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PEH:Introduction to Wellhead Systems

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 8 - Introduction to Wellhead Systems

By Mike Speer, Dril-Quip, Inc.

Pgs. 343-368

ISBN 978-1-55563-114-7
Get permission for reuse

The objective of this chapter is to provide a brief overview of the types of wellhead systems and equipment commonly found on wells drilled in today ’

s oil and gas industry. First, we discuss two broad categories of surface wellhead systems: onshore and offshore. Then, we discuss wellhead systems used in subsea and ultradeepwater applications.

Drilling a Well on Land

When a well is drilled on land, an interface is required between the individual casing strings and the blowout preventer (BOP) stack. This interface is required for four main reasons:

  • To contain pressure through the interface with the BOP stack.
  • To allow casing strings to be suspended so that no weight is transferred to the drilling rig.
  • To allow seals to be made on the outside of each casing string to seal off the individual annulus.
  • To provide annulus access to each intermediate casing string and the production casing string.
  • We will address each of these points in turn and describe in more detail how this is achieved with the wellhead.

Pressure Containment

When drilling a well on land, a spool wellhead system is traditionally used, as shown in Fig. 8.1. This wellhead is considered a "build as you go" wellhead system that is assembled as the drilling process proceeds. The spool system consists of the following main components:

  • Starting casing head.
  • Intermediate casing spools.
  • Slip casing hanger and seal.
  • Tubing spool (if well is to be tested and/or completed).
  • Studs, nuts, ring gaskets, and associated accessories required to assemble the wellhead.

Starting Casing Head. The starting casing head (see Figs. 8.2 and 8.3) attaches to the surface casing (conductor) by either welding or threading on to the conductor. The top of the starting casing head has a flange to mate with the bottom of the BOP. The flange must meet both size and pressure requirements. The starting casing head has a profile located in the inside diameter (ID) that will accept a slip-and-seal assembly to land and support the next string of casing. The slip-and-seal assembly transfers all of the casing weight to the conductor while energizing a weight-set elastomeric seal.

Intermediate Casing Spools. The intermediate casing spool is typically a flanged-by-flanged pressure vessel with outlets for annulus access (see Fig. 8.4). The intermediate casing spool (or spools) is installed after each additional casing string has been run, cemented, and set. The bottom section of each intermediate casing spool seals on the outside diameter (OD) of the last casing string that was installed. The bottom flange will mate with the starting casing head or the previous intermediate casing spool. The top flange will have a pressure rating higher than the bottom flange to cope with expected higher wellbore pressures as that hole section is drilled deeper.

The intermediate casing spool also incorporates a profile located in the ID, which accepts a slip-and-seal assembly similar to the one installed in the starting casing head. This slip and seal will be sized in accordance with the casing program.

Tubing Spool. The tubing spool, as shown in Fig. 8.5, is the last spool installed before the well is completed. The tubing spool differs from the intermediate spool in one way: it has a profile for accepting a solid body-tubing hanger with a lockdown feature located around the top flange. The lockdown feature ensures that the tubing hanger cannot move because of pressure or temperature. The flange sizes vary in accordance with pressure requirements.

Load-Carrying Components

Casing weight is transferred to the starting casing head and intermediate spools with two different types of hanger systems:

  • A slip-and-seal casing-hanger assembly.
  • A mandrel-style casing hanger.

The slip-and-seal casing-hanger assembly (Fig. 8.6) has an OD profile that mates with the internal profile of the starting casing head and intermediate casing spools. Integral to this casing-hanger assembly is a set of slips with a tapered wedge-type back and serrated teeth that bite into the OD of the casing being suspended.

When the casing has been run and cemented, the BOP is disconnected from the casing spool and lifted up to gain access to the spool bowl area. After the slip-and-seal casing-hanger assembly is installed, the traveling block will lower the casing and set a predetermined amount of casing load onto the slip-and-seal casing-hanger assembly. The teeth on the slips will engage the pipe OD and transfer the suspended weight of the casing to the starting casing head. As the slips travel down, they are forced in against the casing, applying greater and greater support capacity. As the slips continue to engage the pipe, a load is placed on the automatic weight-set elastomeric seal assembly, sealing the annulus between the casing and the casing head. This installation creates a pressure barrier and isolates the annular pressure below the slip-and-seal casing hanger from the wellbore.

