Subsea 101 Rev3

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Subsea 101

An Introduction To

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WARNING: This information is provided to FMC customers solely to illustrate the operation of FMC equipment. It does not provide complete

Subsea Wellhead & Completions Reference Book

Section 1 Introduction to FMC

Section 2 Vessels Utilized in Drilling, Production and

Workover Operations

Section 3 Casing and Casing Programs

Section 4 Drilling a Subsea Well

Section 5 UWD-15 Subsea Drilling Systems

Section 6 Subsea Trees

Section 7 Subsea Production Systems

Section 8 Subsea Controls Systems

Section 9 ManTIS Products

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Section 1 Introduction to FMC Technologies

1.0 Introduction

The following information was taken directly from the FMC Technologies website located at:

http://www.fmctechnologies.com/

1.1 Legacy

From exploration to delivery, FMC Technologies supports it all. FMC Energy Production Systems and Energy Processing Systems businesses are global technology leaders providing solutions for customers engaged in petroleum

exploration, production, measurement and transportation. Those solutions include the design, manufacture and supply of technology and equipment.

How did we get here?

FMC Corporation acquired O-C-T (Oil Center Tools) in 1957 and committed the assets to enhance manufacturing and service capabilities, grow the business into the offshore sector and expand internationally. There were numerous acquisitions by FMC following O-C-T, including Well Equipment Company (WECO),

Chiksan, Smith Meter, SOFEC and Kongsberg Offshore (KOS), CBV and CDS. Now these entities are part of FMC Technologies.

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This pattern of acquiring companies with strong products and name recognition assisted in growing FMC Airport Equipment and Services business as well. The acquisition of Jetway Systems in the 1990s aided FMC Airport Systems division in becoming a leading supplier of proven and advanced technology solutions to

airlines and airports worldwide. In more than 200 airports in 40 countries, FMC Technologies is the standard for passenger boarding bridges, cargo loaders, de-icers, push-back tractors, automated guided vehicles and a wide range of airport services.

FMC FoodTech, the food processing equipment group of FMC Technologies, is an important player in the history of FMC Technologies. FMC Technologies traces its roots to 1884 when inventor John Bean developed a new type of spray pump to combat San Jose scale in California's orchards. By the mid-1930s FMC was the world's largest manufacturer of machinery and equipment for handling fruits, vegetables, milk, fish and meat products. In 1996 FMC purchased Frigoscandia Equipment, the leading food freezing equipment manufacturer -- and now FMC FoodTech equipment is used to prepare more than 50% of the world's frozen food. FMC FoodTech sterilizes more than 50% of the world's shelf-stable canned foods as well.

1.2 Mission

Our Vision

To be the premier provider of world-class, mission-critical technology solutions for the energy, food processing and air transportation industries

Our Path:

• Build and strengthen alliances

• Partner with our customers

• Focus on providing complete solutions instead of selling hardware

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• Focus on growing profits and increasing returns

• Attract and retain the best talent in the industry

1.3 Energy Systems and Services

FMC Technologies' energy production and processing systems provide solutions for customers engaged in petroleum exploration, production, measurement and transportation. Those solutions include the design, manufacture and supply of technology and equipment.

Through strategic alliances with customers and suppliers worldwide, FMC Technologiesdelivers an industry leading mix of stand-aloneproducts and

integrated systems designed to meet the technical, economic, and life cycle demands of customers onsix continents. FMC Technologies' emphasis on cost-effective,life-of-field solutions has led to numerous technology breakthroughs.

Production

Subsea Processing promises significant cost savings by partially processing the well stream at the sea floor. This helps customers reduce investment costs for flow lines and topside processing equipment. Additionally, subsea processing

potentially increases overall recovery rates and field life.

Light Well Interventionsignificantly enhances hydrocarbon recovery by

improving reservoir management. FMC have designed a cost-effective solution for diverless subsea wireline intervention from a dynamically positioned vessel.

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New generation "building block"deepwater subsea production systemdesigns deliver unprecedented flexibility and cost savings. These new systems include subsea trees, template/manifold systems and state-of-the-art control systems suitable for use in water depths up to 3000 meters. New generation subsea trees are designed to meet customer needs for high-pressure, high-temperature operating conditions with ease of workover from various types of vessels.

Tension Leg Platform (TLP) / Spar Dry Tree Systems provided by FMC Technologies are fast becoming the industry standard for advanced wellhead technology. Innovations that keepFMC at the forefront of technology in this area include the development of a deepwater riser load measurement system, adjustable mandrel hanger system and internal tieback connector.

Surface Wellsite Management combines FMC technologies and know-how to help customers worldwide better manage surface wells and wellhead assets. By managing wellsite assets for customers, FMC Technologies enables regulation compliance, enhanced wellhead performance and life, rig time savings, improved wellsite knowledge and better asset utilization.

Processing

Flowline Asset Management tracks and maintains high-pressure flowline

equipment used in oilfield service applications. FMC have developed a web-based asset management solution that identifies the equipment, tracks usage patterns and establishes inspection and repair intervals to ensure that the right products are shipped to the job site on time

and in top working condition.

New Generation Metering

Systems, provided by the world leader in the flow measurement of petroleum products, deliver technical superiority in a complete range of liquid and gas custody transfer solutions.

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Boom-to-tanker LNG loading systems, developed in cooperation with 10 major global energy companies. FMC Technologies enables the offloading of liquified natural gas (LNG) from an offshore production vessel to a shuttle carrier.

Advanced Truck and Railcar Loading Systems feature long-life Series 2000 swivel joint and carbon-fiber reinforced composite spring balancing devices. These devices are redefining truck and railcar loading arm performance and life cycles.

