Norway Well Testing System 5xw71

NORSOK STANDARD D-007 Edition 2, September 2013

Well testing system

This NORSOK standard is developed with broad petroleum industry participation by interested parties in the Norwegian petroleum industry and is owned by the Norwegian petroleum industry represented by the Norwegian Oil and Gas Association and The Federation of Norwegian Industries. Please note that whilst every effort has been made to ensure the accuracy of this NORSOK standard, neither the Norwegian Oil and Gas Association nor The Federation of Norwegian Industries or any of their will assume liability for any use thereof. Standards Norway is responsible for the istration and publication of this NORSOK standard. Standards Norway Strandveien 18, P.O. Box 242 N-1326 Lysaker NORWAY

Telephone: + 47 67 83 86 00 Fax: + 47 67 83 86 01 Email: [email protected] Website: www.standard.no/petroleum

Copyrights reserved © NORSOK. Any enquiries regarding reproduction should be addressed to Standard Online AS. www.standard.no

NORSOK standard

NORSOK standard D-007

NORSOK STANDARD

Edition 2, September 2013

D-007

Well testing system Contents 1 

Scope ..................................................................................................................................................... 3 

2 

Normative and informative references ................................................................................................... 3  2.1  Normative references ................................................................................................................... 3  2.2  Informative references ................................................................................................................. 5 

3 

, definitions and abbreviations ..................................................................................................... 6  3.1  and definitions ................................................................................................................... 6  3.2  Abbreviations ............................................................................................................................... 7 

4 

General principles .................................................................................................................................. 8 

5 

Functional requirements ......................................................................................................................... 8  5.1  General ........................................................................................................................................ 8  5.2  Products and services .................................................................................................................. 8  5.3  Performance and output .............................................................................................................. 9  5.4  Performance level ........................................................................................................................ 9  5.5  Process and ambient conditions .................................................................................................. 9  5.6  Operational requirements .......................................................................................................... 10  5.7  Maintenance requirements ........................................................................................................ 13  5.8  Layout and sea fastening requirements ..................................................................................... 13  5.9  Well test design report ............................................................................................................... 13 

6 

Specific requirements ........................................................................................................................... 15  6.1  General ...................................................................................................................................... 15  6.2  Non-anchored operations – dynamic positioning operations ..................................................... 15  6.3  Production clean-up ................................................................................................................... 16  6.4  Bleed-off ..................................................................................................................................... 16 

7 

Exceptions to standards ....................................................................................................................... 16  7.1  Exceptions to NORSOK standards ............................................................................................ 16  7.2  Exceptions to other standards ................................................................................................... 17 

Annex A (normative) Drill stem test tools system requirements.................................................................. 18  Annex B (normative) Landing string equipment system requirements ....................................................... 20  Annex C (normative) Surface equipment system requirements.................................................................. 22  Annex D (normative) Reservoir information data system requirements ..................................................... 27  Annex E (normative) Test tubing system requirements .............................................................................. 29 

Foreword The NORSOK standards are developed by the Norwegian petroleum industry to ensure adequate safety, value adding and cost effectiveness for petroleum industry developments and operations. Furthermore, NORSOK standards are, as far as possible, intended to replace oil company specifications and serve as references in the authorities' regulations. The NORSOK standards are normally based on recognized international standards, adding the provisions deemed necessary to fill the broad needs of the Norwegian petroleum industry. Where relevant, NORSOK standards will be used to provide the Norwegian industry input to the international

NORSOK standard

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standardization process. Subject to development and publication of international standards, the relevant NORSOK standard will be withdrawn. The NORSOK standards are developed according to the consensus principle generally applicable for most standards work and according to established procedures defined in NORSOK A-001. The NORSOK standards are prepared and published with by the Norwegian Oil and Gas Association, the Federation of Norwegian Industries, the Norwegian Shipowners' Association and the Petroleum Safety Authority Norway. NORSOK standards are istered and published by Standards Norway.

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1 Scope This standard describes functional, performance and operational requirements for temporary well testing, production clean-up and bleed-off equipment and systems used for hydrocarbon flow from exploration or production wells on both mobile units and fixed platforms.

