ept 10-t-04 subsea production systems

© Mobil Oil,1998 1 of 95

Subsea Production Systems EPT 10-T-04

September 1992 Draft

EPT 10-T-04 Subsea Production Systems September 1992 Draft


Table of Contents

1. Scope.........................................................................................................................................13

2. References ...............................................................................................................................15

2.1. MEPS–Mobil Engineering Practices ..........................................................................16

2.2. Mobil Tutorials ................................................................................................................16

2.3. API–American Petroleum Institute ...............................................................................16

3. Instructions for Use................................................................................................................16

3.1. .........................................................................................................................................16

3.2. .........................................................................................................................................17

3.3. .........................................................................................................................................17

3.4. .........................................................................................................................................17

3.5. .........................................................................................................................................18

3.6. .........................................................................................................................................18

3.7. .........................................................................................................................................18

4. Design Basis and Functional Requirements...................................................................19

4.1. .........................................................................................................................................19

4.2. Design Basis..................................................................................................................19

4.3. General ...........................................................................................................................20

4.4. Reservoir Characteristics .............................................................................................20

4.5. Fluid Properties .............................................................................................................21

4.6. Reservoir Management/Production Profiles...............................................................22

4.7. Drilling System...............................................................................................................23

4.8. Location Parameters.....................................................................................................23



4.9. Government Regulations and Industry Standards ......................................................24

5. Subsea Well System Configuration ...................................................................................28

5.1. .........................................................................................................................................28

5.2. .........................................................................................................................................28

5.3. .........................................................................................................................................28

5.4. Reservoir Pressure Maintenance/Downhole Artificial Lift/Seafloor Pumping.........31

5.5. Pressure Maintenance..................................................................................................32

5.6. Artificial Lift.....................................................................................................................33

5.7. Seafloor Pumping..........................................................................................................34

5.8. Well Location..................................................................................................................36

5.9. Manifold Location..........................................................................................................37

5.10. Subsea Choke Location ...............................................................................................39

5.11. Chemical Injection..........................................................................................................39

5.12. Flow Schematic .............................................................................................................40

5.13. Tree Valving ...................................................................................................................41

5.14. Pigging............................................................................................................................43

5.15. Manifolds ........................................................................................................................44

5.16. Flowlines.........................................................................................................................45

5.17. Flow/Service Line Redundancy....................................................................................46

5.18. Valves .............................................................................................................................47

5.19. Results ............................................................................................................................48

6. Maintenance Concepts .........................................................................................................48

6.1. Wellbore..........................................................................................................................48

6.2. Subsea Equipment ........................................................................................................55

Appendix A–Nomenclature..........................................................................................................61



1. Diverless System....................................................................................................................61

2. Diver Assist System...............................................................................................................61

3. ROV Assist System................................................................................................................61

4. Subsea Well Template ...........................................................................................................61

5. Riser Base Manifold (RBM) ..................................................................................................62

6. Pipeline End Manifold (PLEM) .............................................................................................62

7. Production Riser.....................................................................................................................62

8. Floating Production Facility (FPF)......................................................................................62

9. Production Control System (PCS) .....................................................................................62

10. Installation/Workover Control System (IWCS) ................................................................63

11. Satellite Subsea Tree .............................................................................................................63

12. Mudline Suspension System...............................................................................................63

13. Subsea Wellhead System.....................................................................................................63

14. Underwater Safety Valve (USV)..........................................................................................64

15. Protective Structure ...............................................................................................................64

Appendix B–Design Basis ...........................................................................................................65

1. General ......................................................................................................................................65

1.1. .........................................................................................................................................65

1.2. .........................................................................................................................................65

1.3. .........................................................................................................................................65

1.4. .........................................................................................................................................65

1.5. .........................................................................................................................................65

1.6. .........................................................................................................................................66

2. Reservoir Characteristics.....................................................................................................67



2.1. Recoverable Reserves..................................................................................................67

2.2. Field Producing Life ......................................................................................................67

2.3. Geology...........................................................................................................................67

2.4. Degree of Consolidation...............................................................................................67

2.5. Depth Subsea Level......................................................................................................67

2.6. Productivity (PI) or Injectivity (II) Index (bbls or mcf/psi Drawdown)..........................67

2.7. Porosity...........................................................................................................................67

2.8. Areal Extent ....................................................................................................................67

2.9. Fluid Contacts ................................................................................................................67

2.10. Pressure .........................................................................................................................68

2.11. Temperature - Bottomhole ............................................................................................68

2.12. Drive Mechanism (Gas, Water)....................................................................................68

2.13. Drainage Area per Well ................................................................................................68

3. Fluid Properties .......................................................................................................................68

3.1. Type Fluid .......................................................................................................................68

3.2. Gas Oil Ratio (GOR), cf/bbl, or Condensate Ratio (bbl/mmcf).................................68

3.3. Fluid Gravity (API)..........................................................................................................68

3.4. Fluid Viscosity ................................................................................................................69

3.5. Bubble Point...................................................................................................................69

3.6. Wax Content of Liquid...................................................................................................69

3.7. Cloud Point.....................................................................................................................69

3.8. Pour Point.......................................................................................................................69

3.9. Gas Composition...........................................................................................................69

4. Reservoir Management/Production Profiles ...................................................................70

4.1. Well Pattern (by Zones) .................................................................................................70



4.2. Number of Wells and Types of Well (Oil, Gas, Water Injection or Gas Injection) ....70

4.3. Completion Sequence for Wells ..................................................................................70

4.4. Dual or Single Completion Requirements ..................................................................70

4.5. Recompletion Schedule ................................................................................................70

4.6. Production Profile for "Typical" or Individual Well(s) - Life of Well ...........................70

4.7. Design Flow Rates (Total Field)..................................................................................71

4.8. Pressure Maintenance and/or Gas Lift Start Date .....................................................71

4.9. Inlet Pressure of 1st Stage Separator.........................................................................71

4.10. Maximum Drawdown Allowable (psi)..........................................................................71

4.11. Gas Deliverability...........................................................................................................71

5. Drilling System........................................................................................................................71

5.1. Floating Rig ....................................................................................................................71

5.2. Jack-Up Rig General Arrangement .............................................................................72

6. Location Parameters..............................................................................................................72

6.1. Geographic Area (Map of Surrounding Area)............................................................72

6.2. Method of Transport/Disposal......................................................................................73

6.3. Water Depths (Prefer Contour Map of Area)..............................................................73

6.4. Seafloor Temperature ...................................................................................................73

6.5. Weather Criteria (Waves, Wind, Current Profiles and Direction) Occurrence........73

6.6. Ocean Current ................................................................................................................73

6.7. Bottom Conditions.........................................................................................................73

6.8. Near Bottom Activity (Fishing, Dredging, Shipping, etc.)..........................................74

6.9. Sales Requirements ......................................................................................................74

7. Government Regulations......................................................................................................75

7.1. Design Codes and Certification (API, DNV, NPD, NACE) ......................................75



7.2. Well Control (Drilling, Temporary Abandonment, etc.) ..............................................75

7.3. Safety Requirements .....................................................................................................75

7.4. Discharge .......................................................................................................................75

7.5. Subsurface Safety Valve...............................................................................................75

7.6. Protection of Seafloor Equipment................................................................................75

7.7. Structural Design Requirements ..................................................................................75

7.8. Operating Procedures...................................................................................................76

7.9. Inspection, Maintenance, Repair Requirements (Testing and Frequency) .............76

7.10. Drilling, Completion, Workover ....................................................................................76

7.11. Permitting .......................................................................................................................76

7.12. Abandonment Requirements........................................................................................76

8. Companies Guidelines..........................................................................................................77

8.1. Applicable Company Standards..................................................................................77

8.2. Safety Requirements .....................................................................................................77

8.3. Pollution Control.............................................................................................................77

8.4. Drilling/Completion-Well Control (Size, Pressure Rating, Use Procedures of BOP's; Cuttings Management; Casing Size, Pressure Rating, Setting Depths, Number of Strings, etc.) ................................................................................................77

8.5. Directional Drilling Rules...............................................................................................77

8.6. Number of Barriers to Pressure ...................................................................................77

8.7. Design Pressure/Codes or Standards........................................................................78

8.8. Simultaneous Drilling/Completion/Well Servicing and Production Rules ................78

8.9. Tree Valving (Number of Master Valves, etc.)............................................................78

8.10. Subsurface Safety Valves - Production String Only, or Annulus and Production Strings?...........................................................................................................................78

8.11. Protection (Structural or Burial/Gloryhole)...................................................................78



8.12. Controls Response Time ..............................................................................................78

8.13. Safety Shut-Down Procedures.....................................................................................78

8.14. Instrumentation Wellhead and Bottom Hole Pressures and Temperatures ............78

8.15. Inspection and Maintenance Procedures and Frequency.........................................78

8.16. Quality Assurance/Quality Control Requirements ......................................................78

8.17. Spares Philosophy ........................................................................................................78

Appendix C–Government Regulations and Industry Standards (Applying Specifically to Seafloor Completed Wells)......................................................................................................79

Appendix D–Functional Requirements ....................................................................................80

1. General ......................................................................................................................................81

1.1. Life of Production/Injection Equipment (May or May not Equal Field Life)..............81

1.2. Availability Goals - System Meantimes between Production Loss and Meantimes between Repair..............................................................................................................81

1.3. Quality Assurance/Quality Control Philosophy............................................................81

1.4. Design Wellhead Pressure - Flowing Wellhead Temperature .................................81

1.5. Damage Protection Criteria.........................................................................................81

1.6. Spares Philosophy ........................................................................................................81

1.7. Maintainability Criteria; Components Interchangeability - What Components are Replaceable ...................................................................................................................82

1.8. Materials Selection - All Components of Each Subsystem Shall be Compatible with Every Fluid it Will Come in Contact with During Testing, Installation, and Operation.........................................................................................................................................82

2. Drilling/Workover ....................................................................................................................82

2.1. Drilling Program.............................................................................................................82

2.2. Casing Program (Size, Grade, Weight, Connection Type, Setting Depths)...........83

2.3. Wellhead (Depends on Drilling and Surface Process Vessel Type) .......................83

2.4. Drilling Rig ......................................................................................................................84



2.5. Completion/Workover System .....................................................................................85

3. Installation of Subsea Equipment ......................................................................................85

3.1. Site Survey Requirements ............................................................................................85

3.2. Diver Assist, Diverless (ROV assist)...........................................................................85

3.3. Weather Limits ...............................................................................................................85

3.4. Subsea Template or Manifold Azimuth Orientation and Leveling ............................86

3.5. Transportation Weight or Size Limitations - Fabrication Site to Integration Site to Offshore Site ..................................................................................................................86

3.6. Ability to Test Flowlines After Laying but Before Connection...................................86

3.7. Ability to Test Flowline Connections............................................................................86

3.8. Ability to Production Test Each Producing Well to the Drilling Rig Immediately After the Downhole Completion Equipment is Installed......................................................86

3.9. Well to be Left "Live" or "Dead" When Rig Moves? (Specify Procedure for Chosen Condition) .......................................................................................................................86

3.10. Ability to Test Control Umbilicals - Before and After Connection.............................86

3.11. Flowline and Umbilical Burial Requirements ..............................................................86

4. Production Operations..........................................................................................................86

4.1. Simultaneous Well Drilling Completion or Workover and Production Rules...........86

4.2. Well Unloading and Cleanup........................................................................................88

4.3. Well Killing Procedure ...................................................................................................88

4.4. Start-Up Procedure .......................................................................................................88

4.5. Well Testing Procedure.................................................................................................88

4.6. Pressure Control............................................................................................................88

4.7. Production Control.........................................................................................................89

4.8. Production Monitoring ...................................................................................................89

4.9. Shut Down Procedures.................................................................................................90



4.10. Failure Response ..........................................................................................................90

4.11. Corrosion Control..........................................................................................................90

4.12. Paraffin Control..............................................................................................................91

4.13. Scale ...............................................................................................................................91

4.14. Viscosity Control............................................................................................................91

4.15. Hydrate Control..............................................................................................................91

4.16. Flowline Operation.........................................................................................................91

4.17. Chemical Injection Supply (On Surface)......................................................................91

4.18. Surface Facility Minimum inlet Pressure .....................................................................92

4.19. Interface with Surface Process Facility Controls ........................................................92

5. Inspection and Maintenance................................................................................................92

5.1. Downhole ........................................................................................................................92

5.2. Seafloor Equipment.......................................................................................................92

5.3. ROV Requirements .......................................................................................................93

5.4. Precautions Prior to Performing Maintenance ...........................................................93

5.5. .........................................................................................................................................93

5.6. .........................................................................................................................................93

5.7. TFL System Requirements ...........................................................................................94

5.8. Major Subsea Component Repair...............................................................................94

6. Abandonment Requirements ..............................................................................................94

6.1. Well Plugging Requirements ........................................................................................94

6.2. Government Approvals and Permits Required...........................................................94

6.3. Requirements for Removal of Equipment and Structures and Clearance of Seafloor.........................................................................................................................................94

6.4. Abandonment Survey Requirements...........................................................................94



6.5. Requirements for Transport and/or Disposal of Salvaged Hardware......................95



Table of Figures

Figure 1: System Design–Total Production System............................................................14

Figure 2: System Design–Total Production System............................................................15

Figure 3: Pressure Maintenance, Artificial Lift, Seafloor Pumping...................................29

Figure 4: Subsea Well System Configuration........................................................................30

Figure 5: Subsea Well System Configuration........................................................................31

Figure 6: Tree Installation/Workover Riser.............................................................................49

Figure 7: Minor Well Servicing...................................................................................................50

Figure 8: Maintenance–Subsea Equipment...........................................................................56



1. Scope

The purpose of the Subsea Production Systems tutorial is to provide the Mobil engineer(s) with a means to specify or select an overall subsea production system design or configuration. This tutorial shall enable the Mobil engineer(s) with a basic knowledge of subsea technology to arrive at the system design or configuration of a reasonable (but possibly not optimum) concept for an entire subsea production system in a relatively short period of time after minimal information has been obtained about a subject reservoir. The contents of this tutorial were taken primarily from Seafloor Well Production Systems - System Design Manual by Seaflo Systems Inc., August 1991.