The businesses that comprise FMC Technologies' energy systems and services ventures include:

Subsea Systems - Advanced technology, products and systems for full field subsea development

Surface Wellhead - Industry-leading surface and platform wellhead equipment and services

Floating Systems - First in turret mooring systems and transfer buoys

Fluid Control - The industry standard in flowline products, production manifold systems and pumps

Loading Systems - Global leader in solutions for marine, truck and rail car fluid handling systems

Measurement Solutions- The industry's leader in liquid and gas measurement systems

Blending and Transfer - Leader in the turnkey supply of blending, transfer, and process control systems for the petroleum and process industries

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FMC Technologies’ global presence makes it strategically placed to meet the deepwater needs of our customers.

Houston Kongsberg Singapore Dunfermline Rio De Janeiro Edmonton Calgary St. John’s Halifax Villahermosa Maracaibo Macae Lagos Eq. Guinea Luanda Muscat Aberdeen Sens Bergen Stavanger Johor Jakarta Perth Anchorage Mauritania Congo

To support drilling and production systems FMC has located manufacturing and support facilities in strategic locations worldwide. The map above shows the location of the key facilities.

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FMC has supplied more subsea trees than any other manufacturer. The following provides an indication of the number of subsea trees supplied by region. It should be noted that the number of trees supplied is increasing on a monthly basis.

FMC is the leading supplier of subsea systems worldwide and the graph below provides an indication of FMC market share during the 2002 to 2004 period. FMC continues to

invest in research and development, manufacturing capabilities and processes and human resources to maintain this leading global position.

FMC’s global inbound tree market share:

N. America 300 Brazil 240 Norway 260 U.K. 80 Africa 200 Asia 120 1,200 Subsea Trees Over 250 Projects 273 229 362 430 464 98 0 100 200 300 400 500 600 2002 2003 2004 2005 2006 F 38% 40% 47% 40%

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FIXED PLATFORM MULTI PORPOSE SERVICE VESSEL (MSV)

TENSION LEG PLATFORM (TLP)

FLOATING, PRODUCTION & OFFLOADING VESSEL

(FPSO)

Section 2 Vessels Utilized in Drilling, Production, Workover &

Intervention Operations

2.0 Vessels used in Production and Workover Operations

The subsea drilling and production business is dependent upon a variety of vessels to support exploration drilling, development, production and workover of wells in shallow and deepwater. New and innovative operational methods are continuously being envisioned and developed to support these efforts. In this section, you will be exposed to several of the most prevalent vessels we at FMC Technologies interface with to install our products.

The graphic below displays four typical methods in which subsea well systems may be tied back in order to accommodate production. Note the Fixed Platform as the name suggests is fixed to the sea bed by fabricated columns. The MSV, TLP, and FPSO all float and do not have a sea bed support structure.

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The graphic below shows the progression of completion depths and the corresponding platform technologies. As can be seen, the structural and

distribution technologies have adapted to the increasing challenges of producing in deeper and deeper waters.

Fixed Platform (To 1650 Feet) Compliant Tower (1500 To 3000 Feet) Mini - TLP (600 To 3500 Feet) Floating Production Systems (FPSO, FPF) (1500 to 7500 Feet) Tension Leg Platform (TLP) (1500 To 4500 Feet) SPAR Platform (SP) (2000 To 7500 Feet) Subsea Systems (To 10000+ Feet) Fixed Platform (To 1650 Feet) Compliant Tower (1500 To 3000 Feet) Mini - TLP (600 To 3500 Feet) Floating Production Systems (FPSO, FPF) (1500 to 7500 Feet) Tension Leg Platform (TLP) (1500 To 4500 Feet) SPAR Platform (SP) (2000 To 7500 Feet) Subsea Systems (To 10000+ Feet)

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For the “heavy” part of the installation, normally called a workover or completion, a semi submersible rig is typically used. For lighter jobs, often called intervention, it is normal to use diving vessels or smaller service rigs. The following are a few vessels FMC commonly interface with in our business:

The Semi-submersible Rig

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RIG SUBMERGED COLUMNS

SUBSEA EQUIPMENT

A semi submersible rig, as the name suggests, means that the columns and hull that support the rig can be filled with water to partially (semi) submerge the rig or emptied to float the rig on the surface.

Partially submerging the rig provides increased rig stability especially in heavy seas. Rig can be ballasted for transport by a vessel or can be towed to location. A semi submersible deck and moon pool arrangement is ideal for handling the subsea equipment associated with subsea drilling and completion equipment. This type rig allows use in deep water applications with dynamic positioning.

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Drill ships allow work to be completed in deep water without anchors using a dynamic positioning system. Dynamic Positioning (DP) is a system to

automatically maintain a ship’s position and heading by using her own propellers and thrusters. This allows operations at sea where mooring or anchoring is not feasible due to deep water, congestion on the sea bottom (pipelines, templates) or other problems. Additionally, this vessel does not require towing between

locations.

The drill ship, as the name implies, has a ship shaped hull with the derrick typically mounted over a “hole” in the center of the hull. Drill ships and semi-submersibles – also known as Mobile Offshore Drilling Units (MODUs), have this “hole” in the hull or deck to allow passage of the subsea equipment to the sea floor. This hole is called the moon pool.

Shown in the above photograph is the top of the marine drilling riser that is connected to the subsea blow out preventor landed and locked to the subsea

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Permanent guidebase being run through the moonpool area

EHXT (Enhanced Horizontal Xmas Tree) landed on support beams in moon pool area

below the tensioning ring stays still (attached to the subsea wellhead) and the rig will move up and down above this point due to sea conditions.

The above photographs show a typical moon pool arrangement on a

semi-submersible rigs. The moon pool size is typically 6 meters square and as such all subsea equipment must be designed to pass through this size.

Moonpool

Areas

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Supply Boats

The supply boat is the work horse of the offshore industry and transports all

supplies to the offshore platforms and rigs. They carry everything from food stuffs, chemicals, casing to subsea production equipment. The picture below shows a compact subsea manifold on the deck of a supply boat.

