing into which it is set so the metal seal does not damage the housing once energized, or provide an opportunity for localized corrosion. Metal seals are used especially in highly corrosive environments.




IRP Both elastomer and metal seals shall be chosen in consultation with the OEM in order to ensure the composition of the seal matches the operating conditions of the well. Ideally, the seal should be chosen to function over the life of the well, but as well conditions or operations change, the OEM should be consulted again to ensure ongoing seal integrity.

IRP Under dynamic operating conditions, all seals should be maintained and replaced as per the OEM’s recommendations.

• See also 5.1.6 Assisted Lift Wells (especially 5.1.6.1 Rod Pumping Wells and 5.1.6.4 Electric Submersible Pump Considerations) and 5.1.7.1 Injection or Disposal for further seal-related IRPs.

• See IRP 21 Coiled Tubing Operations: Section 6.4.

5.1.3.10.2. Seal Types

Ring Gaskets

A ring gasket provides the actual seal in any flanged or studded connection, and also in some hub clamp connections. The ring gasket is a precisely machined, metal seal designed to fit the grooves on each flange or hub face. As the studs on a flange or clamp are torqued, the softer metal of the ring gasket is compressed against and conforms to the harder metal of the face. Each ring gasket carries a rating for the range of pressures, temperatures, and corrosive fluids that may be present.

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Figure 24. API Metal Ring Gasket Styles



There are three basic styles of API approved ring gaskets:

• R-style is designed for standard ring joint grooves. R-style includes both oval and octagonal cross sections which are interchangeable in a standard groove.

• RX-style also fits standard ring grooves. However, RX style ring gaskets are designed to fit snugly into the 23° sides on the ring groove. This provides for an easier make-up. It also offers enhanced pressure resistance as increasing pressure only improves the effectiveness of the seal (hence RX-style are required in critical sour operations).

• BX-style ring gaskets are unique and require a BX groove on the flange. With their shorter profile, the flange faces can come together, surrounding the gasket on both inner and outer diameters. BX-style gaskets also have a vertical pressure balance hole to ensure equalization of any pressure that may be trapped in the grooves.

In terms of pressure rating:

• R/RX-Style may be used in 13.8-34.5 MPa operations

• BX-Style are typically used in any operation above 34.5 MPa

See further Appendix A: Flange / Ring dimensions.

IRPs related to Ring Gaskets

IRP Under no circumstances shall ring gaskets be re-used. Ring gaskets are permanently deformed when energized and are designed for single use.

IRP Ring gaskets shall be chosen to match the known operating conditions of the well and take into account pressure, temperature and fluid exposures.

• See further Flanged, Studded and Clamp hub Connections under 5.2.3.4 Installation Procedures for IRPs related to ring gasket make up.

Primary and Secondary Seals

Casing strings (other than the surface casing) that terminate in the wellhead are typically sealed twice. First, a primary seal is set when a casing is suspended by a casing hanger in the top bowl of a casing head or casing spool. This seal will isolate the annulus between this casing string and the previous casing string. The casing itself extends into the counterbore of the next wellhead component where a secondary seal can be set. When both a primary and secondary seal are set, the seals themselves and the connection between the two wellhead components can be pressure tested for integrity via a test port. This same principle can be applied to a welded connection between the casing head and surface casing when it is welded both on the top of the casing on the inside of the head, as well as outside on the



bottom of the casing head. A test port between the two welds provides a means to pressure test the integrity of the welds.

5.1.4 SWEET FLOWING WELLS

Each province has different guidelines for sweet or sour wells. In ERCB Directive 056: Energy Development Applications and Schedules, wells with any H2S (greater than 0.00%) are classified as sour, whereas British Columbia, Saskatchewan, and Manitoba use 0.3 kPa H2S partial pressure (PP). For design considerations, such as material selection, the NACE limit is 0.3 kPa H2S PP.

For the purposes of the following IRPs, the threshold between sweet and sour flowing wells is 0.3 kPa Hydrogen Sulfide (H2S) partial pressure (PP). Hence, sweet flowing wells are defined as wells with less than 0.3 kPa H2S PP that flow to surface without the assistance of any means of artificial lift.





5.1.4.1 Below 13.8 MPa

Figure 25. Wellheads for Sweet Flowing Well (≤ 13.8 MPa)

IRP Sweet flowing wells with a bottom hole pressure equal to or below (≤) 13.8 MPa and that are not expected to face operational pressures above 13.8 MPa over the life of the well may use a variety of connection types in wellhead design, including threaded connections on casing heads and spools provided they are fit for purpose.



5.1.4.2 Above 13.8 MPa

Figure 26. Wellhead for High Pressure Sweet Flowing Well

IRP For wellheads on high pressure sweet flowing wells (bottom

hole or operational pressure > 13.8 MPa), all major exterior component connections shall be flanged, studded, or clamped. Although a welded connection between the casing head and surface casing is recommended, the casing head may use a threaded connection.



IRP For wellheads experiencing extremely high pressures (bottom hole or operational pressure ≥ 103.5 MPa), all major exterior component connections shall be studded or clamped. Gas wells with this pressure level should use PSL 3G or higher rated materials. Although a welded connection between the casing head and surface casing is recommended, the casing head may use a threaded connection.

5.1.4.3 Low Pressure / Low Risk Gas Wells

For the purposes of the following IRPs, a low pressure/low risk well is one in which the well demonstrates declining performance with time and exhibits the following characteristics—it is easy to control, presents minimal safety and environmental risk, and occurs in an area with a confirmed knowledge of the reservoir and well operating conditions. These characteristics can be quantified as follows:

• Bottom Hole Pressure below 6 MPa

• Gas Deliverability below 17 e3m3/d AOF @ MPP

• Combined ratio (Pressure*Rate) below 80 (MPa * e3m3/d)

• H2S content no greater than 0.00 %

• Hydrocarbon Liquids below 30 ml/m3

• Production Casing cemented with good quality cement returns to surface

• Well Density greater than 4 wells / 3 km radius

This definition is usually applicable in shallow well applications where all formations are below the above BHP criteria; it is not just for depleted production formations.

IRP Low pressure/low risk wells may use a simplified wellhead which consists of a single master valve connected to the casing (see Figure 27). The master valve shall comply with all normal requirements allowing full bore access to the casing and meet all API standards for the service conditions. If surface casing or conductor pipe is present, a centralizer ring should be installed to stabilize the wellhead.

Typically a simplified wellhead such as this will consist of a gate valve threaded on to the production casing, a flow tee with a wing valve to the side to isolate the wellhead from the flow line and a bleed off valve on the top.



Figure 27. Simplified Wellhead for Low Pressure / Low Risk Gas Wells

IRP In areas not prone to vent flows, where good quality cement returns were observed during primary cementing operations, and vent flow or gas migration has not been detected around the wellhead, a variety of methods may be used to monitor or isolate the annulus between the surface and production casings per government regulations or approvals.

Note. Companies may apply to the appropriate regulator for exemption from the requirement to install a surface casing vent.

IRP Where vent flow or gas migration is detected around the wellhead, a packoff assembly shall be installed on the surface casing to isolate the annulus between the surface and production casings.

Note: If the vent flow or gas migration is non-serious, a company may apply to the appropriate regulator for exemption from the requirement to install a permanent surface casing vent.



IRP When the well’s flow characteristics warrant installing a tubing string, it may be run through the master valve, which results in the tubing hanger being installed above the initial master valve. The configuration, however, shall still provide access to the tubing casing annulus. A flow tee may be installed below the tubing hanger if the hanger cannot accommodate a port for a casing wing valve. A full opening (tubing size) valve should be installed below the production flow tee to provide isolation of the tubing string.

5.1.5 CRITICAL SOUR, SOUR AND CORROSIVE WELLS

Within this IRP, for the purpose of wellhead design, sour wells are defined as any well having 0.3 kPa H2S PP or greater.

Wells with less than 0.3 kPa H2S PP and other corrosive products should consider the application of the following sour standards to cover the potential for more aggressive corrosion.

The distinction between sour and critical sour wells is determined by regulators. This determination typically takes into account a number of factors including H2S release rates and proximity to populated centers.

For example, in Alberta, ERCB Interim Directive 97-06: Sour Well Licensing and Drilling Requirements (1.2.1) provides the following definition for critical sour wells:

A critical sour well includes any well from which the maximum potential H2S release rate is: (1) 0.01 cubic metres per second (m3/s) or greater and less than 0.1 m3/s

and which is located within 500 metres (m) of the corporate boundaries of an urban centre, or

(2) 0.1 m3/s or greater and less than 0.3 m3/s and which is located within 1.5 km of the corporate boundaries of an urban centre, or

(3) 0.3 m3/s or greater and less than 2.0 m3/s and which is located within 5 km of the corporate boundaries of an urban centre, or

(4) 2.0 m3/s or greater.

5.1.5.1 Critical Sour Wells

Wellhead requirements for any well deemed to be critical sour can be found in IRP Completing and Servicing Critical Sour Wells, 2.1 Wellheads and will not be repeated here.

The following IRPs are provided only for sour wells not designated as “critical sour” by the applicable regulator.

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5.1.5.2 Sour Wells

Sour wells present a dual risk. First, H2S is a deadly gas for humans even at low levels. Second, H2S is a corrosive product that can degrade both metal and elastomer components in the wellhead. The higher standard for connections and product service level for sour wells is designed to address both risks. However, H2S is not the only corrosive factor to consider. The following examples all present a corrosion hazard:

• CO2 and water

• Salt water

• Aggressive solvents (e.g., DMDS)

• Acid (well stimulation)

Where corrosion is aggressive, the higher product standard for sour or critical sour wells may be equally applicable to wells with these or other corrosive fluids.

Furthermore, damage from H2S can be accelerated when it is combined with other corrosive fluids. In such cases higher product and safety standards, such as those applied to critical sour wells, may be implemented.



Figure 28. Non-Critical Sour Well Example

IRP All primary wellhead components on sour wells should use

appropriate materials as specified by ANSI/NACE MR0175 / ISO 15156 standards (see also API Specification 6A [19th Edition] Trim Selection Chart or Appendix B). Primary wellhead components include the tubing head adaptor, tubing head, tubing hanger, and the lower master valve.

IRP At minimum, all primary wellhead components on sour wells should meet Product Service Level 2 (PSL 2) standards. The API recommendation on minimum PSL for primary parts of the wellhead and Christmas tree equipment should be followed.



See API Specification 6A Specification for Wellhead and Christmas Tree Equipment (Figure A.3 Recommended minimum PSL for primary wellhead components and Christmas tree equipment). Also available in API 6A Guidelines - Purchasing Guidelines Handbook

IRP Wellhead design for any sour well should also consider all other characteristics of the produced or injected fluids (e.g., CO2, chlorides, sand, solvents), as well as the rate of production or injection and proximity to environmentally sensitive areas or human populations.