Traditionally, mandrel hangers (Fig. 8.7) are used only to suspend tubing from the tubing head. Occasionally, they can also be used in intermediate casing spools as an alternative to the slip-and-seal casing-hanger assembly. The mandrel hanger is a solid body with a through-bore ID similar to that of the tubing or casing run below, and it also has penetrations for downhole safety valve line(s) and temperature and pressure gauges, if required. Traditionally in spool wellheads, elastomeric seals are used to seal the annulus between the casing-spool body and the casing or tubing hanger.

Annulus Seals

The seals used on spool wellhead systems are traditionally elastomeric. This is primarily because the seal must be energized against the casing-bowl ID and must also seal against the rough finish of the casing OD.

This elastomeric sealing system is used for the slip-and-seal assembly as well as the bottom of the intermediate casing or tubing spools. The slip-and-seal assembly (Fig. 8.8) provides a primary annulus seal, while the elastomeric seal in the bottom of each casing and tubing spool also provides a seal. The casing-spool flange connection becomes a secondary seal for both annulus and wellbore pressure. The elastomeric seals are manufactured using different materials to allow for various pressures, produced fluids, and other environmental conditions. The exception is the seal between each flange face, which is a metal-to-metal sealing ring gasket that provides a pressure-tight seal between each of the spool flanges. Ring gaskets are also used between the wellhead and the BOP stack, as well as the valves used for annulus access.

While drilling the well, it is required that the seal bores in each of the intermediate casing spools and tubing spools be protected. A series of wear bushings (Fig. 8.9) are supplied to protect the seal areas discussed during the drilling operation. The wear bushings are run on a drillpipe tool (Fig. 8.10) with J-lugs located on the OD that interface with J-slots located in the top ID section of the wear bushing.

It is also required that the flanged connections between each spool and the BOP be tested during the drilling and completion phases. The tools required are available from the equipment supplier. The tool used for testing the BOP is typically a plug type with a heavy-duty elastomer seal.

Annulus Access

For onshore wells, during the drilling operation, access to each annulus is required for the following reasons:

  • To provide a flow-by area for returns during cementing of casing strings.
  • To provide access for possible well kill operations.
  • To monitor the annulus for pressure below the slip-and-seal assembly.

Product Material Specifications

When ordering wellhead equipment, the following should be considered:

  • All surface wellhead equipment and gate valves should be manufactured to the latest edition of the American Petroleum Inst. (API) and Intl. Organization for Standardization (ISO) standards. These standards define equipment specifications as follows:
  • Material class: based on produced fluids; AA, BB, CC, DD, EE, FF, and HH (please see the example for gate-valve trims, shown in Fig. 8.11).

  • Temperature range: 75 to+


  • Please review the relevant API specifications for your application or consult your equipment supplier for further information.

Drilling a Well Offshore From a Jackup Drilling Rig Using Mudline Suspension Equipment

From a historic point of view, as jackup drilling vessels drilled in deeper water, the need to transfer the weight of the well to the seabed and provide a disconnect-and-reconnect capability became clearly beneficial. This series of hangers, called mudline suspension equipment, provides landing rings and shoulders to transfer the weight of each casing string to the conductor and the sea bed.

The mudline hanger system (shown in Fig. 8.12) consists of the following components:

  • Butt-weld sub.
  • Shoulder hangers.
  • Split-ring hangers.
  • Mudline hanger running tools.
  • Temporary abandonment caps and running tool.
  • Tieback tools.
  • Cleanout tools.