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Other vessel used include Dive Support vessels and Multi Service Vessels that provide services including diver operations for multiple operations, light weight intervention to subsea trees, flow line and flow line jumper installation and rock dumping to protect flow lines.

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Section 3 Casing & Casing Programs

3.0 Introduction

Drilling for a hole in the earth in the search for hydrocarbons involves the use of special equipment to both drill the hole and to install strings of casing. Casing is steel pipe used to support the open hole to prevent it from caving in and to separate

different geological formations. This is especially important during the drilling of the well and later when total depth or “TD” is reached to assure the oil and gas can be brought back to the surface. Casing is usually cemented into the hole to ensure a pressure tight connection to the oil and gas reservoir. Standard casing sizes range from 7” to 36” in diameter.

Overall, casing serves to:

• Prevent cave in or washout of the hole

• Prevent contamination of freshwater sands by fluids from lower zones

• Exclude water from the producing formation

• Confine production to the well bore

• Isolates different formations

• Provide a means of controlling the well pressure

• Permit installation of artificial lift equipment for producing the well

• Provide a flow path for produced fluids

3.1 Types of Casing

During the course of drilling the well, casing is run and set at various intervals of hole depth. The number and size of casing strings will vary with each well and is

determined by the drilling engineer(s) as the well is being planned. There are

typically 3 to 5 strings of casing run on any given well. The different types of casing strings include conductor, surface, intermediate, production, and liner.

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Structural or Conductor

Structural, or conductor, pipe is a short string of pipe that is usually 30” to 36” in diameter. It provides structural support for subsea drilling equipment and may extend 300 feet or more below mudline. Obtaining a strong structural foundation is critical to the drilling operations and for any future development including the use of subsea completion systems i.e. subsea Christmas tree. Conductor pipe may be lowered into a predrilled hole, jetted in with high pressure fluid, or driven in. The use of jetting operations is not recommended as the surface casing may not be located in a true vertical position using this method. FMC recommend that an angle of two degrees from vertical is the maximum angle permitted to prevent problems with subsequent completion or tie back operations.

Surface Casing

Surface casing (typically 20/26”)is the first string to be run inside the conductor pipe and is typically attached to the bottom of the 18-3/4” wellhead housing. This casing may extend from 200’ to more than 4000’ depending upon sea floor characteristics and the specified well program. The length of this casing string will usually be engineered around the need to isolate shallow

water flow or shallow gas deposits or both.

Intermediate Casing

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upon hole formation requirements. This casing string protects and isolates zones during drilling that may take drilling fluids from the hole as the well becomes deeper. It will usually be hung inside the wellhead on casing hangers and the annulus sealed off using seal assemblies that seal between the casing hanger and the wellhead housing.

Production Casing

The production casing is sometimes referred to as the oil string, or long string. It isolates the well bore from undesirable formation fluids or gases and provides a means to protect the production tubing and allow a packer inside to create isolation between production tubing OD and the production casing ID.

Liner String

A liner is a short string of casing suspended inside another larger casing string and is used to isolate open hole below an existing string of casing. A special liner hanger mechanism attaches to the ID of a larger casing string typically using a slip type suspension system and seals to the ID of the casing string. It extends from the bottom of that casing string into the open hole with an overlap of approximately 100’ or more inside the previous larger casing string.

3.2 Casing Properties

While the size of casing is important to us in the wellhead industry, there are other considerations that bear equal importance. When casing is run, the weight per foot and the grade are required to calculate the collapse or burst pressures it can withstand. This is important information because the casing string will be exposed to certain test pressures to verify the integrity of the system after the wellhead equipment is

installed.

The drift diameter of the casing must also be determined. This diameter is necessary to ensure that all tools and equipment run into the hole will actually fit inside the casing. Information such as tensile strength and pipe body yield are also used to assure other wellhead associated members will function in a similar fashion as the casing.

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The type of materials selected must also allow use with chemicals expected to be found in the different formations.

All of this information is found inside the casing, tubing, and drill pipe tables

provided by API. An example of an API casing table can be found on the following table.

Typical Casing Table

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WARNING: This information is provided to FMC customers solely to illustrate the operation of FMC equipment. It does not provide complete information for

Section 4 Drilling a Subsea Well – Graphic Depiction

4.0 – Introduction to drilling a well

The following graphics show the major sequence of operations involved in drilling a well from a Mobile Offshore Drilling Unit (MODU) starting from the initial drilling phase, also called “spud in”, through running the production tubing.

The diagram above shows the typical arrangement for a 30/36” (Conductor Pipe) x 20” (Surface Casing) x 13-3/8” (Intermediate) x 9-5/8”/10-3/4” (Production Casing).

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This graphic depicts the location of the reservoir below the sea floor. This reservoir could be located anywhere from 1000 ft to 10,000 ft below the sea floor and in some cases even more than this. The reservoir is the target for the drilling operations.

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After the rig is on location and anchored in position if the rig is not dynamically positioned and prior to the start of the surface hole drilling operations some operators run a Temporary Guide Base (TGB) to land on the sea floor. Guide lines are attached to the TGB that extend back to the rig. These wires guide the drilling tool string and surface conductor pipe into the well. This type of equipment would be used in water depths typically up to 2000 feet. Beyond 2000 feet, guide lines become impractical due to their weight.

The first operation to take place is to drill the surface hole section. This is commonly referred to as “spudding the well.”

A drill bit is run with a bottom hole assembly consisting of heavy sections of pipe called drill collars and lowered to the sea floor on drill pipe. Sea water is then pumped through the drill bit as it is rotated to drill the hole.

It is always preferred that the surface hole section is drilled and the surface casing installed rather than “jetting” the surface casing into position as this improves the possibility of the surface casing being in a true vertical position inside the drilled hole.

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After the 36” surface hole section is drilled, typically to a depth of +/- 100-150 meters, the 30/36” conductor pipe is run. The FMC 30/36” conductor housing is welded to the top of the surface casing string. If guide line will be used on the well, a Permanent Guide Base (PGB) will be attached to the outside of the conductor housing.