IRP All wellhead connections, including valves on a sour well, shall be flanged or studded. The casing head shall use a welded connection to the surface casing.

IRP Extended neck tubing hangers complete with a back pressure valve (BPV) preparation should be utilized in sour well completions.

The extended neck with a sealed tubing hanger confines and restricts the produced sour fluids from the top bowl's lock down screw assemblies and ring gasket of the tubing head. Other styles of tubing suspension systems which give the operator the BPV preparation, and provide similar protection to the lock down screw assemblies and ring gasket, are acceptable. (See above Figure 12 and 14).

IRP All valves on wellheads on sour wells should be rated for sour service and fit for purpose. The surface casing vent is excluded from this requirement.

IRP For sour wells, the injection line on a circulating string shall be equipped with a check valve.

REG Sour wells must have a minimum of two master valves.

5.1.5.3 Corrosive Flowing Wells

IRP The standards outlined for sour wells or for critical sour wells should be considered in the design for any wellheads that will be subject to aggressive corrosive materials in the course of operations over the life of the well.

IRP Wellhead designers should ensure optimal compatibility between wellhead metallurgy and the specific corrosive materials that primary wellhead components and sealing systems will be subjected to in the course of operations over the life of the well.

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5.1.6 ARTIFICIAL LIFT WELLS

Artificial Lift is installed to increase the production rate from flowing wells or enable production at wells that will not flow due to issues such as reservoir depletion, an inadequate inflow pressure, or an increased water-oil ratio in the produced fluid. Artificial lift may be installed in sweet or sour wells and both the artificial lift and wellhead OEMs should be consulted to ensure all wellhead components are rated for the expected fluid conditions, pressures, temperatures and loads.

The more common types of artificial lift and the wellhead modifications required to enable the safe use of the equipment are summarized below and described in more detail in the following sections.

• Gas Lift

o Essentially a flowing well, the wellhead must be modified to allow gas injection and fluid production at the same time. Gas lift wells often are completed with an isolation packer in the tubing – casing annulus (see section 5.1.3.6 Tubing Hanger).

• Electric Submersible Pump (ESP)

o Essentially a flowing well, the wellhead must include a gas tight feed-through for the electric power cable that runs from surface to the downhole ESP motor.

• Reciprocating Rod Pump (RRP)

o A stuffing box and blowout preventer are installed to seal around the polished rod that is installed at the top of the rod string. The wellhead master valve often is removed.

• Progressing Cavity Pump (PCP)

o It includes the components required by RRP above. In addition, the wellhead must also include a flanged or studded adaptor to support the PCP drivehead or electric motor.

• Plunger Lift

o Essentially a flowing well with a lubricator / “plunger catcher” installed on top of the flow cross.

• Hydraulic Pump

o The flowing well wellhead is modified to allow injection of high pressure power fluid to a downhole pump, and recovery of the exhausted power fluid and produced reservoir fluid stream(s). A downhole packer might also be required (see section 5.1.3.6 Tubing Hanger). A switching valve and lubricator are included on top of the flow cross.



IRP Any assisted lift equipment mounted on the wellhead shall match the requirements of operating service (e.g., if the wellhead requires flanged connections, the BOP connections or plunger lift assembly shall also be flanged or have at least a comparable rating such as a clamp hub). Note that frequently lift equipment is added later in the life of a well. Where conditions have changed such that the original wellhead requirements are no longer applicable, the current, not original, conditions shall guide equipment design and selection.

5.1.6.1 Reciprocating Rod Pump

A reciprocating rod pump (RRP) artificial lift system includes a surface drive (usually a pumpjack set behind the well), a rod string and a downhole pump. The rod string connects the surface driver to the downhole pump and is reciprocated vertically to activate the pump and produce the reservoir fluid to surface. The wellhead must be adapted to provide a tight ongoing seal against the polished rod that enters the top of the wellhead, and full containment of all well fluids for maintenance purposes and in the event of a broken polished rod. These functions are provided by the polished rod stuffing box and blowout preventer, respectively.



Figure 29. Integrated Pollution Control Stuffing Box and BOP



IRP All reciprocating rod pumping wells shall have a polished rod stuffing box and BOP that are fit for purpose. Stuffing box and BOP design and sealing components must be fit for the type of conditions under which they will be used (e.g., exposure to specific fluids, climate conditions, thermal well conditions, excessive wear in a slanted well, or other unique operation wear considerations). See further 5.2.6.3 Rod Pumping Well Maintenance for additional recommendations regarding maintenance and replacement of stuffing box sealing components.

IRP All rod pumping wells shall have a pressure switch that automatically shuts down the pump in the event of rising pressures exceeding a pre-determined limit or a drop in pressure indicating a leak at surface. In the event an isolation valve has been installed below the pressure switch, the isolation valve shall be secured open during operations to ensure the functionality of the pressure switch.

IRP A pollution control stuffing box (also called an environmental BOP stuffing box) can provide an automatic seal across the well bore in the event a polished rod breaks and pulls out of the stuffing box.

This equipment should be installed:

• On any rod pumping well capable of flowing to surface.

• On any rod pumping operations on sour wells (0.3 kPa H2S PP or greater and not designated as critical sour).

This equipment shall be installed:

• On any rod pumping well in close proximity to human populations or environmentally sensitive areas.

IRP In rod pumping operations on sour wells (0.3 kPa H2S PP or greater and not designated as critical sour) consideration should be given to including a master valve that can be used in the event of a rod failure. This is in addition to the polished rod BOP. The master valve handle should be either removed or chained and locked during normal production operations to prevent accidental closure.

IRP In rod pumping operations on sour wells or wells capable of flowing to surface, operators should consider the use of a dual stage or double ram BOP



5.1.6.2 Progressing Cavity Pump (PCP)

The progressing cavity pump artificial lift system also includes a surface drive, rod string and downhole pump, but in this technique the rod string is rotated instead of being reciprocated. The PCP drivehead and stuffing box are mounted above the flow cross and in electrically powered systems the electric motor also is mounted on or suspended from, the wellhead.

There are pumping operations that utilize an Electric Submersible Progressing Cavity Pump (ESPCP). The IRPs on the Electric Submersible Pump (ESP) are more appropriate for this type of pump design.

Figure 30. Wellhead for PCP Pump



IRP In addition to the reciprocating rod pumping IRPs, wellheads accommodating a progressing cavity pump shall be designed and implemented with the additional demands of the PCP drivehead taken into consideration. Wellheads with a PCP drivehead should be made up with flanged or studded connections to support the additional weight of the motor or drivehead and sustain the vibration, torque, and fatigue created by the PCP operation.

5.1.6.3 Plunger Lift

In a plunger lift system, fluids are moved up and out of a well by a plunger that is carried up by natural well pressures. At surface the arriving plunger is captured in a lubricator, the produced fluid unloaded to the flowline, and the plunger is released to fall back to the bottom of the well where the unloading cycle can then repeat.

In terms of wellhead integrity, the key concern with plunger lift systems is the arrival of the plunger at surface. In normal operations, the force of the incoming plunger is absorbed by the fluid column and springs and stops in the lubricator assembly.



Figure 31. Plunger Lift System



IRP Wellhead equipment used with a plunger lift system shall be of a design and function to withstand the unique impact forces that may be encountered during plunger lift operations. This includes the possible impact forces from a plunger that is traveling upwards without a fluid column.

Note: If well conditions change or the plunger is caught by paraffin, wax, sand or hydrate buildup in the tubing string and fails to drop to the well bottom, the plunger may fail to capture fluid. When it is subsequently pushed up by well pressure, the plunger may strike the surface assembly with an unexpectedly high velocity and a much greater impact force. In extreme circumstances, a plunger arriving at a high velocity without a fluid column may be capable of blowing through the top of the lubricator.

IRP Plunger lift systems should be designed, timed or pressure set, and maintained to minimize the impact of the plunger's arrival on the wellhead. In particular, springs and stops at the top of the plunger lift assembly should effectively absorb the force of the incoming plunger. Systems should be in place to prevent ice and hydrates from forming in the plunger lift's lubricator assembly and especially the spring housing. If the top flow line on the plunger lift is not tied into the outflow line, ice and debris can build up and trap pressure in the lubricator. Shelters over the wellhead can also reduce the risk of freezing. Furthermore, impact forces should be considered whenever plungers of different weight and length are swapped in and out to optimize production. See further Alberta Human Services, Employment and Immigration, Workplace Health and Safety Bulletin, AL034-Alert, "Worker Seriously Injured Servicing a Plunger Lift System" (May 2007).

5.1.6.4 Electric Submersible Pump

An electric submersible pump (ESP) is installed at the base of the production tubing and the completion might include a downhole packer. Electric power is supplied to the downhole motor by a cable that is run along the tubing, from surface. The high voltage, high amperage power cable is passed through and sealed at the wellhead via a specially engineered electric feed through connector.



Figure 32. Wellhead for Electric Submersible Pump (ESP)



IRP The electric feedthrough connector for an ESP shall provide an electrically grounded, gas-tight seal that is fit for the well’s operating conditions and the surface environment.

Note: The feedthrough connector is not designed to carry the weight of the cable. The cable is run with and banded or clamped to the production tubing string. Sufficient slack must be allowed to avoid landing the cable in tension.

5.1.6.5 Hydraulic Pump

A hydraulic pump is a downhole pump that is driven by high pressured (power) fluid supplied from the surface. Hydraulic pumps come in a variety of designs including jet, piston, and turbine pumps.

The simplest design pumps the power fluid down the production tubing and brings the combined power and produced fluid stream to surface through the production casing-tubing annulus. In another configuration where higher pressure or potentially corrosive fluids must not contact the casing, power fluid is pumped down one tubing string and the hydraulic and production fluids brought to surface through a second tubing string. Both completions, which often include downhole packers to avoid injecting fluid into the reservoir, are typical of jet pumps. Reciprocating or piston hydraulic pumps typically use three tubulars or conduits since the power fluid, which is re-circulated, must be kept separate from the production fluids to avoid picking up fines or other particles which can seize the downhole pump.

Wells completed with a hydraulic pump require a switching valve and lubricator at surface to retrieve the pump.

IRP Wellhead equipment operating with a hydraulic artificial lift system shall be designed to withstand the high pressures required to operate the hydraulic pump. Similar to a plunger lift system, the lubricator shall include sufficient “shock protection” to avoid damaging equipment when the downhole pump is surfaced to change components. Note that with a hydraulic pump, the maximum operating pressure typically is at the surface (power fluid pressure).