The three major parts of any subsea production system can be visualized as the Well System, the Surface Production Facility, and the Export System. Major decisions within each part of the system are indicated in Figure 1. This document addresses only the Subsea Well System and associated subsystems. Surface Completed Wells, Surface Production Facility and the Export System are not addressed herein.



Figure 1: System Design–Total Production System



Figure 2: System Design–Total Production System

Section 3 - Instructions for Use is followed by sections that address Design Basis and Functional Requirements, Subsea Well System Configuration and Maintenance Concepts. Example Design Basis and Functional Requirements for the total production system are presented as generic tables which serve as a starting point for the users in defining the needs of a specific subsea system. Each section includes a flow chart of decisions required showing all interactions and written text explaining the decisions. The user can move through the sections in the order presented, reconsider decisions made in previous sections, and then progress to select the best subsea well production system. Alternately, the user can use this tutorial as a "reference" and use the index to go directly to the specific subsystem and decision that is of immediate interest.

This tutorial addresses the overall aspects of subsea systems. As such, this tutorial shall be considered a preface to all other Mobil E&P Engineering Guide Tutorials that address specific subsystems within the total subsea production system.

2. References

The following Mobil guides and industry publications shall be considered a part of this EPT. Refer to the latest editions unless otherwise specified herein.



2.1. MEPS–Mobil Engineering Practices

MP 65-P-01 Subsea Trees - Diver & ROV Assisted

MP 65-P-03 Subsea Control Systems & Umbilicals

MP 65-P-04 Subsea Templates & Manifolds

MP 65-P-05 Subsea Pipeline & Flowline Connection Systems

2.2. Mobil Tutorials

EPT 10-T-01 Subsea Trees

EPT 10-T-02 Subsea Production Controls

EPT 10-T-03 Subsea Templates and Manifolds

EPT 10-T-05 Offshore Tanker Loading Systems

EPT 10-T-06 Submarine Pipeline and Flowline Connection Systems

EPT 10-T-07 Submarine Pipelines

EPT 10-T-08 Engineering Checklist for the Design, Manufacture and Construction of Submarine Pipelines

EPT 10-T-09 Submarine Flowline

2.3. API–American Petroleum Institute

API RP 17A Recommended Practice for Design and Operation of Subsea Production Systems Second Edition

3. Instructions for Use

3.1.

This tutorial is designed to lead the Mobil engineer(s) through the decisions required for system design and configuration of a subsea well production system. It is applicable to all types of systems including: satellite, template or cluster drilled wells for oil production, gas production or water/gas injection; mudline and non-mudline completions; and system designed for diver assist, diverless, guideline installation, and maintenance connected to any type of surface facility either overhead or remote.



3.2.

The tutorial can be used as a reference by the experienced Mobil engineer(s). The specific subsystem and decision of interest can be located directly from the table of contents. Further, the tutorial can be used by less experienced Mobil experienced engineer(s) with a basic working knowledge of subsea technology as a road map to a reasonable system design or configuration of the best candidate subsea production system. The tutorial considers all types of systems and all decisions, but is arranged to allow the user to bypass decisions which are obvious or which do not apply for the specific field of immediate interest.

3.3.

System design requires consideration of all available information in order to decide on the best production system for developing the field. This information shall be reviewed and incorporated into the Design Basis, Functional Requirements, and ultimately, the system selection. Information to be considered includes:

1. known facts about the reservoir and other reservoirs in the area

2. known facts about the geographic area (water and atmospheric environment, etc.)

3. reservoir management plan

4. corporate management philosophy

5. government regulations (present and pending)

6. other developments in the area - other reservoirs and the local infrastructure

7. available proven technology

8. acceptable risk at the time and place

This information shall be reviewed and incorporated into the Design Basis, Functional Requirements, and ultimately, the system selection.

3.4.

The Design Basis and Functional Requirements are general and apply both to the total production system and to all subsystems and components. Example tables of a Design Basis and Functional Requirements indicating the type of information required are provided in Appendix B. It is important to gather at least preliminary information to complete these tables before starting system design. For each equipment subsystem, a separate tutorial shall be referenced.



3.5.

System design of each subsystem shall start with preparation of Subsystem Specific Functional Requirements incorporating the applicable considerations from the total system Design Basis and Functional Requirements and the other factors specific to that subsystem. The most efficient approach to system design or configuration is outlined in the following steps:

1. Preparation of the Design Basis and Functional Requirements for the total system (Section 4).

2. The Subsea Well System Configuration (Section 5).

3. Maintenance concepts (Section 6).

4. The equipment subsystem tutorials as listed below:

a) EPT 10-T-01 Subsea Trees - Diver and ROV Assist

b) EPT 10-T-02 Production Control Systems

c) EPT 10-T-03 Subsea Template and Manifolds

d) EPT 10-T-06 Pipeline & Flowline Pull-In and Connection Systems

e) EPT 10-T-07 Submarine Pipeline Design

f) EPT 10-T-08 Submarine Pipeline Engineering Checklist

g) EPT 10-T-09 Subsea Flowlines

5. Reconsider Design Basis and Functional Requirements.

6. Finalize System Design or Configuration.

3.6.

After a "first pass" through each applicable subsystem, it shall be necessary to review decisions that affect more than one subsystem. It is likely that the total system Functional Requirements may have to change and that the project team or task force may wish to appeal or at least consult management on requirements imposed by the Design Basis which are increasing complexity, cost or schedule of the project. After this interaction, a second pass through each subsystem may be necessary. A second discussion of interfaces and a third pass at system design may also be required.

3.7.

The Mobil engineer(s) may wish to review API RP 17A, "Recommended Practice for Design and Operation of Subsea Production Systems" in conjunction with this subsea



production systems tutorial. This API document provides general industry guidelines for the design, installation, operation, repair, and abandonment of subsea production systems. It includes information on a wide range of equipment and operations to emphasize interrelationships and the need to consider subsea production systems from a "Total Systems" point of view.

4. Design Basis and Functional Requirements

4.1.

The DESIGN BASIS specifies all factors that shall control or affect the design or configuration of a subsea production system. FUNCTIONAL REQUIREMENTS are the requirements specified for the subsea production system to meet the Design Basis. There shall be a Functional Requirements document for the total subsea production system as shall be addressed in this section of the tutorial.

4.2. Design Basis

4.2.1.

The following information shall be addressed:

1. General Topics

2. Reservoir Characteristics

3. Fluid Properties

4. Reservoir Management/Production Profiles

5. Drilling System

6. Location Parameters

7. Government Regulations and Industry Standards

8. Company Policy

4.2.2.

In preparation of the "Design Basis" for the subsea production system equipment, it is assumed that reservoir engineering has been completed based on the best available information; requirements based on definition of the reservoir and the planned reservoir management plan are assumed to be as



firm as possible prior to start of development, and are therefore included, where appropriate, in the Design Basis.

4.2.3.

For any subsea production system design or configuration, there will be "gray" areas in the "Design Basis." During the evolution of the system design or configuration, any Design Basis item that is seriously affecting design of the subsea production system shall be examined for (1) certainty of the requirement and (2) possibility for change. For example, early specification of physical parameters such as expected sand or water production, or reservoir drive mechanisms are often an estimate at best. When they control the system design or seriously impact project economics, they shall be reviewed. If the requirement is not well founded, it could be considered as a "contingency factor" rather than as a primary Design Basis requirement. If a company policy or government regulation is causing a serious design impact, the basis for requesting a waiver or even a change shall be evaluated; at the least, the consequences of the requirement shall be noted and the proper levels of management advised accordingly.

4.2.4.

A listing of typical Design Basis items is presented in Appendix B. This example table is presented in a numbered paragraph format for ease of incorporation into other documents. The significance of some of these items shall be discussed in the following.

4.3. General

Overview guidelines which give direction to subsea production system design or configuration are presented in Section 1 of Appendix B.

4.4. Reservoir Characteristics

4.4.1.

Recoverable reserves and field life determine the relative importance of cost, reliability and maintainability. Productivity or injectivity index will indicate whether fracture or chemical treatment stimulation shall be required. Productivity index also allows estimating the pressure differential across the formation near the wellbore that will occur during production. Geology (rock type and age or degree of consolidation) can be used with pressure drop into the well to estimate the maximum flowrate which can be produced without damaging the completion, and to determine whether the completions shall be gravel packed.



4.4.2.

The areal extent and depth of the reservoir will be an indication as to whether the wells can be drilled from one location or shall be drilled from multiple locations using one or more rigs, and will give an indication of drilling times. Reservoir and drilling depth will determine requirements for the workover subsystem. Thickness of the producing interval, fluid contacts and reservoir drive mechanism will indicate the vertical precision with which the wells must be perforated or gravel packed, and whether it is likely that the wells will have to be recompleted during field life. If information is available from more than one well or from multiple zones and different fault blocks, the commonality of gas/oil or water/oil contacts shall indicate whether pressure barriers exist between zones or across fault blocks. This is an indication of whether these individual fault blocks or zones must be treated as separate reservoirs, therefore produced from a separate completion.

4.4.3.

Initial reservoir pressure determines the pressure rating of the completion and production equipment. Drive mechanism will determine whether reservoir pressure declines during the life of the field and whether increased gas/oil ratio or water cuts can be expected. This will indicate the rate at which a gas field shall be produced and whether oil wells can be flowed without artificial lift throughout their life. Reservoir temperature affects the production equipment material selection criteria and provides an indication of whether paraffin formation might occur and where, and whether hydrate formation will occur and where.

4.5. Fluid Properties

4.5.1.

The type of fluid, oil or gas, will determine the requirements for the topside facilities and probably the completion design. The gas/oil ratio or the condensate ratio, fluid gravity, and fluid viscosity will be used in sizing the tubing and flowlines or risers and determining whether slug catchers will be required. These properties will also be used in determining whether artificial lift is required and, if so, in selecting the best concept. Wax content and cloud point of the liquid coupled with the reservoir temperature indicates the potential for wax formation and the probable location (downhole, flowlines or risers).

4.5.2.

The pour point, which may or may not be associated with wax content, indicates whether the liquid will solidify at a temperature which might occur



either during production or during shut-in. Gas composition likewise indicates the amount of liquid which will occur during normal production, and the corrosiveness of produced fluids.

4.6. Reservoir Management/Production Profiles

4.6.1.

The number and type of wells and the well pattern needed for each zone or fault block will indicate the size of the subsea production system or the size and number of platforms or floating production facilities. The recoverable reserves and production profiles of the wells for optimum recovery will be an indication of the field life, the economic optimum drilling schedule and the design capacity of the production system, and the importance of well servicing and well workover.

4.6.2.

The completion sequence for wells will allow planning of the drilling operation, will define the required precision of directional drilling, and will allow more accurate projection of the field production profile if adjacent wells must be shut-in during drilling of each well to the kick-off depth or to total depth. Requirements for dual completions will affect the drilling program and schedule, and obviously the downhole completion design.

4.6.3.

Recompletion schedule will allow more accurate estimates of operating cost and production profiles. If a majority of wells must be recompleted during the field life, this will affect selection and specification of the surface facility, and may determine whether all wells are connected to all headers in manifolded systems.

4.6.4.

Individual well producing flow rates and pressures, and fluid properties determine the size of tubing and flowlines that are required. The design field rate and first stage separator pressure normally determines the size of risers, process facilities and export pipelines or risers. The "Flowrate" and availability guaranteed in a gas sale contract ("deliverablity") will affect the capacity and reliability requirements for a gas production system.



4.7. Drilling System

4.7.1.

Selection of the drilling rig may or may not be made at the initial stages of subsea production system design or configuration. If a specific drilling or class of drilling rig is known, then the rig specification shall become part of the Design Basis. The drilling rig selected will affect the subsea wellhead or suspension system, the drilling and completion procedure, and in a multiwell system with wells drilled in one location, the well spacing. The rig may also determine the installation procedure if a multiwell template is used.

4.7.2.

The subsea wellhead or suspension system shall be compatible with the subsea BOP stack of the floating drilling rig subsea wellhead system, or the drilling riser system of a jack-up type drilling rig (mudline suspension system). If an existing well is to be completed, either the wellhead shall be compatible with the drilling rig BOP stack or riser, or an adaptor shall be installed to make it compatible. When multiple wells are drilled at one location, BOP stack or riser package size, and guidance method (guideline or guidelineless), available deck space, and crane arrangement will affect completion procedures. Vessel hull shape, semisubmersible pontoon spacing and jack-up rig size, deck-arrangement, crane capacity and reach, and environmental limits will determine whether a multiwell template can be installed from the rig.

