Subsea 101 Rev3

Innovative Technologies, Creative Solutions

Subsea 101 An Introduction To Subsea Production Systems

REVISED June 2006 COPYRIGHT

C

2006 By FMC Technologies Inc.

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 1

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.

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

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, deicers, 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



• •

1.3

Focus on growing profits and increasing returns Attract and retain the best talent in the industry

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 costeffective, 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. 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


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. 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


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.

Anchorage

Edmonton St. John’s

Calgary

Bergen Kongsberg Aberdeen Stavanger Dunfermline Sens

Halifax Houston

Villahermosa

Mauritania Maracaibo

Muscat

Lagos Eq. Guinea

Congo

Luanda Macae Rio De Janeiro

Johor Singapore Jakarta

Perth

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 Norway 260 invest in research and development, U.K. 80 N. America manufacturing 300 capabilities and processes and human Africa 200 resources to maintain this Brazil Asia 240 120 leading global position.

1,200 Subsea Trees Over 250 Projects

FMC’s global inbound tree market share: 600 500

38%

40%

47%

40%

98

400 300 200

362 273

100

430

464

229

0 2002

2003

2004

2005

2006 F



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.

FIXED PLATFORM

MULTI PORPOSE SERVICE VESSEL (MSV)

TENSION LEG PLATFORM (TLP) FLOATING, PRODUCTION & OFFLOADING VESSEL (FPSO)



The graphic below shows the progression of completion depths and the corresponding platform technologies. As can be seen, the structural and distribution technologies have adapted to the increasing challenges of producing in deeper and deeper waters.

Fixed Platform (To 1650 Feet)

Compliant Tower (1500 To 3000 Feet)

Mini - TLP (600 To 3500 Feet)

Tension Leg Platform (TLP) (1500 To 4500 Feet)

SPAR Platform (SP) (2000 To 7500 Feet)

Floating Production Systems (FPSO, FPF) (1500 to 7500 Feet)

Subsea Systems (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 Diving Vessel

The Service Rig

The Semi-submersible Rig



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.

RIG SUBMERGED COLUMNS

SUBSEA EQUIPMENT



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 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


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.

Moonpool Areas Permanent guidebase being run through the moonpool area

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

The above photographs show a typical moon pool arrangement on a semisubmersible rigs. The moon pool size is typically 6 meters square and as such all subsea equipment must be designed to pass through this size. 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


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.

Supply Boats



Other Support Vessels

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.



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: • • • • • • • •

3.1

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

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 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


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. 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


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.



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: H-4 Mandrel Profile Gasket Area Wear Bushing

Internal Profile

18 ¾” High Pressure Wellhead Housing Annulus Seal Assemblies

Low Pressure Housing

Casing Hangers

Conductor Pipe



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.

18 ¾” Wellhead Housing

30/36”Conductor Housing

30/36”Conductor Pipe

20/26”Intermediate Casing

16” Submudline Receptacle, Hanger, & Running Tool



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:

H-4 Mandrel Profile Gasket Area Internal Profile

Wear Bushing 18 ¾” High Pressure Wellhead Housing

36” Conductor Housing

Annulus Seal Assemblies

Rigid Lock Seal Assembly

Casing Hangers


36” Conductor Pipe



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 Gasket Area Wear Bushing

Internal Profile

18 ¾” High Pressure Wellhead Housing


Annulus Seal Assemblies

Rigid Lock Seal Assembly 26” Conductor Housing

Casing Hangers

Expanding Load Ring

Conductor Pipe



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.

16” 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.

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.





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.

1992

1994

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

Hardware Cost

2000

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

Installation Cost

6000

1996 - 1998

10000

Water Depth, ft.

2000 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


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 Completion: The assembly of downhole equipment required to enable safe and efficient production from an oil or gas well

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

The type of flowline connection system: On or off a template, diver or diverless

The type of well production: Gas or oil, H2S and CO2 content



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 “offthe-shelf” trees are: A proven design, minimal need for engineering (or reengineering), 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.

CAPEX per Tree System $ (Mill.)

4.5 4 3.5 3 2.5

Project Engineering Cost Tree Cost

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

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.

Vertical Tree Horizontal 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-forpurpose, 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. 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


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 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


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. 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


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 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


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. Emergency The dual bore would also be in the Subsea Disconnect tree valve block and vertical pressure (EDP) 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 Lower Subsea tree valve block. Riser Package The top profile of the vertical tree would (LRP) 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.

Vertical Tree

Tubing Head



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. ANNULUS MASTER & SWAB VALVE HYDRAULIC ACTUATORS

PRODUCTION MASTER & SWAB VALVE HYDRAULIC ACTUATORS

RE-ENTRY HUB WITH PRODUCTION & ANNULUS BORES



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 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


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.



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.