IRP The composition of the power fluid shall also be considered when selecting wellhead components.

5.1.6.6 Gas Lift

A gas lift system enables or enhances well production by injecting high pressure gas into the production fluids to reduce the hydrostatic pressure and improve the ability to flow to surface under natural reservoir pressures. The high pressure lift gas is injected either into the production casing tubing annulus or the production tubing. It



is then introduced to the production fluid through a series of mandrels and valves installed in the production tubing. Produced fluids, with their reduced density, now flow up either the annulus (if the tubing is the conduit for the lift gas) or the tubing (if the annulus is the conduit for the lift gas). A downhole packer typically is included with the completion to avoid injecting gas into the reservoir. Annular gas injection with tubing production by far is the most common completion.

IRP Wellhead equipment operating with a gas lift system shall be designed to withstand the increased pressures and flow conditions resulting from the lift gas.

IRP The composition of the lift gas shall also be considered when selecting wellhead components.

5.1.6.7 Velocity String

A velocity string is a means of enhancing production by reducing the liquid loading in a well. The velocity string is a small diameter tubular inserted into the production casing or tubing. The reduced diameter results in a higher flow velocity so the liquid can now be carried to surface under natural reservoir pressure, reducing the liquid load in the well and improving production. Velocity strings most often are used to de-water low rate gas wells.

Velocity strings can be created with jointed tubing. However, coiled tubing is more commonly used in this application. In wells with a multiple tubing configuration, typically the velocity string is hung in the tubing head below the master valve. A single coiled tubing string may also be hung above and run through the master valve. See 5.1.7.3 Coiled Tubing Considerations.

5.1.6.8 Coiled Tubing

In the event a well is completed using coiled tubing (e.g., coiled tubing functioning as a velocity string, instrumentation string, or running of small diameter logging tools to evaluate well conditions), the coiled tubing adaptor and hanger may be placed above the tubing head. Or, depending on its function, it may be hung alongside a tubing string. In some cases, the coiled tubing may even be hung above the master valve of the Christmas tree.

See below Fig , for an example of a coiled tubing configuration for a thermal operation.

ure 37, Additional Example for SAGD Wellhead for Rod Pumping



Figure 33. Coiled Tubing Hangers

IRP In the event that coiled tubing runs through a master valve on a Christmas tree, the master valve handle should be either removed or chained and locked during normal production operations to prevent accidental closure. In these cases, an additional master valve (or valves) shall be installed above the tubing head to control and isolate the well.

5.1.7 OTHER WELL TYPES

5.1.7.1 Injection or Disposal

In terms of wellhead equipment and design, injection or disposal wells present two areas of concern: pressure and injection fluid. Structurally, injection and disposal wells are typically identical to wellheads designed for flowing wells. However, both existing and new wellheads to be used for injection or disposal purposes require an engineering assessment (and potentially modification) to ensure adequate pressure rating and ability to safely handle the injected fluid.

The maximum pressure a wellhead will face in an injection operation is usually determined by the nature of the operation itself. For example, the nature of the formation and regulatory requirements may set an upper limit on pressure for frac operations. Automatic pressure shut down devices that shut down the injection pump before maximum pressure is reached are essential.



The assessment of wellhead requirements would also have to address both pressure and fluid consideration with respect to backflow. Injection can recharge the target zone, flowing back the injection and produced fluids at a new higher pressure. At the same time, the returning fluid is a combination of injected and production fluids with unknown properties. An injected liquid may flow back as a gas (e.g., CO2) carrying higher pressure from the charged formation.

A third consideration with injection wells is temperature, especially in enhanced oil recovery methods that rely on steam injection. For SAGD and CSS recovery methods, see next section on thermal operations.

Figure 34. Basic Injection Wellhead

IRP Wellhead components, connections, and seals shall be rated

to withstand any additional pressures or temperature variations created by injection operations. For stimulation operations, operators may use isolation equipment in order to meet this recommendation (e.g., isolation sleeves or blast joints during stimulation operations). Although most injection operations are conducted down tubing with the tubing-casing annulus isolated by a packer, sweet gas may be injected via the tubing-casing annulus. As a result consideration may need to be given to both burst and collapse ratings of various wellhead components, tubing and casing strings terminating in the wellhead.



IRP Wellhead components, especially elastomer and metal seals, shall be rated to adequately withstand any corrosive or erosive effects created by injected fluids and gases. Operators should also consider any effects from a combination of injected and produced fluids and gases. The following are representative of common examples of injected material--the list is not exhaustive:

Table 1: Injection Material

Fluid Injected Anticipated Problems Considerations – Material Compatibility

Sulphur Solvents (e.g., dimethyldisulphide /DMDS)

Elastomer deterioration Requires DMDS resistant elastomers or metal to metal seals

CO2 Metal loss, elastomer deterioration

Requires ANSI/NACE MR0175 / ISO 15156 rated metals (see further API Spec 6A [19th ed] Trim Selection Chart or Appendix B)

H2S Metal loss and sulphide cracking, elastomer deterioration

Requires ANSI/NACE MR0175 / ISO 15156 rated metals (see further API Spec 6A [19th ed] Trim Selection Chart or Appendix B)

Liquid Nitrogen Introduces extreme temperature variation (i.e., cold)

Should ensure seal elastomers can handle the temperature variations created by the introduction of liquid nitrogen

Water (Salt or Fresh)

Corrosion, scaling Should account for erosion from turbulence; May require chemical inhibitors (oxygen scavengers, corrosion and scaling inhibitors), coatings, cladding

Sand; other solids Erosion, plugging Should optimize erosional velocity; May require design to minimize or avoid sharp bends, alternate materials, or hard surfacing

Hydrocarbons Seal degradation, waxing, emulsions

Should ensure seal compatibility with hydrocarbon; May require design to deal with viscous, hard to pump fluid

Industrial Waste Potentially any of the above, depending on waste composition

Should ensure seal and metallurgy compatibility with all potential individual waste components and effects of combining components

Mixed Products May accelerate expected detrimental effects of individual components

Should ensure seal and metallurgy compatibility with all potential individual waste components, components resulting in these breaking down further, and the effects of combining components



IRP Whenever highly corrosive fluids (e.g., CO2 or acid gas) are going to be continuously injected or stored, the operator should consult with their OEM supplier, review applicable regulations, and/or consult with the relevant regulator on wellhead design criteria. It is especially important in those cases where injection is to take place in recompleted wells, the well designers need to consider the change of conditions and ensure existing wellhead equipment meets the material requirements of the new operations and is fully fit for purpose.

5.1.7.2 Thermal Operations

Wellhead recommendations for heavy oil / oil sands wells which utilize a variety of thermal stimulation techniques to enhance oil recovery are available in IRP 3 In Situ Heavy Oil Operations. These recommendations cover such topics as:

• Designing wellhead for the temperatures and pressures that accompany thermal stimulation.

• Accommodating for the expansion and contraction created by temperature variations.

• Welding requirements and procedures.

• Requirements related to well control devices, surface casing vents, tubing hangers, stuffing boxes on rod pumped wells, pressure shut down devices, BOPs, and master valves.

There are two basic designs for operations using thermal stimulation techniques—Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS).

SAGD production will involve twin horizontal wells, each with their own wellhead. Low pressure steam, and potentially solvents, are injected into the upper well. This creates a lower viscosity for the heated crude oil or bitumen, allowing it to flow along with the condensed water to the lower production wellbore. Typically, some form of assisted lift, such as progressing cavity pumps, are used in the production well to produce the high viscosity fluid and water. In the simplest terms, SAGD production will require one well with an injector wellhead designed for steam injection, another with a wellhead designed for a given method of assisted lift.

CSS production involves first injecting high pressure steam into the producing formation, allowing for a “soaking” period, and then producing out of the same well, typically first as a flowing well (due to the increased natural pressure from the injected steam) and then via some method of assisted lift. Once production tails off again, the cycle of steam/soak/produce is repeated. CSS wellheads must therefore be adapted for both steam injection and assisted lift. In many cases, CSS wellheads involve a single tubing string that is threaded directly into the tubing bonnet.





Typically an integral flow tee / BOP component and high temperature stuffing box are mounted above that.

Additional design consideration for thermal wellheads includes the need for high temperature seals and pipe swivels or spring hangers to manage expansion and contraction with temperature swings. Produced fluids have a high water vapour load as well as H2S and CO2 gases. Injected fluids may also include light hydrocarbons to boost recovery. Wellhead equipment may also need to be monitored and protected from risk of higher levels of erosion. This may include controlling production rates as well as sand or erosion probes.

IRP Wellheads that are anticipating a bending moment or side loading due to thermal expansion should consider using swivel joints on all connecting pipes to reduce the stress on wellhead connections and improve long term sealing of pipes.

Figure 35. Integral Flow-Tee BOP



Figure 36. Simple Steam Injection Wellhead for SAGD



Figure 37. Additional Example of SAGD Wellhead for Rod Pumping



Figure 38. Example of Cyclic Steam (CSS) Wellhead



5.1.7.3 Cavern Storage Well

Cavern storage wells are naturally occurring or artificially created underground formations that can store typically large volumes of hydrocarbon gases or liquids. As such, cavern storage wells may use large diameter pipes and valves that fall outside the scope of API standards proper. These will be covered by ANSI standards. In addition to the IRPs below, wellhead design for cavern storage wells needs to consider the type of fluids that will be injected and produced through the wellhead. Separate wellheads may be required for developing and operating the well, especially where the cavern is developed in a salt formation. On this matter see 5.1.7.1. Injection and Disposal Considerations above.

Figure 39. Cavern Storage Wellhead



IRP Anyone designing and implementing a wellhead for a cavern storage operation should consult CSA Z341 Series-10: Storage of hydrocarbons in underground formations to ensure safe and compliant operations. See especially CSA Z341 Series-10, 4.3 Wellhead assembly and Christmas tree assembly.

Note: While ANSI rated valves may be necessary in completing cavern storage wells, these are not recommended for drilling purposes.

5.1.7.4 Observation Well

Observation wells are used to (e.g.) monitor formation conditions or the efficiency of the reservoir depletion process. Depending on their function, observation wells may or may not enter the producing zone and those completed in the overburden might not be exposed to the reservoir in situ or operating environments.

IRP Wellheads on an observation well, including those that do not enter a producing formation, shall be designed for all anticipated conditions, and provide for full isolation of the wellbore.