Mudline Hangers

Each mudline hanger landing shoulder and landing ring centralizes the hanger body and establishes concentricity around the center line of the well. Concentricity is important when tying the well back to the surface. In addition, each hanger body stacks down relative to the previously installed hanger for washout efficiency. Washout efficiency is necessary to clean the annulus area of the previously run mudline hanger and running tool (Fig. 8.13). This ensures that cement and debris cannot hinder disconnect and retrieval of each casing riser to the rig floor upon abandonment of the well.

As each hole section is drilled and each casing string and mudline hanger is run, the hanger is positioned in the casing string to land on a landing shoulder inside the mudline hanger that was installed with the previous casing string. Each of the mudline hangers have casing and a mudline hanger running tool made up to it. These running tools are released through right-hand rotation to allow disconnect from the well. The threads on the mudline hanger used by the running tool can be used to install temporary abandonment caps (Fig. 8.14) into selected hangers to temporarily "suspend" drilling operations at the conclusion of the well.

The main difference between the wellheads used in the land drilling application and the jackup drilling application (with mudline) is the slip-and-seal assembly (Fig. 8.15). Because the weight of the well now sits at the seabed, a weight-set slip-and-seal assembly is not used. Instead, a mechanical set (energizing the seal by hand) is used, in which cap screws are made up with a wrench against an upper compression plate on the slip-and-seal assembly to energize the elastomeric seal.

Temporarily Abandoning the Well

The mudline suspension system also allows the well to be temporarily abandoned (disconnected) when "TD" is achieved (when drilling is finished at total depth). When this occurs, the conductor is normally cut approximately 5 to 6 ft above the mudline and retrieved to the surface. After each casing string is disconnected from the mudline suspension hanger and retrieved to the rig floor in the reverse order of the drilling process, threaded temporary abandonment caps or stab-in temporary abandonment caps (both of which makeup into the threaded running profile of the mudline hanger; see Fig. 8.14) are installed in selected mudline hangers before the drilling vessel finishes and leaves the location. The temporary abandonment caps can be retrieved with the same tool that installed them.

Reconnecting to the Well

A mudline suspension system also incorporates tieback tools to reconnect the mudline hanger to the surface for re-entry and/or completion. These tieback tools can be of two types: threaded and stab-in (see Fig. 8.16). The tieback tools are different from the running tools in that they makeup into their own dedicated right-hand makeup threaded profile. The stab-in tieback tool offers a simple, weight-set, rotation-lock design that provides an easy way to tie the well back to the surface. A surface wellhead system is installed, and the well is completed similarly to the method used on land drilling operations.

The mudline suspension system has been designed to accommodate tying the well back to the surface for surface completion, and it also can be adapted for a subsea production tree. A tieback tubing head can be installed to the mudline suspension system at the seabed, and a subsea tree can be installed on this tubing head.

The Unitized Wellhead

The unitized wellhead is very different from the spool wellhead system because it incorporates different design characteristics and features. The unitized wellhead, shown in Fig. 8.17, is a one-piece body that is typically run on 13 3/8 -in. casing through the BOP and lands on a landing shoulder located inside the starting head or on top of the conductor itself. The casing hangers used are threaded and preassembled with a pup joint. This way, the threaded connection can be pressure tested before leaving the factory, ensuring that the assembly will have pressure-containing competence. Gate valves are installed on the external outlet connections of the unitized wellhead to enable annulus access to each of the intermediate and the production casing strings.

After the next hole section is drilled, the casing string, topped out with its mandrel hanger, is run and landed on a shoulder located in the ID of the unitized wellhead. A seal assembly is run on a drillpipe tool to complete the casing-hanger and seal-installation process. Each additional intermediate casing string and mandrel hanger is run and landed on top of the previously installed casing hanger without removing the BOP stack. Besides saving valuable rig time, the other advantage of the unitized wellhead system over spool wellhead systems is complete BOP control throughout the entire drilling process.

The unitized wellhead (Fig. 8.18) consists of the following components:

  • Unitized wellhead body.
  • Annulus gate valves.
  • Mandrel casing hangers.
  • Mandrel tubing hangers.
  • Metal-to-metal sealing for the annulus seals.