INTERNAL TREE CAP BALL VALVE

WIRE LINE PLUGS

WIRE LINE PLUG TUBING HANGER

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. 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


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. 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




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 One less BOP trip (Drill Through completion) Tubing hanger landed in wellhead (or tubing head) Can be installed on competitors wellhead Allows intervention without a rig (X-tubing/tugging head) 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 Installed CAPEX considered to be lower than disconnecting flowlines 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 More rig deck space needed to accommodate accommodate IWOCS umbilical additional tooling and riser Higher bending loads on the wellhead Rig needs to handle more tooling system Potential leak oaths below the BOP additional wellhead casing hangers rigidizing trip required Well must be plugged prior to removing the Tubing hanger seals in the ID of the UWD-15 tree casing that could be damaged during drilling operations Some concern with wireline plugs for Need to remove the tree for tubing workover vertical barriers Suitable for large bore 7”> gas wells



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.

Swab Valve Production Master 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 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


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

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.

MASTER CONTROL STATION (MCS) (HPU)

HYDRAULIC POWER UNIT (HPU)

HYDRAULIC TEST PANEL

ELECTRICAL JUNCTION BOX UMBILICAL HANG OFF



8

Template Systems – Hinge Over Subsea (HOST)



9



10

The drawing below shows a typical HOST retrievable manifold assembly…

ROV INTERFACE FOR VALVE OPRERATION

HORIZONTAL FLOW LINE HUBS

VERTICAL FLOW LINE HUBS



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. 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


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. 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


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 Master Control Station data & alarms. A typical MCS consists of two (MCS) with Human complete and independent networks incorporating Machine Interface (HMI) Workstation 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. 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


Graphics Based Control Interface

Tabular 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 Typical UPU power and communication source is cabinet 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.



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 SPCTU with Test supplies to dual redundant computer Equipment 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.

Typical EPU

Spooling reel mounted umbilical



Umbilical Terminations If the control umbilical is the main artery from the surface to subsea, then the flying leads are the Cross Section of Control capillaries that supply Umbilical with Electrical the system. The “quads” and Hydraulic deployed umbilical must Hoses 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 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


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





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 HFL Assembly to/from subsea equipment to prevent with MQC Junction Plate contamination of the hydraulic system with seawater and vice versa.

Outboard MQC Plate

Male and Female Hydraulic Couplers Male and Female MQC Plates

Inboard MQC Plate



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 EFLs with ROV the flying lead may have any plug/receptacle Electrical combination according to customer needs. Connections 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 subseainstalled, electro-hydraulic SCM with Electrical manifold designed to Connectors on control the operation of a Xmas Tree Guide Funnel 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. 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


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.

SCM

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 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.

Pressure and Temperature sensor

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 Pig steel pig passes the pole’s Detector pieces, it is sensed and the on data is transmitted to the Subsea Manifold surface by the SCM.

Sand Detector assembly



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 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


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.

Typical ElectroHydraulic Piloted system with computer control station

Mk IV 150 “Mini SCM.” Provides limited high and low pressure functions as well as limited sensor monitoring.



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. 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


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 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


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-LITE

CAT



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.

















Acronyms Definitions Abbreviations 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 AFD AFE AFE AFLC AFV AGA AI AICF AISC AIV ALARP AMV AN ANSI ANSYS

Approved For Construction Approved For Design Approved For Enquiry Approved For Expenditure Annulus Flowline Connector Annulus Flowline Valve American Gas Association Analog Input Analog Input ConFiguration American Institute of Steel Construction Annulus Isolation Valve As Low As Reasonably Practical Annulus Master Valve Alliance Newfoundland American National Standards Institute A finite element program for analysis of structural stresses and strains Avalon Offshore Alliance Annulus Pressure (Sensor) American Petroleum Institute Abandon Platform Shutdown Adjustable Riser Support System Acoustic Sand Detector LWRP Annulus Shear Closed LWRP Annulus Shear Open

AO AP API APS ARSS ASD ASHC ASHO


Rev June 2006

ASHRAE ASL ASME ASNT ASTM ASV ASV (alternate meaning) AVB AVIM AVV AWHEM AWS AWV AX AXOV bar bbld bbls BBS BESD BOD BOM BOP bopd BOPSJ bpd BPV BSL BTC BTU BTV BV BV bwpd C/WO CA

American Society of Heating, Refrigeration, and Air Conditioning Engineers Annulus Supply Line American Society of Mechanical Engineers American Society for Nondestructive Testing American Society of Testing and Materials Annulus Swab Valve Annulus Shear Valve Annulus Valve Block Actuator Valve Internals Module Annulus Vent Valve (use ASV) Association of Wellhead Equipment Manufacturers American Welding Society Annulus Wing Valve Cooper Cameron Division proprietary metal seal and its derivatives Annulus Crossover Valve 1 kg/cm2 (pressure) barrels per day Barrels Best Business Solution Bridge Area Emergency Shutdown Basis of Design Bill of Materials Blow Out Preventor Barrels of oil per day Blow Out Preventor Spanner Joint Barrels per day Bypass Valve Below Sea Level Tubing Hanger Running Tool Bottom Test Cap or Buttress Thread Casing British Thermal Units Bore Test Valve Bureau Veritas Branch Valve Barrels of water per day Completion Workover Certifying Authority