This assembly will be lowered on drill pipe connected to a running tool that is made up to the 30” conductor housing. When a TGB is used, the PGB will land on the TGB.

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The 30/36” conductor pipe is then cemented in place by pumping cement through the drill pipe landing string, out the bottom of the casing, and into the hole section. The casing would be held in suspension by the drill pipe landing string until the cement hardens sufficiently to support the weight of the casing.

Note that the hole drilled for the casing will not be a straight 36” hole section. Soft formations may be washed out as the hole is being drilled resulting in a hole of various sizes and in some cases there may be large cavities where the formation has been washed away.

For this reason the cement volume pumped may be in 100 to 200% excess above the normal required to fill the drilled hole. This is to ensure a strong foundation is provided for subsequent subsea equipment to land and be supported.

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An alternative method of installing the 30/36” surface casing is to “jet” the casing into position. Soft bottom conditions are required to allow this method to be used. The jetting operation involves pumping sea water through drill pipe that is attached to the bottom of the 30” wellhead running tool. The drill pipe is spaced out to locate the drill bit just inside the bottom the 30/36 casing.

As the casing is lowered, the pump pressure washes away the formation and the

casing sinks by virtue of its own weight to the desired depth. When jetting operations are complete, the conductor housing is typically 3-4 meters above the sea floor. After pumping is stopped, the formation will settle in place around the casing and the skin friction of the sediment will support the weight of the casing. No cement is required. This method is typically used in the Gulf of Mexico. Care must be taken that the casing is installed in a true vertical position. FMC does not recommend that the casing be more than 2 degrees from vertical as any angle above this would cause problems in subsequent drilling, completion, and tie back operations.

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After the 30/36” casing is installed, the 30” wellhead running tool would be released and retrieved. A 26” drill bit would then be run to drill the hole for the next casing that is typically 20” O.D.

The hole would be drilled to the desired casing depth, which is typically 500 to 600 meters. Fluid returns from the drilled hole would be pumped to the top of the 30/36” conductor pipe and exit through side exit ports in the side of the wellhead housing.

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The 20” surface casing would then be run with the high pressure wellhead housing welded to the top of the casing string. The assembly would be lowered on drill pipe connected to a wellhead running tool made up to the high pressure wellhead housing. The high pressure wellhead would then be lowered to land out and lock into the 30” conductor housing.

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The 20” surface casing would then be cemented in place by pumping cement through the drill pipe landing string, out the bottom of the 20” casing and into the 30” x 20” casing annulus.

Fluid returns would exit the 30” casing via the side exit holes in the side of the 30” conductor housing.

After the cementing operations were complete the wellhead running tool would be released and retrieved to surface.

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The subsea Blow Out Preventor (BOP) would then run and landed on the high pressure wellhead housing. Using the BOP control system the BOP hydraulic wellhead

connector would be locked to the wellhead housing.

A test tool would then be run and landed in the wellhead housing to allow pressure testing of the BOP-to-wellhead connection

The next section of hole would then be drilled. This hole will typically accommodate 13-3/8” intermediate casing.

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The 13-3/8” intermediate casing string would then run and landed inside the wellhead housing. The casing would typically be lowered on drill pipe using a single trip tool that allows the casing and annulus seal assembly to be installed together.

At the top of the casing string would be the 13-3/8” casing hanger. This hanger would land on the high strength load shoulder in the bottom of the 18-3/4” wellhead housing. The casing would then be cemented in place by pumping cement through the drill pipe landing, out the bottom of the casing and into the 20” x 13-3/8” annulus. Fluid returns from the well would be circulated back to the rig. The annulus seal assembly would then be set and tested.

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The hole section for the production casing, which is typically 9-5/8” or 10-3/4”, would then be drilled. The casing would be installed, cemented, and the annulus seal

assembly would be set per the same procedures as the intermediate casing string A hole section into the reservoir would then be drilled. The production tubing would then be installed through the completions equipment and production of hydrocarbons could begin.

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Section 5 FMC UWD-15 Subsea Drilling Systems

5.0 Why Do We Need a Wellhead System?

Hydrocarbon reservoirs deep underground are composed of porous rock such as limestone or sandstone. This rock is not solid; rather it has small empty pockets throughout called pores. The pores in the rock allow hydrocarbons to accumulate over time and form a reservoir. The term Pore Pressure refers to the amount of pressure exerted on the fluid found in the pores of a

reservoir, which is usually equal to the hydrostatic pressure. When we drill into a reservoir and begin to remove hydrocarbons, they must migrate between the pores in the rock to reach the production tubing. The measurement of the rate at which a liquid can migrate through a porous material is called permeability. The more permeable a rock formation, the easier it is for the hydrocarbons to flow.

Different types of rock formations have different permeability characteristics. That means that fluids flow better through some formations than others. Also, different rock formations have different pore pressures, which could cause migration problems when drilling from a low pressure zone to a high pressure zone or vice versa. Migration occurs when high pressure fluids travel into low pressure zones. These different physical characteristics make it necessary to isolate the zones from one another. The isolation of these different formations is achieved through the use of separate casing strings that are installed and cemented in place in the well bore. These casing strings allow control of formation pressures when the well is being drilled.

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5.1 UWD-15 Overview

The FMC UWD-15 family of Subsea Drilling System can be provided in three distinct wellhead systems. These systems are the Standard, Rigid Lock, and Large Bore as shown in the figure below.

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The drawing below shows a typical casing program for a subsea well drilled from a MODU. The casing setting depths are also shown.

