Api rp 17a 2017 (american petroleum institute)

Microsoft Word 17A e5 (master) Design and Operation of Subsea Production Systems—General Requirements and Recommendations API RECOMMENDED PRACTICE 17A FIFTH EDITION, MAY 2017 Special Notes API publica[.]

Design and Operation of Subsea

Production Systems—General

Requirements and Recommendations

API RECOMMENDED PRACTICE 17A

FIFTH EDITION, MAY 2017

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is not intended in any way to inhibit anyone from using any other practices

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is solely responsible for complying with all the applicable requirements of that standard API does not represent, warrant, or guarantee that such products do in fact conform to the applicable API standard

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Copyright © 2017 American Petroleum Institute

Nothing contained in any API publication is to be construed as granting any right, by implication or otherwise, for the manufacture, sale, or use of any method, apparatus, or product covered by letters patent Neither should anything contained in the publication be construed as insuring anyone against liability for infringement of letters patent.Shall: As used in a standard, “shall” denotes a minimum requirement in order to conform to the specification.

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to conform to the specification

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iii

1 Scope 1

2 Normative References 1

3 Terms, Definitions, Acronyms, Abbreviations, and Symbols 2

3.1 Terms and Definitions 2

3.2 Acronyms and Abbreviations 3

4 Subsea Production Systems 5

4.1 General 5

4.2 System Configuration 5

4.3 Overview of API 17-series Documents by Categories 6

5 Systems Engineering 10

5.1 General 10

5.2 Process 10

5.3 Systems Engineering Inputs 10

5.4 Systems Engineering Approach 14

5.5 System Engineering Analyses and Evaluations 16

5.6 Systems Engineering Documentation 20

5.7 System Reviews 20

6 Equipment Design Requirements 21

6.1 General 21

6.2 Safety 21

6.3 Environmental Conditions 22

6.4 Materials and Corrosion Protection 22

6.5 Structural Analysis 22

6.6 Piping Analysis 23

6.7 Dropped Objects and Fishing Gear Loads 23

6.8 Lifting Devices, Padeyes, and Unpressurized Structural Components 24

6.9 Colors and Marking 24

6.10 Tolerance Evaluation 24

6.11 General Requirements for Transportation, Preservation, and Storage 25

6.12 Load-out Planning 25

6.13 Installation Planning 26

6.14 Maintainability 27

7 Technology Management 27

7.1 Development and Qualification 27

7.2 Obsolescence Management 27

8 Manufacture through Commissioning 28

8.1 Reliability, Integrity, and Technical Risk Management 28

8.2 Manufacture 28

8.3 Assembly 28

8.4 Testing 29

8.5 Installation 30

8.6 Commissioning 30

9 Operations 30

9.1 Integrity Management 30

9.2 Production Management 31

v

9.3 Seabed and Surface Equipment Maintenance 31

9.4 Failure Reporting 32

10 Well Intervention 32

11 Decommissioning 32

Annex A—Generic Testing Terms for Use in API 17-series Documents 33

Bibliography 42

Figures 1 Basic Subsea Systems 6

Tables 1 Dropped Object Loads 24

2 Fishing Gear Loads 24

vi

This document has been prepared to provide general requirements, recommendations, and overall guidance for the user to the various areas requiring consideration during development of a subsea production system for the petroleum and natural gas industry The intention is to facilitate and complement the decision process rather than to replace individual engineering judgment and, where requirements are nonmandatory, to provide positive guidance for the selection of an optimum solution.

The development of this document is based on input from API Subcommittee 17 (Subsea Production Systems) technical experts The technical revisions have been made in order to accommodate the needs of industry and to move this specification to a higher level of service to the petroleum and natural gas industry

This document is not intended to inhibit a manufacturer from offering, or the purchaser from accepting, alternative equipment or engineering solutions for a specific application This may be particularly applicable where there is innovative or developing technology

Users should be aware that the current revision of this document no longer includes much material that was considered to be tutorial in nature The majority of this material can now be found in API Technical Report 17TR13

vii

The complete subsea production system comprises several subsystems necessary to produce hydrocarbons from one or more subsea wells and transfer them to a given processing facility located offshore (fixed, floating,

or subsea) or onshore, or to inject water/gas through subsea wells

This document, given its broad scope, has a systems engineering section The purpose of this section is to help ensure consistency across the various subsystems

If requirements as stated in this document are in conflict with, or are inconsistent with, requirements as stated

in other API 17-series documents, then the specific requirements in the subsystems series document(s) take precedence

2 Normative References

The following referenced documents are indispensable for the application of this document For dated references, only the edition cited applies For undated references, the latest edition of the referenced document (including any amendments) applies

API Recommended Practice 17B, Recommended Practice for Flexible Pipe

API Recommended Practice 17C, Recommended Practice on TFL (Through Flowline) Systems