4.7.3.

If the development plan utilizes different drilling rigs for drilling and completion, the drilling systems shall be compatible. It is not uncommon for wells to be drilled from a floating or jack-up drilling rig, and to be completed on a platform, TLP or floating production facility.

4.8. Location Parameters

4.8.1.

The location of the nearest pipeline could impact the choice of the surface facility as well as the method with which the oil or gas will be transported. Existence of pipelines in the area may also influence the station keeping of rigs and construction vessels, and the route and installation method of any new flowlines. The location of the nearest platform processing fluids and the character of the expected produced fluids can also determine the need for a surface production facility in the field to be developed, or whether or not the



production system for the new field could support only first-stage separation and be tied back to final separation and export facilities on an existing platform. It is also important to know whether the Company operates other facilities in the area. This will impact the surface facilities and the infrastructure that must be built and thereby the project economics. Producing to a joint interest facility will usually involve tariffs for use of such a facility.

4.8.2.

When pipelines are not available, and there is no onshore market for production, location parameters shall identity the nearest market ports and the distance from the field. Method of transport of liquid or gas for sale and gas or water for disposal, and also the distance to the point of sale or disposal are important in determining number and size of pipelines, tankers, and barges.

4.8.3.

Water depths, seafloor temperatures, design weather criteria, bottom conditions (whether they are soft, hard, whether the visibility is sufficient to allow use of ROV's, whether the contour is steep enough that the equipment set on bottom will have to be leveled, etc.) affect the installation procedures and selection of surface vessels, and the subsea equipment maintenance concepts. Presence of rock outcrops or boulders can affect drilling, and the procedures for installation of flowlines and seafloor equipment. The distance from the reservoir site to shallow water where other facilities might be installed at lower cost may control the overall production system layout.

4.8.4.

Bottom fishing activity or other non-oil production related bottom activity determines the need for protective structures and also helps establish the design criteria for those structures. The sales requirements, which are common in a given geographical area, will determine the requirement for stabilization of oil and also separation and dehydration required for gas for transport.

4.9. Government Regulations and Industry Standards

4.9.1. Status of Existing Regulations and Standards

1. There are no Government Regulations which are specific to subsea wells or subsea production systems. However, more general regulations which apply to offshore mining or oil and gas development are usually applied whenever applicable. Draft regulations for Norway from the Norwegian Petroleum Directorate have been under development since at least 1982,



but they are not final or adopted as of July 1991. There are also draft regulations for subsea wells for the UK North Sea which have been under development since the early 1980s. The status of those draft regulations is unknown as of July 1991. The safest course is to inquire of applicable regulations when a subsea well system or subsea production system is contemplated. A partial list is included in Appendix C.

2. The API Committee 17 - Committee on Standardization of Subsea Production Systems has issued several Recommended Practices (RP) and Standards on various subsystems of subsea production systems. The applicable API standards and recommended practices have been referenced in the reference section of the various Mobil E & P Engineering Guides pertaining to subsea production systems.

4.9.2. General Regulations

General regulations, which vary widely between different areas, shall specify which codes and standards are to be met during design and whether the equipment shall be certified. An increasingly common requirement is materials "traceability." Regulations may also dictate equipment and procedures used for well control. These may determine the procedures which are required during drilling and also the procedures required for temporary abandonment of a well and for permanent abandonment of the field.

4.9.3. Discharge Requirements

Discharge requirements shall dictate whether or not drilling mud can be discharged at the seafloor, and when returns are taken to the drilling rig, and whether they can be dumped overboard. Regulations may also determine the amount of treating required for dumping anything overboard. Government regulations frequently specify the maximum oil content of water which is discharged overboard. They shall also de termine whether controls hydraulic fluid can be dumped overboard or discharged to the ocean. This includes both water and oil based fluids. In certain locations, gas flaring is completely disallowed, and other areas it is allowed. In almost every area, flaring will be allowed under certain extenuating circumstances, such as emergencies or during well testing.

4.9.4. Subsurface Safety Valves

Subsurface safety valves are required in most locations. In several locations, subsurface safety valves must now be certified, which means materials traceability, design certification, and qualification testing. Some governments are also imposing testing procedures and test frequency for subsurface safety valves during producing operations.



4.9.5. Burial of Flowlines

Burial of flowlines may or may not be required - existing rules and proposed rules vary widely. In some areas, no burial is required. In other areas burial is required for small lines. In other areas, burial is required for almost every flowline or pipeline.

4.9.6. Structural Design Criteria

Structural design criteria for subsea equipment, are set by regulations in certain countries. The size and weight of dropped objects, and the snag loads which the structure must withstand or absorb without serious damage are specified. In some areas, the structure must be able to deflect a fishing trawl net without damaging the net. In other areas, seafloor equipment must be below a certain water depth (shipping or defense lanes) or a certain distance below the mudline (iceberg scour).

4.9.7. Operating Procedures

Operating procedures specified by certain regulatory and certification agencies are onerous on operating personnel. For example, in many locations it is necessary to inspect equipment and to test all valves including subsurface safety valves on a fairly frequent interval. In other locations, proposed regulations require special detectors to determine when failures have occurred. Reporting of equipment tests or inspection results and failures is required in certain areas. Shut-down procedures and the amount of supervision and instrumentation that is required is also specified in some areas. For example, the requirements for monitoring annulus wellhead pressure and bottomhole pressures while producing have been proposed.

4.9.8. Permitting Procedures

Permitting procedures are important in a Design Basis because they may indeed control the development schedule. One example is offshore California where permitting can take several years and adds considerable uncertainty to the economics of a project.

4.9.9. Abandonment Requirements

Abandonment requirements are important, especially for short-lived fields. Wells shall be secured as required. Equipment shall be designed to be abandoned at minimum costs. Disposal of removed equipment shall also be planned.



4.9.10. Company Policies

1. Most companies have environmental safety requirements. These deal mainly with surface activities and equipment and operating procedures. For example, companies are becoming increasingly aware of their environment and have strong policies governing dumping of any material into the sea. They have adopted strong policies regarding how their operations protect the environment and comply with local laws.

2. There are also general Company policies covering a wide range of the operations of any field. Drilling and completion requirements may dictate the well control procedures. For example, the size and pressure rating of BOP stacks relative to reservoir pressure may be specified. The procedures for use of BOPs may also be specified, for example - are BOPs used on the 20 in casing or are they only connected to the 13 5/8 in casing? Is one stack or a "two stack" system used. Cuttings management is increasingly important. Certain areas will not allow cuttings to be dumped overboard, and if they are, they shall be treated. The severe penalties for environmental damage have focused management attention into this area. Management may also set policies on casing size, pressure ratings, setting depths, and the number of strings in each well. The number of barriers to pressure, whether simultaneous drilling and completion or well servicing and production is allowed, and the number of master valves that shall be included on any subsea tree may also be dictated. Some companies have also set polic ies on the number of subsurface safety valves required and indicated whether one is required only in the production tubing, in each string of tubing or on both the production and annulus strings

3. Certain companies have established the requirement for protection of wells on the seafloor, either structural bumpers and/or by burying in gloryholes. Some companies have control response time requirements. For example, it may be necessary to implement an ESD, (emergency shut-down), in less than one minute or in less than 20 seconds, etc. Company policy frequently dictates safety shut-down procedures. These procedures may require that equipment failure or production problems are classified to a response level defined in a safety shut-down procedure. Instrumentation to monitor operations is also specified by certain companies. This can include the requirement for production or annulus wellhead pressure and bottomhole pressures.

4.9.11. Functional Requirements

An example of the Functional Requirements which shall be determined by the Mobil engineer(s) is illustrated by the example presented in Appendix D.



5. Subsea Well System Configuration

5.1.

This section addresses the overall arrangement and flow pattern of the subsea well system. Because of the effect on feasibility and risks of certain well arrangements, the need and alternatives for reservoir pressure maintenance, wellbore artificial lift or seafloor pumping is discussed first. Location of wells, manifolds and chokes for the total subsea production system are then considered. The result of this thought process is a flow schematic for the total subsea production system.

5.2.

The Section 4.0 - Design Basis and Appendix B, shall establish the size, shape and depth of the reservoir and the number of wells and their drilling schedule. It shall specify if and when pressure maintenance or artificial lift are required. The Functional Requirements part of Section 4.0 - Design Basis and Appendix D, shall provide the size of tubing and flowlines, need for chokes, method and expected frequency of well maintenance, reliability and availability goals for the system, and requirements for pigging and well testing. Functional Requirements may also define need for subsea pumping. Section 6.0 - Maintenance Concepts, shall establish whether minor well workovers are performed by wireline or TFL.

5.3.

The decisions required to configure the subsea well system are shown in Figures 3 and 4. Note that "well location" and "manifold location" indicated in Figure 3 include options of both surface and subsea sites. These surface options are included in the figures in cross hatch for completeness of the thought process; they are not addressed in the discussion which covers only the subsea options.



Figure 3: Pressure Maintenance, Artificial Lift, Seafloor Pumping



Figure 4: Subsea Well System Configuration



Figure 5: Subsea Well System Configuration

5.4. Reservoir Pressure Maintenance/Downhole Artificial Lift/Seafloor Pumping

5.4.1.

Reservoir pressure can be partially and sometimes fully maintained to cause the well to flow at maximum rates by injecting water into the existing aquifer to supplement natural expansion or inflow of the aquifer. Reservoir pressure



can also be maintained by injecting gas into the gas cap. Flow from the reservoir can also be increased by reducing "back pressure" against flow from the reservoir by artificial lift in the wellbore or by pumping the produced fluids at the seafloor.

5.4.2.

Analysis of the Reservoir shall determine whether pressure maintenance, artificial lift or subsea pumping are justified and when they shall be started; this will become part of the Design Basis. Mobil engineer(s) shall consider availability of water and gas, and the status of technology of downhole or seafloor pumping and its complexity/reliability. The cost and potential benefits of the alternatives shall be compared to determine how the Design Basis requirements shall be met. The decisions required to evaluate the alternatives are presented in Figure 3.

5.5. Pressure Maintenance

5.5.1.

Either seawater or produced water can be injected from the surface into the reservoir for pressure maintenance. If injection must start early in the field life, seawater is the only choice. Later in the field life, produced water shall have to be treated and either discharged overboard or re-injected. Compatibility of seawater with formation water and rock, local regulations, and operating difficulty shall be the basis for choosing whether produced water is re-injected.

5.5.2.

Either produced gas or manufactured gas (i.e., inert gas) can be used for gas injection or gas lifting. Natural gas is operationally preferred, by far. Manufactured gas is normally obtained by partial oxidation of oil or condensate to get flue gas. The cost per unit volume of gas is expensive because of the equipment to make and clean the gas, the effect of equipment size and weight on surface facility costs, or the cost of metallurgy to control corrosion if the manufactured gas is not fully treated. Availability of natural gas, the capital cost of manufactured gas and incremental compression costs shall determine the choice between natural and manufactured gas. The capital and operating cost of the selected alternatives shall then be justified for project economics.



5.6. Artificial Lift

5.6.1.

Artificial lift to reduce flowing bottom hole pressure can be conducted using gas lift to lighten the fluid base, or by downhole pumping. To date, only gas lift has been used in seafloor completed wells; over 80 subsea wells have been gas lifted.

5.6.2.

Gas lifting is normally done by injecting gas from the surface through multiple gas lift valves installed at various depths in the downhole tubing, allowing start up ("kick-off") of the well using the normal gas lift compressors. This approach minimizes initial cost, and the space and weight requirements on the surface facility, but has, in the past, significantly increased operating cost and downtime because of the frequent workovers required to repair gas lift valves. Alternatively, gas can be injected through a single annulus/production tubing crossover, set deep in the wellbore. A relatively small, high pressure, low volume compressor would be used to start the wells before switching to the normal gas lift compressor. The gas lift design shall be based on life of field costs of compression, downhole equipment and well maintenance.

5.6.3.

Downhole gas lift supply is commonly by annulus injection. However, in annulus gas lift, every gas lift valve is a potential leak path from the production tubing to the annulus. Tubing supply requires use of a second tubing string with crossover to the production tubing, and may require a second downhole safety valve. The choice of gas lift supply shall be based on company policy, interpretation of local regulations, and cost.

5.6.4.

In multiwell systems, gas for gas lift will probably be supplied through a common supply line to several or all of the wells. Control of gas to balance the flow to each well usually requires use of an adjustable choke on each well. Differential pressures will probably be measured across the choke to provide at least an indication of the effect of choke adjustments to allow the well system to be balanced in a reasonable time during start-up. Choke position sensors can be used to reduce the dependence on well testing for choke calibration. (Note, remote controls for such a system will probably be electrohydraulic and the surface controls console can be programmed to make required flow calculations for a system operating either with or without choke position sensors.)



5.6.5.

Remote controlled chokes of the design used subsea have been in use for land wells for nearly 20 years on the North slope and elsewhere. They have been in use in the North Sea at Highlander since 1986 and in Balmoral since 1987. No failure of remote controlled chokes has been reported.

5.6.6.

