Subsea 101 Rev3

Subsea 101

An Introduction ToSubsea Production Systems

Innovative Technologies, Creative Solutions

COPYRIGHT 2006 By FMC Technologies Inc.COPYRIGHT 2006 By FMC Technologies Inc.C

REVISED June 2006

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

Page 1 of 1

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

Section 10 Glossary of Terms

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

Page 1 of 7 Rev June 2006

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.



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 • Working with customers, develop technologies and technical solutions

driven by customer needs



• 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 Technologies delivers an industry leading mix of stand-alone products and integrated systems designed to meet the technical, economic, and life cycle demands of customers on six 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 Intervention significantly enhances hydrocarbon recovery by improving reservoir management. FMC have designed a cost-effective solution for diverless subsea wireline intervention from a dynamically positioned vessel.



New generation "building block" deepwater subsea production system designs 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 keep FMC 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.



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



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.



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

273229

362430 464

98

0

100

200

300

400

500

600

2002 2003 2004 2005 2006 F

38% 40% 47% 40%



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.



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.

FixedPlatform

(To 1650 Feet)

Compliant Tower(1500 To

3000 Feet) Mini - TLP(600 To

3500 Feet)

Floating ProductionSystems

(FPSO, FPF)(1500 to

7500 Feet)

TensionLeg Platform

(TLP)(1500 To

4500 Feet)

SPARPlatform

(SP)(2000 To

7500 Feet)

SubseaSystems

(To 10000+ Feet)

FixedPlatform

(To 1650 Feet)

Compliant Tower(1500 To

3000 Feet) Mini - TLP(600 To

3500 Feet)

Floating ProductionSystems

(FPSO, FPF)(1500 to

7500 Feet)

TensionLeg Platform

(TLP)(1500 To

4500 Feet)

SPARPlatform

(SP)(2000 To

7500 Feet)

SubseaSystems

(To 10000+ Feet)



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

The Diving Vessel

The Service Rig



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.



Drill ships



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 wellhead system. The wires that can be seen attached to the tensioning ring on top of the riser are connected to the riser tensioning system that maintains a constant tension on the riser to compensate for the movement of the vessel. The riser pipe



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



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.



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.

Other Support Vessels



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.



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 Intermediate casing may also be called production casing and may be 7” to 14” in diameter. It is possible to run more than one intermediate string on a well depending



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.



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



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).



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.



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.



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.



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.



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.



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.



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.



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.



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.



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.



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.



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.



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.

UWD-15 Standard UWD-15 Rigid Lock UWD-15 Large Bore



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



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:



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.



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


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:



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


Wear Bushing

Conductor Pipe

Rigid Lock Seal

Assembly

Expanding Load Ring

26” Conductor Housing



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”

18”



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



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.



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.





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.

Hardware Cost Installation Cost



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



0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

ProjectSpecific

(Traditonal)(One of a Kind,Purpose Built)

UniqueProjects (R&D

Intensive)

StandardizedTree

(Representing80% of

Portfolio)

"Opportunistic,Leftover or Re-

work Tree"Force Fit to

Project

CA

PE

X p

er T

ree

Sys

tem

$ (M

ill.)

Project Engineering CostTree Cost

Changing any one of these parameters changes the tree configuration and may reduce the likelihood of using an “off-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.



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 Tree



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.



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



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.



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.

GLL VERTICAL TREE ASSEMBLY



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

Typical GLL Tubing Head



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.



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.



Typical GLL Tubing Head Vertical Subsea Tree Arrangement





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)



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.



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.



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. Fine alignment between the subsea tree and the tubing hanger can be provided by



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.



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.



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.



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.





The graphic below shows the major features of the EHXT tubing hanger.









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,



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.



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.





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:



CAPEX and OPEX Considerations



Installed CAPEX and Life of Field OPEX Comparison

Workover Time Comparison in 6000 ft Of Water



With the development of “smart well” completions that require that sliding sleeves in the down hole production tubing be operated hydraulically the number of downhole control lines that can be accommodated through the tubing hanger becomes important. The following compares the EHXT and the VXT ability to handle down hole control lines. The completion size that can be accommodated by the tree system is important especially in gas production where larger completion sizes may be required to handle the gas flow rates. The following is a brief overview of the completion size issues between EHXT and VXT tree systems



The following chart summarizes some of the advantages and disadvantages associated with the EHXT and VXT tree systems.

EHXT VXT

Advantages Suitable for large bore 7”> gas wells One less BOP trip (Drill Through completion)

Tubing hanger landed in wellhead (or tubing head)

Can be installed on competitors wellhead (X-tubing/tugging head)

Allows intervention without a rig

Uses rig riser system Reduced wellhead loading Simplified rig interface Metal sealing gate valves for environmental

barriers (not filed installed like wireline plugs) Suitable for SMARTWELL technology Suitable for SMARTWELL technology Passive TH orientation Tubing intervention simpler as no wireline

lugs need to be retrieved Allows Work over without pulling tree or disconnecting flowlines

Installed CAPEX considered to be lower than EHXT

Flow base typically not required Wellhead casing hanger rigidizing mechanism integral to the tree Flexibility of design to accommodate natural flow, gas lift, water injection & ESP

Disadvantages Requires additional BOP trip May require BOP modification for TH

orientation mechanism Requires an SSTT and landing string Requires lead impression tool run to verify TH

spaceout BOP may require modifications to accommodate IWOCS umbilical

More rig deck space needed to accommodate additional tooling and riser

Higher bending loads on the wellhead system

Rig needs to handle more tooling

Potential leak oaths below the BOP additional wellhead casing hangers rigidizing trip required

Well must be plugged prior to removing the tree

Tubing hanger seals in the ID of the UWD-15 casing that could be damaged during drilling operations

Some concern with wireline plugs for vertical barriers

Need to remove the tree for tubing workover



Best Practice Tree

The best practices tree is a hybrid of past guideline project experience and deepwater guidelineless technology. The tree features simple block valve designs with diver assist or diverless flowline and umbilical connections, ROV valve panels, and a ROV tree cap. This tree is a stripped down version of its deepwater cousin to take advantage of marginal field development opportunities in water depths less than 3000 feet. This system also makes use of low cost dual tubing string completion risers and controls.

Production Master Valve

Swab Valve



Mudline Tree The CM-1 tree (completion method #1), or mudline tree, was FMC’s initial entry into subsea completions. The tree is basically a “marinized” surface stacked valve or block valve tree with subsea actuators and diver assist clamp connectors. It is designed to interface with mudline wellhead equipment normally associated with surface platform tiebacks and jack-up drilling. The mudline tree also features a dual tieback assembly that connects to two casing strings and structurally braces against the drive (conductor) pipe to transfer bending loads. Once completed, it presents a tubing head complete with annulus valves and a prep to receive a tubing hanger. The diver then guides the tree in place as it is lowered from the rig and makes the final connections to the tubing head, flowline, and the control umbilical.

• 3” x 2” 10,000 psi mudline tree • Standard maximum water depth rating: 500 ft • Standard 17D temperature class, 35-250° F • Standard material class “FF”, NACE, H2S service • Tree, tubing hanger and tubing head designed with

intent of API 17D PSL-3 • Tubing hanger designed for 3 ½” 9.2 lbs/ft tubing • Production master and wing valves are

monogrammed as API 6A/17D USVs • Premium FMC Series 100 gate valves. Hydraulic

actuated gate valves operate at 2,000 psi or less, but can sustain pressures up to 4,000 psi



CM-1 Tree



Gate Valves All FMC VXT and EHXT tree systems use the FMC series 100 metal sealing gate valves. FMC have standardized on the use of 10K (690 bar) gate valves for all applications. The pressure limiting factor in the rating of a tree may be in other tree components such as the flow loops or flow line flange connections. The graphics below show the major features of the series 100 gate valves and the M3000 hydraulic actuators.

1



Section 7 Introduction to Subsea Production Systems

7.0 Subsea Production Systems This section is meant to expose those new to subsea equipment to some of the peripheral systems utilized to complete the total production system. FMC provides the building blocks required make up these systems. Following are the five key systems, of which only the last three will be addressed in this section.

• Subsea Wellhead System – Discussed in Section 5 • Subsea Tree System – Discussed in Section 6 • Subsea Controls System - Discussed in this Section 7 • Topsides Controls System - Discussed in this Section 7 • Manifold & Tie In Systems - Discussed in this Section 7

The graphic below shows examples of subsea systems building blocks.