2 Normative and informative references 2.1 Normative references The standards referred to below include provisions and guidelines that constitute provisions and guidelines for this NORSOK standard. Latest issue of the references shall be used unless otherwise agreed. Other recognized standards may be used provided it can be shown that they meet the requirements of the referenced standards. Table 1 – Normative references Standard

Title

Comments vs. NORSOK D-007

NORSOK D-001

Drilling facilities

NORSOK D-010

Well integrity in drilling and well operations

NORSOK S-001

Technical safety

NORSOK S-002

Working environment

NORSOK Z-015

Temporary equipment

EU 2006/42/EC on machinery

Directive 2006/42/EC on machinery

IEC 61508 (SIL)

Functional Safety of Electrical /Electronic/ Programmable Electronic Safety-related Systems

Handled via Norwegian Oil and Gas guideline 070 – Application of IEC 61508 and IEC 61511 in the Norwegian petroleum industry

IEC 61511 (SIL)

Functional safety - Safety instrumented systems for the process industry sector

Handled via Norwegian Oil and Gas guideline 070 – Application of IEC 61508 and IEC 61511 in the Norwegian petroleum industry

ISO 10407 (API RP 7G)

Petroleum and natural gas industries - Drilling and production equipment - Drill stem design and operating limits

ISO 10418

Petroleum and natural gas industries - Offshore production Installations - Analysis, design, installation and testing of basic surface process safety systems

ISO 10423 (API Spec. 6A)

Petroleum and natural gas industries - Drilling and production equipment. - Wellhead and Christmas tree equipment

ISO 10432 (API Spec. 14A)

Petroleum and natural gas industries - Downhole equipment Subsurface safety valve equipment

NORSOK standard

Covers lifting and electrical requirements

Equivalent to API RP 14C

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Standard

Title

Comments vs. NORSOK D-007

ISO 13628-11 (API RP 17B)

Petroleum and natural gas industries - Design and operation of subsea production systems - Part 11: Flexible pipe systems for subsea and marine applications

ISO 14310 (API Spec 11D1)

Petroleum and natural gas industries - Downhole equipment Packers and bridge plugs

ISO 15156 (ANSI/NACE MR0175)

Petroleum and Natural Gas Industries - Materials for use in H2S containing environments in oil and gas production

ISO 23251 (API RP 521)

Petroleum and natural gas industries - Pressure-relieving and depressurizing systems

API Spec, 5CT

Specifications for casing and tubing

API RP 14C

Recommended practice for analysis, Equivalent to ISO 10418 design, installation and testing of basic surface safety systems on offshore production platforms

API RP 44

Recommended Practice for Sampling Petroleum Reservoir Fluids

API RP 520

Recommended practice for sizing, selection and installation of pressure-relieving devices in refineries

ASME Section VIII Div. 1 and 2

Boiler and Pressure Vessel Code – VIII, Pressure Vessels

EN 13445

Unfired Pressure Vessels

This is based on BS 5500, updated and harmonized with the EU Machinery Directive.

PD 5500

Specification for unfired, fusion welded pressure vessels

This is the continuation of the former BS 5500.

ASME B31.3

Process piping

This is the old ANSI B31.3 Chemical plant and petroleum refinery piping

EN 13480

Metallic industrial piping

European equivalent to ASME B31.3

ASME B16.5

Pipe flanges and flanged fittings NPS 1/2 through NPS 24 metric/ inch standard

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ANSI/NACE MR0175 underwent a major revision in 2003, which cannot be bridged for older equipment. Equipment built before 2003 follows the old version of the standard, while equipment built after the major revision follows the latest edition of the standard.

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2.2 Informative references Table 2 – Informative references Standard

Title

ISO 13703 (API RP 14E)

Petroleum and natural gas industries – Design and installation of piping systems on offshore production platforms

IEC 61892 all parts

Mobile and fixed offshore units Electrical installations

API RP 505

Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, and Zone 2

DNV-RP-A203

Qualification of New Technology

NORSOK D-002

Well intervention equipment

NORSOK standard

Comments vs. NORSOK D-007 Refer also to NORSOK P-001 which modifies ISO 13703 with alternative velocity and sizing criteria.