API Specification 17D, Design and Operation of Subsea Production Systems―Subsea Wellhead and Tree

Equipment

API Specification 17E, Specification for Subsea Umbilicals

API Standard 17F, Standard for Subsea Production Control Systems

API Recommended Practice 17G, Recommended Practice for Completion/Workover Risers

API Recommended Practice 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems API Specification 17J, Specification for Unbonded Flexible Pipe

API Specification 17K, Specification for Bonded Flexible Pipe

API Specification 17L1, Specification for Flexible Pipe Ancillary Equipment

API Recommended Practice 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment

API Recommended Practice 17N, Recommended Practice for Subsea Production System Reliability and

Technical Risk Management

API Standard 17O, Standard for Subsea High Integrity Pressure Protection Systems (HIPPS)

API Recommended Practice 17P, Design and Operation of Subsea Production Systems―Subsea Structures

and Manifolds

API Recommended Practice 17Q, Subsea Equipment Qualification―Standardized Process for

Documentation

API Recommended Practice 17R, Recommended Practice for Flowline Connectors and Jumpers

API Recommended Practice 17S, Recommended Practice for the Design, Testing, and Operation of Subsea

Multiphase Flow Meters

API Recommended Practice 17U, Recommended Practice for Wet and Dry Thermal Insulation of Subsea

Flowlines and Equipment

API Recommended Practice 17V, Recommended Practice for Analysis, Design, Installation, and Testing of

Safety Systems for Subsea Applications

API Recommended Practice 17W, Recommended Practice for Subsea Capping Stacks

API Specification Q1, Specification for Quality Management System Requirements for Manufacturing

Organizations for the Petroleum and Natural Gas Industry

API Specification Q2, Specification for Quality Management System Requirements for Service Supply

Organizations for the Petroleum and Natural Gas Industries

3 Terms, Definitions, Acronyms, Abbreviations, and Symbols

3.1 Terms and Definitions

For the purposes of this document, the following definitions apply

Test conducted to verify that the specified requirements, for a product that has been transported from one site

to another, are still fulfilled

3.1.6

system function test

SFT

Test conducted to validate that the requirements for a specific intended use or application, of a set of products

that form a “complete” functional system, have been fulfilled

3.1.7

system integration test

SIT

Test conducted to validate that the requirements for a specific intended use or application, of a set of products

that form an integrated system, have been fulfilled

Test conducted to confirm that the specified requirements for a product have been fulfilled

3.2 Acronyms and Abbreviations

CRA corrosion-resistant alloy

C/WO completion/workover

EFAT extended factory acceptance test

EFL electrical flying lead

FAT factory acceptance test

FMEA failure modes and effects analysis

FMECA failure mode, effects, and criticality analysis

HAZOP hazard and operability study

HFL hydraulic flying lead

HIPPS high integrity pressure protection system

HPHT high-pressure high-temperature

HPU hydraulic power unit

HSE health, safety, and environment

ICT interchangeability test

IWOCS installation workover control system

LRFD load and resistance factored design

MCS master control station

MODU mobile offshore drilling unit

MPFM multiphase flow meter

NORM naturally occurring radioactive materials OEM original equipment manufacturer

OREDA Offshore Reliability Data

PDT predeployment test

P&ID piping and instrumentation diagram PLEM pipeline end manifold QRA quantitative risk assessment

RAM reliability, availability, and maintainability ROT remotely operated tool

ROV remotely operated vehicle

SCM subsea control module

SFT system function test

SIT system integration test

SRT site received test

SUDU subsea umbilical distribution unit

SUT subsea umbilical termination

TBD to be determined

TCRT tree cap running tool

THRT tubing hanger running tool

TRT tree running tool

USV underwater safety valve (see API 6A [17]) VIV vortex induced vibration

WSD working stress design

4 Subsea Production Systems

4.1 General

Subsea production systems can range in complexity from a single satellite well with a flowline linked to a fixed platform or an onshore installation, to several wells on a template or clustered around a manifold producing via subsea processing/commingling facilities, and transferring to a fixed or floating facility, or directly to an onshore installation

Subsea production systems can be used to develop reservoirs, or parts of reservoirs, which require drilling of the wells from more than one location Deepwater conditions can also inherently dictate development of a field by means of a subsea production system, since traditional surface facilities such as on a steel-piled jacket might be either technically unfeasible or uneconomical due to the water depth

Subsea equipment may also be used for the injection of water/gas into various formations for disposal and/or

to provide pressure maintenance in the reservoir

4.2 System Configuration

The elements of the subsea production or injection system may be configured in numerous ways, as dictated

by the specific requirements and the operator strategy For a description of various subsystems and components that can be combined to form a complete subsea system, refer to API 17TR13 Figure 1 provides

an overview of a basic subsea system with references to the relevant API 17-series documents