2



Why think System instead of Components? Providing all the subsea components as a system instead of the customer buying individual components from different suppliers provides benefits to both the customer and FMC. There are many interfaces to be managed between the various subsea components. When FMC provides all these components means that all the interfaces are managed by one organization. This reduces project engineering and management time and very importantly minimizes risk associated with these interfaces. The following is a summary of the various building blocks available,

3



The graphic below shows the major types of interfaces involved in subsea production systems.

These interfaces require detailed management to ensure that no problems are encountered during installation of the equipment and during the field life cycle. Each one of these interfaces must be thoroughly tested prior to installation.

4



CONTROL SYSTEM CONSIDERATIONS Selecting the correct type of control system is important to ensure the most cost effective solution is selected to meet the field requirements. The table below provides a guide to the selection criteria used for the different control system types.

5



The subsea control system is a vital element in the subsea production system and it is vital that this performs reliably throughout the life of the field. Critical components of the system can be retrieved to surface for maintenance and replacement as required. The graphic below shows the major components of the subsea control system.

6



In a subsea system control system, typically hydraulic and electrical controls umbilicals will be connected between subsea components using relatively short lengths of umbilical. For this requirement Hydraulic and Electric Jumper Umbilicals are used. These can be located on subsea distribution modules located on the seabed positioned close to the subsea components e.g. Christmas tree or manifold. An ROV would then connect the umbilicals. The graphic below shows a typical subsea distribution system.

7



HYDRAULIC POWER UNIT (HPU)

MASTER CONTROL STATION (MCS) (HPU)

HYDRAULIC TEST PANEL

ELECTRICAL JUNCTION BOX

UMBILICAL HANG OFF

All hydraulic and electrical power comes from the Topside Control System typically mounted at the production facility e.g. platform or FPSO. In addition to supplying the subsea power the top side controls would interface with the facility emergency shut down systems to ensure safety procedures were maintained. The drawing below shows a typical top side control system arrangement.

8



Template Systems – Hinge Over Subsea (HOST)

9



10



HORIZONTAL FLOW LINE HUBS VERTICAL FLOW LINE HUBS

ROV INTERFACE FOR VALVE OPRERATION

The drawing below shows a typical HOST retrievable manifold assembly…

11



The Host manifold system can be configured to accommodate different field development requirements. The system allows wells to be located on or off the Host template or a combination of both. The following shows the typical well arrangements that can be accommodated by the HOST system.

In this scenario all the wells are located on the HOST template structure.

12



In this scenario the manifolds are connected together in a piggy back fashion or daisy chained together. This method allows a second manifold to be added with minimized cost due to the reduction in flow lines required.

13



In the above scenario all the wells located around the manifold in a cluster arrangement with short flow line and control jumpers. This arrange is typically used when the top hole locations need to spaced to reach the different reservoir targets. This scenario above shows a hybrid arrangement for the wells with some being located on the template manifold and some satellite wells located off template.

14



TYPICAL MODULAR MANIFOLD

ARRANGEMENT

15



16



Flow-line / Tie In Systems - FMC have developed a number of flow line connection systems for use in shallow and deep water applications. The flow line connection systems are part of the KOSCON family of connection systems; the family of 6 connection systems has been developed for shallow to ultra deep water, for flexible and hard pipe flow lines and for hard and soft sea bed conditions.



Section 8 Introduction to FMC Controls Systems

8.0 What are Subsea Controls? All subsea equipment located on the sea floor in both shallow and deep water need to be operated remotely. To allow operation of the subsea components i.e. tree and manifold valves, sub surface safety valves, connectors, chokes, transducers, etc. a subsea control system is required. Hydraulic and electrical functions need to controlled and monitored from the host facility control station. The control station (master control station or MCS) for the production control system can be located on a platform or on a floating facility such as an FPSO. The subsea components need to operate in water depths up to 8000 feet below the surface of the water at crushing hydrostatic pressures of 2500 pounds per square inch? The subsea systems must also accommodate diver or ROV operations during initial installation and replacement of critical components in the system such as subsea control modules (SCM). Modern Subsea Controls have been likened to “a dentist sitting on the ninth floor filling the molar of a patient on the first,” by Tore Halvorsen, Vice President-Energy Production Systems for FMC Technologies. Subsea control equipment is the conduit between the operator on the surface and the well control equipment on the sea bed. The production control system can be a complex Electro Hydraulic (EH) Control system for a 40 well field, or a simpler direct hydraulic control system that just operates one Xmas Tree at a time. Both require, to a degree, the same building blocks and must provide a high degree of reliability. Topside controls equipment must supply both hydraulic and electrical power and a way to safely, efficiently, accurately and reliably control and monitor subsea functions. Increasing water depths and offset distances require that both types of equipment, topside and subsea, to work seamlessly and safely to provide the operator total control of the well.



Selecting the correct type of control system is critical to ensuring safe, efficient and long term reliability of the system. CAPEX is also an important consideration. The chart below shows some of issues that need to be considered when designing and selecting the production control system.



FMC has developed the major building blocks that allow the production control system to be configured to provide the maximum flexibility to meet the field development requirements. Careful selection and management of the system interfaces is critical to ensure long term reliability of the control system. The graphic below shows the major building blocks of the production control system. It should be noted that the system includes the control umbilicals. Although not manufactured by FMC, as part of the system design FMC conducts a hydraulic analysis of the system and provides recommendations to be used in the umbilical design.



8.1 Top Side Control Equipment The top side equipment provides the hydraulic and electrical power for the subsea production control system. Dual hydraulic and electrical systems are typically provided to provide back in the event of failure of the primary system The hydraulic power unit (HPU) would provide low and high pressure hydraulic supply with redundant pumps The electrical power system also has dual redundancy to ensure safe operation of the system in the event of a power failure. The master control system is typically linked to the emergency shut down system on the platform do that the production can be shut in safely in an emergency. A back up power pack would provide emergency power supply for the system. The following is a summary description of the major components in the top side control system. Hydraulic Power Unit The heart of any Control System is the Hydraulic Power Unit or HPU. HPUs can be pneumatically or electrically powered, or have both in a redundant role. Even though HPUs can differ in their complexity or use, all have the same basic internal components. Hydraulic fluid is stored in the reservoir, which is a clean, sealed container that supplies fluid to the pumps. These pumps supply pressure to move the hydraulic fluid to the storage accumulators and through the umbilical supply lines. Accumulators are pre-charged containers that store pressurized hydraulic fluid for use when a larger volume of pressurized fluid is needed than is otherwise capable of being supplied by the pumps. HPUs utilize pressure regulators to safely and efficiently supply the pressure.



Master Control Station (MCS) with Human Machine Interface (HMI) Workstation

Regulators are devices that control the flow and pressure of the hydraulic fluid to the subsea installed equipment. These adjustments are made on the Control Panel which contains the valves & gauges needed to regulate and monitor HPU as well as the hydraulic supply during operation. Relief valves are installed in the event supply pressure exceeds the safe, predetermined operating pressure of the equipment being supplied. These devices direct hydraulic fluid back to the reservoir should the output pressure exceed the safe predetermined value. Master Control Station An integral part of the Electro-Hydraulic Control system is the Master Control Station (MCS). The MCS provides control and monitoring of the surface equipment and the entire subsea installed equipment. The main function of the MCS is to transmit operator inputs & control commands to the equipment and to display information received from the subsea equipment. Added benefits of an MCS are the abilities to execute safety shutdowns and record data & alarms. A typical MCS consists of two complete and independent networks incorporating high reliability software and PLC (Programmable Logic Control) hardware architectures that simultaneously monitor data functions to and from surface and subsea. The redundancy is designed in the event of a primary channel network problem or failure. In the event of such a failure, the secondary channel continues to seamlessly operate the external control system interfaces. All input and monitoring done at the MCS is via a computer workstation called a Human Machine Interface or HMI. The HMI is a computer terminal used by the operator to perform all actions necessary to maintain safe operation of the system. The interface can be a Graphical User Interface (GUI) system or a tabular text-based interface system.