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H-4 Mandrel Profile 18 ¾” High Pressure Wellhead Housing Low Pressure Housing Internal Profile Casing Hangers Annulus Seal Assemblies Wear Bushing Conductor Pipe Gasket Area

5.2 UWD-15 Standard Wellhead System

• 15,000 psi H2S service rating

• Weight-set straight-in and straight-out operation

• All metal sealing

• Compression set, metal-capped elastomer seal option

• Multi-function tools minimize running time and save trips

• Guideline and guidelineless systems available

• Internal and external platform tieback options

• Optional 16” submudline casing string

The UWD-15 Standard Wellhead System is comprised of the following major components:

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18 ¾” Wellhead Housing 30/36”Conductor Housing 30/36”Conductor Pipe 20/26”Intermediate Casing 16” Submudline Receptacle, Hanger,

& Running Tool

The UWD-15 Standard wellhead system and the UWD-15 Rigid Lock wellhead system both have the option to run 16” casing, which is hung off below the mudline on a landing ring positioned in the 20” casing string as shown in the graphic on this page. The UWD-15 Rigid Lock wellhead system will be discussed on the next page. This submudline hanger system enables more flexibility in casing programs to accommodate complex downhole conditions.

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Wear Bushing Casing Hangers Rigid Lock Seal Assembly H-4 Mandrel Profile 18 ¾” High Pressure Wellhead Housing 36” Conductor Housing Gasket Area Internal Profile 36” Conductor Pipe Annulus Seal Assemblies 26” Conductor Housing

5.3 UWD-15 Rigid Lock Wellhead System

• Operates with or without 26” casing string for added flexibility

• Rigid lock between low and high pressure housings

• Rigid-lock seal assembly is run, casing string is cemented, and seal assembly is set and tested in a single trip

• Rigid-lock seal assembly can be retrieved, re-run, and tested with the 18-3/4” housing in place

• Same optional 16” casing string installed submudline as the UWD-15 Standard wellhead system

• All internal tools are identical to the standard system

The UWD-15 Rigid Lock Wellhead System is comprised of the following components:

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5.4 UWD-15 Large Bore Wellhead System

• An extension of the Rigid Lock System with provision to run two casing strings (18” and 16”) which are hung off submudline

• Two submudline systems are fully independent of one another and can be placed anywhere in the string below the high-pressure housing

• The 16” and 18” submudline hangers and seal assemblies are run in a single trip

• A bit retrieval bore protector is available

• Guideline or guidelineless configurations available

The UWD-15 Large Bore Wellhead System is comprised of the following components: H-4 Mandrel Profile 18 ¾” High Pressure Wellhead Housing 36” Conductor Housing Gasket Area Internal Profile Casing Hangers Annulus Seal Assemblies Wear Bushing Conductor Pipe Rigid Lock Seal Assembly Expanding Load Ring 26” Conductor Housing

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The Large Bore Wellhead System can be installed with two optional submudline casing strings. These 16” and 18”

submudline casing systems are unique to the Large Bore system and therefore cannot be run on the Standard or Rigid Lock systems. The submudline receptacles can be installed anywhere in the 18” and 16” casing strings.

The landing mechanisms of the two submudline systems are physically different, so it is impossible for the 18” casing hanger to land out in the 16” receptacle.

16”

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The following chart shows the major features and benefits of the UWD-15 family of wellhead systems.

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5.5 Casing Hangers and Annulus Seal Assemblies

All 18 ¾” UWD-15 casing hangers and annulus seal assemblies are standard and interchangeable between the wellhead systems. UWD-15 Casing Hangers are manufactured sizes ranging from approximately 13” to 7”.

All standard casing hangers in the UWD-15 system have common features

including two point centralization, identical seal profiles for the metal-to-metal and elastomer seal assemblies, and can all be run using the same running tools and procedures.

The 13-3/8” casing hanger can only land on the high strength load shoulder in the bottom of the 18-3/4” wellhead housing. Should the 13-3/8” casing string be eliminated then a spacer bushing must be run below the next casing hanger,

typically 9-5/8” or 10-3/4”, to space out the hanger in the normal landing position in the wellhead.

Critical internal seal profiles in the hanger neck used for sealing of tubing hangers, tie back connectors or Christmas tree isolation sleeves are inlaid with corrosion resistant material to ensure long service life in the well production mode.

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18 ¾” Annulus Seal Assemblies are available with both metal-to-metal and elastomer seals. The two different types of seal assemblies are 100%

interchangeable with each other and require no procedural changes when running one versus the other.

Inside Diameter and Outside Diameter lock rings secure the annulus seal assemblies to the casing hangers and wellhead, respectively.

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information for service or maintenance. Improperly performed service, maintenance, or installation could cause serious injury or death. FMC equipment is to be installed, serviced and maintained only by trained, authorized FMC personnel. © 2005 FMC Technologies, Inc

Comparison of Tree installation and hardware costs as a function of water depth

Section 6 FMC Subsea Tree Systems

6.0 Introduction

Operators are developing subsea oil and gas fields in increasingly difficult circumstances, often at higher associated costs. Water depths for the deepest subsea completions are approaching 7,500 feet and the industry doubles its water depth record every 3-5

years. Exploration wells are presently being drilled in water depths approaching 10,000 feet, and current deepwater development

projects are in progress for water depths from 6,000 to 7,000 feet. As water depth increases, the operational costs associated with completing and working over subsea wells increases at a

significantly higher rate than the cost of subsea tree hardware. As shown in the figure below, the ratio of the installation and

hardware costs for a subsea tree in 2,000 feet of water is roughly 1:1, but that ratio increases to 3:1 in 10,000 feet of water.

Thus, the focus for achieving significant cost savings on deepwater subsea tree systems must be on operational time-savings during well completions and workovers.

1992 1994 1996 - 1998 2000 2000 6000 10000 Water Depth, ft.