REG Monitoring lines of any sort installed in observation wells must be secured with a gas-tight seal. Wirelines run into an observation well must also meet all electric codes and electric isolation at surface. (See further IRP 5.1.6.4 Electric Submersible Pump )

5.1.7.5 Other Strings (not part of well flow)

Increasingly, wellheads must be designed to accommodate a variety of small diameter strings and lines that are used for a number of purposes. For example, small diameter chemical injection strings are used for corrosion control, de-waxing, scale inhibition, emulsion breaking or viscosity reduction. Subsurface safety control valves (tubing and annular) also create a requirement for lines running through the wellhead. There are also an increasing number of instrument lines used to monitor downhole pressures and temperatures. These include both bubble tubes and instrument cables.

IRP Cables or strings that are not part of the main well flow that run through and exit via wellhead equipment must be sealed and packed off at surface and tested to the working pressure of the wellhead.



5.1.7.6 Environmentally Sensitive Areas

IRP In any areas with a heightened environmental sensitivity, due to the natural environment (e.g. parks, groundwater sources or designated bodies of water) or proximity to human population, consideration should be given to exceeding minimal wellhead design criteria and components. For example, the heightened design specifications for sour or critical sour may be appropriate in a scenario where any hydrocarbon release to atmosphere could produce significant environmental risk or harm. Other considerations may include heightened redundancies, emergency shut down devices, and online monitoring.

5.1.7.7 Cold Climate Considerations

IRP In any area in which temperatures may fall below -29° C, wellhead components shall be temperature rated to -46° C (API Temperature Classification N, L, or K). For example, a search of low temperatures recorded in Cold Lake, AB between 2001 and 2010 shows a record low of -43.7° C. As such, operations here would fall under this recommendation. See further Appendix C: API 6A Temperature Classification Table.

IRP In any area in which temperatures may fall below -46° C, wellhead components shall be temperature rated to -60° C (API Temperature Classification K). Appendix C: API 6A Temperature Classification Table.

IRP For thermal operations where standard classifications for temperature ranges may not be applicable, operators should confirm with the OEM supplier that the wellhead equipment will be fit for purpose.

IRP Operators should consult with the OEM supplier to ensure that elastomer seals are fit for purpose given possible cold temperature considerations.



5.2. WELLHEAD IMPLEMENTATION 5.2.1 GENERAL RESPONSIBILITIES IN WELLHEAD IMPLEMENTATION

IRP Operators shall take responsibility for:

• Providing accurate data on well conditions for wellhead design;

• Ensuring wellhead components ordered meet all design and regulatory requirements;

• Ensuring all required wellhead maintenance is conducted in a timely fashion by competent workers;

• Maintaining records of all work carried out on the wellhead for the life of the well;

• Conducting a risk assessment of the well and considering revised wellhead requirements whenever the producing character of a well changes (e.g., rising H2S, increased pressure post stimulation, etc.) or operations are adjusted (e.g., interventions, EOR, assisted lift introduced);

• Changing out components as required to meet or exceed new conditions.

IRP OEMs and OEM suppliers of wellhead components shall take responsibility for:

• Recommending components that meet the design and regulatory requirements communicated by the operator;

• Supplying components which meet or exceed design requirements and are free of defect;

• Providing detailed handling instructions and required maintenance procedures and schedule;

• Providing details of component specifications and history where applicable.

IRP Contractors or OEMs that undertake drilling or servicing operations that involve making up all or some portion of the wellhead, dismantling wellhead components, or maintaining wellhead components shall take responsibility for:

• Carrying out installation and maintenance according to the OEM's instructions and with the use of the appropriate equipment;

• Providing operator a record of work conducted and the condition of the components;



• Returning used components when replacing parts for the operator to inspect, test, or forward to the OEM as necessary.

5.2.2 DETERMINING WELLHEAD REQUIREMENTS

Wellhead selection is a task that may be relatively straightforward in some circumstances. In other cases it may be much more complex and involve consideration of multiple factors. The IRPs below on determining wellhead requirements are primarily directed at achieving a wellhead that meets minimum requirements for the type of well and operations carried out with a given well. Selecting an optimum wellhead for a well may also require broader safety and economic considerations such as:

• The overall field development strategy

• Known changes in production characteristics and fluid composition in a field over time

• The value of standardization in lowering installation and maintenance costs

• Short to long term EOR strategies

5.2.2.1 Required Information Gathering

The first step in ensuring minimum wellhead requirements are met is careful and thorough information gathering by the operator. Typically wellhead OEM suppliers will require operators to complete a data sheet as part of the ordering process. These will capture most of the critical factors that must be considered in wellhead component selection. However, to accurately and successfully complete such a data sheet, the following tasks will have to be accomplished.

IRP Operators shall ensure that the following tasks have been completed and the results factored into wellhead design prior to wellhead equipment selection.

• Identify well type

This IRP has divided wells into sweet vs. sour, flowing vs. assisted lift, and then divided up various types of assisted lift and EOR wells. Not only are there unique wellhead requirements for different well types, but each well type will demand different questions to be answered in order to design a safe and optimal wellhead.

• Identify and calculate pressures and pressure variation

In the absence of additional wellhead pressures created by assisted lift or well intervention techniques, BHP will determine wellhead component requirements (see above, 5.1.2 Component Requirements Applicable to All Wellheads). In more



developed and well known oil and gas fields, this can be accurately predicted. In exploration contexts where formation pressures are harder to predict, wellheads will need to be overdesigned to accommodate the unknown. Any stepping down in component pressure specifications from one component to the next should only be done where there is certainty about pressure requirements and full pressure containment. Bear in mind that with any well that unloads to gas at any point, anticipated wellhead pressure can be considered equal to BHP.

• Confirm temperatures (surface, bottom hole, and external)

Both highs and lows as well as the degree of temperature variation will affect wellhead design and composition and especially seal selection. Note any risks related to the range and speed of temperature shifts, e.g., start up or loss of steam in winter conditions in CSS wells. These need to be specified and pointed out to the OEM supplier. (See above, 5.1.7.1 Injection or Disposal and 5.1.7.2 Thermal Operations).

• Assess any other ambient conditions

In Canada is it is critical that possible cold weather conditions are accounted for (see above, 5.1.7.7 Cold Climate Considerations).

• Provide fluid analysis

This will not be possible in a new field and may require the operator to overdesign the wellhead to safely manage unanticipated components in the produced fluids. Based on the geological prognosis operators should make best estimates on the basis of analog formations. It is absolutely critical that the presence and release rates of H2S be documented in the fluid analysis. Fluid analysis should also provide information regarding:

• The presence of other corrosive or erosive components

• The API gravity for oil / specific gravity for gas and gas-oil ratio

• Fluid viscosity

• The presence of produced water and its salinity and specific gravity

• The potential for scale or asphaltene deposits, corrosion, or emulsions



• Identify stimulation / intervention requirements

In those cases where it is either already known or likely that particular stimulation or intervention techniques will be applied to a well, the pressures, temperatures, and/or injected materials should be documented in advance and the wellhead designed accordingly. For instance, a fracturing operation that introduces both high pressures and an erosive product (sand) should be accounted for in the wellhead design. A monthly acid treatment would create other requirements. In those cases where the likelihood of particular types of stimulation or intervention techniques is somewhat less certain, there will likely be an economic evaluation to determine if designing for these in the present is more cost effective than replacing components at a subsequent date.

• Evaluate well life cycle

The more accurately the entire life cycle of the well can be sketched in advance, the better the likelihood of choosing a wellhead that provides optimal safety and economic benefits over its lifetime of the well. Important considerations include predictable changes in well operating strategies or reservoir depletion methods that will alter well operating pressure, injected or produced fluids, or might affect H2S release rates. Optimal wellheads are those that take into account specific well characteristics at present and future field development, in addition to considering safety and costs over the entire life cycle of the well and wellhead.

• Identify environmental concerns

Heightened environmental concerns may require overdesign of the wellhead as an additional precautionary measure. Environmental concerns may include:

• Proximity to human populations

• Proximity to designated or known environmentally sensitive areas

• Proximity to surface water

• Proximity to domestic livestock operations

There may be a need to consult applicable regulations or consult with the local regulator. Where concerns exist, consultation with the regulator with respect to the plan is essential.

See further 5.1.7.6 Environmentally Sensitive Areas.



• Confirm functionality of wellhead for drilling, well servicing, and all well operations

Items to consider here include rig floor height, surface casing height, valve orientation, etc. Any issues here should also be brought to the pre-spud meeting to ensure adequate stakeholder communication.

5.2.2.2 Transmitting required data for wellhead design

IRP The OEM/OEM supplier and operator should discuss and be in agreement on all the information provided on the OEM data sheet. The operator should ensure the relative quality of the available well data and their risk assessment of the well are shared with the OEM/OEM supplier. See API Specification 6A Specification for Wellhead and Christmas Tree Equipment (Tables A.2-A.12 of ISO/FDIS 10423: 2009). Also available in API 6A Guidelines - Purchasing Guidelines Handbook

IRP The original information provided by the operator to the OEM/OEM supplier and a list of the components ordered should be retained by the operator for the life of the wellhead.

5.2.2.3 Competency requirements for wellhead design

IRP The selection and configuration of wellhead components shall to be done by or under the direction of a competent individual who has a good understanding of the proper application of wellhead components.

5.2.3 WELLHEAD INSTALLATION

5.2.3.1 Contractor Competency and Compliance

IRP Operators should exercise due diligence in the evaluation and selection of contractors that will provide wellhead installation services to ensure the contractor selected is competent in the installation of the selected wellhead and is compliant with applicable regulations. See further the industry-produced Guideline on Contractor Management Systems, especially Step Three: Conduct Contractor Pre-Qualification and Selection (pg. 12-15).

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IRP Contractors should exercise due diligence in the evaluation and hiring of employees who will provide wellhead services to ensure they are competent in the design, manufacture and installation of the selected wellhead and compliant with applicable regulations.

5.2.3.2 Pre-Spud Meeting

IRP Before wellhead installation operations commence, personnel involved in the planning and execution of wellhead installation should fully discuss the operation in a pre-spud meeting. This meeting should:

• Include a review of safety regulations and legislation (e.g., PPE, required tickets, radios, etc.)

• Ensure ERP awareness, understanding, and application

• Ensure onsite hazard assessments are assigned and scheduled

• Ensure an understanding of wellhead equipment, installation equipment, and installation procedures

• Provide an opportunity to coordinate all contractors involved in the procedures

Note: Future operational difficulties can be avoided if there is buy in from stakeholders on the details of the final wellhead configuration required for subsequent operations. For instance, operating companies should inform drilling and wellhead installation companies of the ideal height for surface casing, location and orientation of wing valves and the surface casing vent.

5.2.3.3 Installation Personnel

Selecting the right personnel for installation tasks is critical. The safe operation of a well for the entire life cycle of the well is dependent on wellhead integrity. It must be done right the first time. Furthermore, working around a well during wellhead installation procedures carries unique hazards.