Graphics Based Control

Interface

Electrical Power and Communication The Subsea Electrical Power and Communication Unit (SEPU) is the power and communication interface between the Master Control station and the Subsea Control Module. Redundant power and communication is provided to each Subsea Control Module. The communication signals to the Subsea Control Module are superimposed on the electrical power lines by the EPU. This method of communication is called “comms-on-power.” In instances where a mobile, less bulky power and communication source is needed, such as in a field environment, a Subsea Power and Communication Test Unit (SPCTU) can be used. These are small, mobile units that can be used for offsite testing as well as for well workovers and installations.

Tabular Based

Control Interface

Typical UPU cabinet



Typical EPU

SPCTU with Test Equipment

Spooling reel mounted umbilical

8.2 Subsea Control Equipment The Subsea distribution equipment is essential within the controls infrastructure. It provides the means for the surface supplied electrical and hydraulic power to reach the subsea installed equipment. As with the topside control equipment, subsea controls are also engineered with redundancy. This redundancy includes everything from two sets of hydraulic supplies to dual redundant computer processors in the SCM's. Control Umbilical A production control umbilical is a conduit between the topside power and communication equipment and the subsea control system. The hydraulic power and control lines are individual hoses or tubes manufactured from steel or thermoplastic materials and encased in the umbilical bundle. The electrical control cables supplying power and control signals can either be bundled with hydraulic lines or laid separately. To avoid any potential faults, the umbilicals are fabricated in continuous lengths, i.e. without splices. Lengths of umbilicals can range from 1.5 miles long when deployed in a spooling reel for well workovers and interventions and up to 30 miles long when deployed subsea. Umbilicals employing metal tubing are usually considered for deepwater applications and when longer umbilical lengths are required. Metal umbilicals are also advantageous when higher working pressures, greater electrical power requirements, or continuous dynamic service are necessary.



Cross Section of Control Umbilical with Electrical “quads” and Hydraulic

Hoses

Umbilical Terminations If the control umbilical is the main artery from the surface to subsea, then the flying leads are the capillaries that supply the system. The deployed umbilical must have a distribution point, commonly called an Umbilical Termination Assembly (UTA) for distribution to more than one Xmas Tree or Manifold. There are four main parts to an UTA and these can be configured separately or fully integrated. The Umbilical Termination Head (UTH) is a boxed structure attached to the subsea control umbilical termination. Inside, all the individual umbilical lines and cables are terminated. Hydraulic and chemical lines are terminated to a junction plate. Electrical quad cables are also terminated to an electrical termination assembly that splits the cables to a group of bulkhead electrical connectors. The purpose of the Hydraulic Distribution Unit (HDU) is to route and distribute the umbilical hydraulic, electrical and chemical supplies to the Xmas Trees, Manifolds, and other infield umbilicals if required. The HDU also allows the availability of spare hydraulic/chemical junction plate(s) to support future field expansion. The Electrical Distribution Unit (EDU) is a rack that holds the electrical distribution harnesses. Electrical services from the UTH are connected to the EDU via electrical jumpers. The purpose of the EDU is to route and distribute the production umbilical electrical services to the Xmas trees, manifolds, and other infield umbilicals if required. In cases that only hydraulic pressure supplies are needed and there is no need for an EDU, a Subsea Distribution Unit (SDU) is used. This piece of equipment terminates the Production Umbilical using a UTH and distributes only hydraulic pressures. The difference between a UTA and a SDU is



that while the UTA is modular and made up of three separate assemblies, the SDU combines both the UTH and HDU into one integrated piece. The support structure that supports the entire UTA assembly or separate components and keeps all UTA components above the mudline is called the Mudmat. This acts to dissipate the weight of the individual components and prevent them from sinking into the soft mud of the sea floor.

Typical UTA arrangement





HFL Assembly with MQC

Junction Plate

Flying Leads Flying Leads, both hydraulic and electric, are umbilical jumpers that connect the hydraulic and electrical signals from the UTH to the HDM/EDU and the HDM/EDU to the tree(s) and manifold(s). Hydraulic Flying leads are built with the same design as an umbilical, the exception is the addition of junction plates called Multiple Quick Connects (MQCs). MQCs make it possible to quickly, safely, and efficiently make and break subsea hydraulic connections with the assistance of a Remotely Operated Vehicle (ROV). The MQCs are designed following standard industry specifications making it possible for interchangeability between production fields and ROV operators. MQCs are robustly designed. They are machined stainless steel parts that are designed to be mated subsea by ROV's, yet be small enough to be manually moved. For the individual connections, hydraulic couplers allow safe passage of hydraulic fluid and chemicals to/from subsea equipment to prevent contamination of the hydraulic system with seawater and vice versa.

Male and Female MQC

Plates

Male and Female

Hydraulic Couplers

Outboard MQC Plate

Inboard MQC Plate



SCM with Electrical Connectors on

Xmas Tree Guide Funnel

EFLs with ROV Electrical

Connections

Electrical Flying Leads (EFLs) are also ROV installable connections. They are named “wet mate” connections due to the fact that they can be installed and retrieved subsea. The Electrical Flying Lead connects communication on power circuits between various pieces of distribution equipment. Typical arrangements would include UTH to Xmas Tree, Xmas Tree to Manifold, etc. The connectors at the end of the flying lead may have any plug/receptacle combination according to customer needs. Xmas Tree/Manifold Mounted Controls

Xmas Tree & Manifold Control systems provide control of all functions of the production system including production/safety

valves as well as pressure and temperature monitoring.

The single most important piece of equipment in modern Xmas Tree or manifold mounted

Electro Hydraulic Control system is the Subsea Control Module (SCM). The Subsea Control Module is a subsea-

installed, electro-hydraulic manifold designed to control the operation of a well via operation/control of hydraulically actuated valves located downhole

and on the Xmas Tree and Manifold. A single SCM is installed on each Xmas Tree. Depending on the Manifold design and field architecture and layout, an SCM could also be configured for installation on the Manifold.



The SCM also provides the means for monitoring critical operating parameters such as reservoir pressure and temperature and the detection of sand in the producing hydrocarbons. The SCM monitors traditional tree functions, manifold valve control, choke adjustment, position indication, header pressure/temperature, downhole intelligence, sand detection, corrosion and multiphase flow measurement. In

addition, the SCM monitors the operation of its own internal hydraulic and electrical systems and performs self-check routines to verify correct operation of its electronic systems. This ‘housekeeping’ data is also transmitted to the MCS on the surface platform for operator review. The SCM is mounted on a Subsea Control Module Mounting Base (SCMMB) and is connected by a locking mechanism that allows independent retrieval and installation of the SCM from the Xmas Tree or Manifold using an ROV operated Running and Retrieval Tool. The SCMMB is fitted with hydraulic couplers and electrical connectors that interface with mating couplers and connectors in the base of the SCM. The SCM is supplied with pressurized hydraulic fluid and combined electrical power and communication signals from the surface installed equipment via the Control Umbilical, HFLs, & EFLs through the Xmas Tree or Manifold mounted SCMMB.

SCM

SCM Mounting Base (SCMMB)



Xmas Tree and Manifold Controls equipment includes pressure and temperature sensors, sand detectors, and pig detectors. The pressure and temperature sensors are used to measure the pressures & temperatures of the produced fluids flowing from the well. Both the pressure and temperature sensing units are built into the same sensor housing. A pressurized oil-filled electrical wire hose is terminated at the sensor and has connector(s) that attach to the SCMMB. Sand detectors are installed to let the operator know that significant erosion from sand in the hydrocarbons can occur. Action should be taken to adjust production rates when a significant amount of sand is present to prevent pipe erosion.

Pigs are used in well maintenance to clean production flowlines. If through-flowline tools are used for well maintenance, it is desirable to know the location of the tool in the pipe prior to performing critical operations. The pig detector simply uses a tool on a sensor to sense the reluctance between its elements. When a steel pig passes the pole’s pieces, it is sensed and the data is transmitted to the surface by the SCM.