Downhole pumping involves use of multistage centrifugal pumps driven by an electric motor, electrical submersible pumps (ESP), or by hydraulic powered turbine motors. ESPs have not yet been used in seafloor completed wells. Lack of a proven high power, wet mateable connector between the umbilical and the subsea tree and between the tree and the tubing hanger; the operational difficulty of handling the power umbilical with no connector at the tree; the historically poor mechanical reliability of ESPs; and unavailability of a reliable cable -suspended electric pump have prevented use of ESPs in subsea satellite wells. Multi-well systems have the added disadvantage that subsea switch gear is unavailable to allow use of one power cable. ESPs are currently being considered however for lifting heavy, low GOR oil in the South China Sea offshore China. However, a recent program for testing a new cable suspended ESP demonstrated that the problems are not yet solved.

5.6.7.

Hydraulic pumps have had limited use on land and on offshore platforms, and no use thus far in seafloor wells. Their efficiency is sensitive to free gas, and they are vulnerable to damage by sand production. Turbine pumps and motors have been developed by Weir in the UK, and installed in a few wells. Experience is not yet sufficient to establish their reliability. Jet pumps are relatively new, and are very power inefficient. They frequently require one or two volumes of power fluid for each volume of produced fluid pumped.

5.6.8.

The basis for choosing the best artificial lift method shall be cost, surface facility space and weight requirements, operating costs (including pumping or compression and well workovers), and risks. In most cases, gas lift will be the base case choice for subsea wells.

5.7. Seafloor Pumping

5.7.1.

Concepts for seafloor pumping involves use of single phase pumps with two-phase separation or use of multi-phase pumps. At present, only a separator



beneath a fixed platform surface facility using a conventional electrical submersible pump is proven technology.

5.7.2.

In single phase pump systems, the liquid is pumped and the gas is flowed to the surface facility. The separator can be located at the base of the surface facility or at the wells or the manifold remote from surface facility. Locating the separator beneath the surface facility may allow use of a submersible pump run from the surface, eliminating need for power cables and an underwater connector. Also, in deep water, pumping from the base of the platform may obtain much of the benefit of pumping from the well site. Texaco installed a slug catcher (separator) for Highlander production beneath the host platform on Tartan in the North Sea and used a conventional electric submersible pump installed down a spare well conductor. That system reportedly worked well. Single pumps to 250 hp are available, and tandem pumps to 700 hp are at least proposed.

5.7.3.

Remote separators are not yet proven. BP, Exxon, Shell, British Offshore Engineering Technology (BOET), and Goodfellow and Associates have each developed systems. The BP separator, installed offshore in the Middle East in the early 1970s, reportedly never operated, apparently because of control system problems. The Exxon unit, also built in the early 1970s, operated on land, but electric power connector failures prevented operation offshore. Shell Oil installed a separator in their Lockheed manifold chamber in the mid-1970s, but it required considerable operator attention and was not used long. BOET installed a prototype separator under the Argyle/Duncan facility in 1989, but initial results were reportedly "disappointing." Further development may be underway. Goodfellow built a prototype separator which was reportedly tested on land during 1990 with nitrogen gas and water, and possibly oil. Results are not available and the status of development is also unknown.

5.7.4.

Multi-phase pumps are also not field proven at this time. A prototype system has been developed by BP (and participants) with Weir. That program is apparently inactive. Total (and others) have developed a pumping system (Poseidon project) using a different pump concept. After extensive laboratory testing, a prototype unit was installed on land in a middle east country. That test was interrupted by the 1991 middle -east crisis. In addition, Mobil has been involved in the development of a subsea positive displacement multi-phase pump which is slated for onshore field testing in the 4th quarter of 1992.



5.7.5.

If flow analysis shows that subsea pumping will be significantly more beneficial than artificial lift, or if gas is not available, pumping systems can be considered. Final selection between artificial lift and subsea pumping shall be based on cost, operating complexity/reliability, and technical risk. Artificial lift by gas lift is proven technology and operationally reliable. It requires a source of gas, compression, a flowline from the surface to the wells, and use of remotely controlled chokes which complicate the control system. Seafloor separation and liquid phase pumping at the surface facility is also proven. Electric down hole pumps require development of a reliable subsea electrical connector. Remote separation require development of reliable controls. Remote subsea pumps are not field proven technology at this point in time. They also require a power cable from the surface.

5.7.6.

The remainder of the well system configuration decisions are presented in Figures 4 and 5.

5.8. Well Location

5.8.1.

The first step is to determine whether all well locations in the reservoir can be reached from one drilling site. Next, the effect of production schedule and system investment cost on project economics shall be determined for drilling from one site or multiple sites. Costs of drilling and completion, flowlines and risers and surface facility, and production schedule shall be considered. Workover costs may also be important if the wells are expected to be trouble prone.

5.8.2.

A related decision is whether any of the wells will be drilled from or under the process facility. The relative cost and availability of a drilling and workover system shall be the basis for that decision. For example, in shallow water, especially with low maintenance, short lived gas wells, it is frequently more economic to drill the wells from a leased jack up rig through a remote well jacket or a seafloor site than to drill the wells through the process platform.

5.8.3.

The decision of whether wells shall be completed on the surface or the seafloor will be mixed with the decision to drill from one or more sites. Surface wells shall be drilled from a bottom founded or tension leg platform



rig or, in shallow water, from a jack up rig. On a platform, one or two rigs can drill at the same time. Subsea wells can be drilled as individual (satellite) wells connected to a central facility by flowlines, or drilled through a template. One floating rig can be used on each satellite well or template, so long as the wells or templates are far enough apart to allow the rig to be moored, or a dynamic positioned rig is used.

5.8.4.

A large number of wells, a deep reservoir, or troublesome production problems, which will require frequent wireline or major well workovers will favor placing the wells on the surface. Increasing water depth, uncertain reserves, a shallow reservoir and good wells, will encourage use of seafloor wells.

5.8.5.

The decision of whether wells are completed individually on the seafloor or in a template depends on the cost of installing and maintaining the individual wells and their flowlines, the cost of the template and the effect of the resulting production profile on project economics. Drilling satellite wells can be started immediately, while drilling wells through a template shall wait until the template is ready; if the process facility can be ready early, use of satellite wells may allow early production with improved profitability. The risk of damage shall also be considered; unless a protective structure is used at each well. Individual wells and their flowlines are more vulnerable to damage by dragged objects than template drilled wells. However, template wells are more vulnerable to damage from objects dropped from the drilling rig. The consequences of damage to one well are much less than the consequences of damage to a multiwell template.

5.9. Manifold Location

5.9.1.

Flow from individual wells is commingled in the production system to avoid the cost of separate facilities for each well. Subsea wells can be connected individually by flowlines to a manifold located at the surface facility, at the base of a production riser, on a stand-alone manifold on the seafloor, or on a well template on the seafloor. Individual wells are referred to as satellite wells. Clustered wells are those drilled within the reach of a drilling rig while stationed in one location, and connected by short flowlines to a stand-alone seafloor manifold.



5.9.2.

A choke is normally required in the flow path of each well upstream of a production manifold or downstream of a gas or water supply manifold. The need for a choke and the type of choke required is dependent on (1) the expected characteristics of the wells, (2) whether artificial lift is needed, and (3) whether natural/gas injection is required. If the wells are expected to flow at low GOR (no slugging) and at near the same pressure, and, if the reservoir is near homogeneous, chokes may not be required. If they are needed and will not be changed often, then fixed chokes can be used.

5.9.3.

If adjustable chokes are needed but adjustment is expected to be infrequent, in both on-surface and subsea manifolds, manual operation is preferred. For subsea systems, space shall be provided for diver or ROV access. If chokes are to be adjusted frequently, remote control is required.

5.9.4.

Remote controlled chokes of the design used subsea have been in use for land wells for nearly twenty years on the North Slope and elsewhere. They have been in use in the North Sea at Highlander since 1986 and in Balmoral since 1987. No failures of remote controlled chokes have been reported.

5.9.5.

Manifold location is selected to balance the cost of flowlines, manifolds, and production risers with the operating complexity and costs of the system. Locating the manifold on the surface requires that each well have an individual flowline, but it allows chokes to be on the surface. This allows direct control on the surface of production from each well, and reduces the cost and complexity of the subsea control system. Location of the manifold near the wells minimizes the flowline costs, but a manifold, probably with chokes, shall be separately installed subsea. Placing the manifold on the riser base, or on a well template eliminates installing a separate manifold support structure. These costs will be combined with the effect of production schedule on project economics; satellite wells can be drilled using multiple rigs and started immediately. Template design, fabrication and installation will take nine to fifteen months or longer.



5.10. Subsea Choke Location

5.10.1.

When located subsea, fixed orifice chokes shall be diver or through flowline (TFL) installed. Although it could be developed, no equipment is available for ROV replacement of a subsea fixed choke. Adjustable chokes can be manually operated or remotely controlled. Proven equipment is available for the chokes to be built permanently into the piping, to be replaceable as a complete unit, or for the internals to be removed from the choke body and replaced subsea. Subsea replacement can be done by divers, or by use of an ROV and lift lines or by using vertically run tools. In either case, ROV or running tool access shall be provided.

5.10.2.

Location of the choke depends on the method chosen for maintenance and on the control system. Fixed bean chokes shall be located in the tree where production from other wells will not be disturbed by choke changeout. Manually adjustable chokes which require no remote control connections could be located either on the tree or the manifold. Location on the tree allows replacement by removing only one tree, shall the choke body ever be damaged. Remote controlled adjustable chokes shall be located on the tree to allow choke body replacement, to minimize the use of controls on the manifold, and to minimize the tree to manifold interface connections.

5.11. Chemical Injection

5.11.1.

Chemicals may have to be injected to control various production problems such as corrosion, paraffin deposition, scale formation and hydrate formation. The injection point in the system will depend on the problem being controlled and the expected point of occurrence. Most problems can be controlled by injecting chemicals into the flowlines or manifolds. In more severe conditions, chemicals may have to be injected into the tree or even downhole.

5.11.2.

Injection into one satellite well flowline or one manifold header requires a manual isolation valve at the tree or header; flow control would be done on the surface. Injection into each tree of a manifolded multiwell system requires either a separate chemical supply line to each tree, a remote controlled valve at each tree connected to a common supply header for periodic batch treatment, or a remote controlled valve and an orifice or other



proportional flow control device to meter chemical from a common header continuously into each well. Depending on local regulations or Company policy, it may be necessary to install a manual isolation valve at the tree on any chemical injection line connected to a tree.

5.11.3.

Wellbore injection can be done by installing supply lines from the tree to a downhole injection point, by bullheading slugs of chemicals down the kill line into the formation (squeeze treatment), or by reentry of the well from overhead and injecting a batch treatment of chemicals down a coiled tubing or macaroni work string.

5.11.4.

Remote chemical supply can be incorporated into the controls umbilical, or a separate line. In most cases, the size will be less than 1 in diameter and could be in the control umbilical. However, small bore steel tubing, especially in 3/4 in and 1 in OD, is inexpensive, costing about $0.15Z/ft compared to $3 per ft for umbilical hoses. For hydrate inhibition in high gas flow rates, the methanol or glycol volumes may require a 2 in supply line which cannot be incorporated into a practical umbilical. A cost/practicality test shall be the basis for selection of the chemical supply line.

5.12. Flow Schematic

5.12.1.

It shall be necessary to prepare preliminary flow schematics and control schematics for each well and manifold configuration that is technically and operationally acceptable at this point. An approximate cost comparison shall be prepared for all alternatives. It is also frequently necessary to perform a comparative reliability analysis of each configuration being considered. A comparison can then be made to select the best configuration considering:

1. Investment Cost

2. Operating/Maintenance Cost

3. Downtime

4. Operability

5.12.2.

Note: This comparison is usually done early in the development planning. It is important that relative cost of the systems be accurate. Preliminary cost and



approximate equipment failure rates can be used for the comparison; absolutely accurate cost and failure rates are not needed at this time. When approximate numbers are used, it may be advisable to normalize the costs and system reliability to permit valid comparison without causing confusion later when accurate total system cost and failure rates are available.

5.13. Tree Valving

5.13.1.

In the Functional Requirements part of Section 4.0 - Design Basis and Appendix D, as indicated in Table 1, valves in the production bore of the tree shall provide for production and/or injection, testing of the well, killing of the well, chemical injection, TFL maintenance and crossover to the annulus flow path as required. It may also be necessary to provide paths for testing and killing of the well either through or around the choke. Valves in the annulus bore shall provide for connection to well killing, artificial lift and chemical injection supply, and crossover to the production bore plus provision for TFL circulation, if used.

Table 1: Tree Valving

Function Production Tubing Annulus Other

Production and Injection X

Crossovers X X

Testing/Killing X X

Annulus

Monitoring/Bleed/Gaslift

Gas

X

Chemical Injection* X X X

SCSSV X

Test Port (for tree

connector)

X X

*Note: Chemical Injection can be connected to Production and/or Annulus bores .

5.13.2.

A satellite well with one flowline, will have a subsurface safety valve, one or two master valves, and a wing valve in the production string. There shall be one or two master valves and a crossover valve on the annulus connected to



the production line. Placing the crossover on the well side of the production wing allows sharing a pressure transducer. Placing the crossover outboard of the production wing allows the annulus to be killed with the production wing closed. Each valve, with exception of the lower master valve, if used, would be hydraulic actuated and failsafe closed. There would be no choke at the tree unless the productivity index was low enough that opening the well to a low pressure flowline could damage the completion. In that case, the choke would be insurance against human error. Chemicals, if needed, would be injected down the controls umbilical through a manual valve and into the tree or downhole through the tree connector.

5.13.3.