IRP Wellhead installation procedures shall only be carried out by competent personnel who are knowledgeable, experienced, and have been trained in the installation of the specific wellhead components being used in a given operation. For training purposes, installations carried out by less knowledgeable or less experienced personnel shall be under the immediate supervision of an individual with the required knowledge, experience, and training.



IRP Wellhead installation procedures shall only be carried out by personnel that are physically fit to carry out the task and are not fatigued. At minimum, wellhead installation personnel should not work a shift that is longer than 12 hours without an 8 hour rest period.

IRP If wellhead installation procedures require field welding of casing heads, casing extensions, or bell nipples, these shall be done by a qualified welder certified by the local jurisdiction to undertake pressure welding. Furthermore, companies contracted to provide welding personnel and services should have a documented Quality Assurance Program. See ASME Section IX - Welding and Brazing Qualifications for information on welding procedure specifications and welder performance qualification. Welder qualification or registration is done by the Alberta Boiler Safety Association, the Saskatchewan Boiler and Pressure Vessel Safety, the Manitoba Boiler’s Branch, and the British Columbia Safety Authority – Boiler’s Branch.

5.2.3.4 Installation Procedures

Protecting Wellhead Equipment in Transport and On Site

IRP In consultation with the OEM, the operator and all contractors involved with wellhead implementation shall ensure connecting surfaces on all wellhead components (threading, flange faces, adjoining and side face on clamp hub connections) are protected from damage during transport, while stored on the lease site, and during installation procedures.

Threaded Connections

Threaded connections are governed by API standards. API stamped threaded components will have a standardized length and type of thread machined onto the connections points of the equipment.

Threaded connections can fail for a variety of reasons: inadequate torque, cross-threading, over tightening, thread damage, and mismatched thread types. Given the critical nature of wellhead connections, the following IRPs are designed to minimize the possibilities of threaded connection failures on wellheads.

IRP When ordering, supplying, and/or using threaded wellhead components, all parties involved should ensure that the thread types on the wellhead components are capable of the total loads that will be carried by the threaded connections.

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The total initial load and any subsequent loads on a threaded connection should not create thread compression and deformation.

IRP Threaded wellhead connections shall only be made up by trained and experienced personnel. For training purposes, these can be carried out by an individual under the direct supervision of someone trained and experienced in making up threaded wellhead connections.

IRP Prior to making up a threaded connection, the individual responsible for making up the connection shall:

• Inspect all threads for damage and cleanliness. Where there is evidence of corrosion or any defects on the threads, these components should not be used.

• Ensure fully matching threads on a given connection (i.e., identical thread type/form and step). Note that wellhead components may be manufactured with different thread forms and/or step in the same component.

• Ensure that the thread compound (pipe dope) is applied as per the manufacturer’s recommendation and that the compound used will provide an appropriate seal under the expected operating conditions.

IRP The following procedures should be applied when making up a threaded connection:

• Connection initially made up by hand (to prevent cross threading)

• After hand tightened, a wrench is applied to fully tighten the connection.

• Typically adequate torque, if connection is threaded properly, is the maximum human force on a 1m (36”) pipe wrench.

• Ideally, the threads are buried in the next component.

Welded Connections

The large heat input and temperature changes resulting from welding have the potential to significantly alter material properties in the weld and especially across the heat affected zone. Welding tasks should only be carried out by qualified and competent personnel using documented and registered welding procedures. This will help to ensure the strength, toughness and cracking resistance of the casing and wellhead components welded are maintained,

Correct welding procedures require good knowledge of the materials being welded. Several grades of steel are used in oil and gas industry casings and wellheads and considerable variation in steel composition can exist, even within a particular grade.



All material being welded shall be of appropriate composition for welding and the composition of each component should be confirmed prior to welding.

IRP Welders shall be qualified in the procedures required and in accordance with ASME Section IX - Welding and Brazing Qualifications. The welder shall have a documented Welder Qualification Test Record (WQTR) on the applicable Weld Procedure Specification (WPS).

IPR Welders shall follow correct and documented procedures, particularly the application of the required pre-heat cool-down, and post-weld heat treat procedures and a hardness check. Confirmation that the correct field welding procedures have been followed shall be captured in documentation at the completion of the welding operation.

IRP The documentation of the welding procedures should include, but not be limited to, the following:

• Identification of the welder and their qualifications (e.g., certification number and required documentation for the specific procedure being undertaken)

• Start times for pre-weld heating and actual welding

• Completion times for welding and post-weld heating

• Weight and grade of casing or pipe, including carbon equivalent

• Casing head or other wellhead component material

• Welding rod material

• Ambient temperatures

• Weld test results including the pressure test

• Results of any non-destructive testing, e.g., radiography

Note: For each component being welded, a specific mill test certificate should be available to document the chemistry and carbon equivalent.

IRP Operators and welding contractors shall develop standards and practices to promote and ensure the correct welding procedures are being followed. This should include, but not be limited to, the following:

• The contractor management system provides a check to ensure contractors providing welding services follow a documented Quality Assurance Program.



• Establish a controlled inventory of casing of known material composition for use as landing joints

• Develop a WPS for each grade and weight of casing.

• Establish a WPS for the specific materials being welded in each instance.

Flanged, Studded and Clamp Hub Connections

IRP Contractors or individuals involved in assembling a flanged, studded, or clamp hub connection shall:

• Ensure a clean and dry ring groove. The ring gasket and ring groove should never be greased.

• Inspect the ring groove for visual damage. Minor scratches shall be repaired and may be done in the field with an emery cloth. More significant damage shall be returned to the OEM for repair or replacement.

• Only use a new ring gasket.

• Only use new OEM supplied studs and/or nuts.

• Tighten nuts as per the pattern recommended by the OEM.

• Follow the torque requirements for studs and/or nuts provided by the OEM/OEM supplier.

• Ensure the studs extend beyond the top of the nut. Typically the standard is two threads extending beyond the top of the nut.

5.2.3.5 Pressure Testing Connections and Seals

IRP As connections and seals are completed during wellhead installation, every connection and seal shall be tested to the less of either the wellhead’s API pressure rating or the burst/collapse pressure rating of the casing or tubing exposed to the pressure test. For example, a pressure test of the welds on a welded casing head would be conducted following completion of welding cool-down. Likewise, as each primary and secondary seal set is completed, there would be a pressure test to ensure their integrity.

IRP The pressure testing of wellhead connections, seals, and components is to be done by competent personnel that are knowledgeable, experienced, and have been trained in the pressure testing of the specific wellhead components being used in a given operation. For training purposes, pressure



testing carried out by less knowledgeable or less experienced personnel shall be under the immediate supervision of an individual with the required knowledge, experience, and training.

5.2.3.6 Installation Considerations

Optimal wellhead design and installation must take into account the final configuration of the wellhead and all flow lines or components connected to the wellhead.

IRP Surface casing should be set and/or cut off at a height that ensures optimal overall height for the completed wellhead and its connected flow lines and, where required, to allow access to the surface casing vent.

IRP When installing any equipment or flow lines attached to a wellhead, consideration shall be given to any loading that may be created on the wellhead by the equipment or flow lines. Among the steps that should be considered are:

• Supporting any flow riser in the bottom of the ditch in a manner that prevents settling of the riser after backfilling. Settling of flow line risers after tie in can generate abnormal loading on a wellhead resulting in stress points being created. This is of particular concern if the wellhead contains a tubing head adapter with a threaded connection to which a rod BOP or master valve is attached. The pin connection is necessarily thin to achieve full bore access to the tubing string. This pin connection becomes a stress point if an abnormal load on the wellhead occurs due to settling of the flow line riser. This condition is accentuated if corrosion is a factor.

• Supporting and securing any equipment connected to the wellhead in a manner that minimizes the stress applied to the wellhead. This includes, for example, snubbing equipment, coiled tubing injectors, assisted lift systems, injection flow lines, movement of wellhead due to thermal variations, etc. This is also a particularly important consideration with slanted wells.

• See further 5.2.5.7 Shallow Gas Intervention Requirements for recommendations on bracing for 114 mm (4 ½”) gate valves (i.e., mud valves).



5.2.3.7 Post-Installation Requirements

IRP Immediately upon completion of any wellhead installation procedures, documentation on the components installed and the installation procedures shall be created. As per the responsibilities outlined in 5.2.1 General Responsibilities in Wellhead Implementation above, individuals or contractors providing wellhead installation services should participate in the documentation process and the operator should ensure these records remain secure and accessible for the life of the well.

5.2.4 WELLHEAD PROTECTION

IRP All wellheads shall be conspicuously marked or fenced such that they are visible in all seasons and display the signage and warning symbols required by local regulations. Furthermore, vegetation should be controlled in the immediate vicinity of the wellhead to ensure it remains visible.

IRP The operator of the well should ensure that no farm or other vehicles operate within a 3 m radius of the wellhead, except for vehicles specifically required to do so as part of an operation being performed on the well such as a completion, workover or well servicing operation. An exception also exists for wellheads that are below ground level and/or protected to accommodate certain unique operations such as irrigation or military manoeuvres. Industry records indicate that a significant number of wellhead failures occur as a result of impact with vehicles. Farm equipment and contractor’s equipment operated too close to wellheads are the major source of these incidents. In some cases, low profile wellhead designs with protective posts and fencing to prevent impact by machinery may allow for a small footprint.



5.2.5 WELLHEAD INTERVENTION

The processes and procedures required for a successful wellhead intervention will vary based on the nature of the operation. The following IRPs are designed to be broadly applicable to any operation which involves the dismantling and make-up of all or part of an existing wellhead.

5.2.5.1 On-Site Audit

IRP Prior to completing an intervention plan or commencing any well intervention operation, an operator shall perform an on-site audit of the well site that includes a confirmation of the wellhead equipment present, wellhead condition, and well site assessment.

5.2.5.2 Intervention Plan

IRP Operating companies should create an intervention plan prior to commencing any well intervention operation. This includes applying any necessary engineering and/or OEM expertise to any re-working of the wellhead.

IRP The recommendations under 5.2.2 Determining Wellhead Requirements should be equally applied to an intervention plan. As such intervention planning will include an information gathering phase (including the on-site audit), transmission of well information, discussion of wellhead requirements with the OEM/OEM supplier, and ensuring the competency of the individual selecting and configuring the revised wellhead.

IRP The intervention plan should be distributed to all companies involved in the wellhead intervention prior to commencing any well intervention operations.

5.2.5.3 Contractor Competency and Compliance

IRP Operators should exercise due diligence in the evaluation and selection of contractors that will provide wellhead intervention services to ensure the contractor selected is competent in the dismantling and make-up of the wellhead on site and is compliant with applicable regulations. See further the industry-produced Guideline on Contractor Management Systems, especially Step Three: Conduct Contractor Pre-Qualification and Selection (pg. 12-15).