Pressure and Temperature

sensor

Sand Detector assembly

Pig Detector

on Subsea

Manifold



8.3 Types of Control Systems Well control can be achieved safely and efficiently through a variety of Subsea Control Systems. The considerations for a Control System architecture include cost, field layout complexity, desired response time, and data feed back needed from the well. The Direct Hydraulic Control System operates the subsea and downhole hydraulic functions through dedicated hydraulic lines in the umbilical. A negative aspect of this type of system is the greater number of hydraulic lines that must be added for increased subsea functions. The requirement for a dedicated line for each function means the umbilical can become large and expensive. Normally there is no subsea monitoring, but pressures can be monitored using a sensor with a set of electrical conductors hardwired back to the platform or offshore drilling unit. This technology is well suited for shallow to medium water depths and where response times are not critical. A Piloted Hydraulic system uses a topside system similar to the direct hydraulic system, but the hydraulic lines control piloted control valves located on a retrievable subsea module instead of controlling the subsea functions directly. The pilot valves distribute hydraulic power from a separate line in the umbilical to the X/T actuators or other subsea functions. A Piloted Hydraulic system offers a faster response time than Direct Hydraulic systems and the pilot lines require smaller umbilical lines, which reduces the umbilical size and weight. An Electro-Hydraulic Piloted Control system is comprised of a similar layout to the piloted hydraulic system, but instead of controlling the subsea pilot valves with hydraulics, the pilot valves are operated with direct electrical current from a separate cable in the Umbilical used to operate the subsea functions. The cable which operates the solenoid valves are smaller and reduce the umbilical size and weight. Also, the response time compared to Piloted Hydraulic is reduced without



Mk IV 150 “Mini SCM.”

Provides limited high and low pressure

functions as well as limited sensor

monitoring.

Typical Electro-

Hydraulic Piloted system with computer control station

the dependence on tree function bore pressure. An Electro-Hydraulic piloted system provides much less flexibility and features compared to MUX systems, but it provides increased response time and range over a Piloted Hydraulic system. Minimal well and Xmas Tree feedback & control is provided via a “Mini SCM.” A Mini-SCM Control System provides a more economical solution than Direct Hydraulic Controls for operating low function Xmas Trees that are located 3 miles or more from the topside production facility. The MK IV offers several advantages over conventional Direct Hydraulic Control Systems including umbilical size and weight reduction, including instantaneous hydraulic venting of the actuators, increased instrumentation capabilities, and ROV retrievability.



An Electro-Hydraulic Control or Multiplexed Electro-Hydraulics Control System, commonly called a MUX system, consists of topside located computers from which control and monitoring of a well is present via a Subsea Control Module (SCM). Very short response times are achieved using the Electro Hydraulic system due to the constant hydraulic supply that is present to operate the Subsea hydraulic functions. This technology is best suited for complex, deep water operations and where great distances are covered between the hydraulic power supply and the equipment being operated. Electro Hydraulic controls also offer new and emerging technologies such as downhole "intelligent well" equipment that provides the ability to isolate or commingle production from flow zones remotely from the host production vessel via the normal Subsea Control System.



Section 9 FMC Manifold and Tie-in Systems - ManTIS

9.0 Overview ManTIS products include the design and supply of subsea manifolds and flow line connection systems. These products can be arranged in a multitude of varying configurations to accommodate the complex architecture of current deep water projects. As shown below below, there is more to a production field than trees and wellheads.

The next section will briefly discuss the major ManTIS components and their functions.



9.1 Components Subsea Manifold FMC subsea manifolds are designed to commingle direct flow from multiple individual wells into either of two production header pipes mounted on the manifold. The manifold design allows the production headers to be sized using nominal pipe diameters. The use of manifolds reduces the number of long flow lines required in a fields development. All manifold piping connections are welded to minimize leak paths and increase reliability. FMC manifolds are designed to operate for up to 20 years. Manifold designs and flow line connection systems vary according to field requirements. The following is a summary of the types of manifolds systems available. Design features include:

• Capable of operating in water depths in excess of 10,000 feet • Up to 15,000 psi working pressures • Sizes from 6” to 12” in diameter • Retrievable pigging loops • Foundations adaptable to all soil conditions • Multi-phase flow meters • Optional manifold mounted subsea control module

PLET



The PLET structure provides a stable base for flowline termination as well as support for the valve(s) and male connector hub receiver assemblies that facilitate tie-in to the subsea manifold and possibly a riser base gas lift distribution unit. In addition, PLETs range in complexity from a single hub with manual isolation valve to multiple hubs with actuated valves, chemical injection, and pig launching capabilities.

• PLET stands for “pipeline end termination” • Will connect directly to a manifold, pipeline, or intermediate sled • Rated up to 15,000 psi • Optional sliding carriage allows thermal expansion/contraction in flowline • Optional skirted mudmat provides penetration into mudline and weighs

approximately 30 tons



MAX Connector Configuration

• Used in flowline applications • Annular “flat-to-flat” contact between the locking mandrel and locking

segments evenly distributes stresses • The factory adjusted reaction ring provides precise, repeatable connector

preload • The locking segments are positively expanded and retained by the locking

mandrel upon unlocking of the connector • The connector is rated for 15,000 psi WP for bore sizes up to 7” ID (higher

for smaller bores, lower for larger bores) • 10,000 ft water depth rating (can be increased) • 20-year life rating • Hydraulic fluid dispensed to the CAT by an ROV provides the power for the

following functions: raise/lower connector, lock/unlock connector, external seal test on gasket

• The locking segments are forced inward by the locking mandrel to engage the mating hub profile, preloading the interface and energizing the seal element

• The connector is unlocked by retracting the locking mandrel using the CAT



Max 8 Production Hub

• Mates w/ MAX-8 connector • Available f/ pipe sizes up to 8” (NPS) • HX & MC gasket profile • Installed in hub support structure • Available with full or selective cladding • Gasket profile overlay w/ CRA material • Optional Inconel 625 butt-weld prep • Pressure ratings (10ksi – 15ksi) • Optional locking profile for pressure cap



Max 14 Production Hub

• Mates w/ MAX-14 connector • Available f/ pipe sizes up to 14” (NPS) • HX & MC gasket profile • Installed in hub support structure • Available with full or selective cladding • Gasket profile overlay w/ CRA material • Optional Inconel 625 butt-weld prep • Pressure ratings (3.6ksi – 15ksi) • Interfaces w/ MAX-14 Pressure Caps



Connector Actuation Tool The Connector Actuation Tool (CAT) was especially designed for vertical tie-in connections utilizing Max connectors and is operated by a standard ROV. The CAT provides "soft land" connections at both ends of the jumper/spool, seal testing and replacement and ROV interfaces for connectors.

• Deployed / retrieved suspended from spreader bars by slings • Passively latches to Mating Hub Assembly (MHA) to isolate surface vessel

heave motions • Provides soft land, lock / unlock, and gasket test functionality for connectors • Provides access for sub sea gasket replacement by ROV • CAT is completely retrievable following locking of connector and testing of

gasket • Three point, positive retention hub latching keeps one end of the jumper

retained while the second end is being landed without having to lower and lock the connector

CAT CAT-LITE



Flow Line Jumpers Custom flow line jumpers or spool pieces are used to connect manifold systems to wells, sleds to wells and/or manifolds to sleds. FMC Technologies offers rigid pipe and flexible pipe configurations in sizes from 4 to 18 inches diameter and lengths exceeding 150 feet (50 meters). Tie-in connections are either vertical or horizontal, based on system selection. Designed for water depths exceeding 10,000 feet (3,000 meters) and working pressures to 15,000 psi, all jumpers or spools are installed using guidelineless techniques. Jumpers or spools are installed after onshore construction and testing to mate to previously installed equipment, based on subsea metrology data.

• Water Depths exceeding 10,000 feet (3,000 meters), pressures to 15,000 psi • Lengths to more than 150 feet (50 meters) • Thermal Insulation • Vortex Induced Vibration Strakes • Flying Leads (Electrical, Optical, and

Hydraulic) • Seafloor Metrology, SIT and Support • Multi-Phased Flowmeters • Acoustic Detection Devices

M-Shape Well Jumpers



M-Shape Flowline and Inter-Manifold

Jumpers



Inverted-U Flowline and Inter-Manifold Jumpers



Suction Piles Suction piles are used to anchor subsea equipment to the seafloor. They are large open-ended cans that penetrate the seafloor under their own weight and the weight of the hydrostatic sea head. Once landed on the sea floor, a ROV is used to close a valve on the top of the suction pile and the water is pumped out of the body. The sea head (.44psi/ft) forces the suction pile downward as the water is evacuated from the body. Suction piles can be up to 20’ in diameter and 90’ long.



The pictures below show the deployment of a manifold structure with suction piles.