In satellite wells, if paraffin is expected, two flowlines or a pig launcher on the tree would be used. With two flowlines, the production would be connected through a wing valve to both lines. The annulus would be connected to one. A crossover would be located between the flowlines outboard of the wing valves. This would allow production or killing through either line, and circulation for paraffin control with the tree wing valves closed. The flow schematic of a pig launcher is dependent on the design and is not discussed here.

5.13.4.

If downhole paraffin were expected, or if frequent subsurface valve failure was expected, or for other reasons downhole TFL well maintenances is chosen, the subsea tree would be connected to two flowlines and equipped with a second tubing string and with a crossover just above the subsurface valve(s) and near the producing formation to permit circulation between the two strings or the production tubing and the annulus. The tree valve block would also include "Y spools" and flow loops with minimum 5 ft radius bends in each bore to be serviced by TFL. (Note: TFL equipped wells to date have all been configured with a second tubing string as opposed to annular circulation.)

5.13.5.

Reliability analysis will show that if two flowlines are laid to a satellite well, for any reason, addition of a second tubing string in the wellbore shall be justified. The incremental cost of TFL may be justified, just to provide inexpensive workover capability for the subsurface safety valve and to permit full circulation deep into the wellbore, if paraffin is even a possibility.

5.13.6.

The rational and flow schematic of template wells will be the same as satellite wells, except, if there is a manifold on the template, all wells will normally be



connected to each flow header or provisions made for future connection; for example production or injection and test/kill. (This is because it is usually not possible to designate years in advance which wells will be used for production procedures and which will be injectors.)

5.14. Pigging

5.14.1.

When pigging is specified in the functional requirements, the decision shall be made whether all tree loops and piping, and any manifold headers will be pigged, or if only flowlines will be pigged. If the flow analysis and associated temperature analysis of the wells and flowlines indicate that the temperature of the flowing fluid will remain above the cloud point in normal production operations, then paraffin formation and subsequent pigging requirements shall be reviewed. If the temperature is expected to drop below the cloud point at some location in the system, it shall be necessary to provide pigging from that point back to the surface facility. Where pigging is used to control mild scaling problems, it shall also be necessary to operate the scraper pig from the point where scale is expected back to the surface.

5.14.2.

The type of pigs that shall be required in the system shall also be considered. If the primary purpose of pigging is to squeegee liquids out of low spots in gas flowlines or pipelines, then only ball pigs shall be required. If the purpose is to remove paraffin or scale, then scraper pigs shall be required. If the purpose is to monitor pitting or corrosion damage in the flowlines, then smart pigs shall be used. The ball pigs, in general, will traverse almost any flow configuration that liquids or gas will navigate. Scraper pigs require a turn radius at least five times the inside diameter of the pipe. Such pigs also will only transition between pipes of approximately 2 in diameter difference. Intelligent pigs require minimum bend radius of five to eight times the inside diameter of pipeline. The pipe flow path, sizes and valving shall be designed to accommodate these various pigs as required for the system.

5.14.3.

The frequency of pigging shall also be estimated. If a pig is seldom used, the cost to insert the pig subsea may still be better than the major initial equipment investment to make pigging more convenient, even though frequent pigging may be required during start-up.



5.14.4.

If it is necessary to pig the headers in the production manifold or if the design to provide for redundancy involves multiple use of certain of the headers, then it is necessary to have a crossover valve between the headers which will be used for the same function. For example, in many systems where there is a possibility of high pressure and low pressure flowing wells, it is frequently advisable to use two production headers and two pipelines back to the surface. In deep water, it may be the same cost or even less expensive to lay two smaller diameter lines using the available pipelay equipment. A crossover between these two headers, which is normally closed, could be opened for circulation during pigging or flushing of those lines. When both production and water injection headers are used, a crossover between these two headers allows pigs to be injected with the water, circulated to the template or the manifold center, passed through the crossover and then carried out through the production line with the oil or gas production, without shutting in production. With two flowlines, shall the production header ever fail or be blocked, it would be possible to shut the isolation block valves, open the crossover and produce the wells through the other line. (Shall the water injection line ever be used for flushing or production from the production header into the water injection line, extensive flushing would be required before the water injection line could be returned to injection service).

5.14.5.

The location of the pig launcher shall also be determined. If two flowlines of the same size connect the subsea system, addition of a "piggable" crossover loop will allow the pig launcher and receiver to be located on the surface. If only one flowline is used, a subsea pig launcher will be needed. For a subsea pig launcher, the decision shall be made whether the pigs are inserted into the subsea launcher by diver, by a remote controlled vehicle or by vertical running tools. The cost of adding another flowline and crossover valve to allow circulating pigs from the surface shall be compared with the installation and operating cost of a subsea pig launcher, including insertion of pigs and the effect of any production delays on project economics.

5.15. Manifolds

5.15.1.

A multiwell manifold shall have at least one header for each function that is required; for example, production, water injection, gas injection, gas lift supply, chemical supply, well test, and probably high pressure and low pressure hydraulic control fluid. It may be necessary to have two production headers if the wells are expected to produce at different pressures during the life of the field. For example, some of the wells might be converted to gas lift at



some point during the field life and those wells might produce at a lower pressure than the wells continuing on natural flow.

5.15.2.

If the functional requirements do not specify which wells are production and which wells are injection for (water or gas) disposal, or if there is uncertainty as to the requirement for injection of chemicals, it shall be necessary to either connect or provide for future connection of each well to each header in the manifold.

5.15.3.

TFL well servicing in a manifolded system requires two service line headers. If the well is to have two strings of production tubing, and TFL servicing is to be done in both, then the two TFL headers shall be the same size. For each well, there shall be a remotely controlled TFL tool diverter in the line to each bore of the trees being serviced. Note: These diverters could be manually operated, but it is likely that TFL will only be installed when its use will be too frequent for practical use of divers or an ROV to operate diverters.

5.16. Flowlines

5.16.1.

In general, one flowline or service line shall be required for each function of the well or manifold being connected. For satellite wells this will include one flowline, hydraulic supply or control lines, and possibly an annulus monitoring or access line, TFL servicing or chemical injection lines. For manifolded wells, it will include lines for production for each producing pressure, well test/kill, and hydraulic supply, and may include water or gas injection, gas lift supply, chemical supply, and TFL well servicing.

5.16.2.

The lines will be first sized for flow rate and function. Sizes based on function shall then be reviewed for installation logistics and cost, and for redundancy (discussed below). For example, a production flowline and water injection flowline might be near the same size and pressure rating. Consideration shall be given to installing two identical lines. The same is true of gas lift and well test/kill or TFL service lines. Depending on required flow rates, chemical injection supply lines might be the same size as the well test/kill line, or the hydraulic supply line. The advantages of common size lines is functional redundancy, simpler logistics and improved economy of pipe purchase and installation. Note: economy may be lost if the lines have different pressure ratings, and require different installation methods.



5.16.3.

TFL service lines shall be fabricated with great care. They shall be made of mechanical tubing (as opposed to API line pipe) to assure their internal diameter and wall thickness, and they shall be welded against an internal mandrel or use other methods to assure internally smooth welded joints. Other than those precautions, TFL headers can be used for test lines, chemical supply, or gas or water supply. A "polished bore" section of pipe will be installed near the inlet of the manifold in each TFL header in which tools will be used. If the manifold is more than a few miles from the surface station, the pressure will be monitored at the inlet of the polished bore on the surface facility side to assist the operator in tracking the tools through the system.

5.17. Flow/Service Line Redundancy

5.17.1.

Redundancy of the headers can, in some cases, be a low cost way to increase flexibility and reliability of the production system. Use of two production headers allows the wells to be produced against two different back pressures. Through the use of a crossover valve between the headers, flushing and pigging by circulation are permitted. Shall one of the headers develop a leak, it would be possible to close block valves in the flowline (if available) and produce wells connected to both headers to the remaining sound header. In many cases, especially depending upon the size of the flowline, it may not be significantly more expensive to lay two smaller lines than it would be to lay one larger line such that these redundant production headers could be essentially free. (Especially true in deep water). It might also be advisable to lay an extra test line which could be a backup to the well test, gas lift, or possibly chemical injection lines. Where chemical volumes require small injection lines (1 in), they could be the same size as the high pressure and the low pressure controls fluid supply, and an additional spare line of this size could be laid at low cost.

5.17.2.

Use of crossover valves between multiple headers of the same or near the same size can also add flexibility to the system. The crossover between two oil headers will allow flushing or pigging by circulation or backup in the case of a failed header as described above. The crossover between a water supply line and oil line, which can usually be made the same or near the same size at little extra cost, will also allow for inserting a pig down the water injection line with crossover and return of the production header without interruption of flow. Again, the water injection line could also serve as a backup to the production line in the event that the production header or the



main production flowline shall fail. (Shall the water line ever be used for this service, extensive flushing would be required to clean the line it before returning it to water injection service). A crossover between the well test and gas lift lines will allow these to be double purpose: well test lines could be dried and used to supply gas lift gas and forego testing while repairs were made. A crossover between TFL and gas lift supply lines could also allow TFL lines to be used as a well test or gas lift or, if the water supply line failed, multiple small lines could be used for water injection. With proper crossover, any of these lines could be used for well killing. The smaller size lines (chemical injection and hydraulic supply) could also be crossed over such that any one of the lines could be used for the others' function. An extra line could be used for backup.

5.18. Valves

5.18.1.

Once the flow schematic has been designed, outline operating procedures from the functional requirements shall be reviewed. The purpose and expected frequency of use of every valve shall be considered. Any valves which are not clearly needed shall be eliminated. Then it shall be decided whether each valve shall be remote controlled or diver/ROV operated, and which valves shall be "fail safe." The "fail safe" position shall then be designated.

5.18.2.

Need for block or crossover valves on the flowlines, upstream of the manifold shall be determined. Plans for pressure testing of the lines during installation and the requirements for flushing the flowlines and auxiliary lines shall be reviewed with the manifold flow schematic. If block valves or crossover lines in the flowlines are needed to accomplish functions not possible using valves in the manifold, the timing and frequency of use shall be determined to establish whether they shall be remotely controlled or manual. Note: remote controlled valves on the pipeline shall be avoided when possible because of the complexity they add to the remote control system.

5.18.3.

Location of valving on the tree and the manifold is extremely important due to reliability and maintainability. In general, remotely controlled valves shall be placed where the number of such valves is minimized and where they can be maintained as easily as possible. With template drilled wells connected directly to the seafloor manifold, it is normally better to place the remotely controlled valves on the tree. The basis for this is that the tree is easier to replace than the manifold. However, if the capability is provided to replace



individual valves in the manifold in-situ, without removing the entire manifold, the opposite could be true.

5.19. Results

Location of the wells decided here will be input to selection and design of the surface facility and of every subsea subsystem. Designation of the wells as satellite or template drilled will be input to the trees, flowlines, remote controls, and base structures. Location of the manifold will be input to the trees, manifolds, flowlines, remote controls, and base structures. The flow schematics and valve designation will be input to the trees, manifolds, flowlines and remote controls.

6. Maintenance Concepts

This section deals with wellbore maintenance and subsea equipment maintenance.

6.1. Wellbore

6.1.1.

Wellbore workovers can be divided into two categories:

1. Major workover - requires removing the subsea tree and pulling the tubing

2. Minor workover - can be performed with the subsea tree and production tubing in place.

6.1.2.

Decisions required in the system design for well servicing are presented in the decision tree diagrams Figures 6 and 7.



Figure 6: Tree Installation/Workover Riser



Figure 7: Minor Well Servicing

6.1.3. Completion/Workover Riser System

1. A "completion riser" is used inside the marine drilling riser and through the subsea BOP stack to install or retrieve the downhole tubing and equipment suspended from the tubing hanger. A "workover riser" is used to give access through the tree to each bore of the tree, and to each remote controlled tree or downhole valve in the production/injection and annulus bores of the well. Note that the completion riser shall pass through the drilling riser and withstand expected internal pressures. The workover riser is normally run in the open sea and shall withstand internal pressure and external environmental loading, and permit safe disconnect from the well.

2. A completion riser attaches to the top of the tubing hanger running tool and extends to a "surface tree" on deck of the drilling rig. It connects each tubing and annulus bore in the tubing hanger to the surface tree, and each downhole hydraulic control line from the tubing hanger to the completion control system. This riser can be as simple as a string of drill pipe used to run a weight set, single bore, non-sealing, concentric tubing



hanger with fluid velocity activated downhole safety valve up to the complexity of a multiple tubing and control umbilical riser required to install a multibore completion with surface controlled downhole valves.

3. A workover riser may include a stress joint, and shall include a Lower Workover Riser Package (LWRP) in addition to the surface tree and controls, tensioners and riser joints of the completion riser.

4. The surface tree on the upper end of the riser shall include valves (typically master, swab, and wing) and manifold connections for flow testing, circulation, or injection. Connections are provided at the top for wireline lubricator assemblies. Necessary work platform and handling provisions are also incorporated in the surface tree.

5. The "riser" can either be self-standing or supported from the rig. Self standing risers can be continuous from the seafloor to the rig, or they can be supported by a submerged buoy, located within diver depth, with the top section of the riser connected at the buoy and extending to the rig. The continuous self-standing riser is only used with jack-up rigs. The buoy supported riser with all steel pipe is also used from a jack-up, or in very calm water, from a floating vessel. The buoy supported riser with flexible pipe upper section can be used from a floating rig or, in calm water areas, from a supply boat equipped for wireline well servicing. Conoco used this approach in their "snap-on" system in the Kepeting field in Indonesia. In use, the flexible pipe is pulled straight to allow wireline or a work string to pass through the riser. Most of the well servicing to date has been conducted through steel risers. Wireline tools have been run into test wells through flexible pipe with no trouble; it is not known if wirelining through flexible pipe is field proven.