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3 , definitions and abbreviations For the purposes of this NORSOK standard, the following , definitions and abbreviations apply. 3.1 and definitions 3.1.1 shall verbal form used to indicate requirements strictly to be followed in order to conform to this NORSOK standard and from which no deviation is permitted, unless accepted by all involved parties 3.1.2 should verbal form used to indicate that among several possibilities one is recommended as particularly suitable, without mentioning or excluding others, or that a certain course of action is preferred but not necessarily required 3.1.3 may verbal form used to indicate a course of action permissible within the limits of this NORSOK standard 3.1.4 can verbal form used for statements of possibility and capability, whether material, physical or casual 3.1.5 by the term "by" as used in this document is not the same as used in NORSOK P-001 section 7.1. For the purpose of this document "by" is used to describe a control process to isolate a process component 3.1.6 large bore subsea equipment subsea equipment of 5” or larger size used for well intervention and well completion operations (large bore subsea equipment is not covered by NORSOK D-007) 3.1.7 main control room the rig’s main control room, where the ESD system control is located 3.1.8 PSD system the electronic process shut-down system for the well test or production clean-up system. The system shuts the process down by stopping inflow from the well on surface. In addition the system has the ability to depressurize the well test or production clean-up system in case of a fire or gas situation. The PSD system is the responsibility of the well test or production clean-up service contractor 3.1.9 rig ESD the rig ESD system, as defined in NORSOK S-001, is a rig owner responsibility, and is independent from the PSD system, except for the interfaces described in NORSOK D-007. 3.1.10 small bore subsea equipment subsea equipment of 5” or smaller internal diameter used for well test operations

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3.1.11 Zone 1 and Zone 2 These are abbreviated for hazardous area classification: Zone 0: An area in which an explosive gas atmosphere is present continuously or for long periods. Zone 1: An area in which an explosive gas atmosphere is likely to occur in normal operation. Zone 2: An area in which an explosive gas atmosphere is not likely to occur in normal operation and, if it occurs, will only exist for a short time. For Norwegian operations it is recommended to use IEC 61892-7 – Mobile and fixed offshore units, electrical installations as the overall basis for area classification. 3.2 Abbreviations Table 3 – Abbreviations Term

Explanation

ANSI

American National Standards Institute

API

American Petroleum Institute

ASME

American Society of Mechanical Engineers

ATEX

ATmosphères EXplosives

BOP

Blow-Out Preventer

°C

Degree Celsius

CO2

Carbon dioxide (gas)

DODO

Drive-Off, Drift-Off

DP

Dynamic Positioning

EN

European standard (or Norm)

ESD System

Emergency Shut-Down System

ESP

Electrical, Submersible Pump

HP

High Pressure

HPHT

High Pressure High Temperature

H2S

Hydrogen sulfide (gas)

ISO

International Organization for Standardization

KO

Knock-Out

LP

Low Pressure

NACE

National Association of Corrosion Engineers

NORSOK

NORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative to add value, reduce cost and lead time and remove unnecessary activities in offshore field developments and operations.

PD

Published Document

P&ID

Process and Instrumentation Diagram

PSD System

Process Shut-Down System

NORSOK standard

Comments

French - explosive atmosphere

British nomenclature for standards.

This is the safety system for the

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Term

Edition 2, September 2013

Explanation

Comments surface well test equipment.

PSD 1

Process Shut-Down System - Level 1

Stops flow to the well test plant.

PSD 2

Process Shut-Down System - Level 2

Stops flow and depressurises the well test plant

RP

Recommended Practice

Used in conjunction with industry standards

SAC

Safety Analysis Checklist

Related to API RP 14C

SAFE

Safety Analysis Function Evaluation

Related to API RP 14C

SAT

Safety Analysis Table

Related to API RP 14C

SI

International System (of units)