Manifold systems have been developed to meet different production and operational requirements. A major FMC accomplishment was the development of the hinge over subsea template system (HOST). Major benefits of the HOST system included:

- Manufactured using assembly line techniques - Reduced weight compared to conventional manifold structures - Deployed through a rig moon pool 6 meters x 6meters eliminating the need

for special installation vessels. - Retrievable manifold - Flexible design to accommodate on template wells, satellite wells, pigging

loops, mounting of subsea pumping.





The pictures below show a guide line type (GL) HOST system during stack up prior to shipment. The suction type anchors can be seen and the deployment of the hinge elements. The center manifold section is shown being lowered on to the base structure.



The HOST system can be configured for on template wells, satellite wells, daisy chain arrangement ect. to accommodate a variety of field development requirements. The graphics below show some of the configurations.





Simple manifold systems can also be provided for small field developments of up to 6 wells. The following is a summary of a simple modular manifold system.



The small modular type manifolds allow installation through a standard 6 meter x 6 meter moon pool. Transportation of the modular manifold can also be done using standard offshore supply vessels. The picture below shows a modular manifold on the deck of a supply vessel.



The graphic below shows a typical arrangement for a simple modular manifold system.



Flow Line Connection Systems Design of the flow line connection systems is also the responsibility of the ManTIS group and the MAX type flow line connection system typically used in the Gulf of Mexico has been described previously. Other flow line connection systems have been developed and supplied by FMC ranging from ROV based systems to large tooling packages capable of connecting and testing large flow lines. The following is a description of the flow line connection systems available from FMC.
















Rev June 2006

Acronyms - Abbreviations

Definitions Explanations

AAV Annulus Access Valve

ABS American Bureau of Shipping

ABT Annulus Bore Test

ACME A type of thread

ACV Annulus Crossover Valve

AD Administration

ADS Atmospheric Diving System

AES Atmospheric Environmental Service

AFC Approved For Construction AFD Approved For Design AFE Approved For Enquiry AFE Approved For Expenditure AFLC Annulus Flowline Connector AFV Annulus Flowline Valve AGA American Gas Association AI Analog Input AICF Analog Input ConFiguration AISC American Institute of Steel Construction AIV Annulus Isolation Valve ALARP As Low As Reasonably Practical AMV Annulus Master Valve AN Alliance Newfoundland ANSI American National Standards Institute ANSYS A finite element program for analysis of

structural stresses and strains AO Avalon Offshore Alliance AP Annulus Pressure (Sensor) API American Petroleum Institute APS Abandon Platform Shutdown ARSS Adjustable Riser Support System ASD Acoustic Sand Detector ASHC LWRP Annulus Shear Closed ASHO LWRP Annulus Shear Open


Rev June 2006

ASHRAE American Society of Heating, Refrigeration, and Air Conditioning Engineers

ASL Annulus Supply Line ASME American Society of Mechanical Engineers ASNT American Society for Nondestructive Testing ASTM American Society of Testing and Materials ASV Annulus Swab Valve ASV (alternate meaning) Annulus Shear Valve AVB Annulus Valve Block AVIM Actuator Valve Internals Module AVV Annulus Vent Valve (use ASV) AWHEM Association of Wellhead Equipment

Manufacturers AWS American Welding Society AWV Annulus Wing Valve AX Cooper Cameron Division proprietary metal

seal and its derivatives AXOV Annulus Crossover Valve bar 1 kg/cm2 (pressure) bbld barrels per day bbls Barrels BBS Best Business Solution BESD Bridge Area Emergency Shutdown BOD Basis of Design BOM Bill of Materials BOP Blow Out Preventor bopd Barrels of oil per day BOPSJ Blow Out Preventor Spanner Joint bpd Barrels per day BPV Bypass Valve BSL Below Sea Level BTC Tubing Hanger Running Tool Bottom Test Cap

or Buttress Thread Casing BTU British Thermal Units BTV Bore Test Valve BV Bureau Veritas BV Branch Valve bwpd Barrels of water per day C/WO Completion Workover CA Certifying Authority


Rev June 2006

CAD Computer Aided Drafting CAM Computer Aided Manufacturing CAPEX Capital Expenditure CAR Correction Action Request CAT Corrective Action Team CAT Connector Actuation Tool CB Choke Bridge CB (alternate meaning) Center of Buoyancy CBP Completion Bore Protector cc Cubic centimeters CC Tool Cement Clean Out Tool CCR Central Control Room CCS Camera Control Station CCTV Closed Circuit Television CCW Counterclockwise CD Committee Draft CG Center of Gravity cg Centigram CGB Completion Guidebase CHC Production Choke Closed CHO Production Choke Open CI Chemical Injection CID Downhole Chemical Injection CIDV Chemical Injection Downhole Valve CIF Common Interrogation Frequency CIIC Chemical Injection Check Valve CIIV Chemical Injection Isolation Valve CIS Chemical Injection Supply CIT Chemical Injection Tree CIU Chemical Injection Unit CIV Chemical Injection Valve CIW Cameron Iron Works CIWV Chemical Injection Wing Valve CL Center Line cm Centimeters CM Completion Mudline CMTU Control Module Test Unit (also CTU) CNC Computer Numerically Controlled CNOPB Canada Newfoundland Offshore Petroleum

Board


Rev June 2006

CO2 Carbon dioxide COB Center of Buoyancy COG Center of Gravity CON Continuity COV Crossover Valve CP Carthodic Protection CP Center Pile cp centi poise (absolute viscosity) CPS Choke Position Sensor CR Common Requirements CR Clamp Ring CRA Corrosion Resistant Alloy CRF Common Reply Frequency CRM Corrosion Resistant Material CS Center section CS Cross section cs centi stokes (kinematic viscosity) CSG API Casing Short Thread C-Spec FMC Coating specification CSU Control & Service Umbilical CT Coiled Tubing CTC Coil Tubing Cutter CTR Cost, Time, and Resource CTU Communications Test Unit (also CTU) cu ft , ft3 Cubic feet cu m, m3 Cubic meter CV Check Valve Cv Flow Coefficient (flow rate (gallons/min) of

water at 60oF at a pressure drop of 1 psi) (see also Kv) (Cv = 1.16Kv)

CW Clockwise CXT Conventional X-mas Tree DAS Data Acquisition System dBa Decibels (sound power level) (a scale) DBD Design Basis Document DBI Data Base Information (Sheet) DC Drill Center DCP Data Collection Point DCR Direct Current Resistance DCS Distribution (Distributed) Control System


Rev June 2006

DCV Directional Control Valve DCV Dummy Control Valve DDS Drum Decanting System DEG Degrees degrees C, oC Degrees Celcius or Centigrade degrees F, oF Degrees Fahrenheit degrees K, oK Degrees Kelvin DF Design Factor DFCS Diverless Flowline Connection System DFO Documentation For Orientation Dg Decigram-.1 gram DGB Drilling Guidebase D/H Direct Hydraulic DHI Downhole Interface DHPT Downhole Pressure and Temperature DHPTM Downhole Pressure and Temperature Monitor DHPTT Downhole Pressure and Temperature

Transducer DHSV Downhole Safety Valve dkg Decagram-10 grams dkm Decameter-10 meters dm Decimeter-.1 meter DMA Dead Man Anchor DMDS SOUR GAS/Dimethyl Disulfide DMG Document Management Group DMT Dual Measuring Transponder DMT Dual Mode Transponder DNV Det Norske Veritas DOD Diver Operated Dredge DP Design Pressure DP Design Principles DP Drill Pipe DP Downhole Pressure DP Dynamically Positioned DPA Development Plan Application DPDSV Dynamically Positioned Dive Support Vessel DPSV Downhole Production Safety Valve DPT Differential Pressure Transmitter DQT Design Qualification Test DQV Design, Qualification, Verification (see Trap)


Rev June 2006

DSP Design Specification DSV Diver Support Vessel DT Downhole Temperature E1, E2 Tree Electrical Connections E1, E2 X-mas Tree SCM Electrical Power and Signal EC Electrical Connector ED Erosion Detector EDC Emergency Disconnect Connector EDL EQD Connector Lock EDM Electrical Distribution Module EDP Emergency Depressuring System EDP Emergency Disconnect Package EDPHOT Emergency Drill Pipe Hang-Off Tool EDR Engineering Document Register EDU Electrical Distribution Unit EDU EQD Connector Unlock EDU Emergency Distribution Unit EFAT Extended Factory Acceptance Test EFL Electrical Flying Lead E/H Electrical and Hydraulic EH, E-H, E/H Electro-Hydraulic EHDM Electro Hydraulic Distribution Manifold EHXT Enhanced Horizontal Christmas Tree EJB Electrical Junction Box ELE1 DHPTT Line #1 ELE2 DHPTT Line #2 EMS Environmental Management System E/T Electronic Technician EPA Environmental Protection Agency EPC Engineering Procurement and Construction EPCI Engineering Procurement, Construction, and