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5.2.5.4 Pre-Intervention Meeting

IRP Before wellhead intervention operations commence, personnel involved in the planning and execution of wellhead intervention should meet to fully discuss the operation. This meeting should:

• Include a review of safety regulations and legislation (e.g., PPE, required tickets, radios, etc.).

• Ensure ERP awareness, understanding, and application.

• Ensure onsite hazard assessments are assigned and scheduled.

• Review any changes in well conditions from previous operations (based on the on-site audit).

• Ensure an understanding of wellhead equipment, installation equipment, and intervention procedures.

• Provide an opportunity to coordinate all contractors involved in the procedures.

Note: See further 5.2.1 General Responsibilities in Wellhead Implementation for a high level breakdown of responsibilities for operators, contractors and OEM/OEM suppliers.

5.2.5.5 Dismantling Procedures

IRP The well shall be isolated in a secure manner before any wellhead dismantling begins. Well characteristics and operational considerations may determine the optimal method for securing the well (e.g., well plug or kill fluid).

IRP When installing a BOP stack, a pressure test to BHP shall be performed on the connection between the BOP stack and the wellhead prior to commencing further operations.

IRP The following inspection procedures should be followed in dismantling wellhead components:

• Inspect studs and nuts that will be re-used. • Visually inspect all exposed inner surfaces for signs of

erosion, corrosion, cracking, pitting, or bending and deformation.

• Visually inspect all threading for compression, galling, corrosion, or cross-threading.

• Visually inspect other critical surfaces such as flange faces.

• Report all negative findings of these inspections to the operator and document any decisions reached on further testing, replacement or inaction.



• Label and securely store all equipment that will be re-used being sure to protect threading, flange faces, or critical clamp hub surfaces.

• Immediately discard components that should not be re-used (e.g., ring gaskets or other seals).

5.2.5.6 Make-up Procedures

IRP The recommendations under 5.2.3.4 Installation Procedures shall be equally applied to wellhead make-up during wellhead interventions.

IRP Whenever seals are exposed in an intervention operation, these should be replaced.

Note: It is good operational practice to retain additional replacement parts on hand during wellhead intervention operations.



5.2.5.7 Shallow Gas Well Intervention Requirements

IRP Shallow gas wells that utilize a gate valve (mud valve) shall use a bracing system during a well workover to avoid damaging or breaking the valve as a result of any bending movement. This is equally applicable to shallow gas wells with or without casing heads. Wells with a casing head left on can use a bracing system that attaches to the surface casing head and extends to the top of the valve. Wells with the casing head removed can use a split base plate that attaches to the existing surface casing and extends to the top of the valve.

5.2.5.8 Post-Intervention Requirements

IRP Immediately upon completion of any wellhead intervention, documentation on the procedures carried out, as well as the components removed and installed, shall be created. As per the responsibilities outlined in 5.2.1 General Responsibilities in Wellhead Implementation above, individuals or contractors providing wellhead intervention services should participate in the documentation process and the operator should ensure these records remain secure and accessible for the life of the well.

5.2.6 MONITORING AND MAINTENANCE

5.2.6.1 Documented Maintenance Schedule and Procedure

IRP All operators shall have a documented maintenance schedule and procedure. This should include, but not be limited to:

• Visual inspection and leak detection • Valves greased and function tested twice a year

IRP All maintenance activities carried out should be fully documented on an ongoing basis.

5.2.6.2 Wellhead Pressure Testing

IRP Pressure testing of all wellhead seals and connections should be carried out during any intervention operation. This is in addition to the required testing of any new seals and connections made up as part of the intervention itself. This does not apply where interventions are occurring more frequently. For example, on a low to medium risk well, pressure testing need not be considered more frequently than once every five years. For a high risk well, this may be as frequent as once



every year. See further ERCB Directive 013: Suspension Requirements for Wells for well classifications.

5.2.6.3 Rod Pumping Well Maintenance

The stuffing boxes, polished rod BOPs, and pressure switch components of rod pumping wells present unique maintenance requirements.

IRP Operators should consult the OEM/OEM supplier of rod pumping well components and create a maintenance schedule and procedure on that basis.

IRP Stuffing box sealing components should be inspected and replaced in accordance with the OEM's recommended schedule. Operators should consult with the OEM to ensure that stuffing box sealing components are still fit for purpose if operation conditions shift as these may need to be replaced. If the nature of the operation will create excessive wear on the stuffing box this should be noted as sealing components will have to be changed more often. The OEM may also provide advice on components that should be stocked and available at all times for ongoing maintenance purposes.

IRP In the event of a leak, the stuffing box components shall be inspected. If routine maintenance cannot stop the leak or the components are in any way damaged, they shall be replaced.

IRP The sealing elements of a polished rod BOP shall be chosen, installed, maintained, and replaced in accordance with the manufacturer's recommendations. This is important given the elements in a polished rod BOP will deteriorate with time depending on operating conditions. Failing to follow the OEM's guidelines on testing may damage the elements as well, especially during cold weather operations. If a polished rod BOP is used for any other purpose than its original intent and design (e.g., hydraulic choke), the OEM should be alerted and consulted as non-standard usage could dramatically change the lifespan of the sealing components.

5.2.6.4 Pressure Shut Down System Maintenance

Pressure shut down systems are critical to the safe operation of pumping wells. A large percentage of pressure shut down systems fail to function as required if they are not regularly maintained and tested, particularly when used in a sour environment.





IRP At minimum, pressure shut down devices on pumping wells shall be function tested:

• Monthly on all wells classified as sour (≥ 0.3 kPa H2S PP) • Bi-monthly on all wells classified as sweet

IRP Function testing of pressure shut down devices should be:

• Incorporated into the operator’s documented maintenance schedule and procedure.

• Captured in the documentation of maintenance activities.

IRP In the event an isolation valve has been installed below the pressure switch, these valves shall be secured in the open position during normal operations.

Note: Isolation valves below the pressure switch are installed in order to facilitate easier calibration, maintenance, or replacement of the pressure switch. These can be locked or car sealed to prevent accidental closure.

IRP A pumping well must not be shut in from a remote flowline location without first shutting down the prime mover at the well site, except in an emergency.

Note: If a pumping well is shut in from a remote flowline location, such as at a battery or satellite facility, the operator is depending on the pressure switch to shut down the pump. If the pressure switch fails and the pump keeps operating and building pressure, human safety is compromised and there is a real threat of equipment and environmental damage.

IRP In an injection operation, the pressure shut down system should be strategically placed and calibrated to ensure protection of the lowest rated pressure equipment in the system.

Note: In an injection scenario, the injection plant may produce pressures beyond the specifications of either the pipeline or the wellhead. If the pipeline represents the weakest link, automatic shut down systems should function on the plant side of the pipeline, not at the wellhead.



5.2.6.5 Procedure for Closing Gate Valves

IRP Personnel closing gate valves should be instructed on the correct procedure for closing wedge and/or slab style gate valves.

Note: The correct procedure for closing a wedge style gate valve is to crank it fully shut while a slab style gate valve requires the user to fully close the valve and then back it off a minimum of one quarter turn. The OEM may also provide guidance on the correct number of turns required for the valve to be fully closed.

5.2.6.6 Weld Repair of Threaded Components

IRP If necessary, a threaded component may be repaired with a weld. However, this should only be considered a temporary fix. Leaking components should be replaced with API certified components immediately.

5.2.7 WELLHEAD REQUIREMENTS FOR SUSPENDED WELLS

IRP Operators must consult local regulations for all wellhead requirements related to suspended wells. See Appendix D for Table 1. Suspension requirements for all inactive wells from Directive 013: Suspension Requirements for Wells. Table 1 of Directive 013 calls for ongoing inspections annually, every three years, or every five years based on the method of suspending the well and the well type.




APPENDIX A - FLANGE/RING DIMENSIONS.



API Pressure Rating

Flange Ring Groove Bolt Studs

NOM SIZE

“old” Nom-

Size in inches

A Outside Dia. ”

T” P or G ” O.D.

E Width

” API No D Bolt

Circle No. Size in inches Length

Casing Thread

O.D. ”

52.4 2 165 33.3 82.55 8.73 23 127.0 8 ⅝ 108 -- 65.1 2½ 191 36.5 101.60 11.91 26 149.2 8 ¾ 127 -- 79.4 3 210 39.7 123.83 11.91 31 168.3 8 ¾ 133 -- 103.2 4 273 46.0 149.23 11.91 37 215.9 8 ⅞ 152 --

2000 lb. WOG 179.4 6 356 55.6 211.14 11.91 45 292.1 12 1 178 177.8 (R or RX Gasket) 228.6 8 416 63.5 269.88 11.91 49 349.3 12 1⅛ 203 219.1

279.4 10 508 71.4 323.85 11.91 53 431.8 16 1¼ 222 273.1 346.1 12 559 74.6 381.00 11.91 57 489.0 20 1¼ 229 339.7 425.5 16 686 84.1 469.90 11.91 65 603.3 20 1½ 260 406.4 539.8 20 813 98.4 584.20 13.49 73 723.9 24 1⅝ 298 508.0 52.4 2 216 46.0 95.25 11.91 24 165.1 8 ⅞ 152 -- 65.1 2 ½ 244 49.2 107.95 11.91 27 190.5 8 1 165 -- 79.4 3 241 46.0 123.83 11.91 31 190.5 8 ⅞ 152 --

3000 lb. WOG 103.2 4 292 52.4 149.23 11.91 37 235.0 8 1⅛ 178 -- (R or RX Gasket) 179.4 6 381 63.5 211.14 11.91 45 317.5 12 1⅛ 203 177.8

228.6 8 470 71.4 269.88 11.91 49 393.7 12 1⅜ 229 219.1 279.4 10 546 77.8 323.85 11.91 53 469.9 16 1⅜ 241 273.1 346.1 12 610 87.3 381.00 11.91 57 533.4 20 1⅜ 260 339.7 425.5 16 705 100.0 469.90 16.67 66 616.0 20 1⅝ 298 406.4 527.1 20 857 120.7 584.20 19.84 74 749.3 20 2 368 508.0 52.4 2 216 46.0 95.25 11.91 24 165.1 8 ⅞ 152 -- 65.1 2 ½ 244 49.2 107.95 11.91 27 190.5 8 1 165 --

5000 lb. WOG 79.4 3 267 55.6 136.53 11.91 35 203.2 8 1⅞ 184 -- (R or RX Gasket) 103.2 4 311 61.9 161.93 11.91 39 241.3 8 1¼ 203 --