WHP

Well Head Pressure

WOCS

Well Operations Control System

WTDR

Well Test Design Report

Control system for subsea and landing string equipment

4 General principles Any well test system design shall include barrier descriptions and schematics, in accordance with the requirements of NORSOK D-010, clause 4 and 6 with associated acceptance tables in clause 15. In addition to the requirements mentioned specifically herein, the requirements in the following normative references shall apply for this NORSOK standard: NORSOK S-002, EU 2006/42/EC on machinery, ISO 10407 (API RP 7G), ISO 10418, ISO 10423 (API Spec. 6A), ISO 10432 (API Spec. 14A), ISO 13628-11 (API RP 17B), ISO 14310 (API Spec 11D1), ISO 15156 (ANSI/NACE MR0175), API RP 44, API RP 520, ASME Section VIII Div. 1 and 2, EN 13445, ASME B31.3, EN 13480, ASME B16.5. In addition to the informative references mentioned specifically herein, the following informative reference is given for informative purposes: API RP 505 and NORSOK D-002.

5 Functional requirements 5.1 General SI units and Imperial units are used in this standard. SI units or imperial units may be used at the author’s discretion, but the chosen unit shall be clearly identified and used consistently. 5.2 Products and services The well testing equipment is grouped into five categories as detailed below. Equipment selection shall be suitable for the service conditions as provided for in the WTDR. 5.2.1 Downhole drill stem test tools The downhole equipment shall control the production of reservoir fluids into the test tubing, or the injection of fluids from the tubing into the formation. It shall also provide a means of establishing communication between tubing and annulus for well control purposes. 5.2.2 Landing string equipment The landing string equipment shall enable shutting in the well and allowing a controlled disconnect at BOP level, as required. It shall also provide means for lubricating working tools into the test string. It also includes a shearable handling sub which provides a suitable place to do emergency cutting using the BOP shear ram. 8

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For jack-up rigs and permanent installations using a BOP safety valve the controlled disconnect does not apply. 5.2.3 Surface equipment The surface equipment shall be designed and equipped to:   

assure a high level of phase separation; assure accurate measurement of individual phase flows; provide for the safe disposal of produced water and hydrocarbons without spill to sea.

5.2.4 Data acquisition and fluid sampling The equipment shall accurately acquire, store and handle data and fluid samples such as:      

reservoir pressure and temperature; seabed pressure and temperature; surface pressure and temperature and flowrates; bottomhole samples; surface fluid samples; wellsite chemical analysis.

5.2.5 Test tubing The test tubing shall provide a gastight conduit to surface. 5.3 Performance and output The equipment provided shall be mobilized, installed, commissioned, operated, maintained and demobilized by competent service personnel. 5.4 Performance level Full system shall be designed for repeat operation. This shall be one of the goals and requirements for the maintenance and design strategy. 5.5 Process and ambient conditions The following table describes the performance envelopes for the various operational categories: Table 4 – Performance envelopes Standard Service

HPHT Service

Ultra HPHT Service

Maximum expected surface pressure

690 bar

1035 bar

Above 1035 bar

Maximum annulus surface pressure

690 bar

1035 bar

Above 1035bar

Maximum downhole temperature

< 150°C

> 150°C

> 150°C

Maximum tubing head temperature

100°C

130°C (note 1)

Above 130°C (note 1)

Design temperature

-20°C

-20°C

-20°C

H2S Service (note 2)

Yes

Yes

Yes

CO2 Service (note 2)

Yes

Yes

Yes

NOTE 1 For operations using a production type surface test tree in combination with rigid piping with hub connectors, the limit is 175°C.

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NOTE 2 Where the reservoir fluid composition is known, the H2S and CO2 service requirements can be removed as applicable. NOTE 3 The above table covers normal ambient conditions. Other conditions like “Arctic” might necessitate modifications to the above ambient requirements.