Installation 5-F Five Function Manipulator 7-F Seven Function Manipulator EPCTU Electrical Power and Communication Test

Unit EPDM Ethylene-Propylene Rubber EPIC Engineering, Procurement, Installation and

Construction EPU Electrical Power Unit


Rev June 2006

EPROM Erasable Programmable Memory EPS Electrical Power System (UPS and EPU) EQD Emergency Quick Disconnect ER Equivalent Round erg A unit of work energy ESD Emergency Shutdown ESDU Emergency Shutdown Unit ESDV Emergency Shutdown Valve ESP Electric Submersible Pump E-Spec FMC Elastomer Specification ET Tree Cap External Test ETU Electronic Test Unit EUTU Electrical Umbilical Termination Unit EWA Existing Well Adapter EWT Extended Well Test EXAL EXAL, a company EXT Extend F&G Fire and Gas FAI Fail As Is FAR Fatal Accident Rate FAT Factory Acceptance Test FAX Facsimile service or device FC Fail Close FCL Flowline Connector Lock FCR Flowline Connector Return FCS Flowline Connector Supply Line FCUL Flowline Connector Unlock FDS Functional Design Specification FEED Front End Engineering & Design FI Financial FIHPC Flowline Protection/Pressure Caps (installed

on inboard hubs of manifold) FITA Field Installable Test Assembly FKM A type of fluoroelastomer FKS FMC/Kongsberg Subsea FLOT Flying Lead Orientation Tool FLP Fail Last Position FLUMB Flowline Umbilical Porch FMECA Failure Mode Effect and Criticality Analysis FMV Flow Master Valve (Surface)


Rev June 2006

FNCR Field Nonconformance Report FOP Forum for Petroleum FPF Floating Production Facility FPS Floating Production Storage FPSO Floating Production Storage & Offloading FPV Floating Production Vessel FRC Fast Rescue Craft FS Factor of Safety FSC Fail Safe Closed FSK Frequency Shift Key FSO Fail Safe Open FSO Field Service Order FSV Flow Swab Valve (Surface) Ft Foot feet ft-lb Foot-pounds FTC Field Termination Cabinet FTH Flowline Termination Head FTU Flowline Termination Unit FUTA Field Umbilical Termination Assembly (also

UTA) FWHP Flowing Wellhead Pressure FWHT Flowing Wellhead Temperature FWV Flow Wing Valve (Surface) GA General Arrangement GA General Assembly (Drawing) GB Grand Banks GBA Grand Banks Alliance GIIV Gas Injection Isolation Valve GIS Global Information System GL Gas Lifter Header GL Guidelined GLIV Gas Lift Isolation Valve GLL Guidelineless GOES Geo Orbiting East Station GOM Gulf of Mexico GOR Gas Oil Ratio GOT Glossary of Oilfield Terminology GP Guidepost GPS Global Positioning System GRA Guidelineless Reentry Assembly


Rev June 2006

GRP Glassfiber Reinforced Plastic GW Guidewire H Hydrostatic test pressure HAM Hydraulic Annulus Master Gate Valve HAZ Heat Affected Zone HAZOP Hazards & Operability HB Hardness Brinell HC Hydraulic/Chemical HCI Hydraulic Chemical Injection HCR High Collapse Resistance (Hose) HDM Hydraulic Distribution Module HES Halliburton Energy Services, a company HFL Hydraulic Flying Lead HF SSB High Frequency Single Sideband HIPPS High Integrity Pressure Protection System HIPPS (alternate meaning) High Integrity Pipeline Protection System hm Hectometer-100 meters HM Horizontal Stabbed (Mounted Vertically) HMAX Maximum Wave Height HMI Human/Machine Interface HNBR Nitroxile - Hydrogenated Nitrile Buna Rubber HOGS Hinge Over Guidance Structure HOPS Houston Operating Procedures HOST Hinge Over Subsea Template HP High Pressure HP Spare High Pressure Spare HPAPH High Pressure Accumulator Pressure High HPAPL High Pressure Accumulator Pressure Low HPAPLL High Pressure Accumulator Pressure Low

Low HPC High Pressure Cap HPC Hydraulic Production Choke HPC-C Hydraulic Production Choke Closed HPC-O Hydraulic Production Choke Open HPM Hydraulic Production Master HPU Hydraulic Power Unit HPUCP Hydraulic Power Unit Well Control Panel HPW Hydraulic Production Wing Gate Valve HR Human Resources HRB Hardness, Rockwell "B"


Rev June 2006

HRPT/TT High Resolution Pressure & Temperature Transmitter

HS Significant wave height HSE Health, Safety, and Environment HST Tubing Hanger Annulus Seal Test HSW Hydraulic Service Wing HT High Tension HTP Hydraulic Test Panel HUTU Hydraulic Umbilical Termination Unit HVAC Heating, Ventilation and Air Conditioning HVT High Voltage Transformer HWL Tubing Hanger to Wellhead Lock HWLV Tubing Hanger to Wellhead Lock Verification HWUL Tubing Hanger to Wellhead Unlock Function HXO Hydraulic Crossover HXT Horizontal X-mas Tree HYDL Tool Hydraulic Block Lock HYDU Tool Hydraulic Block Unlock IAP Instrument Air Pressure IBC International Bulk Containers ICF Individual Channel Frequency ICS Intervention Control System ICV Injection Choke Valve ID Inside Diameter IDC Inter Discipline Check IDS Interface Data Sheet IF Internal Flush IIP International Ice Patrol IMR Intervention, Maintenance, and Repair IMT Integrated Management Team IMV Injection Master Valve IPMS Integrated Project Management System (a

computer based control system used for engineering documents)

IR Insulation Resistance ISC Integrated Services Contract ISO International Standards Organization ISV Injection Swab Valve IT Intervention Tool ITM Intervention Tool Module


Rev June 2006

IWOCS Installation Work Over Control System IWV Injection Wing Valve J Joule, a unit of work or energy equal to

10,000,000 ergs J Tube A tube on the side of the platform for the riser J-Bowl Tool A tool for the J-bowl-a wearing bushing with a

J-slot J-Lay A method of laying pipe J-Mode Recovery Using a J-tool to recover an item with a J-slot JD Jeanne d'Arc Contractors Alliance JIP Joint Industry Project JPT Journal of Petroleum Technology Kbps Kilo (1,000) bits per second kip 1,000 pounds kJ kilo Joule km Kilometers kN Kilo Newton KOS Kongsberg Offshore KPI KOS Provided Items ksi 1,000 psi Kv Flow Factor (flow rate (cubic meter/hr) of

water at 20oC at a pressure drop of 1 bar) (see also Cv) (Kv = 0.853Cv)

LAMV Lower Annulus Master Valve LAN Local Area Network lbf-ft pound (force)-feet (ft-lbs is preferred) LBL Long Base Line LCP Local Control Panel LCSG API Casing Long Thread LCV Level Control Valve LDHI Low Dosage Hydrate Inhibitor LDP Liquid Dye Penetrant LER Local Equipment Room LF Low Frequency LFM Limited Fine Mesh LIMV Lower Injection Master Valve LIT Lead Impression Tool LMRP Lower Marine Riser Package LNBR Low Temperature Nitrile Buna Rubber LNG Liquefied Natural Gas


Rev June 2006

LP API Line Pipe LP Low Pressure LPAPH Low Pressure Accumulator Pressure High LPAPL Low Pressure Accumulator Pressure Low LPMV Lower Production Master Valve LRP Lower Riser Package LRQA Lloyd's Register of Quality Assurance LRTJ Lower Riser Tensioner Joint LS Landing String LT long ton-2,240 pounds LTL Lower Tree Lock LTST Lower Tree Seal Test LTSTV Lower Tree Seal Test Valve LTU Lower Tree Unlock LV Lubricator Valve LVDT Linear Variable Displacement