Mandrel Casing Hangers

The mandrel casing hangers (see Fig. 8.19) are a one-piece construction and are manufactured to meet the casing and thread types specified by the customer. The mandrel casing hanger has a 4° tapered sealing area on its OD. The mandrel hanger still also incorporates running threads and seal-assembly threads to facilitate installation. The hanger carries a lock ring that locks the hanger down when the seal assembly is installed. The mandrel casing hanger lands on either the shoulder located in the bottom of the unitized wellhead body or on top of the previous casing hanger.

Seal Assembly

The seal assembly incorporates a metal-to-metal or elastomeric seal (Fig. 8.20), which is run on a running tool through the BOP stack once the casing has been cemented. The seal assembly seals off the pressure from above and below and isolates the annulus from the wellbore. The annulus can still be monitored through the outlets on the unitized wellhead body and the gate valves mounted to them.

There is a full range of tools available for the unitized wellhead system:
  • Wellhead-housing running tool.
  • BOP test tool.
  • Casing-hanger running tool.
  • Seal-assembly running and retrieving tool.
  • Wear-bushing running and retrieving tool.

The unitized wellhead is more often used with platform-development projects than with exploration applications.

Drilling a Well Subsea

The subsea wellhead system (Fig. 8.21) is a pressure-containing vessel that provides a means to hang off and seal off casing used in drilling the well. The wellhead also provides a profile to latch the subsea BOP stack and drilling riser back to the floating drilling rig. In this way, access to the wellbore is secure in a pressure-controlled environment. The subsea wellhead system is located on the ocean floor and therefore must be installed remotely with running tools and drillpipe.

The subsea wellhead ID is designed with a landing shoulder located in the bottom section of the wellhead body. Subsequent casing hangers land on the previous casing hanger installed. Casing is suspended from each casing-hanger top and accumulates on the primary landing shoulder located in the ID of the subsea wellhead. Each casing hanger is sealed off against the ID of the wellhead housing and the OD of the hanger itself with a seal assembly that incorporates a true metal-to-metal seal. This seal assembly provides a pressure barrier between casing strings, which are suspended in the 18¾-in. wellhead.

Once drilling is complete, the wellhead will provide an interface for the production tubing string and the subsea production tree or, if required, a point to tie back to a platform. The design objective of the subsea wellhead system is twofold: first, to provide the operator with the latest equipment technology incorporating reliable solutions for the well conditions to be encountered, as well as maximum strength and capacities; and second, to provide a system that is easy to install and requires a minimal amount of handling and rig time.

A standard subsea wellhead system will typically consist of the following:
  • Drilling guide base.
  • Low-pressure housing.
  • High-pressure wellhead housing (typically 18¾ in.).
  • Casing hangers (various sizes, depending on casing program).
  • Metal-to-metal annulus sealing assembly.
  • Bore protectors and wear bushings.
  • Running and test tools.

Drilling Guide Base

The drilling guide base (Fig. 8.22) provides a means for guiding and aligning the BOP onto the wellhead. Guide wires from the rig are attached to the guideposts of the base, and the wires are run subsea with the base to provide guidance from the rig down to the wellhead system.

Low-Pressure Housing

The low-pressure housing (typically 30 or 36 in.; see Fig. 8.23) provides a location point for the drilling guide base and provides an interface for the 18¾-in. high-pressure housing. It is important for this first string to be jetted or cemented in place correctly because this string is the foundation for the rest of the well.

High-Pressure Housing

The subsea high-pressure wellhead housing (typically 18¾ in.) is effectively a unitized wellhead with no annulus access. It also provides an interface between the subsea BOP stack and the subsea well. The subsea wellhead is the male member to a large-bore connection, as shown in Fig. 8.24 (the female counterpart is the wellhead connector on the bottom of the BOP stack) that will be made up in a remote subsea, ocean-floor environment. The 18¾-in. wellhead will house and support each casing string by way of a mandrel-type casing hanger. The ID of the 18¾-in. wellhead provides a metal-to-metal sealing surface for the seal assembly when it is energized around the casing hanger. The wellhead provides a primary landing shoulder in the bottom ID area to support the combined casing loads and will typically accommodate two or three casing hangers and a tubing hanger. The minimum ID of the wellhead is designed to let a 17½-in. drilling bit pass through.