Rev June 2006

CAD CAM CAPEX CAR CAT CAT CB CB (alternate meaning) CBP cc CC Tool CCR CCS CCTV CCW CD CG cg CGB CHC CHO CI CID CIDV CIF CIIC CIIV CIS CIT CIU CIV CIW CIWV CL cm CM CMTU CNC CNOPB

Computer Aided Drafting Computer Aided Manufacturing Capital Expenditure Correction Action Request Corrective Action Team Connector Actuation Tool Choke Bridge Center of Buoyancy Completion Bore Protector Cubic centimeters Cement Clean Out Tool Central Control Room Camera Control Station Closed Circuit Television Counterclockwise Committee Draft Center of Gravity Centigram Completion Guidebase Production Choke Closed Production Choke Open Chemical Injection Downhole Chemical Injection Chemical Injection Downhole Valve Common Interrogation Frequency Chemical Injection Check Valve Chemical Injection Isolation Valve Chemical Injection Supply Chemical Injection Tree Chemical Injection Unit Chemical Injection Valve Cameron Iron Works Chemical Injection Wing Valve Center Line Centimeters Completion Mudline Control Module Test Unit (also CTU) Computer Numerically Controlled Canada Newfoundland Offshore Petroleum Board


Rev June 2006

CO2 COB COG CON COV CP CP cp CPS CR CR CRA CRF CRM CS CS cs CSG C-Spec CSU CT CTC CTR CTU cu ft , ft3 cu m, m3 CV Cv CW CXT DAS dBa DBD DBI DC DCP DCR DCS

Carbon dioxide Center of Buoyancy Center of Gravity Continuity Crossover Valve Carthodic Protection Center Pile centi poise (absolute viscosity) Choke Position Sensor Common Requirements Clamp Ring Corrosion Resistant Alloy Common Reply Frequency Corrosion Resistant Material Center section Cross section centi stokes (kinematic viscosity) API Casing Short Thread FMC Coating specification Control & Service Umbilical Coiled Tubing Coil Tubing Cutter Cost, Time, and Resource Communications Test Unit (also CTU) Cubic feet Cubic meter Check Valve Flow Coefficient (flow rate (gallons/min) of water at 60oF at a pressure drop of 1 psi) (see also Kv) (Cv = 1.16Kv) Clockwise Conventional X-mas Tree Data Acquisition System Decibels (sound power level) (a scale) Design Basis Document Data Base Information (Sheet) Drill Center Data Collection Point Direct Current Resistance Distribution (Distributed) Control System


Rev June 2006

DCV DCV DDS DEG degrees C, oC degrees F, oF degrees K, oK DF DFCS DFO Dg DGB D/H DHI DHPT DHPTM DHPTT DHSV dkg dkm dm DMA DMDS DMG DMT DMT DNV DOD DP DP DP DP DP DPA DPDSV DPSV DPT DQT DQV

Directional Control Valve Dummy Control Valve Drum Decanting System Degrees Degrees Celcius or Centigrade Degrees Fahrenheit Degrees Kelvin Design Factor Diverless Flowline Connection System Documentation For Orientation Decigram-.1 gram Drilling Guidebase Direct Hydraulic Downhole Interface Downhole Pressure and Temperature Downhole Pressure and Temperature Monitor Downhole Pressure and Temperature Transducer Downhole Safety Valve Decagram-10 grams Decameter-10 meters Decimeter-.1 meter Dead Man Anchor SOUR GAS/Dimethyl Disulfide Document Management Group Dual Measuring Transponder Dual Mode Transponder Det Norske Veritas Diver Operated Dredge Design Pressure Design Principles Drill Pipe Downhole Pressure Dynamically Positioned Development Plan Application Dynamically Positioned Dive Support Vessel Downhole Production Safety Valve Differential Pressure Transmitter Design Qualification Test Design, Qualification, Verification (see Trap)


Rev June 2006

DSP DSV DT E1, E2 E1, E2 EC ED EDC EDL EDM EDP EDP EDPHOT EDR EDU EDU EDU EFAT EFL E/H EH, E-H, E/H EHDM EHXT EJB ELE1 ELE2 EMS E/T EPA EPC EPCI 5-F 7-F EPCTU EPDM EPIC EPU

Design Specification Diver Support Vessel Downhole Temperature Tree Electrical Connections X-mas Tree SCM Electrical Power and Signal Electrical Connector Erosion Detector Emergency Disconnect Connector EQD Connector Lock Electrical Distribution Module Emergency Depressuring System Emergency Disconnect Package Emergency Drill Pipe Hang-Off Tool Engineering Document Register Electrical Distribution Unit EQD Connector Unlock Emergency Distribution Unit Extended Factory Acceptance Test Electrical Flying Lead Electrical and Hydraulic Electro-Hydraulic Electro Hydraulic Distribution Manifold Enhanced Horizontal Christmas Tree Electrical Junction Box DHPTT Line #1 DHPTT Line #2 Environmental Management System Electronic Technician Environmental Protection Agency Engineering Procurement and Construction Engineering Procurement, Construction, and Installation Five Function Manipulator Seven Function Manipulator Electrical Power and Communication Test Unit Ethylene-Propylene Rubber Engineering, Procurement, Installation and Construction Electrical Power Unit