179.4 6 394 92.1 211.14 13.49 46 317.5 12 1⅜ 273 177.8 228.6 8 483 103.2 269.88 16.67 50 393.7 12 1⅝ 305 219.1 279.4 10 584 119.1 323.85 16.67 54 482.6 12 1⅞ 349 273.1 346.1 673 112.7 408.00 19.96 BX-160 590.6 16 1 ⅝ 318 339.7

API – BX 425.5 772 130.2 478.33 17.91 BX-162 676.3 16 1 ⅞ 368 406.4 5000 lb. WOG 476.3 905 165.9 563.50 25.55 BX-163 803.3 20 2 445 473.1 (BX Gasket) 539.8 991 181.0 632.56 27.20 BX-165 885.8 24 2 476 508.0

46.0 187 42.1 77.77 11.84 BX-151 146.1 8 ¾ 127 -- 52.4 200 44.1 86.23 12.65 BX-152 158.8 8 ¾ 133 -- 65.1 232 51.2 102.77 14.07 BX-153 184.2 8 ⅞ 152 -- 77.8 270 58.3 119.00 15.39 BX-154 215.9 8 1 171 --

API – BX 103.2 316 70.2 150.62 17.73 BX-155 258.8 8 1 ⅛ 203 -- 10,000 lb. WOG 130.2 357 79.4 176.66 16.92 BX-169 300.0 12 1 ⅛ 222 --

(BX Gasket) 179.4 479 103.2 241.83 23.39 BX-156 403.2 12 1 ½ 286 177.8 228.6 552 123.8 299.06 26.39 BX-157 476.3 16 1 ½ 330 219.1 279.4 654 141.3 357.23 29.18 BX-158 565.2 16 1 ¾ 381 244.5 346.1 768 168.3 432.64 32.49 BX-159 673.1 20 1 ⅞ 438 298.8 425.5 872 168.3 478.33 17.91 BX-162 776.3 24 1 ⅞ 445 406.4 476.3 1040 223.0 577.9 32.77 BX-164 925.5 24 2 ¼ 572 473.1 539.8 1143 241.3 647.88 34.87 BX-164 1022.4 24 2 ½ 622 508.0 46.0 208 45.2 77.77 11.84 BX-151 160.3 8 ⅞ 140 -- 52.4 222 50.8 86.23 12.65 BX-152 174.6 8 ⅞ 152 --

API – BX 65.1 254 57.2 102.77 14.07 BX-153 200.0 8 1 171 -- 15,000 lb. WOG 77.8 287 64.3 119.0 15.39 BX-154 230.2 8 1 ⅞ 191 --

(BX Gasket) 103.2 360 78.6 150.62 17.73 BX-155 290.5 8 1 ⅜ 235 -- 179.4 505 119.1 241.83 23.39 BX-156 428.6 16 1 ½ 324 177.8 228.6 648 146.1 299.06 26.39 BX-157 552.5 16 1 ⅞ 400 219.1 279.4 813 187.3 357.23 29.18 BX-158 711.2 20 2 489 244.5 46.0 257 63.5 77.77 11..84 BX-151 203.2 8 1 191 --

API – BX 52.4 287 71.4 86.23 12.65 BX-152 230.2 8 1 ⅛ 210 -- 20,000 lb. WOG 65.1 325 79.4 102.77 14.07 BX-153 261.9 8 1 ¼ 235 --

(BX Gasket) 77.8 357 85.7 119.00 15.39 BX-154 287.3 8 1 ⅜ 254 -- 103.2 446 106.4 150.62 17.73 BX-155 357.2 8 1 ¾ 311 -- 179.4 656 165.1 241.83 23.39 BX-156 554.0 16 2 445 177.8

API Pressure Rating

Flange Ring Groove Bolt Studs

NOM SIZE

“old” Nom-

Size in inches

A Outside Dia. ”

T” P or G ” O.D.

E Width

” API No D Bolt

Circle No. Size in inches Length

Casing Thread

O.D. ”

2 1/16 2 6 ½ 1 5/16 3 ¼ 15/32 23 5. 8 ⅝ 4 ½ --

2 9/16 2½ 7 ½ 1 7/16 4 15/32 26 5 7/

8 8 ¾ 5 -- 3 ⅛ 3 8 ¼ 1 9/

16 4 7/8 15/32 31 6 5/

8 8 ¾ 5 ¼ -- 4 1/16 4 10 ¾ 1 13/

16 5 7/8 15/32 37 8 ½ 8 ⅞ 6 --

2000 lb. WOG 7 1/16 6 14 2 3/16 8 5/

16 15/32 45 11 ½ 12 1 7 7 (R or RX Gasket) 9 8 16 ½ 2 ½ 10 5/

8 15/32 49 13 ¾ 12 1⅛ 8 8 5/8

11 10 20 2 13/16 12 ¾ 15/32 53 17 16 1¼ 8 ¾ 10 ¾

13 5/8 12 22 2 15/

16 15 15/32 57 19 ¼ 20 1¼ 9 13 3/8

16 ¾ 16 27 3 5/16 18 ½ 15/

32 65 23 ¾ 20 1½ 10 ¼ 16

21 ¼ 20 32 3 7/8 23 17/32

73 28 ½ 24 1⅝ 11 ¾ 20 2 1/16 2 8 ½ 1 13/

16 3 ¾ 15/32 24 6 ½ 8 ⅞ 6 -- 2 9/16 2 ½ 9 5/

8 1 15/16 4 ¼ 15/32 27 7 ½ 8 1 6 ½ --

3 ⅛ 3 9 ½ 1 13/16 4 7/

8 15/32 31 7 ½ 8 ⅞ 6 -- 3000 lb. WOG 4 1/16 4 11 ½ 2 1/16 5 7/

8 15/32 37 9 ¼ 8 1⅛ 7 -- (R or RX Gasket) 7 1/16 6 15 2 ½ 8 5/

16 15/32 45 12 ½ 12 1⅛ 8 7 9 8 18 ½ 2 13/

16 10 5/8 15/32 49 15 ½ 12 1⅜ 9 8 5/

8 11 10 21 ½ 3 1/16 12 ¾ 15/32 53 18 ½ 16 1⅜ 9 ½ 10 ¾ 13 5/

8 12 24 3 7/16 15 15/32 57 21 20 1⅜ 10 ¼ 13 3/

8 16 ¾ 16 27 ¾ 3 15/

16 18 ½ 21/32 66 24 ¼ 20 1⅝ 11 ¾ 16 20 ¾ 20 33 ¾ 4 ¾ 23 25/32 74 29 ½ 20 2 14 ½ 20 2 1/16 2 8 ½ 1 13/

16 3 ¾ 15/32 24 6 ½ 8 ⅞ 6 -- 2 9/16 2 ½ 9 5/

8 1 15/16 4 ¼ 15/32 27 7 ½ 8 1 6 ½ --

5000 lb. WOG 3 ⅛ 3 10 ½ 2 3/16 5 3/

8 15/32 35 8 8 1⅞ 7 ¼ -- (R or RX Gasket) 4 1/16 4 12 ¼ 2 7/

16 6 3/8 15/32 39 9 ½ 8 1¼ 8 --

7 1/16 6 15 ½ 3 5/8 8 5/

16 17/32 46 12 ½ 12 1⅜ 10 ¾ 7 9 8 19 4 1/16 10 5/

8 21/32 50 15 ½ 12 1⅝ 12 8 5/8

11 10 23 4 11/16 12 ¾ 21/32 54 19 12 1⅞ 13 ¾ 10 ¾

13 5/8 26 ½ 4 7/

16 16.063 0.786 BX-160 23 ¼ 16 1 ⅝ 12 ½ 13 3/8

API – BX 16 ¾ 30 3/8 5 1/

8 18.832 0.705 BX-162 26 5/8 16 1 ⅞ 14 ½ 16

5000 lb. WOG 18 ¾ 35 5/8 6 17/

32 22.185 1.006 BX-163 31 5/8 20 2 17 ½ 18 5/

8 (BX Gasket) 21 ¼ 39 7 1/

8 24.904 1.071 BX-165 34 7/8 24 2 18 ¾ 20

1 13/16 7 3/8 1 21/

32 3.062 0.466 BX-151 5 ¾ 8 ¾ 5 -- 2 1/16 7 7/

8 1 47/64 3.395 0.498 BX-152 6 ¼ 8 ¾ 5 ¼ --

2 9/16 9 ½ 2 1/64 4.046 0.554 BX-153 7 ¼ 8 ⅞ 6 --

3 1/16 10 5/8 2 19/

64 4.685 0.606 BX-154 8 ½ 8 1 6 ¾ -- API – BX 4 1/16 12 7/16 2 49/

64 5.930 0.698 BX-155 10 3/16 8 1 ⅛ 8 --

10,000 lb. WOG 5 1/8 14 1/16 3 1/

8 6.955 0.666 BX-169 11 13/16 12 1 ⅛ 8 ¾ --

(BX Gasket) 7 1/16 18 7/8 4 1/16 9.521 0.921 BX-156 15 7/

8 12 1 ½ 11 ¼ 7 9 21 ¾ 4 7/

8 11.774 1.039 BX-157 18 ¾ 16 1 ½ 13 8 5/8

11 25 ¾ 5 9/16 14.064 1.149 BX-158 22 ¼ 16 1 ¾ 15 9 5/8

13 5/8 30 ¼ 6 5/

8 17.033 1.279 BX-159 26 ½ 20 1 ⅞ 17 ¼ 11 ¾ 16 ¾ 34 5/

16 6 5/8 18.832 0.705 BX-162 30 9/

16 24 1 ⅞ 17 ½ 16 18 ¾ 40 15/

16 8 25/32 22.752 1.290 BX-164 36 7/

16 24 2 ¼ 22 ½ 18 5/8

21 ¼ 45 9 ½ 25.507 1.373 BX-164 40 ¼ 24 2 ½ 24 ½ 20 113/

16 8 3/16 1 25/

32 3.062 0.466 BX-151 6 5/16 8 ⅞ 5 ½ --

2 1/16 8 ¾ 2 3.395 0.498 BX-152 6 7/8 8 ⅞ 6 --

API – BX 2 9/16 10 2 ¼ 4.046 0.554 BX-153 7 7/8 8 1 6 ¾ --

15,000 lb. WOG 3 1/16 11 5/16 2 17/

32 4.685 0.606 BX-154 9 1/16 8 1 ⅞ 7 ½ --

(BX Gasket) 4 1/16 14 3/16 3 3/32 5.930 0.698 BX-155 11 7/

16 8 1 ⅜ 9 ¼ -- 7 1/16 19 7/

8 4 11/16 9.521 0.921 BX-156 16 7/

8 16 1 ½ 12 ¾ 7 9 25 ½ 5 ¾ 11.774 1.039 BX-157 21 ¾ 16 1 ⅞ 15 ¾ 8 5/

8 11 32 7 3/

8 14.064 1.148 BX-158 28 20 2 19 ¼ 9 5/8

1 13/16 10 1/

8 2 ½ 3.062 0.466 BX-151 8 8 1 7 ½ -- API – BX 2 1/16 11 5/

16 2 13/16 3.395 0.498 BX-152 9 1/

16 8 1 ⅛ 8 ¼ -- 20,000 lb. WOG 2 9/16 12 13/

16 3 1/8 4.046 0.554 BX-153 10 5/

16 8 1 ¼ 9 ¼ -- (BX Gasket) 3 1/16 14 1/

16 3 3/8 4.685 0.606 BX-154 11 5/

16 8 1 ⅜ 10 -- 4 1/16 17 9/

16 4 3/16 5.930 0.698 BX-155 14 1/

8 8 1 ¾ 12 ¼ -- 7 1/16 25 13/

16 6 ½ 9.521 0.921 BX-156 21 13/16 16 2 17 ½ 7



APPENDIX B - TRIM SELECTION CHART

H2S Partial Pressure

CO

2 Par

tial P

ress

ure

0 to 0.34 kPa absolute (0 to <0.05 psia)