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The type of Completion: The assembly of

downhole equipment required to enable safe and efficient production from an oil or gas well

The type of well production:

Gas or oil, H2S and CO2 content

The Control System Requirements: Length from platform or rig, control equipment on or off the tree

The configuration of a subsea tree dictates the sequence of well completion and workover operations and therefore has a significant impact on the cost of those operations. When a subsea tree is selected for a given application, a thorough understanding of the installed cost (CAPital EXpenditures) and the life-of-field operational costs (OPerational EXpenditures) for that tree should be developed. Those costs can be compared for different types of subsea trees to ensure that the most cost effective system is selected for the application. The greatest opportunity for reducing the CAPEX and OPEX of deepwater subsea tree systems is to focus on operational time-savings during installation and workover, and then design the trees accordingly. Ultimately, the selection process for deepwater subsea trees is most often guided by the operational philosophy and experience of the operator. However, the configuration of the subsea tree itself is dictated to by four main criteria:

The type of flowline connection system: On or off a

template, diver or diverless

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0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 Project Specific (Traditonal) (One of a Kind, Purpose Built) Unique Projects (R&D Intensive) Standardized Tree (Representing 80% of Portfolio) "Opportunistic, Leftover or Re-work Tree" Force Fit to Project

CAPEX per Tree System $ (Mill.)

Project Engineering Cost Tree Cost

Changing any one of these parameters changes the tree configuration and may reduce the likelihood of using an the-shelf” tree. The drivers for using “off-the-shelf” trees are: A proven design, minimal need for engineering (or

re-engineering), quicker delivery, and lower cost. However, reducing the engineering cost and delivery time is subject to the characteristics of the well and the field architecture in which the tree is installed. For example, a tree built from carbon steel components cannot be used on a well with high CO2 or H2S. Similarly, a tree

with a connector that fits a clamp hub profile will not interface with a mandrel (H4) wellhead profile.

Project specific trees are used in large projects with large budgets where there is a desire to customize equipment to maximize the value of the field. However, other times, such as a one or two well project, customers wish to purchase an “off the shelf” or standard tree. Purchasing a standard tree is more cost effective, but the standard design might be a limiting factor for the completion. The first bar in the graph below represents a normalized custom project specific tree cost.

Comparison of Tree hardware costs as a function of project usage -- Normalized on project specific Tree = $2MM.

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The second bar represents very special one-of-a-kind projects that involve

research and development to achieve the technology level for new frontiers. The third bar represents where “off-the-shelf” can pay off by looking at a portfolio of fields and finding commonality between them and build a tree that can adapt to all involved. The fourth bar represents “opportunistic” endeavors where an existing design is force-fit into a field architecture that is similar to the field for which the design was originally created.

6.1 Selecting the Tree Type

Once the four characteristics that influence the subsea tree design are defined, the next step in selecting the subsea tree for a deepwater development is to evaluate the different types of trees and how they best fit the application.

Subsea trees can be divided into two major types, horizontal trees and vertical trees (sometimes referred to as conventional trees).The major components and valve quantities are similar for both types of trees but they are arranged in a different manner. The major difference between the two types of trees is that for horizontal trees the tubing hanger is located in the body of the tree composite valve block and for the vertical tree the tubing hanger is located below the tree either in a wellhead or tubing head. The tubing hanger location drives the arrangement of the tree valves.

The graphic below shows how the tree valves are arranged for horizontal and vertical trees.

Horizontal Tree Vertical

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Other major considerations include the well control philosophy of the operator, the environment in which the tree will be installed, and the vessel(s) installing the tree. Three example subsea tree designs are described below. All three of the following tree designs are used for deepwater field developments. These trees are fit-for-purpose, safe, reliable, and functionally equivalent in production service.

These tree designs can be configured for guideline (GL) and guidelineless (GLL) applications. For GL trees the tree guide frame would provide guide funnels located on an API standard 6ft radius to interface with guide posts on the wellhead or tubing head to guide and orient the tree to land in the desired orientation.

For vertical trees this guidance arrangement would also orient the tree production, annulus, hydraulic and electrical stabs with the mating profiles in the tubing

hanger. Guidelines are not normally used when completing a well in water depths that exceed 2,500 feet.

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Other trees illustrated later provide large diameter re-entry funnels to allow orienting and landing of the tree in deep water without the need for guidelines. This configuration is referred to as guidelineless, where a large guide funnel

captures the equipment and internal profiles (such as helixes) rotate the equipment into the proper orientation instead of guidelines.

Wellhead Completed Vertical Tree

The vertical tree system has the tubing hanger located in the wellhead or tubing head below the tree.

A tubing hanger is a component used in the completion of production wells. It is set in the tree or the wellhead and suspends the production tubing that provides a continuous bore from the production zone to the wellhead through which oil and gas can be produced. Sometimes it provides

porting to allow the communication of

hydraulic, electric and other downhole functions, as well as chemical injection. It also serves to seal-in the annulus and production areas.

Much more care in completion design is required when the tubing hanger is installed into a wellhead to account for casing hanger tolerance stack up and to ensure that correct orientation and alignment is achieved.

The use of a guideline/guidepost guidance system helps simplify in-the-wellhead completions because the wellhead permanent guidebase (PGB) becomes the

orienting keystone. The guide posts orient the blow out preventer stack assembly, or BOP stack, that in turn orients the tubing hanger typically using a hydraulic

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orienting pin connected to one of the BOP side outlets. When the subsea tree assembly is installed the same guideposts orient the tree to align the tree with the tubing hanger. In guide lineless operations, the BOP is typically not oriented, so other alignment tools and techniques must be employed. Installing the tubing hanger in the wellhead allows the well to be drilled and completed without the need to retrieve the BOP stack. The BOP stack does not have to be removed from the well to install the tubing hanger. However, all casing hangers, seal assemblies, and completion equipment must land and space-out exactly in the wellhead to ensure a successful completion operation because the tubing hanger metal seals are usually specified to seal between tubing bores, the wellhead, and tree.