Rev June 2006

EPROM EPS EQD ER erg ESD ESDU ESDV ESP E-Spec ET ETU EUTU EWA EWT EXAL EXT F&G FAI FAR FAT FAX FC FCL FCR FCS FCUL FDS FEED FI FIHPC FITA FKM FKS FLOT FLP FLUMB FMECA FMV

Erasable Programmable Memory Electrical Power System (UPS and EPU) Emergency Quick Disconnect Equivalent Round A unit of work energy Emergency Shutdown Emergency Shutdown Unit Emergency Shutdown Valve Electric Submersible Pump FMC Elastomer Specification Tree Cap External Test Electronic Test Unit Electrical Umbilical Termination Unit Existing Well Adapter Extended Well Test EXAL, a company Extend Fire and Gas Fail As Is Fatal Accident Rate Factory Acceptance Test Facsimile service or device Fail Close Flowline Connector Lock Flowline Connector Return Flowline Connector Supply Line Flowline Connector Unlock Functional Design Specification Front End Engineering & Design Financial Flowline Protection/Pressure Caps (installed on inboard hubs of manifold) Field Installable Test Assembly A type of fluoroelastomer FMC/Kongsberg Subsea Flying Lead Orientation Tool Fail Last Position Flowline Umbilical Porch Failure Mode Effect and Criticality Analysis Flow Master Valve (Surface)


Rev June 2006

FNCR FOP FPF FPS FPSO FPV FRC FS FSC FSK FSO FSO FSV Ft ft-lb FTC FTH FTU FUTA FWHP FWHT FWV GA GA GB GBA GIIV GIS GL GL GLIV GLL GOES GOM GOR GOT GP GPS GRA

Field Nonconformance Report Forum for Petroleum Floating Production Facility Floating Production Storage Floating Production Storage & Offloading Floating Production Vessel Fast Rescue Craft Factor of Safety Fail Safe Closed Frequency Shift Key Fail Safe Open Field Service Order Flow Swab Valve (Surface) Foot feet Foot-pounds Field Termination Cabinet Flowline Termination Head Flowline Termination Unit Field Umbilical Termination Assembly (also UTA) Flowing Wellhead Pressure Flowing Wellhead Temperature Flow Wing Valve (Surface) General Arrangement General Assembly (Drawing) Grand Banks Grand Banks Alliance Gas Injection Isolation Valve Global Information System Gas Lifter Header Guidelined Gas Lift Isolation Valve Guidelineless Geo Orbiting East Station Gulf of Mexico Gas Oil Ratio Glossary of Oilfield Terminology Guidepost Global Positioning System Guidelineless Reentry Assembly


Rev June 2006

GRP GW H HAM HAZ HAZOP HB HC HCI HCR HDM HES HFL HF SSB HIPPS HIPPS (alternate meaning) hm HM HMAX HMI HNBR HOGS HOPS HOST HP HP Spare HPAPH HPAPL HPAPLL HPC HPC HPC-C HPC-O HPM HPU HPUCP HPW HR HRB

Glassfiber Reinforced Plastic Guidewire Hydrostatic test pressure Hydraulic Annulus Master Gate Valve Heat Affected Zone Hazards & Operability Hardness Brinell Hydraulic/Chemical Hydraulic Chemical Injection High Collapse Resistance (Hose) Hydraulic Distribution Module Halliburton Energy Services, a company Hydraulic Flying Lead High Frequency Single Sideband High Integrity Pressure Protection System High Integrity Pipeline Protection System Hectometer-100 meters Horizontal Stabbed (Mounted Vertically) Maximum Wave Height Human/Machine Interface Nitroxile - Hydrogenated Nitrile Buna Rubber

Hinge Over Guidance Structure Houston Operating Procedures Hinge Over Subsea Template High Pressure High Pressure Spare High Pressure Accumulator Pressure High High Pressure Accumulator Pressure Low High Pressure Accumulator Pressure Low Low High Pressure Cap Hydraulic Production Choke Hydraulic Production Choke Closed Hydraulic Production Choke Open Hydraulic Production Master Hydraulic Power Unit Hydraulic Power Unit Well Control Panel Hydraulic Production Wing Gate Valve Human Resources Hardness, Rockwell "B"


Rev June 2006

HRPT/TT HS HSE HST HSW HT HTP HUTU HVAC HVT HWL HWLV HWUL HXO HXT HYDL HYDU IAP IBC ICF ICS ICV ID IDC IDS IF IIP IMR IMT IMV IPMS IR ISC ISO ISV IT ITM