Casing Hangers

All subsea casing hangers are mandrel type, as shown in Fig. 8.25. The casing hanger provides a metal-to-metal sealing area for a seal assembly to seal off the annulus between the casing hanger and the wellhead. The casing weight is transferred into the wellhead by means of the casing hanger/wellhead landing shoulder. Each casing hanger stacks on top of another and, consequently, all casing loads are transferred through each hanger to the landing shoulder at the bottom of the subsea wellhead. Each casing hanger incorporates flow-by slots to facilitate the passage of fluid while running through the drilling riser and BOP stack and during the cementing operation.

Metal-to Metal Annulus Seal Assembly

The seal assembly (Fig. 8.26) isolates the annulus between the casing hanger and the high-pressure wellhead housing. The seal incorporates a metal-to-metal sealing system that today is typically weight-set (torque-set seal assemblies were available in earlier subsea wellhead systems). During the installation process, the seal is locked to the casing hanger to keep it in place. If the well is placed into production, then an option to lock down the seal to the high-pressure wellhead is available. This is to prevent the casing hanger and seal assembly from being lifted because of thermal expansion of the casing down hole.

Bore Protectors and Wear Bushings

Once the high-pressure wellhead housing and the BOP stack are installed, all drilling operations will take place through the wellhead housing. The risk of mechanical damage during drilling operations is relatively high, and the critical landing and sealing areas in the wellhead system need to be protected with a removable bore protector and wear bushings, as shown in Fig. 8.27.

Running and Test Tools

The standard subsea wellhead system will include typical running, retrieving, testing, and reinstallation tools (see Fig. 8.28). These tools include:

  • Conductor Wellhead Running Tool. The conductor wellhead running tool runs the conductor casing, conductor wellhead, and guide base. This tool can be used for jetting in the conductor or cementing the conductor into a predrilled hole. The tool is a cam-actuated tool that minimizes any high torque that may be encountered during operations.
  • High-Pressure Wellhead Running Tool. The high-pressure wellhead running tool operates just like the conductor wellhead running tool, but it runs the high-pressure wellhead and 20-in. casing. It is a cam-actuated tool that minimizes any high torque that may be encountered during operations.
  • Casing-Hanger Seal-Assembly Running Tool. The casing-hanger seal-assembly running tool runs the casing, casing hanger, and seal assembly in one trip. It also allows testing of the seal assembly (after installation) and the BOP stack, and it has the additional benefit of bringing back the seal assembly if debris is in the way and the seal assembly cannot be installed.
  • Multipurpose Tool and Accessories. The multipurpose tool runs and retrieves the nominal bore protector and all wear bushings. A jet sub and/or jet sub extension can be attached to the multipurpose tool so that wellhead washout can occur during the retrieval process. The multipurpose tool also retrieves the seal assembly and becomes a mill-and-flush tool by attaching the mill-and-flush adapter.
  • BOP Isolation Test Tool. The BOP isolation test tool allows testing of the BOP stack without allowing pressure to be applied against the casing-hanger seal assembly. The BOP isolation test tool can land on the casing hangers or wear bushings.
  • Seal-Assembly Running Tool. The seal-assembly running tool is used in the event that a second seal assembly needs to be run. The seal-assembly running tool is a weight-set tool and, like the casing-hanger seal-assembly running tool, it allows testing of the BOP stack and recovers the seal assembly if it cannot be installed (because of debris in the sealing area of the annulus).

Big Bore Subsea Wellhead Systems

As the offshore oil and gas industry has continued to explore for oil and gas in deeper and deeper waters, the requirements for well components have changed as a result of the challenges associated with deepwater drilling. Ocean-floor conditions in deep and ultradeep water can be extremely mushy and unconsolidated, which creates well-foundation problems that require development of new well designs to overcome the conditions. Second, underground aquifers in deep water have been observed in far greater frequency than in shallower waters, and it quickly became clear that these zones would have to be isolated with a casing string. Cementing requirements changed, and wellhead equipment designs would also have to change to accommodate the additional requirements.