0.34 to 3.44 kPa absolute (0.05 to 0.5 psia)

>3.44 to <10.34 kPa absolute

(>0.5 to 1.5 psia)*

>10.34 kPa absolute (>1.5 psia)*

0 to <48.263 kPa absolute

(0 to < 7 psia)

AA Non-Sour

Non-Corrosive

EE-0.5 or DD-0.5 Sour

Non-Corrosive

DD-1.5 or EE-1.5** Sour

Non-Corrosive

DD-NL or EE-NL*** Sour

Non-Corrosive 48.263 to 206.84 kPa

absolute (7 psia to 30 psia)

BB Non-Sour

Slightly Corrosive

EE-0.5 Sour

Slightly Corrosive

EE-1.5** Sour

Slightly Corrosive

EE-NL*** Sour

Slightly Corrosive >206.84 kPa to <

1378.95 kPa absolute (>30 psia to <200 psia)

CC Non-Sour

Moderately to Highly Corrosive

FF-0.5 Non-Sour


FF-1.5 Non-Sour


FF-NL*** Non-Sour


1378.95 kPa absolute and up

(200 psia and up)

Corrosion resistant alloys may be needed

CC or HH Non-Sour

Highly Corrosive

FF-0.5 or HH-0.5 Sour

Highly Corrosive

FF-1.5 or HH-1.5 Sour

Highly Corrosive

FF-NL or HH-NL Sour

Highly Corrosive Corrosion resistant alloys should be considered beginning at CO2 partial pressure of 1378.95 kPa (200 psia) Consult with engineering for material selection. Additional factors should be considered.

*Material Class ZZ may be used when materials and trims previously used for sour service will not comply with current NACE MR175/ISO15156 standards **17-4 stainless steel is not allowed for stems or tubing hangers above 3.44 kPa (0.5 psia) H2S. ***410 stainless steel is not allowed for stems or tubing hangers above 10.34 kPa (1.5 psia) H2S.

Partial Pressure Formulas: H2S Partial Pressure = x working pressure CO2 Partial Pressure = x flowing pressure H2S Partial Pressure = x working pressure

H2S PPM ________ 1,000,000

CO2 % _____ 100

H2S % _____ 100



APPENDIX C: API 6A TABLE 2 - TEMPERATURE RATINGS

Temperature classification

Operating range

oC (oF)

min. max. min. max.

K -60 82 -75 180

L -46 82 -50 180

P -29 82 -20 180

R Room temperature Room temperature

S -18 66 0 150

T -18 82 0 180

U -18 121 0 250

V 2 121 35 250



APPENDIX D: TABLE 1 FROM ERCB DIRECTIVE 013: SUSPENSION

REQUIREMENTS FOR WELLS



EUB Directive 013: Suspension Requirements for Wells (July 2007) • 3

Table 1. Suspension requirements for all inactive wells Low-risk well Medium-risk well High-risk well Well types Type 1. Noncritical sour cased wells - no perforations.

Type 2. Gas wells < 28 000 m3/day1 that are low risk (see the appendix). Type 3. Water source wells. Type 4. Class 4 injectors (see Directive 0512, Section 2). Type 5. Nonflowing3 oil wells with an H2S content < 50 moles per kilomole (mol/kmol).

Type 1. Gas wells that are medium risk (see the appendix) Type 2. Nonflowing2 oil wells > 50 mol/kmol H2S. Type 3. Flowing oil wells. Type 4. Class 2 & 3 injection, carbon dioxide (CO2) injection/disposal wells (see Directive 051, Section 2). Type 5. Class 1B waste disposal wells (see Directive 051, Section 2), and cavern service wells. Type 6. Completed low-risk wells suspended longer than 10 years.

Type 1. Critical sour wells, perforated or not. Type 2. Acid gas wells. Type 3. Class 1A waste disposal wells (see Directive 051, Section 2).

Downhole requirements

There are no downhole requirements, as these wells do not pose a significant risk while suspended.

Option 1. Packer and a tubing plug. Option 2. Bridge plug. Option 3. Type 5 cavern service wells only. All product to be evacuated from the cavern and replaced with saturated brine. All hanging tubing/casing strings to be removed and a bridge plug set.

Option 1. Packer and a tubing plug. Option 2. Bridge plug capped with 8 m lineal cement.

Inspection/ monitoring/ pressure testing requirements

Type 1. Pressure test casing to 7 megapascals (MPa) for 10 minutes. Type 2, 3, 4, 5. Read and record shut-in tubing pressure (SITP) and shut-in casing pressure (SICP).

Option 1. Pressure test annulus and tubing to 7 MPa for 10 minutes. Option 2, 3. Pressure test casing to 7 MPa for 10 minutes.

Option 1. Pressure test annulus and tubing to 7 MPa for 10 minutes. Option 2. Pressure test casing to 7 MPa for 10 minutes.

Inspection frequency

Types 1,2,3,4 – 5 years. Type 5 – 1 year.

Option 1 – 3 years. Option 2,3 – 5 years.

Option 1 – 1 year. Option 2 – 5 years.

Reporting Within 30 days after completion of inspection or suspension operations. Within 30 days after resumption of production/injection. Wellbore fluid None Wellbore fluid is to be inhibited with a nonfreezing fluid in the top 2 m. Wellheads Unperforated wells may use a welded steel plate atop the

production casing stub. The plate must provide access to the wellbore for pressure measurement. Perforated wells are to have standard wellheads.

Standard wellheads as outlined in Oil and Gas Conservation Regulations. 6.100(3), 6.130(1)(2), 7.050(3), 7.060(8), ID 98-02, ID 97-6, IRP (ARP) 2, IRP 5 and API - 6A. CSA Z341 (Caverns)

Wellhead maintenance

There shall be no wellhead leaks. Regular wellheads require servicing and pressure testing of sealing elements at time of suspension and at each subsequent inspection. All outlets except surface casing vents are to be bull plugged or blind flanged with needle valves. Valves must be functional (open/close). Grease and service as required to maintain functionality.

Security All wellheads are to be conspicuously marked or fenced such that they are visible in all seasons with well identification sign in plain view. In agricultural areas, farming operations must be restricted to safe distances from the wellhead. Pumpjacks must be left in a secure condition. Valve handles must be chained and locked, or as an alternative, valve handles may be removed.

Surface casing vent flows

Systems must be open and comply with the Oil and Gas Regulations 6.100 (1) (2) (3). Vent flows, if detected, are to be handled as described in ID 2003-01: 1) Isolation Packer Testing, Reporting, and Repair Requirements; 2) Surface Casing Vent Flow/Gas Migration Testing, Reporting, and Repair Requirements; 3) Casing Failure Reporting and Repair Requirements.

1 This flow rate is the stabilized wellhead absolute open flow (AOF). 2 Directive 051: Injection and Disposal Wells – Well Classifications, Completions, Logging and Testing Requirements. 3 Nonflowing refers to wells without sufficient reservoir pressure to sustain flow against atmospheric pressure without artificial lift. The flowing product is a fluid.

http://www.eub.ca/portal/server.pt/gateway/PTARGS_0_0_270_233_0_43/http%3B/extContent/publishedcontent/publish/eub_home/industry_zone/rules__regulations__requirements/directives/directive051.aspx




http://www.eub.ca/docs/requirements/actsregs/ogc_reg_151_71_ogcr.pdf

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http://www.eub.ca/docs/requirements/actsregs/ogc_reg_151_71_ogcr.pdf





ACRONYMS API: American Petroleum Institute

ASME: American Society of Mechanical Engineer

BHP: Bottom Hole Pressure

BOP: Blowout Preventer

BPV: Back Pressure Valve

CSA: Canadian Standards Association

CSS: Cyclic Steam Stimulation

DACC: Drilling and Completions Committee

ERP: Emergency Response Plan

ESP: Electric Submersible Pump

ERCB: Energy Resources Conservation Board

ESPCP: Electric submersible progressing cavity pump

FTD: Final Total Depth

GOR: Gas / Oil Ratio

H2S: Hydrogen Sulfide

HSN: Highly Saturated Nitrile

IRP: Industry Recommended Practice

OEM: Original Equipment Manufacturer

PCP: Progressing cavity pump

PP: Partial Pressure

PPE: Personal Protective Equipment

PSL 2: Product Service Level 2

RRP: Reciprocating Rod Pumping

SAGD: Steam Assisted Gravity Drainage

WOR: Water / Oil Ratio

WPS: Welding Procedure Specification

WQTR: Welder Qualification Test Record


REFERENCES American Petroleum Institute. (2009) API Specification for Wellhead and Christmas Tree Equipment

Enform (2010) Guideline on Contractor Management Systems

Drilling and Completions Committee (2002). IRP Volume #2 – Minimum Wellhead Requirements.

Drilling and Completions Committee. (2011) IRP Volume #3 – In Situ Heavy Oil Operations

Drilling and Completions Committee. (2010) IRP Volume #21 – Coiled Tubing Operations

ERCB (2007) Directive 013: Suspension Requirements for Wells

ERCB (2006) Directive 036: Drilling Blowout Prevention Requirements and Procedures

ERCB (2011) Directive 056: Energy Development Applications and Schedules

The Oil and Gas Conservation Regulations, 1985, 60.1.c.

National Association of Corrosion Engineers (2009) MR0175, Standard Material Requirements

http://ww2.enform.ca/safety_resources/publications/guidelinesandbestpractices/contractor_management_systems.aspx�











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