High Resolution Pressure & Temperature Transmitter Significant wave height Health, Safety, and Environment Tubing Hanger Annulus Seal Test Hydraulic Service Wing High Tension Hydraulic Test Panel Hydraulic Umbilical Termination Unit Heating, Ventilation and Air Conditioning High Voltage Transformer Tubing Hanger to Wellhead Lock Tubing Hanger to Wellhead Lock Verification Tubing Hanger to Wellhead Unlock Function Hydraulic Crossover Horizontal X-mas Tree Tool Hydraulic Block Lock Tool Hydraulic Block Unlock Instrument Air Pressure International Bulk Containers Individual Channel Frequency Intervention Control System Injection Choke Valve Inside Diameter Inter Discipline Check Interface Data Sheet Internal Flush International Ice Patrol Intervention, Maintenance, and Repair Integrated Management Team Injection Master Valve Integrated Project Management System (a computer based control system used for engineering documents) Insulation Resistance Integrated Services Contract International Standards Organization Injection Swab Valve Intervention Tool Intervention Tool Module


Rev June 2006

IWOCS IWV J J Tube J-Bowl Tool J-Lay J-Mode Recovery JD JIP JPT Kbps kip kJ km kN KOS KPI ksi Kv LAMV LAN lbf-ft LBL LCP LCSG LCV LDHI LDP LER LF LFM LIMV LIT LMRP LNBR LNG

Installation Work Over Control System Injection Wing Valve Joule, a unit of work or energy equal to 10,000,000 ergs A tube on the side of the platform for the riser A tool for the J-bowl-a wearing bushing with a J-slot A method of laying pipe Using a J-tool to recover an item with a J-slot Jeanne d'Arc Contractors Alliance Joint Industry Project Journal of Petroleum Technology Kilo (1,000) bits per second 1,000 pounds kilo Joule Kilometers Kilo Newton Kongsberg Offshore KOS Provided Items 1,000 psi Flow Factor (flow rate (cubic meter/hr) of water at 20oC at a pressure drop of 1 bar) (see also Cv) (Kv = 0.853Cv) Lower Annulus Master Valve Local Area Network pound (force)-feet (ft-lbs is preferred) Long Base Line Local Control Panel API Casing Long Thread Level Control Valve Low Dosage Hydrate Inhibitor Liquid Dye Penetrant Local Equipment Room Low Frequency Limited Fine Mesh Lower Injection Master Valve Lead Impression Tool Lower Marine Riser Package Low Temperature Nitrile Buna Rubber Liquefied Natural Gas


Rev June 2006

LP LP LPAPH LPAPL LPMV LRP LRQA LRTJ LS LT LTL LTST LTSTV LTU LV LVDT LWI LWRP ManTIS M/T M2M mA MAO MAP max. MCC MCP MCS MCU MDS MEG MEOH MF Mhz MIL SPEC MIL-STD min ML

API Line Pipe Low Pressure Low Pressure Accumulator Pressure High Low Pressure Accumulator Pressure Low Lower Production Master Valve Lower Riser Package Lloyd's Register of Quality Assurance Lower Riser Tensioner Joint Landing String long ton-2,240 pounds Lower Tree Lock Lower Tree Seal Test Lower Tree Seal Test Valve Lower Tree Unlock Lubricator Valve Linear Variable Displacement Transmitter/Transducer Local Work Instructions Lower Workover Riser Package Manifold and Tie-In Systems Mechanical Technician Metal-to-Metal milliAmps Manual Annulus Outlet Gate Valve To manipulate and program a system using a controlling computer terminal Maximum Master Control Console Master Control Panel Master Control Station Master Control Unit Material Data Sheet Mobil Equatorial Guinea Methanol Medium Frequency Mega hertz Military Specification, USA Military Standard, USA Minimum Mudline


Rev June 2006

MLS MM MMI mm MM mmbbl MMCFPD MMS MMSCFD mN MOC MODU Mpa MPI MQC MQC (alternate meaning) MRB MRKB MRP MRP MSA mscf/d MSCFD MSDS MSL M-Spec MSRC MSS MSV MTBF MTTR MTU M/U MUX MVB MWP N-M NACE

Mudline Suspension System Manifold Module Man Machine Interface (use HMI) Millimeters Million, a thousand thousand, 10 6 a million barrels (a thousand thousand barrels) million cubic feet per day Minerals Management Service Million Standard Cubic Feet per Day milli Newton Management of Change Mobil Offshore Drilling Unit (Semi) Mega Pascal SI Unit for Pressure Magnetic Particle Inspection Mechanical Quick Connect Multi Quick Connect Material Review Board Mean Rotary Kelly Bushing Material Requirements Planning Movable ROV Panel Mine Safety Appliance thousand standard cubic feet per day Thousand Standard Cubic Feet per Day Material Safety Data Sheet Mean Sea Level FMC Material Specifications Marine Spill Response Corporation Manufacturers Standardization Society of the Valve and Fittings Industry Multi-service Support Vessel Mean Time Between Failures Mean Time To Repair Manifold Termination Unit Make-Up Multiplex-an electro-hydraulic control system Master Valve Block Maximum Working Pressure Newton Meter National Association of Corrosion Engineers