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— routine production operations, for both producing/injecting and shut-in modes as well as for service modes such as circulating of flowlines and pigging;

— well intervention activities, involving reentry into a well and or retrieval of a tree;

— maintenance activities, such as replacement of a subsea choke;

— decommissioning activities

Similarly, for new subsea projects the barrier philosophy should cover all of the pressure-containing elements

of the system, from the reservoir(s) through to the first block valve(s) at the receiving/injecting facilities on the permanent host facility or the mobile offshore drilling unit (MODU)/intervention vessel, as applicable

In situations where a project/field specific barrier philosophy (as described above) does not exist (e.g for preexisting subsea production facilities), then it is advisable to develop an operating barrier philosophy or generic barrier philosophy to cover at the least the barrier requirements during “routine” operation of the system, i.e production, shut-ins and barrier testing A case-specific barrier philosophy can then be developed prior to any intervention, workover, etc., activity to address those elements not covered in the operating/generic barrier philosophy document

Given the wide variety of possible field characteristics and equipment configurations, as well as the varying requirements of existing local regulations combined with field operator preferences, it is not possible or desirable to provide specific guidance that could be used as a standard barrier philosophy Notwithstanding this constraint, it can be stated that

— the barrier philosophy for each subsea production system shall be consistent with all applicable local regulations;

— a barrier shall be testable;

— while some aspects of a generic barrier philosophy may be applicable to many subsea production systems, each specific situation should be evaluated on a case-by-case basis to at least confirm that the generic barrier philosophy is appropriate and applicable;

— development of both generic and case-specific barrier philosophies requires the use of experienced personnel and typically involves the use of one or more risk assessment techniques such as hazard and operability study (HAZOP), failure modes and effects analysis (FMEA), quantitative risk assessment (QRA), task analysis, and/or scenario-based risk assessment;

— the barrier philosophy should be clearly communicated to all relevant personnel, including design engineers, equipment suppliers, and field personnel;

— the guidance/requirements contained in the barrier philosophy should be clear and concise, i.e not open

to different interpretations and/or misinterpretation

The following documents provide relevant information regarding barrier considerations for subsea equipment:

— API 96 [24];

— IMCA D044 [50];

— NORSOK D-010 [70];

— Oil & Gas

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of the development to identify any key vulnerability The evaluation should cover the entire system over its life cycle, from the perforations through to and including the processing/storage/export facilities on the host facility [including the potential impact of flow assurance solutions (such as chemicals) on the exported fluids] at various phases of the development Additionally, for subsea tie-backs, the first-pass evaluation should include any “brownfield” assets that the new subsea development is tying into so the performance of the holistic system is considered

Various factors can have a significant influence on the flow assurance issues for a development, including:

— the hydrostatic head in the product lines/completion riser, under flowing and shut-in conditions;

— the insulating characteristics of the seabed soils;

— the seabed temperature profile;

— the seawater temperature and ambient air temperature profiles for risers and topside piping;

— the seabed terrain profile;

— planned and unplanned flowrate changes in individual lines (e.g due to natural well flowrate decline, redirection of a single well into a test line for metering purposes, shut-in of a well due to a mechanical failure, etc.);

— changes in the reservoir and/or produced fluid properties over the life of the facility (e.g reservoir pressure decline, commencement of sand production, increasing water cut, changes in gas-oil ratio, changes in oil API Gravity, etc.);

— the chemical compatibility of any chemicals introduced into the product streams, with the produced fluid, other chemicals being used, the materials of construction, and with the export route for produced fluids;

— subsea system configuration (including system insulation characteristics)

For those flow assurance issues identified as having the potential to significantly impact the performance of the system over its life cycle, further evaluation should be undertaken to predict the extent and severity of the problem and to identify possible prevention and remediation measures Such evaluation is best handled by a multidisciplinary team that can apply expert knowledge over the system life cycle

Two key elements in correctly assessing the impact of flow assurance issues on any given production system are as follows

— An accurate understanding of the properties of the fluids being produced This is typically based on a series of empirical observations and measurements using fluid samples collected during the exploration phase of the project

— The ability to accurately model the fluid flow from the sand face to the host facility, including prediction of the prevalent flow regimes as well as the detailed pressure and temperature profiles under both transient and steady-state conditions

The fluid-flow modelling is typically performed after the exploration wells are drilled and can be further improved upon as new information becomes available; however, deficiencies in the exploration-well fluid sampling program cannot be easily rectified once the rig has been demobilized from the site Hence, attention should be given to defining the requirements of the fluid sampling program and gathering adequate data for the optimization of future production facilities, prior to commencement of the drilling of exploration and/or appraisal wells

Determination of the fluid properties, combined with modelling of the fluid flow through the system, should provide sufficient data for an overall assessment of the above-mentioned issues Once this assessment is

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