6. Floating drilling/workover rig-supported risers can be flexible pipe or steel. The steel pipe risers are supported with hydraulic operated "Tensioners" which hold a constant tension on the riser to accommodate surface vessel motion.

7. Multibore steel risers shall have one bore for each bore in the tree, or a diverter in the LWRP which allows access through one riser bore into all bores of the tree. Refer to Figure 6 for a simplified decision tree. These risers can be either: (1) non-integral and (2) integral configuration.

8. Non-integral risers consist of drill pipe or production tubing run by making-up one joint of pipe at a time for each bore. They are the lowest cost and are most applicable to installing simple, single-bore completions. Drill pipe has several advantages over tubing: availability, higher strength, repeatable connections, better fatigue life and lower cost. A disadvantage of non-integral risers, when used with multiple bore systems, is the special handling tools required, difficulty of make-up, and the rig time required to make up the multiple tubing strings simultaneously.



9. Integral risers consist of preassembled joints, like a drilling riser, with all the flow and control fluid conduits in a single assembly with a mandrel on top and a connector on the bottom. The joints are then made up end-for-end to assemble the required length. They are the most expensive, but they increase operational flexibility and reduce the time to conduct a workover in a multiple bore completion. Non-jacketed integral risers obtain structural strength from the tubing which is exposed to the ambient sea. They are less expensive, especially in shallow water where added buoyancy is not needed to support riser weight, and they are easily inspected. The jacketed integral risers have an outer structural shell surrounding the tubing and control lines. They offer four advantages over non-jacketed types: single point pressure test of connections during makeup, containment of loose pieces when installing the tubing hanger, no environmental load applied to the pressure containing bores, and the jacket can be used to make the riser partially buoyant to reduce the required top tension. Jacketed risers are inherently stiffer than other types, and therefore, require the subsea tree to have higher bending strength. They are also more expensive.

10. The selection between non-integral and integral risers is based on comparison of rig time to run the riser during completion and workover, and the initial cost of the riser. Drill pipe or even two strings of production tubing is low cost. Therefore, in shallow water where riser running time is short, a non-integral riser is usually best. Also, when only a few wells are to be completed, the riser running time that can be saved by use of an integral riser may not pay the higher cost of the riser. The integral riser will be best for systems in deep water and with more wells.

11. The stress joint, located above the LWRP, is a flexible section of the riser which prevents high stress when the surface vessel is not exactly over the well and the riser is at a different vertical angle than the wellbore. It is required with any steel riser except in very calm weather areas.

12. A Lower Workover Riser Package (LWRP) is installed at the lower end of the riser. In its simplest form, the LWRP is only a remotely controlled connector compatible with the top of the trees and permitting disconnect with the riser axis offset at a high angle from the wellbore. For high pressure wells, it frequently also includes a "workover BOP" which has rams capable of cutting wireline or coiled tubing, providing pressure sealing around a wireline or tubing above the swab valves, and permitting circulation through the riser bores. It may also include a bag type preventor.

6.1.4. Major Workover

Replacement of the tubing retrievable subsurface safety valves, production/injection tubing and packers; completion failures; or recompletion to another zone are the most common reasons for major workovers. For this discussion, it is assumed that the well has been "killed" with fluid before the



workover operation is started. The tree would have been retrieved. The tubing can then be pulled.

6.1.5. Minor Workover

1. The Functional Requirements part of Section 4.0 - Design Basis and Section 5.0 - Subsea Well System Configuration shall define the well servicing needs of the system. As stated above, a minor workover is defined as a workover tha t can be performed with the subsea tree and production tubing in place (so the work downhole is performed inside the tubing string). Minor workovers include typical remedial operations that are common to both platform and subsea wells such as replacement of wireline installed downhole safety valves, setting plugs, shifting of sleeves, sand bailing, paraffin removal, running pressure gauges, sand washing, chemical injection, and squeeze cementing.

2. There are four basic methods of conducting minor workovers as follows: (1) wireline, (2) coiled tubing, (3) concentric tubing and (4) TFL, or Through-Flow Line well servicing. The decisions required in system design for minor well servicing are presented in Figure 6.

6.1.6. Wireline Servicing

1. Wireline servicing can be done using a lubricator and wireline BOP stack on the surface connected to the subsea tree by a high pressure riser, or by use of a subsea lubricator and wireline BOP stack which is connected to the top of the subsea tree (i.e., subsea wirelining). The commonly used conventional, method is the surface lubricator and wireline BOP. This technique is used from floating rigs and jack-up rigs and it is fully proven. A high pressure riser to the surface vessel is required and hydrocarbons are routed to the surface during workover operations.

2. Subsea wirelining is a new technique developed recently in the North Sea. With the lubricator and BOP stack mounted subsea on the tree, no high pressure riser to the surface vessel is required and the wireline is in contact with the seawater environment. The main advantage is that no riser is required and therefore, the subsea wireline unit can theoretically be operated from a smaller vessel with a lower day rate. To date, subsea wireline units have only been run from semisubmersible rigs or monohull DSVs (diving support vessels). Further, some will argue that subsea wirelining is inherently safer because no hydrocarbons are brought to the surface.

3. Several different subsea wireline systems have been built and others have been prototype tested. The only two that are field proven and commercially available are operated in the UK North Sea by SWIS (Subsea Well Intervention Systems) and Camco/Stena Seawell. SWIS is a joint venture between Otis Engineering and Rockwater, setup solely for the purposes of offering this type of well servicing. One company



located in Aberdeen (Subsea Well Services) offers a wireline system incorporating a subsea winch system, but it is not field proven. In that system, the winch is mounted adjacent to the subsea lubricator, so that the wireline does not run through the water back to the surface. The subsea wirelining systems are proven technology in diver assist operations, but shall be considered new technology for diverless systems.

6.1.7. Coiled Tubing

Coiled tubing servicing into subsea wells can also be conducted using (1) a conventional system with a surface lubricator/BOP and high pressure riser or (2) potentially with a subsea coiled tubing unit. The only field proven method of conducting coiled tubing work is via use of a high pressure riser to the surface. SWIS is the only company that has built a subsea coiled tubing unit to date. It is located at the Otis facility in Montrose, Scotland, but has never been used on a subsea well. Therefore, this system is not considered to be field proven.

6.1.8. Concentric (or Macaroni) Tubing

Concentric (or macaroni) tubing operations can also be conducted in subsea wells, but only through use of a high pressure riser to the surface vessel. One inch tubing with premium connections is normally used. Typical well servicing applications are milling, jarring, fishing and circulation.

6.1.9. Through Flowline (TFL)

1. Through Flow Line (TFL) well servicing shall be used whenever frequent downhole servicing is expected due to recompletion, paraffin buildup, or subsurface safety valve failure. TFL tools have been fully developed in 2 in through 4 in sizes to perform virtually any task which can be done using wireline, even perforating. Several oil companies have conducted land testing with these tools through up to 10 miles of flowlines and in test wells. The 3 in TFL tool size has been tested and used more extensively than any other size. The design of 2 in tools has not been updated to include modern technology and are basically not proven.

2. Two examples of use of "modern" TFL tools are:

a) "Cobia" single satellite well located offshore Australia a few miles from the host platform where Esso performed TFL paraffin scraping once or twice each week, using 3 in tools, for a few years with reportedly no problems.

b) The Cormorant UMC, a nine-well commercial subsea system in the UK North Sea located seven miles from the surface platform is equipped for 3 in TFL capability. It has been used to prove the system, but there has been no need for downhole well servicing.



3. The major advantage of TFL is that the workover operation can be done remote from the well, independent of weather and without a surface maintenance vessel. Therefore, a TFL workover can be conducted whenever needed to minimize downtime of a well, and at far less cost than a conventional wireline workover which requires a vessel to be mobilized. Other advantages are that the fluid system is always "closed" during well servicing with no fluid leakage minimizing safety risk, and that TFL tools can be manipulated with considerable force, without concern for breaking a wire such as in wireline work. Additionally, a circulation path is provided to the bottom of the wellbore in a TFL system and this feature offers benefits other tha n for well servicing (production path redundancy/reliability, circulation of inhibitors, well killing, well unloading, etc.).

4. The reasons why TFL systems are not used widely are as follows:

a) complexity of production system is increased

b) increase in the initial cost of the equipment (surface equipment, special weld requirements for flowlines, Y-spool and diverters in subsea tree, special downhole equipment, TFL diverters in subsea manifolds, added testing during integration and installation, etc.)

c) lack of personnel in operating companies that are experienced with TFL.

d) A test loop to train operation personnel and thoroughly evaluate the tools may be required (especially if prototype tools are required).

5. The same tools used in TFL can be used down a dual bore workover riser from a surface vessel in what is referred to as a Pump Down Tool system, PDT. This system has the advantage over TFL that no remote control or manifold complexity is required. The tree and completion shall still be dual or multiple bore. The advantage over wirelines or coiled tubing is that no line passes through the tree, and therefore, no lubricator or BOP is required; the tree can be used to control the well. There is also no risk of breaking the wireline or tubing, and in recent years, loss of TFL equipment requiring a "fishing" job in a well has become very rare.

6.2. Subsea Equipment

6.2.1.

Maintenance concepts will have an influence on the selection of subsea production system equipment. A common mistake is to select equipment and then decide how it will be maintained. The best approach is to identify subsea components which have to be maintained, to prioritize those components by



criticality and failure frequency, to select component configurations, and then to design the maintenance tools toge ther with the subsea equipment.

6.2.2.

Alternative maintenance systems for seafloor equipment are presented in Figure 8.

Figure 8: Maintenance–Subsea Equipment

6.2.3. Unmanned

1. Seafloor production system components which could be installed, operated and maintained without in-situ manual intervention were developed starting in the late 1950s.

2. Vertical running tools were developed during the 1960s for virtually every component of subsea production systems because the primary installation vessel was a drilling rig equipped with guidelines. The running tools were run to the subsea location on the guidelines. The same technology is being extended today to guidelineless systems. The advantage is that drilling technology and methods familiar to rig crews are used. The disadvantage is that an expensive rig is required.

3. Unmanned vehicle development started in the early 60s with tethered manipulators which operated on tracks on the subsea systems. The first



vehicles were designed to be manned. However, by the time they were built, television and electrohydraulic controls, and methods of remote operation had improved to the point that the systems were only used unmanned. The goal was to design subsea equipment and special manipulator tools that worked together. The track was used to keep the manipulator in a known position, to minimize space requirements and risk of damage, and to absorb reaction forces. Power was provided through an umbilical. These manipulators were to be operated from diver support vessels. The advantage over manned bells and free flying vehicles was lower risk, smaller access space and unlimited bottom time. The disadvantage was the cost of special production valves, serviceable by the manipulator, the cost of the manipulator and the need to maintain the vehicle and its crew.

4. Remote Operated Vehicles (ROVs), free swimming tethered vehicles, were developed in the early 1980s using the latest low-light television and controls equipment. The early models were a "flying eyeball" for observation only. Larger versions were soon developed which could do limited work subsea. They have now become widely available and are used frequently all over the world. Their capability ranges from small observation units, small work ROVs, to a few larger special work vehicles. A commonly available "ROV of opportunity" will lift 150 lbs, carry 75 lbs, and is about 4 ft by 4 ft front area by 5 ft long. Many are equipped with an articulated arm and a grabber arm. Special tools such as cable cutters, socket wrenches, clamps, saws, hydraulic jets and other have also been developed. These tools can be used to attach lift lines, to release damaged or failed components, to guide the old part out of position and the new part into place, and to reconnect.

6.2.4. Manned

1. Manned systems include divers and men working at one atmosphere pressure inside fixed or maneuverable chambers (suits). Diving systems are influenced by water depth. Air is breathed to about 150 ft water depth. For all but minor work, saturation diving using helium breathing mixtures is used beyond 150 ft water depth to allow reasonable on-bottom work time. Beyond 600 ft water depth, special breathing gases are used. Commercial work has been done to 1000 ft and simula ted work has been done in the ocean to 1550 ft water depth. Simulated work has been done in tanks to over 2000 ft simulated water depth. Saturation and especially decompression times, and the cost of breathing gas goes up dramatically beyond 600 ft water depth, quickly making divers uneconomic beyond this depth except as a last resort. Within Mobil, the practical water depth limit for diver operations is considered to be 750 ft and the economic water depth limit for diver intensive operations is considered to be 400 ft.