Rev June 2006

NAS NAS NB NB NBR NC NCR NCRI NDE NGL NM NOA or NOAA NOM NP NPD NPT NPTF NPTM NPV NTS OBS OC OCTG OD OEC OII OMM OMUS OOIP OPEX OS OSHA OTC OWC OWS P&I P & ID

National Aeronautics Society National Aerospace Standard Note Bene (Latin) Note Especially Nominal Bore Nitrile Butal Rubber (Buna N or NBR) Numbered Connection Non-Conformance Report Non-Conformance Rework Instruction Non-Destructive Examination Natural Gas Liquid Nautical Mile National Oceanographics and Atmospheric Agency Nominal Nominal Schedule Pipe Norwegian Petroleum Directorate National Pipe Thread National Pipe Thread Female National Pipe Thread Male Net Present Valve Norwegian Technology Standards Institution Ocean Bottom Suspension (mudline wellhead equipment - obsolete) (see SD-1) Operator Console Oil Country Tubular Goods Outside Diameter Other End Connector Oceaneering International Inc. Operations & Maintenance Manual Oceaneering Multiflex USA Oil Originally In Place Operations Expenses Operator Station Occupational Health and Safety Administration Offshore Technology Conference Oil/Water Contact Operator’s Work Station Piping and Instrumentation (Flow Schematics) Piping and Instrumentation Drawing


Rev June 2006

P-C PA PBOF PBT PCC PCM PCO PCS PCU PCV PCVD PCVI PD-PK PDQ PDU PE PE PEEK PETU PEP PFD PFL PFU PFV PGB PGV PH PIV PL PLC PLCM PLEM PLET PLF PLFS PLM PLM PLMS PLMV

Petro-Canada, a company Public Address and Alarm Pressure Balance Oil Filled Production Bore Test Production Choke Close Process Co-ordination Method Production Choke Open Production (Process or Platform) Control System Process (Production) Control Unit Production Choke Valve Production Choke Valve Decrease Production Choke Valve Increase Pig Detector Parking Production, Drilling & Quarters Power Distribution Unit SCM Pigging Loop Electrical Connection Professional Engineer Polyetheretherketone Portable Electrical Test Unit Project Execution Plan Process Flow Diagrams Production Flowline Connector Production Flow Unlock Production Foot Valve Permanent Guidebase Pigging Valve Pigging Loop Module Valve Production Isolation Valve Pig Valve and Detector Sensor Programmable Logic Controller Power Line Carrier Modem Pipeline End Module Pipeline End Termination Power Line Filters Power Line Filter Single Pigging Loop Module Power Line Modem Power Line Modem Single Production Lower Master Valve


Rev June 2006

PLP PM PMT PMT PMV POOH PORRT PP/PT ppb ppg ppm PPSD PQR PR PR1 PR2 PRE PSD PSDV PSHC PSHO psi psia psig PSL PSL P-Spec PSRST PSV PSV PT PT P/T PTCD PTD PTFE PTT P/U

Pig Loop Porch Pig Module Pipe Measurement Tool Pressure Test and Monitoring Tool Production Master Valve Pull out of hole Packoff Running and Retrieving Tool Production Pressure and Temperature Sensor Parts per billion Pounds per gallon Parts per million Partial Process Shutdown Procedure Qualification Record Performance Requirement Performance Requirement Level One Performance Requirement Level Two Pitting Resistance Equivalent Process (Production) Shut Down Production or Process Shut Down Valve LWRP Production Shear Closed LWRP Production Shear Open Pounds per square inch (always lowercase) Pounds per square inch absolute Pounds per square inch gauge Pressure (Product) Specification Level Production Shutdown Logic FMC Purchasing Specification Production System Review and Selection Task Production Swab Valve / Production Shear Valve Production and Storage Vessel Tree Cap Production Bore Test Pressure Transmitter Pressure/Temperature Positive Temperature Coefficient Thermistor Board Project To Date A Teflon™, poly tetra fluor ethylene Pressure & Temperature Transmitter Pick Up


Rev June 2006

PUMV PUP PV PV-PK PVB PVC PWHT PWV QA QC QC QCDC QD QM Q-Spec QTC QTP R&D R&R Tool R/D R/T R/U RAP RCA RCJ REG RET RF RFC RFD RFI RFQ RICAS RIH RIT RKB RLMS RMM ROT

Production Upper Master Valve Pipe Utility Piece, a short piece of pipe Pigging Valve Pigging Valve Parking Production Valve Block Poly Vinyl Chloride Post Weld Heat Treatment Production Wing Valve Quality Assurance Quality Control Quick Connect Quick Connect Disconnect Quick Disconnect Quality Matrix FMC Assembly or Quality Specification Qualification Test Coupons Qualification Test Procedure Research and Development Running and Retrieval Tool Rig Down Running Tool Rig Up Reliability Assurance Program Remote Cable Anchors Riser Cross-over Joint Regular Return Radio Frequency Revised for Construction Revised for Design Request for Issue Request for Quotation Replaceable Inboard Cap Assemblies Run In Hole Receiving Inspection Testing Rig Kelly Bushing Riser Load Monitor System Retrievable Manifold Module Remotely Operated Tool