Metal seals require precise alignment to within .003 inches and less than ¼ degree. Therefore, an error free stack-up is essential. The UWD-15 wellhead system

provides an indication of correct space out of the casing hangers and seal

assemblies in the wellhead when the seal assembly internal and external lock rings engage the lock down grooves in the casing hanger neck and the bore of the

wellhead housing.

If the casing hanger or seal assembly is landed high in the wellhead housing the seal assembly would not set correctly and be retrieved to surface with the running tool. Any debris, “gumbo”, silt, and/or scratches left behind by the drilling or completion process that lands on top of the tubing hanger may also cause problems in interfacing the tree to the wellhead/tubing hanger.

Vertical tree systems require two sets of landing strings or work strings for installation: one internal riser system for installing the tubing and tubing hanger through the BOP stack and drilling riser; the second via an open water

completion/workover riser system that connects to the top of the subsea tree to allow access from the surface through the tree’s production bore and into the well. During the production phase, pressure containing tree caps are provided to add a second barrier above the tree’s swab valve. These tree caps can be run on drill pipe, riser pipe, wire rope, or ROV depending on water depth and installation conditions.

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Open water completion risers are not available for water depths exceeding 7,500 feet, but industry development work is ongoing in that area. This issue may be a key decision driver in the tree selection process for ultra deep water.

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Vertical Tree Installed on a Tubing Head

Installing the tubing hanger in a tubing head provides a number of advantages over installing the tubing hanger directly into the wellhead.

Tubing head advantages include:

- Can serve as cross over from a competitor’s wellhead system to allow identical tubing hangers and trees to be used with the tubing head and FMC wellhead systems.

- Provides new landing, lock down and sealing profiles for the tubing hanger that have not been exposed to drilling operations.

- Can provide annulus access below the tubing hanger - Provide passive orientation for the tree

- Allows connection and testing of the flow lines prior to installing the tree - Allows retrieval of the tree without disconnecting the flow lines

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Tubing head disadvantages include: - Higher CAPEX.

- Additional leak path between the wellhead and tubing head interface. - Additional stack up height that can add to the loading on the wellhead

system when the subsea BOP or completion equipment is installed.

The tubing hanger lands, locks down and seals in the tubing head. Annulus access past the tubing hanger can be provided through a port in the tubing head below the tubing hanger that is sealed with a ROV-operated gate valve. The GLL tubing head has a funnel down interface with the wellhead and a funnel up interface with the BOP stack and tree. Flowline connection may also be attached to the tubing head assembly. The tree interfaces to the tubing head with a second intermediate flowline connector so that the tree can be installed and retrieved without affecting the primary flowline connection. The tubing hanger’s slim design allows it to be installed or retrieved through smaller bore risers, which use smaller, less expensive completion vessels if desired.

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When a tubing head is used, annulus access can be routed below the tubing hanger in a manner similar to that used in the horizontal Subsea tree . This can simplify the annulus access through the tubing hanger. The annulus would be isolated by series 100 metal sealing gate valves with hydraulic actuators or by manual valves operated by ROV.

Passive orientation of the tubing hanger can also be provided by an integral 360 degree mule shoe bushing (helix) integral to the tubing head. The graphic below shows the typical annulus flow path arrangement in a tubing head.

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The vertical tree system has a dual vertical bore for production and annulus access. The production and annulus bores in the tubing hanger would have a wire line plug profile to allow a plug to be installed while the subsea

BOP is removed and the Subsea tree is installed. The dual bore would also be in the Subsea

tree valve block and vertical pressure barrier barriers would be provided by

FMC series 100 metal sealing gate valves, Production and annulus master and swab valves would provide the dual vertical barriers to the environment. Production and annulus wing valve blocks, chokes and flow

loops would be connected to the side of the Subsea tree valve block.

The top profile of the vertical tree would provide and interface profile (typically a 13-5/8” hub) for the lower riser package

and emergency disconnect package. The graphic at left shows the vertical tree system tool package system.

Tubing Head Vertical Tree Lower Riser Package (LRP) Emergency Disconnect (EDP)

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RE-ENTRY HUB WITH PRODUCTION & ANNULUS BORES PRODUCTION MASTER & SWAB

VALVE HYDRAULIC ACTUATORS ANNULUS MASTER & SWAB VALVE

HYDRAULIC ACTUATORS

The vertical tree valve block assembly would include the production and annulus series 100 metal sealing gate valves and hydraulic actuators. The hydraulic

actuators are designed for water depths up to 3000 meters hence they are

designated M3000 type actuators. The valves are normally set up to be fail safe close on loss of hydraulic operating pressure. In some cases the valves can be set to be fail safe open. This is typically done (failsafe open) with a cross over valve to allow circulating to be done via the production and service flow lines. The graphic below shows a typical vertical tree valve block arrangement.

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The vertical tree system tubing hanger lands, locks, and seals inside the wellhead housing or tubing head. Metal to metal seals isolate the production annulus. A rigid lock down mechanism on the tubing hanger prevents any movement in the metal seals during production due to pressure or temperature cycles. Movement of the seals could cause premature failure of the metal seals. Elastomer back up seals is also provided on the tubing hanger. The graphic below shows the major features of the vertical tubing hanger.

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Orientation between the tubing hanger and subsea tree is critical to ensure correct engagement and make up of the production, annulus, down hole hydraulic and electrical connections.

For GL & GLL applications orientation is typically provided by a hydraulic pin that is installed to one of the side outlets on the subsea BOP stack. This pin interfaces with a helix profile on a tubing hanger orientation joint (THOJ)

connected to the top of the tubing hanger running tool, When a tubing head is used a passive orienting mechanism can be made integral to the tubing head using a 360 degree helix profile.

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alignment slots in the tubing hanger that engage mating keys in the subsea tree connector. This positively aligns the tree stabs prior to engagement with tubing hanger.

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Horizontal Tree Systems

As describes earlier, in a horizontal tree system the tubing hanger lands inside the horizontal tree body (the composite valve block)

Two types of horizontal tree systems have been provided to date.