2. Fixed Chamber Production systems to house production equipment were developed in the mid-1960s, when subsea production systems for use



beyond 600 ft water depth were first contemplated, and when no proven subsea equipment was available to operate submerged exposed to the ambient ocean, (especially remote control components). Further, with little component operating experience, reliability was assumed to be poor, thus requiring frequent repair. Two systems were developed to encapsulate land type equipment for subsea use. The North American/Rockwell - Mobil Subsea Atmospheric System (SAS) used "wet" drilling and installation techniques for the subsea trees and the downhole completion, and a "dry" chamber to house the production controls and manifold headers. A submarine was required to transport the maintenance personnel. Manned entry and the controls were in a breathable air compartment. The manifolds were in an inert atmosphere to prevent fire; men wore breathing masks to do maintenance. A prototype system was installed adjacent to an existing platform in the early 1970s, and oil from the platform was circulated through the manifolds. No commercial application has been made. Lockheed - Petroleum Services, Pan American (now Amoco) and eventually Shell developed a system later marketed by CanOcean where all subsea components were inside dry chambers. A man transfer bell system was also developed. Several commercial satellite wells and an experimental manifold were installed by Shell in the Gulf of Mexico, and eight satellite wells and a manifold center were installed by Petrobras in Brazil using the dry wellhead chamber system.

3. The disadvantages of these systems are:

a) safety of maintenance personnel is always a concern.

b) to guard against flooding, all equipment is subsea rated.

c) the chambers are expensive to fabricate, place limitations on the production equipment arrangement, and add operating cost to maintain the chamber itself.

d) the risk of serious problems is high if the chambers are ever damaged.

e) maintaining the man transfer capsule and a trained crew is expensive.

4. These disadvantages have made this type of system virtually obsolete. Even though several hundreds of successful maintenance jobs have been done with no significant accidents, the psychological problems of sending men into a subsea chamber with a live well or high pressure hydrocarbon piping was a deterrent to the use of a dry system. As wet subsea equipment became more widely developed and the reliability of the same increased, these dry chamber concepts fell from consideration by the industry.

5. Manned diving suits have also been developed. One concept permits the man to walk and in another, the man controls propellers to move. In both



cases, the pilot puts his hands through articulated arms in the suit and operates crude tools. This attempt to encapsulate man to do the work that divers would normally do has been successful for tasks such as untangling guidelines and for observation. While a few of these systems are still in use, they have been largely replaced by the small remote operated vehicles (ROV).

6. Manned Submarines and tethered bells were equipped with manipulator arms of varying sophistication during the mid-70s. Manned bells were popular for supporting deepwater drilling operations for several years. As underwater television improved, these too have been replaced by the ROV. Submarines were never very popular, although they have been promoted heavily. They cannot handle useful loads or do heavy work because of power limitations. Their main use, which continues, is pipeline survey work.

6.2.5. Maintenance Operations

1. Vertical running tools are the best maintenance method for installing or retrieving objects which are heavy, but small enough to pass through a drilling rig moon pool. These tools can be guided into place by use of guidelines, or can be used without guidelines. In guidelineless systems, an ROV is normally used to observe the operation, to provide minor positioning assistance.

2. ROV's can be economic alterna tives to divers for some installation and maintenance operations. In addition, they can eliminate the hazards to human life associated with diving operations. ROV's can be used to observe, to attach or release lines, to make up connectors, and provide orientation subsea. For example, a subsea choke or control module can be packaged to be installed and retrieved vertically. An ROV can be used to attach a lift line, to install guidelines and to release a connector or clamp so that the device can be lifted. During replacement, an ROV can guide those relatively small objects into place as they are lowered, and make-up a connector or clamp. Also, an ROV can be used to attach lifting slings to larger objects such as a manifold, for replacement from a crane barge.

3. ROV's are also commonly used to operate manual valves and adjustable chokes, and manual overrides on valves and connectors. Standard ROV valve interface equipment has been developed, is available from various suppliers of ROV's and is described in API RP 17A. Interface requirements for the Mobil developed ROV Intervention System tool packages are provided in Appendix A to Mobil E&P Engineering Guides MP 65-P-01 Subsea Trees - Diver and ROV Assist and MP 65-P-04 Subsea Templates and Manifolds.

4. ROV's have also been considered, but not yet used, to replace individual valves, TFL Diverter actuators, and chokes in manifolds, trees, and other



systems, and to replace seal plates in flowline connectors. Providing the equipment is designed to be ROV replaceable. These tasks can obviously be done by an ROV.

5. The installation and maintenance of trees, manifolds, flowline connectors, and remote controls are discussed in more detail in the specific sections dealing with these subsystems.


Appendix A–Nomenclature

1. Diverless System

A system of subsea components or subsystems designed or configured to be installed, maintained, and operated remotely without the use of divers. Diverless system may also include some ROV Assist Components and Subsystems.

2. Diver Assist System

A system of subsea components or subsystems designed or configured to be installed and maintained with the use of divers. These systems are generally operated remotely, however divers may operate some back-up or contingency functions.

3. ROV Assist System

A system of subsea components or subsystems designed or configured to be remotely connected, operated, or maintained by the use of a Remotely Operated Vehicle (ROV).

4. Subsea Well Template

A seabed founded structure that provides a guide for drilling and/or support for other subsea equipment, and provisions for establishing a foundation (piled or gravity base). A subsea well template is used to group several subsea wells at a single location. The template maybe unitized or modular in design.



5. Riser Base Manifold (RBM)

A template system which supports a marine production riser or loading terminal, and which serves to react loads imposed on the riser throughout its service life. This type of template may also include provisions for pipeline connections from several subsea well templates or other well production facilities.

6. Pipeline End Manifold (PLEM)

A template system used to support a manifold and pipeline connection equipment necessary to collect and distribute produced or injected from multiple sources to a single production facility.

7. Production Riser

Production Riser - A system of fluid conduits between seafloor equipment and surface production facilities for the sole purpose of transporting produced and/or injected fluids. The fluid conduits may be rigid or flexible pipe. The risers and support structures may also provide support for auxiliary lines and control umbilicals.

8. Floating Production Facility (FPF)

A ship, semi-submersible, or other hull form surface vessel equipped with production facilities to collect, process, and distribute produced or injected fluids for the service life of the subsea production system.

9. Production Control System (PCS)

The production control system provides the means to safely control operation of the tree. Production control functions typically include opening/closing downhole, tree and flowline valves, control subsea chokes, shut in production due to abnormal flow conditions, and operate production related utility functions.



10. Installation/Workover Control System (IWCS)

An installation /workover control system provides the means to control the subsea equipment functions for:

1. Initial installation and testing of the subsea tree.

2. Operations during vertical reentry for well servicing.

3. Retrieval and/or reinstallation of the tree for major well workover.

Installation and workover controls are generally designed to actuate all of the normal production functions, as well as functions restricted to installation and workover. Examples of restricted functions are connector latch/unlatch, vertical well bore access, and DHSV control line isolation valve open/close.

11. Satellite Subsea Tree

Is an individual assembly of remotely controlled valves to interrupt or direct wellstream flow when necessary for operational or safety reasons. The tree provides pressure integrity between the wellhead and flowline that transports fluids to a surface facility.

12. Mudline Suspension System

A drilling system consisting of a series of housings used to support casing strings at the mudline, installed from a bottom-supported rig using a surface BOP. Mudline casing suspension systems are designed to be used with bottom supported drilling rigs. They can be completed with a subsea tree if the proper adaptation is made. An adaptor is provided to give a profile for the tubing hanger and an attachment profile for the tree.

13. Subsea Wellhead System

A drilling system consisting of a series of housings, usually a conductor housing and a wellhead housing which is pressure containing that provides a means for suspending and sealing the well casing strings installed during a floating drilling operation. The subsea wellhead supports and seals casing strings, supports the blowout preventer stack (BOP) during drilling and workover operations and the



tree after completion. The subsea wellhead is designed to accommodate casing landing, sealing and completion operations remotely from the surface.

14. Underwater Safety Valve (USV)

An automatic valve assembly (installed at an underwater wellhead location) which will close upon loss of power supply.

15. Protective Structure

A Protective Structure to protect the tree or other subsea equipment from commercial fish activity, anchor and anchor line damage, and dropped objects. The structure may be constructed of steel or concrete and is often designed to deflect objects as well as absorb impact energies.


Appendix B–Design Basis

1. General

1.1.

The production system to be implemented shall use only commercially proven and available technology, equipment and procedures. Exceptions are if the new technology is absolutely necessary or if the added risk can be defined and is justified by clearly defined benefits. The equipment and procedures shall be demonstrated in tests simulating as closely as possible the actual conditions and planned use for the system.

1.2.

The system shall be designed for the production capacity specified below. However, design options shall be evaluated which provide flexibility to increase or decrease capacity, or to modify the system to adapt to changes in field requirements found during development, with minimum initial cost impact.

1.3.

Cost of the system shall be optimized considering "life of the field" economics and operability (ability of traditional personnel and infrastructure to reliably operate), maintainability, and reliability.

1.4.

Are all procedures to be simulated on land for maximum practical function test of equipment and for personnel training before offshore installation?

1.5.

SPPE-1 to be required for subsea tree valves and OCS certificates to be required for subsurface safety valves?



1.6.

Are producing wells to be switched to injection, or producing oil wells to be converted to gas lift?



2. Reservoir Characteristics

2.1. Recoverable Reserves

2.1.1. Liquid

2.1.2. Gas

2.2. Field Producing Life

2.3. Geology

2.3.1. Rock Type

2.3.2. Age

2.4. Degree of Consolidation

2.5. Depth Subsea Level

2.5.1. Reservoir depth

2.5.2. Thickness of producing interval

2.6. Productivity (PI) or Injectivity (II) Index (bbls or mcf/psi Drawdown)

2.7. Porosity

2.8. Areal Extent

2.9. Fluid Contacts



2.9.1. Gas/Oil

2.9.2. Oil/Water

2.10. Pressure

2.10.1. Bottomhole

2.10.2. Wellhead

2.10.3. Water or Gas Injection

2.11. Temperature - Bottomhole

2.12. Drive Mechanism (Gas, Water)

2.13. Drainage Area per Well

3. Fluid Properties

3.1. Type Fluid

3.1.1. Oil

3.1.2. Gas

3.1.3. Water

3.2. Gas Oil Ratio (GOR), cf/bbl, or Condensate Ratio (bbl/mmcf)

3.3. Fluid Gravity (API)

3.3.1. Oil



3.3.2. Gas

3.4. Fluid Viscosity

3.4.1. Gas

3.4.2. Liquid

3.5. Bubble Point

3.6. Wax Content of Liquid

3.7. Cloud Point

3.8. Pour Point

3.9. Gas Composition

3.9.1. Carbon dioxide

3.9.2. Nitrogen

3.9.3. Methane

3.9.4. Ethane

3.9.5. Propane

3.9.6. n-butane

3.9.7. Isopentane

3.9.8. n-pentane

3.9.9. Hexane

3.9.10. Heptane plus



3.9.11. Molecular weight C 7+

3.9.12. H2S

4. Reservoir Management/Production Profiles

4.1. Well Pattern (by Zones)

4.2. Number of Wells and Types of Well (Oil, Gas, Water Injection or Gas Injection)

4.3. Completion Sequence for Wells

4.4. Dual or Single Completion Requirements

4.5. Recompletion Schedule

4.5.1. Schedule by well

4.5.2. Need to convert producing wells to gas lift or to water or gas injection? (Remote or local switch after well completions?)

4.6. Production Profile for "Typical" or Individual Well(s) - Life of Well

4.6.1. Produced Fluid

1. Oil or gas

2. Water

4.6.2. Injection

1. Gas



2. Water

4.6.3. Gas (for gas lift gas)

4.7. Design Flow Rates (Total Field)

4.7.1. Produced Fluid

1. Oil or gas

2. Water

4.7.2. Injection

1. Gas

2. Water

4.7.3. Gas (for gas lift gas)

4.8. Pressure Maintenance and/or Gas Lift Start Date

4.9. Inlet Pressure of 1st Stage Separator

4.10. Maximum Drawdown Allowable (psi)

4.11. Gas Deliverability

5. Drilling System

Drilling rigs may be defined by management for long term objectives in a specific geographic area - especially remote areas of the world