Rev June 2006

ROV RP RPGB RPLM R/R Tool RT RV S&HO S-Lay SA SAE SAFOP SAG SAS Sb

SBMS SBR SBS SBS SCADA SCE SCE sdf/d SCF\BBL SCM SCMMB SCMTS SCP SCPC SCSSV SCU SCU SCU sd SD SD SD (alternate meaning) SD-1 SD1

Remotely Operated Vehicle Recommended Practice Retrievable Permanent Guidebase Retrievable Pigging Loop Module Running and Retrieving Tool Running Tool Retainer Valve Stab and Hinge Over Method of laying pipe Maximum Allowable Tensile Strength Society of Automotive Engineers Safety and Operability Successful Alliance Groups Safety Automation System Bending Stress Straight Bore Metal Seal Shawmount Brown and Root, a company Short Bore Selector Straight Bore Selector Supervisory Control and Data Acquisition Sanction Cost Estimates Subsea Communications Enclosure Standard cubic feet per day Standard Cubic Feet Per Barrel Subsea Control Module (i.e. POD) Subsea Control Module Mounting Base Subsea Control Module Test Stand Subsea Control Pod (use SCM) Subsea Communications Protocol Converter (or Computer) Surface Controlled Subsea Safety Valve Secondary Connector Unlock Subsea Control Unit Tree Cap Secondary Unlock Standard day Shutdown Sand Detector Stacked Down Stack Down (FMC mudline wellhead system) Acoustic Sand Detector


Rev June 2006

SDC SDV SE

SE1, SE2 SEM SEMI SETE SEPU SETU SF SFL SFT SI SIO SIOLT SIT SJ SL Tool SLC SLC Sm

SOI SOR SOS SP SPCU SPCTU SPE SR SRI SRIC SRT SS SSCS SSDS

Single Discipline Check Shut Down Valve Maximum allowable equivalent stress at the most highly stressed distance into the pressure vessel wall, computed by the distortion energy theory method Step Out umbilical Electric Power and Signal Subsea Electronic Module Semi-submersible Vessel Subsea Electronic Test Equipment Subsea Electrical Power and Communications Unit Subsea Electronic Test Unit Safety Factor Steel Flying Lead Surface Flow Tree International System Serial Input/Output Serial Input/Output Line Termination Systems Integration Test Slick Joint Spring Loaded Tool Single Line Coupler Slim Line Connector Membrane Stress/design stress intensity at rated working pressure Shell Offshore Inc., a company Statement of Requirements Scope of Supply Single Porch Subsea Power and Communications Unit Subsea Power and Communication Test Unit Society of Petroleum Engineers System Specific Requirements Subsea Retrievable Insert Subsea Retrievable Insert Choke Running Tool / Secondary Release Tool Subsea Subsea Sour Control Systems Safety Shutdown System


Rev June 2006

SSF Sshr

STRT SSM SSOI SSSV SSTT SSV St

ST ST ST ST ST Tool STL STT STT S uts SV SVCU SW SWHP SWL Sy Syld

T TA Cap TBA TC TCB TBD TGB T1, T2, T3 TC TC TCL TCL TCRT

Subsea Filter Allowable Stress in Shear Secondary Tree Release Tool Subsea Modem Safety System Operator Interface Subsurface Safety Valve Subsea Test Tree Surface Safety Valve Maximum allowable general primary membrane stress intensity at hydrostatic test pressure Seal Test Surface Test Tree Surface Tree Swivel/Turret/Mooring Single Trip Tool Submerged Turret Loading Subsea Test Tree Surface Test Tree Ultimate Tensile Strength Safety Valve Subsea Valve Control Unit Software Shut-in Wellhead Pressure Safe Working Load Material minimum specified yield strength Yield stress

Ton-2,000 pounds Temporary Abandonment Cap To be announced Tree Cap Tieback Connector To be determined API Tubing Well/Tree #1 Test Coupon Tree Cap Tree Cap Lock Tree Connector Lock Tree Cap Running and Retrieving Tool


Rev June 2006

TCSL TCSU TCT TCTV TCRT TCU TCUL TE TEG TEI TEMP TEO TF TFE TFL TGB TH TH TH TH THAS THCP THDSS THERT THHT THI THL THL THLV THMAX THO THOJ THRA THRT THS THST THTS THT THUL