Transmitter/Transducer LWI Local Work Instructions LWRP Lower Workover Riser Package ManTIS Manifold and Tie-In Systems M/T Mechanical Technician M2M Metal-to-Metal mA milliAmps MAO Manual Annulus Outlet Gate Valve MAP To manipulate and program a system using a

controlling computer terminal max. Maximum MCC Master Control Console MCP Master Control Panel MCS Master Control Station MCU Master Control Unit MDS Material Data Sheet MEG Mobil Equatorial Guinea MEOH Methanol MF Medium Frequency Mhz Mega hertz MIL SPEC Military Specification, USA MIL-STD Military Standard, USA min Minimum ML Mudline


Rev June 2006

MLS Mudline Suspension System MM Manifold Module MMI Man Machine Interface (use HMI) mm Millimeters MM Million, a thousand thousand, 10 6 mmbbl a million barrels (a thousand thousand

barrels) MMCFPD million cubic feet per day MMS Minerals Management Service MMSCFD Million Standard Cubic Feet per Day mN milli Newton MOC Management of Change MODU Mobil Offshore Drilling Unit (Semi) Mpa Mega Pascal SI Unit for Pressure MPI Magnetic Particle Inspection MQC Mechanical Quick Connect MQC (alternate meaning) Multi Quick Connect MRB Material Review Board MRKB Mean Rotary Kelly Bushing MRP Material Requirements Planning MRP Movable ROV Panel MSA Mine Safety Appliance mscf/d thousand standard cubic feet per day MSCFD Thousand Standard Cubic Feet per Day MSDS Material Safety Data Sheet MSL Mean Sea Level M-Spec FMC Material Specifications MSRC Marine Spill Response Corporation MSS Manufacturers Standardization Society of the

Valve and Fittings Industry MSV Multi-service Support Vessel MTBF Mean Time Between Failures MTTR Mean Time To Repair MTU Manifold Termination Unit M/U Make-Up MUX Multiplex-an electro-hydraulic control system MVB Master Valve Block MWP Maximum Working Pressure N-M Newton Meter NACE National Association of Corrosion Engineers


Rev June 2006

NAS National Aeronautics Society NAS National Aerospace Standard NB Note Bene (Latin) Note Especially NB Nominal Bore NBR Nitrile Butal Rubber (Buna N or NBR) NC Numbered Connection NCR Non-Conformance Report NCRI Non-Conformance Rework Instruction NDE Non-Destructive Examination NGL Natural Gas Liquid NM Nautical Mile NOA or NOAA National Oceanographics and Atmospheric

Agency NOM Nominal NP Nominal Schedule Pipe NPD Norwegian Petroleum Directorate NPT National Pipe Thread NPTF National Pipe Thread Female NPTM National Pipe Thread Male NPV Net Present Valve NTS Norwegian Technology Standards Institution OBS Ocean Bottom Suspension (mudline wellhead

equipment - obsolete) (see SD-1) OC Operator Console OCTG Oil Country Tubular Goods OD Outside Diameter OEC Other End Connector OII Oceaneering International Inc. OMM Operations & Maintenance Manual OMUS Oceaneering Multiflex USA OOIP Oil Originally In Place OPEX Operations Expenses OS Operator Station OSHA Occupational Health and Safety

Administration OTC Offshore Technology Conference OWC Oil/Water Contact OWS Operator’s Work Station P & I Piping and Instrumentation (Flow Schematics) P & ID Piping and Instrumentation Drawing


Rev June 2006

P-C Petro-Canada, a company PA Public Address and Alarm PBOF Pressure Balance Oil Filled PBT Production Bore Test PCC Production Choke Close PCM Process Co-ordination Method PCO Production Choke Open PCS Production (Process or Platform) Control

System PCU Process (Production) Control Unit PCV Production Choke Valve PCVD Production Choke Valve Decrease PCVI Production Choke Valve Increase PD-PK Pig Detector Parking PDQ Production, Drilling & Quarters PDU Power Distribution Unit PE SCM Pigging Loop Electrical Connection PE Professional Engineer PEEK Polyetheretherketone PETU Portable Electrical Test Unit PEP Project Execution Plan PFD Process Flow Diagrams PFL Production Flowline Connector PFU Production Flow Unlock PFV Production Foot Valve PGB Permanent Guidebase PGV Pigging Valve PH Pigging Loop Module Valve PIV Production Isolation Valve PL Pig Valve and Detector Sensor PLC Programmable Logic Controller PLCM Power Line Carrier Modem PLEM Pipeline End Module PLET Pipeline End Termination PLF Power Line Filters PLFS Power Line Filter Single PLM Pigging Loop Module PLM Power Line Modem PLMS Power Line Modem Single PLMV Production Lower Master Valve


Rev June 2006

PLP Pig Loop Porch PM Pig Module PMT Pipe Measurement Tool PMT Pressure Test and Monitoring Tool PMV Production Master Valve POOH Pull out of hole PORRT Packoff Running and Retrieving Tool PP/PT Production Pressure and Temperature Sensor ppb Parts per billion ppg Pounds per gallon ppm Parts per million PPSD Partial Process Shutdown PQR Procedure Qualification Record PR Performance Requirement PR1 Performance Requirement Level One PR2 Performance Requirement Level Two PRE Pitting Resistance Equivalent PSD Process (Production) Shut Down PSDV Production or Process Shut Down Valve PSHC LWRP Production Shear Closed PSHO LWRP Production Shear Open psi Pounds per square inch (always lowercase) psia Pounds per square inch absolute psig Pounds per square inch gauge PSL Pressure (Product) Specification Level PSL Production Shutdown Logic P-Spec FMC Purchasing Specification PSRST Production System Review and Selection Task PSV Production Swab Valve / Production Shear

Valve PSV Production and Storage Vessel PT Tree Cap Production Bore Test PT Pressure Transmitter P/T Pressure/Temperature PTCD Positive Temperature Coefficient Thermistor

Board PTD Project To Date PTFE A Teflon™, poly tetra fluor ethylene PTT Pressure & Temperature Transmitter P/U Pick Up


Rev June 2006

PUMV Production Upper Master Valve PUP Pipe Utility Piece, a short piece of pipe PV Pigging Valve PV-PK Pigging Valve Parking PVB Production Valve Block PVC Poly Vinyl Chloride PWHT Post Weld Heat Treatment PWV Production Wing Valve QA Quality Assurance QC Quality Control QC Quick Connect QCDC Quick Connect Disconnect QD Quick Disconnect QM Quality Matrix Q-Spec FMC Assembly or Quality Specification QTC Qualification Test Coupons QTP Qualification Test Procedure R&D Research and Development R&R Tool Running and Retrieval Tool R/D Rig Down R/T Running Tool R/U Rig Up RAP Reliability Assurance Program RCA Remote Cable Anchors RCJ Riser Cross-over Joint REG Regular RET Return RF Radio Frequency RFC Revised for Construction RFD Revised for Design RFI Request for Issue RFQ Request for Quotation RICAS Replaceable Inboard Cap Assemblies RIH Run In Hole RIT Receiving Inspection Testing RKB Rig Kelly Bushing RLMS Riser Load Monitor System RMM Retrievable Manifold Module ROT Remotely Operated Tool


Rev June 2006

ROV Remotely Operated Vehicle RP Recommended Practice RPGB Retrievable Permanent Guidebase RPLM Retrievable Pigging Loop Module R/R Tool Running and Retrieving Tool RT Running Tool RV Retainer Valve S&HO Stab and Hinge Over S-Lay Method of laying pipe SA Maximum Allowable Tensile Strength SAE Society of Automotive Engineers SAFOP Safety and Operability SAG Successful Alliance Groups SAS Safety Automation System Sb Bending Stress SBMS Straight Bore Metal Seal SBR Shawmount Brown and Root, a company SBS Short Bore Selector SBS Straight Bore Selector SCADA Supervisory Control and Data Acquisition SCE Sanction Cost Estimates SCE Subsea Communications Enclosure sdf/d Standard cubic feet per day SCF\BBL Standard Cubic Feet Per Barrel SCM Subsea Control Module (i.e. POD) SCMMB Subsea Control Module Mounting Base SCMTS Subsea Control Module Test Stand SCP Subsea Control Pod (use SCM) SCPC Subsea Communications Protocol Converter