With subsea wellhead systems, conductor and intermediate casing strings can be reconfigured to strengthen and stiffen the upper section of the well (for higher bending capacities) and overcome the challenges of an unconsolidated ocean floor at the well site. But each "water flow" zone encountered while drilling requires isolation with casing and, at the same time, consumes a casing-hanger position in the wellhead. It became obvious that more casing strings and hangers were required to reach the targeted depth than the existing wellhead-system designs would accommodate.

The 18¾-in. Big Bore Subsea Wellhead System (Fig. 8.29) was designed for wells that will be installed in unconsolidated ocean-floor conditions and will penetrate shallow water-flow zones. These well conditions require additional casing strings. The wellhead system incorporates an 18¾-in. high-pressure wellhead housing designed for 15,000 psi and 7 million pounds end-load carrying capacity. Unlike conventional subsea wellhead systems, the big-bore high-pressure wellhead housing (Fig. 8.30) is run atop 22-in. pipe (as opposed to 20-in. pipe) and has a large minimum ID bore to pass 18-in. casing. The wellhead system incorporates a rigid lockdown mechanism to preload the connection between the high-pressure wellhead and the conductor wellhead. A supplemental hanger adapter is installed in the 22-in. casing to provide a landing shoulder and seal area for the 18-in. and 16-in. supplemental hangers and their testable, retrievable seal assemblies.

Optional 28-in., 26-in., and 24-in. supplemental casing-hanger systems can be incorporated into the design to accommodate a secondary conductor string and thereby increase the overall bending capacity of the upper section of the well and/or provide an additional barrier for a water-flow zone. All casing hangers and seal assemblies are run, set, and tested on drillpipe in a single trip. These subsea wellhead systems can easily accommodate alternative casing programs and can be configured to address any deepwater (and shallow-water) drilling application.


As has been discussed in this chapter, wellhead systems (whether the application is surface wellheads on land, jackups or offshore production platforms, or subsea wellheads) serve as the termination point of casing and tubing strings. As such, these systems control pressure and provide access to the main bore of the casing or tubing or to the annulus. This pressure-controlled access allows drilling and completion activities to take place safely and with minimal environmental risk. Multiple barriers are used, such as primary and secondary seals, to reduce risk in case of equipment failure.

Land wellhead systems, offshore surface wellhead systems, and subsea wellhead systems have been discussed. Offshore wellhead systems are normally more sophisticated in design to handle ocean currents, bending loads, and other loads induced by the environment during the life of the well. Some of these loads are cyclic in nature, so fatigue-resistant designs are desirable, particularly for deepwater developments. Material specifications play an important role in equipment performance; organizations such as API, the American Soc. of Mechanical Engineers (ASME), and NACE Intl. offer helpful standards to provide cost-effective solutions to technical challenges.

In certain applications such as deepwater platforms, spars, and tension-leg platforms (TLPs), surface wellheads and subsea wellheads are used together to safely produce hydrocarbons. In water depths of 500 to 1,400 ft, subsea wellheads are used to explore and develop offshore fields. Deepwater production platforms can be placed over these wells and tied back to the subsea wellheads; the top termination of the tieback at the platform will typically use surface unitized wellheads with solid block Christmas trees (which have fewer leak paths) as pressure-controlled access points to each well. Spars and TLPs are floating vessels used in deep water up to 4,500 ft. The wells are drilled using subsea wellheads, which are then tied back to the production deck of the spar or TLP, again using unitized wellheads and solid block trees to safely control and produce the well. For these special applications, it is recommended to contact your equipment supplier for more detailed information.

General References

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Anchaboh, L., de Lange, F.P.A., van Beelen, C.J. et al. 2001. Conductor Sharing Wellheads—More For Less. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 17–19 April. SPE-68699-MS.