Tree Cap Soft Landing Tree Connector Secondary Unlock Tree Cap Test / or Tree Connector Test Tree Connector Test Valve Tree Cap Running Tool Tool Control Unit Tree Cap Unlock Tree Electric Tri-Ethylene Glycol Tree Electric-Inner Tree Temperature Tree Electric-Outer Tree Topsides Facilities Teflon™, tetra fluor ethylene Through Flowline Tools Temporary Guide Base Tubing Hanger Tubing Head Tree Hydraulic X-mas Tree Hydraulic Tubing Hanger Adapter Sleeve Tubing Hanger Crown Plug Tubing Hanger Deck Storage Stand Tubing Hanger Emergency Recovery Tool Tubing Hanger Handling Tool Tree Hydraulic-Inner Tree Tool to Hanger Lock THRT to Tubing Hanger Lock THRT to Tubing Hanger to Lock Verification Period associated to HMAX-wave height Tree Hydraulic-Outer Tree Tubing Hanger Orientation Joint Tubing Hanger Running Assembly Tubing Hanger Running Tool Tubing Head Spool Tubing Head Seal Test Tubing Hanger Test Stand Tree Handling Tool Tool to Tubing Hanger Unlock


Rev June 2006

THWIS THWNP TIV TIW TLM TLP Tp TP TP TPE TQM TRAP TRSCSSV TRT TSJ TST TT TTC TTL TTL TTSL TTSU TTU TTU TUTA TVD Tz U/V UAMV UAP UCS UCU UGF UH UIMV

Tubing Hanger Wireline Isolation Sleeve Tubing Hanger Wireline Nipple Protector Test Isolation Valve Texas Iron Works (valve) Total Loss Management Tension Leg Platform Peak period associated with wave height (usually significant wave height) (see also Hs) Test Pressure Triple Porch Thermoplastic Elastomer Total Quality Management Technology Risk Assurance Process (also see DQV) Tubing Retrievable Surface Controlled Subsurface Safety Valve Tree Running Tool Tapered Stress Joint Tree Seal Test Temperature Transmitter Tubing Hanger Running Tool Top Test and Handling Cap TRT Connector Lock Tree Lock Tool Tree Tool Soft Landing Tree Tool Secondary Unlock Tree Tool Unlock Tree Tool Connector Unlock Topsides Umbilical Termination Assembly (also UTA) Total Vertical Depth Zero up crossing period-wave height Ultra Violet Upper Annulus Master Valve Utility Air Pressure UTIS Control System Utility Control Unit Universal Guide Frame Main E/H Umbilical UTH Hydraulic Upper Injection Master Valve


Rev June 2006

UK UKOLS UKOOA ULS UMC UNC UNF UPMV UPS UPTBG URT USD USD USV UT UTA UTAJ UTB UTH UTIS UTL UTP UTSL UTST UTSTV UTU UV Design

UWD V-SAT VAM ACE VBM VDU VHF VIS

United Kingdom Ugland Kongsberg Offshore Loading System United Kingdom Offshore Operators Association, London Ultimate Limit State Underwater Manifold Center Unified National Coarse (USA thread profile) Unified National Fine (USA thread profile) Upper Production Master Valve Uninterruptible Power Supply API Tubing External Upset Tubing Universal Running Tool Unit Shutdown United States Dollar Underwater Safety Valve Umbilical Termination Umbilical Termination Assembly Umbilical Termination Assembly Jumper Umbilical Termination Box Umbilical Termination Head Universal Tie In System Upper Tree Lock Umbilical Termination Panel Upper Tree Soft Landing Upper Tree Seal Test Upper Tree Seal Test Valve Upper Tree Unlock A staged pressure energized packing set comprised of a spring load U seal backed up by multiple V seal rings, interspaced nonextrusion rings Underwater Drilling (Wellhead System) Small aperture terminal-type of satellite communication system VAM is a company/ACE is a casing and tubing thread type Valve Body Module Visual Display Unit Very High Frequency Vendor Information Server


Rev June 2006

VIS VM VP VPI VSE VSS VX VXT VXT WBS WC WCT WCT-BOP WD WETU WH WHD WIIV WLA WO Riser WOC WOCS WP WPS WSCM WTU X-mas Tree X-Sect XOV XT XTC-L XTC-U Y1, Y2 Ya YH Ys YTD

Vendor Interface System Vertical Stabbed (Mounted Horizontally) Variable Position Variable Position Indicator for LVDT Valve Signature Enclosure Valve Signature Server ABB Vetco Gray proprietary metal seal and its derivatives VX Gasket Test Vertical Xmas Tree Work Breakdown Structure Well Construction/Reservoir Wireline Coiled Tubing Wireline Coil Tubing Blowout Preventor Working Draft Workover Electronic Test Unit Wellhead System Wellhead Water Injection Isolation Valve Wireline Adapter Assembly Work Over Riser Wait on Cement Work Over Control System Working Pressure Welding Procedure Specification Workover Subsea Control Module Well Termination Unit X-mas Tree, set of control valves for well Cross Section Crossover Valve X-mas Tree X-mas Tree Connector Lock X-mas Tree Connector Unlock Daisy Chain HOST Electric Power and Signal Actual average yield strength from test specimens Daisy Chain HOST Hydraulic Specified minimum Yield strength Year to Date


Rev June 2006


Rev June 2006

Subsea 101 Rev3

Recommend Documents