(or Computer) SCSSV Surface Controlled Subsea Safety Valve SCU Secondary Connector Unlock SCU Subsea Control Unit SCU Tree Cap Secondary Unlock sd Standard day SD Shutdown SD Sand Detector SD (alternate meaning) Stacked Down SD-1 Stack Down (FMC mudline wellhead system) SD1 Acoustic Sand Detector


Rev June 2006

SDC Single Discipline Check SDV Shut Down Valve SE Maximum allowable equivalent stress at the

most highly stressed distance into the pressure vessel wall, computed by the distortion energy theory method

SE1, SE2 Step Out umbilical Electric Power and Signal SEM Subsea Electronic Module SEMI Semi-submersible Vessel SETE Subsea Electronic Test Equipment SEPU Subsea Electrical Power and Communications

Unit SETU Subsea Electronic Test Unit SF Safety Factor SFL Steel Flying Lead SFT Surface Flow Tree SI International System SIO Serial Input/Output SIOLT Serial Input/Output Line Termination SIT Systems Integration Test SJ Slick Joint SL Tool Spring Loaded Tool SLC Single Line Coupler SLC Slim Line Connector Sm Membrane Stress/design stress intensity at

rated working pressure SOI Shell Offshore Inc., a company SOR Statement of Requirements SOS Scope of Supply SP Single Porch SPCU Subsea Power and Communications Unit SPCTU Subsea Power and Communication Test Unit SPE Society of Petroleum Engineers SR System Specific Requirements SRI Subsea Retrievable Insert SRIC Subsea Retrievable Insert Choke SRT Running Tool / Secondary Release Tool SS Subsea SSCS Subsea Sour Control Systems SSDS Safety Shutdown System


Rev June 2006

SSF Subsea Filter Sshr Allowable Stress in Shear STRT Secondary Tree Release Tool SSM Subsea Modem SSOI Safety System Operator Interface SSSV Subsurface Safety Valve SSTT Subsea Test Tree SSV Surface Safety Valve St Maximum allowable general primary

membrane stress intensity at hydrostatic test pressure

ST Seal Test ST Surface Test Tree ST Surface Tree ST Swivel/Turret/Mooring ST Tool Single Trip Tool STL Submerged Turret Loading STT Subsea Test Tree STT Surface Test Tree S uts Ultimate Tensile Strength SV Safety Valve SVCU Subsea Valve Control Unit SW Software SWHP Shut-in Wellhead Pressure SWL Safe Working Load Sy Material minimum specified yield strength Syld Yield stress T Ton-2,000 pounds TA Cap Temporary Abandonment Cap TBA To be announced TC Tree Cap TCB Tieback Connector TBD To be determined TGB API Tubing T1, T2, T3 Well/Tree #1 TC Test Coupon TC Tree Cap TCL Tree Cap Lock TCL Tree Connector Lock TCRT Tree Cap Running and Retrieving Tool


Rev June 2006

TCSL Tree Cap Soft Landing TCSU Tree Connector Secondary Unlock TCT Tree Cap Test / or Tree Connector Test TCTV Tree Connector Test Valve TCRT Tree Cap Running Tool TCU Tool Control Unit TCUL Tree Cap Unlock TE Tree Electric TEG Tri-Ethylene Glycol TEI Tree Electric-Inner Tree TEMP Temperature TEO Tree Electric-Outer Tree TF Topsides Facilities TFE Teflon™, tetra fluor ethylene TFL Through Flowline Tools TGB Temporary Guide Base TH Tubing Hanger TH Tubing Head TH Tree Hydraulic TH X-mas Tree Hydraulic THAS Tubing Hanger Adapter Sleeve THCP Tubing Hanger Crown Plug THDSS Tubing Hanger Deck Storage Stand THERT Tubing Hanger Emergency Recovery Tool THHT Tubing Hanger Handling Tool THI Tree Hydraulic-Inner Tree THL Tool to Hanger Lock THL THRT to Tubing Hanger Lock THLV THRT to Tubing Hanger to Lock Verification THMAX Period associated to HMAX-wave height THO Tree Hydraulic-Outer Tree THOJ Tubing Hanger Orientation Joint THRA Tubing Hanger Running Assembly THRT Tubing Hanger Running Tool THS Tubing Head Spool THST Tubing Head Seal Test THTS Tubing Hanger Test Stand THT Tree Handling Tool THUL Tool to Tubing Hanger Unlock


Rev June 2006

THWIS Tubing Hanger Wireline Isolation Sleeve THWNP Tubing Hanger Wireline Nipple Protector TIV Test Isolation Valve TIW Texas Iron Works (valve) TLM Total Loss Management TLP Tension Leg Platform Tp Peak period associated with wave height

(usually significant wave height) (see also Hs) TP Test Pressure TP Triple Porch TPE Thermoplastic Elastomer TQM Total Quality Management TRAP Technology Risk Assurance Process (also see

DQV) TRSCSSV Tubing Retrievable Surface Controlled

Subsurface Safety Valve TRT Tree Running Tool TSJ Tapered Stress Joint TST Tree Seal Test TT Temperature Transmitter TTC Tubing Hanger Running Tool Top Test and

Handling Cap TTL TRT Connector Lock TTL Tree Lock Tool TTSL Tree Tool Soft Landing TTSU Tree Tool Secondary Unlock TTU Tree Tool Unlock TTU Tree Tool Connector Unlock TUTA Topsides Umbilical Termination Assembly

(also UTA) TVD Total Vertical Depth Tz Zero up crossing period-wave height U/V Ultra Violet UAMV Upper Annulus Master Valve UAP Utility Air Pressure UCS UTIS Control System UCU Utility Control Unit UGF Universal Guide Frame UH Main E/H Umbilical UTH Hydraulic UIMV Upper Injection Master Valve


Rev June 2006

UK United Kingdom UKOLS Ugland Kongsberg Offshore Loading System UKOOA United Kingdom Offshore Operators

Association, London ULS Ultimate Limit State UMC Underwater Manifold Center UNC Unified National Coarse (USA thread profile) UNF Unified National Fine (USA thread profile) UPMV Upper Production Master Valve UPS Uninterruptible Power Supply UPTBG API Tubing External Upset Tubing URT Universal Running Tool USD Unit Shutdown USD United States Dollar USV Underwater Safety Valve UT Umbilical Termination UTA Umbilical Termination Assembly UTAJ Umbilical Termination Assembly Jumper UTB Umbilical Termination Box UTH Umbilical Termination Head UTIS Universal Tie In System UTL Upper Tree Lock UTP Umbilical Termination Panel UTSL Upper Tree Soft Landing UTST Upper Tree Seal Test UTSTV Upper Tree Seal Test Valve UTU Upper Tree Unlock UV Design A staged pressure energized packing set

comprised of a spring load U seal backed up by multiple V seal rings, interspaced non-extrusion rings

UWD Underwater Drilling (Wellhead System) V-SAT Small aperture terminal-type of satellite

communication system VAM ACE VAM is a company/ACE is a casing and tubing

thread type VBM Valve Body Module VDU Visual Display Unit VHF Very High Frequency VIS Vendor Information Server


Rev June 2006

VIS Vendor Interface System VM Vertical Stabbed (Mounted Horizontally) VP Variable Position VPI Variable Position Indicator for LVDT VSE Valve Signature Enclosure VSS Valve Signature Server VX ABB Vetco Gray proprietary metal seal and its

derivatives VXT VX Gasket Test VXT Vertical Xmas Tree WBS Work Breakdown Structure WC Well Construction/Reservoir WCT Wireline Coiled Tubing WCT-BOP Wireline Coil Tubing Blowout Preventor WD Working Draft WETU Workover Electronic Test Unit WH Wellhead System WHD Wellhead WIIV Water Injection Isolation Valve WLA Wireline Adapter Assembly WO Riser Work Over Riser WOC Wait on Cement WOCS Work Over Control System WP Working Pressure WPS Welding Procedure Specification WSCM Workover Subsea Control Module WTU Well Termination Unit X-mas Tree X-mas Tree, set of control valves for well X-Sect Cross Section XOV Crossover Valve XT X-mas Tree XTC-L X-mas Tree Connector Lock XTC-U X-mas Tree Connector Unlock Y1, Y2 Daisy Chain HOST Electric Power and Signal Ya Actual average yield strength from test

specimens YH Daisy Chain HOST Hydraulic Ys Specified minimum Yield strength YTD Year to Date


Rev June 2006

Documents

Subsea 101 Rev3