The first generation of horizontal trees (HXT) utilized a tubing hanger landed in the tree with an internal tree cap installed above the tubing hanger. Both landed, locked and sealed independent from the other. Dual vertical barriers to the environment has been provided by a wire line plug set in the tubing hanger and by a solid internal tree cap or by an internal tree cap with a wire line plug profile. In some cases the internal tree cap has been provided with a ball valve operated by the running tool.

All manufacturers of this type of tree (separate tubing hanger and internal tree cap) experienced problems with debris when installing the internal tree cap. Operational requirements meant that the tubing hanger was installed through the drilling riser and BOP first and a wire line plug installed. The tubing hanger running tool was then retrieved to be used to run the internal tree cap. When the internal tree cap was run it was often found that debris had been dislodged from inside the drilling riser and accumulated on top of the tubing hanger and wire line plug preventing the internal tree cap from being installed.

Considerable rig time was then involved in running special flushing tools to wash out the debris before the internal tree cap could be installed. This rig down time cost operators lots of money.

To overcome the debris problems the latest generation of horizontal trees called the enhanced horizontal tree (EHXT™) was developed. The EHXT utilized an extended length tubing hanger that could incorporate two vertical wire line plugs to provide a dual barrier to the environment. This eliminated the need for the independent internal tree cap.

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WIRE LINE PLUGS WIRE LINE PLUG

BALL VALVE

TUBING HANGER INTERNAL TREE CAP

The drawings below show the different tubing hanger arrangement for the HXT and the EHXT. The traditional HXT shows the separate tubing hanger and internal tree cap in this case with integral ball valve. The EHXT shows the extended tubing hanger with the two wire line plugs installed.

FMC has standardized on the EHXT design and no longer propose the HXT to customers unless specifically requested for example when a customer may want to add another same again tree design to an existing field.

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In a horizontal tree system the tubing hanger orients, land, locks and seals inside the tree composite valve block. The lower extension on the tree provides a 360 degree mule shoe (helix) profile for orienting the tubing hanger. No orienting mechanism is required in the subsea BOP stack as is the case with vertical tree completion systems.

The EHXT composite valve block assembly provides integral product master, annuls master, annulus access valves. Wing valve blocks bolted to the composite valve block provide the wing valves and cross over valve. These wing valve blocks also allow mounting of pressure/temperature transducers and chemical injection valves as required.

Metal to metal seals are located above and below the production side outlet of the tubing hanger to isolate the side exit production bore in the tree composite valve block.

The down hole hydraulic and electric connections are routed through the EH-5 penetrator couplers on the side of the tubing hanger. These interface with the EH-5 radial penetrator on the side of the composite valve block. In the Gulf of Mexico the hydraulic and electric connections also exit the top of the tubing hanger to allow operation and monitoring of the down hole functions through the tubing hanger running tool when the tubing hanger is being run. A maximum of 9 down hole functions can be provided when two EH-5 penetrators are used. One of the hydraulic ports through the EH-5 penetrators is used to monitor between the upper and lower wire line plugs set in the EHXT tubing hanger.

A secondary tubing hanger lock down mechanism is installed above the tubing hanger in the EHXT system. This mechanism can be part of an ROV installed internal tree cap or can be provided by an independent secondary lick down mechanism (THISL). The EHXT can be configured for GL and GLL applications The graphic below shows the EHXT landed on a UWD-15 wellhead system with the tree lower extension (isolation sleeve) engaged and sealed inside the upper casing hanger in the wellhead.

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Down hole electric and hydraulic connections between the EHXT and the tubing hanger is provided by the EH-5 radial penetrator mechanism. As the designation indicates up to 5 connections can be provided through the penetrator. This can be a combination of hydraulic and electrical functions as required.

Two EH-5 penetrators can be used on the EHXT if required. One of the hydraulic ports through the EH-5 penetrator is used to monitor pressure between the wire line plugs set in the tubing hanger. The EH-5 penetrator (s) has a center shaft connected to the ROV panel on the tree to allow rotary operation by an ROV. The mechanism also has an emergency release mechanism operated by the ROV in the event that the rotary mechanism cannot be used. The graphic below shows the features of the EH-5 mechanism,

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Positive and accurate orientation of the tubing hanger inside the EHXT is critical to correct alignment of the production side outlet on the tubing hanger and correct make up of the hydraulic and electrical connections between the tubing hanger and the EHXT EH-5 radial penetrator(s).

Primary (rough) orientation is provided by the large orienting key on the bottom of the tubing hanger engaging the 360 degree mule shoe in the bottom of the EHXT and secondary fine alignment is provided by the fixed alignment key on the body of the tubing hanger that engaged a milled slot in the bore of the composite valve block. The graphic below shows the primary and secondary orienting mechanisms.

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In the EHXT system vertical barriers to the environment are provided by wire line set metal sealing plugs that land, lock down and seal inside the tubing hanger. These plugs are Halliburton SSP plugs and provide a rigid lock down mechanism to ensure long term reliability of the metal seals. FMC provide the straight bore metal seals (SBMS-2) for these plugs. The drawing below shows the major features of the Halliburton SSP plug assembly.

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EHXT vs. VXT

The decision to use a vertical or horizontal is dependent on a number of factors. The following is a brief overview of some of the issues associated with the tree selection process. Typical tree decision drivers include:

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Subsea 101 Rev3

Subsea 101

An Introduction To

Subsea Wellhead & Completions Reference Book

Table of Contents

Section 1

Introduction to FMC

Section 2

Vessels Utilized in Drilling, Production and

Workover Operations

Section 3

Casing and Casing Programs

Section 4

Drilling a Subsea Well

Section 5

UWD-15 Subsea Drilling Systems

Section 6

Subsea Trees

Section 7

Subsea Production Systems

Section 8

Subsea Controls Systems

Section 9

ManTIS Products