5.1. Floating Rig

5.1.1. Hull Type & Shape

1. Ship or semi



2. Hull (draft, number column and bracing (if semi))

3. Existing station keeping

5.1.2. Blowout Preventer (BOP)

1. Size

2. Pressure rating

3. "Foot print" dimensions

4. Guideline or guidelineless

5.2. Jack-Up Rig General Arrangement

6. Location Parameters

6.1. Geographic Area (Map of Surrounding Area)

6.1.1. Location of nearest oil or gas and condensate pipelines

6.1.2. Location of nearest platform processing fluids of the character of expected produced fluids

6.1.3. Location of company operated facilities in area

6.1.4. Location of joint interest facilities in the area

6.1.5. Distance to Point of Sale

1. Liquid

2. Gas



6.2. Method of Transport/Disposal

6.2.1. Liquid

6.2.2. Gas

6.3. Water Depths (Prefer Contour Map of Area)

6.4. Seafloor Temperature

6.5. Weather Criteria (Waves, Wind, Current Profiles and Direction) Occurrence

6.5.1. 100 year

6.5.2. 50 year

6.5.3. 25 year

6.6. Ocean Current

6.6.1. Surface - tidal or seasonal

6.6.2. Deep ocean - normal profile

6.6.3. Deep ocean - loop current

6.7. Bottom Conditions

6.7.1. Soils

6.7.2. Visibility

6.7.3. Contour

1. Slope

2. Distance to shallow water



6.8. Near Bottom Activity (Fishing, Dredging, Shipping, etc.)

6.9. Sales Requirements

6.9.1. Liquid

1. Vapor pressure

2. Water content

6.9.2. Gas

1. Liquid content

2. Corrosivity level

3. Dewpoint



7. Government Regulations

7.1. Design Codes and Certification (API, DNV, NPD, NACE)

7.2. Well Control (Drilling, Temporary Abandonment, etc.)

7.3. Safety Requirements

7.4. Discharge

7.4.1. Drilling mud

7.4.2. Water-oil content

7.4.3. Control fluids

7.4.4. Gas flaring allowed?

7.4.5. Other

7.5. Subsurface Safety Valve

7.5.1. Certification requirements

7.5.2. Maximum setting depths

7.6. Protection of Seafloor Equipment

7.6.1. Flowline and/or umbilical trenching or burial

7.6.2. Tree, manifold or template

7.7. Structural Design Requirements



7.7.1. Damage control

7.7.2. Over trawl ability

7.8. Operating Procedures

7.8.1. Failure detection

7.8.2. Reporting

7.8.3. Emergency shut down procedures

7.8.4. Supervision required

7.8.5. Instrumentation (wellhead and bottom hole pressures and temperatures?)

7.8.6. Frequency of monitoring subsea sensors

7.9. Inspection, Maintenance, Repair Requirements (Testing and Frequency)

7.10. Drilling, Completion, Workover

7.11. Permitting

7.11.1. Drilling

7.11.2. Development

7.11.3. Operating

7.11.4. Abandonment

7.12. Abandonment Requirements

7.12.1. Well plugging



7.12.2. Clearing seafloor

7.12.3. Post abandonment surveys

7.12.4. Transport/disposal of salvaged equipment

8. Companies Guidelines

8.1. Applicable Company Standards

8.2. Safety Requirements

8.3. Pollution Control

8.3.1. Acceptable type/quality of drill fluids dumped to sea

8.3.2. Acceptable quality of water dumped to sea

8.3.3. Acceptable quantity and type of hydrocarbons discharged to sea? (zero?)

8.3.4. Allowable quantities of oil or gas to be flowed.

8.4. Drilling/Completion-Well Control (Size, Pressure Rating, Use Procedures of BOP's; Cuttings Management; Casing Size, Pressure Rating, Setting Depths, Number of Strings, etc.)

8.5. Directional Drilling Rules

8.6. Number of Barriers to Pressure



8.7. Design Pressure/Codes or Standards

8.8. Simultaneous Drilling/Completion/Well Servicing and Production Rules

8.9. Tree Valving (Number of Master Valves, etc.)

8.10. Subsurface Safety Valves - Production String Only, or Annulus and Production Strings?

8.11. Protection (Structural or Burial/Gloryhole)

8.11.1. Flowline/umbilicals

8.11.2. Pipeline

8.11.3. Seafloor equipment

8.12. Controls Response Time

8.13. Safety Shut-Down Procedures

8.14. Instrumentation Wellhead and Bottom Hole Pressures and Temperatures

8.15. Inspection and Maintenance Procedures and Frequency

8.16. Quality Assurance/Quality Control Requirements

8.17. Spares Philosophy


Appendix C–Government Regulations and Industry Standards (Applying Specifically to Seafloor Completed Wells)

Indonesia No Regulations specifically to Seafloor wells. Government approves drilling plans , fabrication shall be certified by approved agency (i.e., Lloyds, etc.), government surveys quality control and witness pipeline and flowline pressure testing, abandoned facilities shall be cleared to the seafloor and there are strict laws against industrial pollution.

Netherlands No regulations specific to oil wells. The government agency, "Supervision of Mines" administers "Mining Regulations Continental Shelf (MRCS), and approves offshore oil development projects on a case by case basis.

Norway ACTS, Regulations and Provisions for the Petroleum Activity. Draft Guidelines for Production and Injection Wells on the Seabed. Equipment and Operations in the Petroleum Activity.

UK Offshore Installations: Guidance on design and construction.

United States Oil, Gas and Sulphur operations in the Outer Continental Shelf 30 CFR 250 May 31, 1988


Appendix D–Functional Requirements

Functional requirements are those imposed on the system by the Mobil engineer(s) to satisfy the criteria specified in the Design Basis. These requirements are within the control of the Mobil engineer(s) and shall be established by evaluation of alternatives.

The following list of functional requirements shall be taken as examples. It is not intended to be complete. Also, certain items included here are also included in the Design Basis.



1. General

1.1. Life of Production/Injection Equipment (May or May not Equal Field Life)

1.2. Availability Goals - System Meantimes between Production Loss and Meantimes between Repair

1.3. Quality Assurance/Quality Control Philosophy

1.4. Design Wellhead Pressure - Flowing Wellhead Temperature

1.4.1. Shut-in

1.4.2. Production

1.4.3. Injection

1.4.4. Well servicing

1.5. Damage Protection Criteria

1.5.1. Impact loads and directions

1.5.2. Ice scour depth

1.5.3. Current bottom scour depth

1.6. Spares Philosophy



1.7. Maintainability Criteria; Components Interchangeability - What Components are Replaceable

1.7.1. Individual components

1.7.2. Major subsystems

1.7.3. Every piece except wells and base structures

1.8. Materials Selection - All Components of Each Subsystem Shall be Compatible with Every Fluid it Will Come in Contact with During Testing, Installation, and Operation

1.8.1. Seawater

1.8.2. Produced fluids

1.8.3. Drilling fluids

1.8.4. Completion fluids

1.8.5. Control fluids

1.8.6. Workover and kill fluids

2. Drilling/Workover

2.1. Drilling Program

2.1.1. Directional and/or horizontal drilling policy

2.1.2. Allowable well deviations



2.1.3. Bore holes (size, depth, where and how to take returns)

1. Conductor hole

2. Surface hole

3. Intermediate hole

4. Production hole

2.2. Casing Program (Size, Grade, Weight, Connection Type, Setting Depths)

2.2.1. Conductor string

2.2.2. Surface string

2.2.3. Intermediate casing/liner

2.2.4. Production casing

2.3. Wellhead (Depends on Drilling and Surface Process Vessel Type)

2.3.1. Size, pressure rating

2.3.2. Type

1. Marine wellhead

2. Tie-back (mudline suspension)

a) Subsea wells

b) Surface trees

3. Seals (metal, resilient, or combination)



2.4. Drilling Rig

2.4.1. Depth rating (for drilling)

2.4.2. Water depth rating

2.4.3. Rig type (jackup, drillship, semi, etc.)

2.4.4. Guidelines or guidelineless

2.4.5. Station keeping system (DP or moored)

2.4.6. ROV support requirements

2.4.7. Well control and safety requirements

2.4.8. Drive mechanism

2.4.9. Arrangement of derrick, tensioners and cranes and access to the moonpool (to move trees, BOP, riser, handle template, etc.)

2.4.10. Contracting procedures

2.4.11. BOP

1. Size

2. Pressure rating

3. Foot print



2.5. Completion/Workover System

2.5.1. Riser (size, number of bores, type { composite, integral, non-integral}).

2.5.2. Lower riser package and workover BOP ( wireline, coiled tubing, work string); includes connector and controls interface.

3. Installation of Subsea Equipment

3.1. Site Survey Requirements

3.2. Diver Assist, Diverless (ROV assist)

3.3. Weather Limits

Flowline

Well Completion Initiation Laying Template or Manifold Installation

Wave Height (or vessel motion

Wind

Ocean Currents



3.4. Subsea Template or Manifold Azimuth Orientation and Leveling

3.5. Transportation Weight or Size Limitations - Fabrication Site to Integration Site to Offshore Site

3.6. Ability to Test Flowlines After Laying but Before Connection

3.7. Ability to Test Flowline Connections

3.8. Ability to Production Test Each Producing Well to the Drilling Rig Immediately After the Downhole Completion Equipment is Installed.

3.9. Well to be Left "Live" or "Dead" When Rig Moves? (Specify Procedure for Chosen Condition)

3.10. Ability to Test Control Umbilicals - Before and After Connection

3.10.1. Hydraulic

3.10.2. Electric

3.11. Flowline and Umbilical Burial Requirements

4. Production Operations

4.1. Simultaneous Well Drilling Completion or Workover and Production Rules



4.1.1. Seafloor wells

1. What wells shut in while landing BOP or riser? (none, all, or near neighbors)

2. What wells are shut-in while drilling or working near a well? (zero, or near neighbor)



4.1.2. Surface wells

4.1.3. Surface process facilities

4.2. Well Unloading and Cleanup

4.2.1. Method (swab, or circulate or gas lift using second tubing (if available) or macaroni or coiled tubing).

4.2.2. Maximum difference between reservoir pressure and wellbore bottom-hole pressure (drawdown).

4.3. Well Killing Procedure

4.3.1. Bull-head into tubing or annulus.

4.3.2. Circulation through second tubing (if available), or by use of macaroni or coiled tubing.

4.3.3. Through or bypass choke.

4.3.4. Injection rate, design maximum.

4.4. Start-Up Procedure

4.5. Well Testing Procedure

4.6. Pressure Control

4.6.1. Ability to bleed annulus pressure

4.6.2. Procedure for securing wells - temporary

4.6.3. When is BOP required?

4.6.4. Is downhole secondary circulation path needed?



4.7. Production Control

4.7.1. Free flow to headers

4.7.2. Chokes? none; diver or TFL installed fixed; or diver, ROV or remote controlled adjustable.

4.7.3. Which functions to be remotely controlled individually to produce, test the wells and troubleshoot failures to within one replaceable module.

4.7.4. Response time

1. Downhole valves

2. Tree valves

3. Manifold valves

4.7.5. Frequency of valve/choke operation (daily, weekly?) minimum time between use.

4.8. Production Monitoring

4.8.1. Subsea metering

4.8.2. Well testing

1. Frequency

2. Individual or by difference



4.8.3. Which data to be monitored remotely (example: choke position, valve position, production/injection and annulus wellhead pressure, downhole pressure and temperatures, choke delta pressure or differential pressure).

4.8.4. Measurement response and monitoring cycle length.

4.8.5. Frequency of subsea sensor interrogation.

4.8.6. Leak detection requirements.

4.9. Shut Down Procedures

4.9.1. Normal production shut down

4.9.2. Emergency shut down

1. Short duration

2. Long duration

4.10. Failure Response

4.10.1. Priority of failure

4.10.2. Classification of failure

4.10.3. Response

4.11. Corrosion Control

4.11.1. Metallurgy

4.11.2. Chemical treatment

1. Batch size and frequency

2. Continuous - injection point and rates



4.11.3. Monitoring approach

4.12. Paraffin Control

4.12.1. Insulation of pipes

4.12.2. Chemical (injection point and volume)

4.12.3. Pigging (type of pigs, frequency)

4.13. Scale

4.13.1. Chemical - when injected, method

4.13.2. Pigging (type of pig, frequency)

4.14. Viscosity Control

4.14.1. Insulation

4.14.2. Diluent injection point and rate

4.15. Hydrate Control

4.15.1. Insulation?

4.15.2. Chemicals

4.16. Flowline Operation

4.16.1. Flushing

4.16.2. Dehydration

4.16.3. Pigging (type pig, frequency)

4.17. Chemical Injection Supply (On Surface)



4.18. Surface Facility Minimum inlet Pressure

4.19. Interface with Surface Process Facility Controls

4.19.1. Control fluid storage

4.19.2. TFL tool storage and fluids storage/pumping requirements

4.19.3. Chemical injection storage/pumping requirements

5. Inspection and Maintenance

5.1. Downhole

5.1.1. Bottom hole pressures - frequency wireline or small work string

5.1.2. Tubing inspection

5.1.3. Tubing replacement

5.1.4. Downhole safety valve

5.1.5. Well stimulation (acid or detergent wash, diesel or cement inject, etc.)

5.2. Seafloor Equipment

5.2.1. Visual inspection - ROV

5.2.2. Individual components replacement

5.2.3. Module replacement



5.3. ROV Requirements

5.3.1. Interface with valve, choke

5.3.2. Interface with hydraulic function

5.3.3. Hydraulic power requirement

5.3.4. Thrust requirement

5.3.5. Payload

5.3.6. Dimension

5.3.7. Surface vessel requirements

5.4. Precautions Prior to Performing Maintenance

5.4.1.

Pressure containing conduits shall be bled down to ambient pressure.

5.4.2.

If possible, hydrocarbons and other potentially contaminating fluids shall be displaced from flow circuits.

5.4.3.

Electrical circuits shall be de-energized if they pose a hazard to divers.

5.5.

Lowering and recovering of tools and modules on workstrings or cables shall be executed with care to minimize risk of damage to seafloor equipment.

5.6.

The subsea system shall be thoroughly tested before being put back to service, after a maintenance operation is completed.



5.7. TFL System Requirements

5.7.1. Tubing mechanical specifications

5.7.2. TFL diverters - if multiwell system

5.7.3. Downhole completion to allow circulation if downhole operation to be provided

5.7.4. Tool position detector (polished sections, pressure surges, etc.).

5.7.5. Surface facilities - fluid; surface pumping, storage, etc.)

5.8. Major Subsea Component Repair

5.8.1. Flowline/manifold flushing requirements

5.8.2. Approach (in-situ repair or replacement of components or modular replacement)

6. Abandonment Requirements

6.1. Well Plugging Requirements

6.2. Government Approvals and Permits Required

6.3. Requirements for Removal of Equipment and Structures and Clearance of Seafloor

6.4. Abandonment Survey Requirements



6.5. Requirements for Transport and/or Disposal of Salvaged Hardware

ept 10-t-04 subsea production systems

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