Andersen, J.N., Rosine, R.S., and Marshall, M. 2000. Full-Scale High-Pressure Stripper/Packer Testing with Wellhead Pressure to 15,000 psi. Presented at the SPE/ICoTA Coiled Tubing Roundtable, Houston, Texas, 5-6 April 2000. SPE-60699-MS.

Bazile II, D.J. and Kluck, L.M. 1987. New Wellhead Equipment for Old Oilfields. Presented at the SPE/IADC Drilling Conference, New Orleans, Louisiana, 15-18 March 1987. SPE-16122-MS.

Burman, S.S. and Norton, S.J. 1998. Mensa Project: Well Drilling and Completion. Presented at the Offshore Technology Conference, Houston, Texas, 4 May-7 May 1998. OTC-8578-MS.

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Dupal, K. and Flodberg, K.D. 1991. Auger TLP: Drilling Engineering Overview. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 6–9 October. SPE-22543-MS.

Eaton, L.F. 1999. Drilling Through Deepwater Shallow Water Flow Zones at Ursa. Presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 9–11 March. SPE-52780-MS.

Gordy, C.A., Combes, J.F., and Childers, M.A. 1987. Case History of a 22,000-ft Deepwater Wildcat. Presented at the SPE/IADC Drilling Conference, New Orleans, Louisiana, 15-18 March 1987. SPE-16084-MS.

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Harms, D.A. 1994. Coiled-Tubing Completion Procedure Reduces Cost and Time for Hydraulically Fractured Wells. Presented at the SPE Western Regional Meeting, Long Beach, California, 23-25 March. SPE-27892-MS.

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Kenda, W.P., Allen, T.J., and Herbel, R.R. 2003. Offline Subsea Wellhead MODU Operations Provide Significant Time Savings. Presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 19-21 February. SPE-79834-MS.

Landeck, C.R. 1996. Application of Stacked Template Structures Offshore Indonesia. Presented at the SPE Asia Pacific Oil and Gas Conference, Adelaide, Australia, 28-31 October. SPE-37033-MS.

McLeod, S. and Harlety, F.J. 2001. Drilling Technology Part 1: Poseidon 29,000-ft well in 4,800-ft depths harbinger of future for US Gulf. Offshore Magazine. 61 (4): 56.

McLeod, S. and Hartley, F.J. 2001. Drilling Technology: Part II: Positive and negative events in drilling of Poseidon 29,750-ft well. Offshore Magazine. 61 (5): 68.

Nikravesh, M., Soroush, M., Johnston, M.R. et al. 1997. Design of Smart Wellhead Controllers for Optimal Fluid Injection Policy and Producibility in Petroleum Reservoirs: A Neuro-Geometric Approach. Presented at the International Thermal Operations and Heavy Oil Symposium, Bakersfield, California, 10-12 February. SPE-37557-MS.

Schulz, R.R., Stehle, D.E., and Murall, J. 1999. Completion of a Deep, Hot, Corrosive East Texas Gas Well. SPE Prod & Oper 14 (2): 150-157. SPE-14983-PA.

Tuah, J.B., Rujhan, M., Mat, B. et al. 2000. Triple Wellhead Technology in Sarawak Operations. Presented at the Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16–18 October. SPE-64277-MS.

Watson, P., Kolstad, E., Borstmayer, R. et al. 2003. An Innovative Approach to Development Drilling in Deepwater Gulf of Mexico. Presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 19–21 February. SPE-79809-MS.

Wei, J. 2000. Technique for Close Cluster Well Head Concentrated High Quality and High Speed Drilling Cementing Surface Interval in Sz36-1d. Presented at the IADC/SPE Asia Pacific Drilling Technology, Kuala Lumpur, Malaysia, 11-13 September 2000. SPE-62776-MS.

SI Metric Conversions Factors

ft × 3.048* E–01 = m
°F   (°F–32)/1.8   = °C
in. × 2.54* E+00 = cm
psi × 6.894 575 E+00 = kPa


Conversion factor is exact.