All process equipment shall be designed for an offshore marine environment with corrosive and salt containing atmosphere, 100 % relative humidity and ambient temperatures ranging from -20 to +30°C. 5.6 Operational requirements 5.6.1 General Shipping: The equipment shall satisfy the requirements in NORSOK Z-015. General commissioning requirements: An acceptance test checklist shall be made and completed. This shall include sequence for initial and pre-job pressure and function testing including the PSD system. 5.6.2 Drill stem test tools 5.6.2.1 General All downhole tools shall have standard API drift diameter tolerance. 5.6.2.2 Operation The operation shall either be annulus or tubing pressure operated, or operated by telemetry. The supplier shall have established procedures that include testing to the functionality and pressure integrity of the tool string. It shall not be possible to unseat or sting out of packers unintentionally regardless of well or operational conditions. The drill stem test string shall be designed so the string has the ability to kill the well in case the tester valve fails closed. Load case verifications shall be performed to determine a safe working envelope. 5.6.2.3 Handling All test string components shall be designed such that handling on deck and drill floor can be performed safely and efficiently using remotely operated pipe handling system as far as possible. Wherever pressure may be trapped there shall be means to safely such trapped pressure and to safely bleed it off. The risk and the procedure for mitigation shall be included in the well test program. 5.6.3 Landing string equipment Landing string valves below the drill floor shall allow for well kill operations. For operations involving use of surface BOP a safety valve shall be installed in the test string close to surface. The safety valve may be either a BOP safety valve or surface controlled subsea safety valve. This valve provides a tubing barrier which becomes part of the BOP barrier when used (ref NORSOK D-010). For semisubmersible rigs there shall be a pressure sensor detecting sudden pressure drops in the tubing string upstream the choke manifold, in case of heave compensator lock-up and subsequent parting of the landing string below the flow-head. The sensor shall trigger automatic closure of the subsea test tree. In addition there shall be a manual back-up to the automatic closure function. 5.6.4 Surface equipment 5.6.4.1 Relief system The discharge from a pressure relief device shall be routed to and terminated in a safe area. The safe area shall be either a minimum of 3 meters below lower deck level or to the burner boom. Where the relief 10

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system is routed to the burner booms, means for draining of the piping and purging with nitrogen shall be installed. For atmospheric tanks adequate vent systems shall be installed and flame arrestor devices installed to prevent air influx. Pressure relief systems shall be designed to handle the effects of any discharge through the system. A valid gas dispersion study, provided by the rig and covering the design criteria shall be present. (Ref. section 5.9 – Well test design report). Rupture discs shall not be used as pressure relief devices. 5.6.4.2 Piping All temporary piping shall be adequately anchored and ed. All piping NOT rated to maximum WHP shall be protected from overpressure according to API RP 14C. Metal to metal seals shall be used for HP (345 bar and upwards) connection, and for all piping upstream the choke manifold. Where appropriate and to provide a safe working environment all piping shall be covered with grating or scaffolding. Systems with different pressure ratings shall have double isolation valves installed at the specification break. 5.6.4.3 Separator level control Continuously manning during operations is accepted as a replacement for level switches as per API RP 14C, when level systems are responding too slowly for adequate use of level switches. 5.6.4.4 Pressure testing (leak testing) The pressure tests for accepting the well test, production clean-up or bleed-off systems shall meet the following requirements:     

water or water-glycol mixture as the pressure test medium; recorders shall be within calibration date and charts shall be kept within the job files; a low pressure test to 15–20 bar for minimum 5 minutes stable reading should be performed prior to high pressure testing in the drilling, completion and intervention activities; for tests exceeding 345 bar, the pressure shall be brought up in 345 bar 10 minute steps from the low pressure level of 15-20 bar; minimum duration of the final pressure level shall be 10 minutes with stable reading.

The following should apply to qualify a pressure test: a. consider the monitored volume when setting the test acceptance criteria; b. establish maximum acceptable deviation from test pressure (x bar deviation from test pressure, e.g. 5 bar for a 345 bar test); c. establish maximum allowable pressure variation over the defined time interval (e.g. 1% or 3,45 bar for a 345 bar test over 10 minutes); d. A condition for the criteria in b) and c) is that the pressure change over time (∆p/∆t) is declining. 5.6.4.5 Water and slop discharges: All slops generated shall be handled in accordance with the well specific discharge permit.   

Any water discharged overboard shall have an oil-in-water content less than the authorized limit for discharged water. Produced water with higher than permitted oil content and slops shall be collected and transported onshore for disposal in accordance with the discharge permit. Any accidental discharge shall be reported to the authorities.

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5.6.4.6 Flaring Flaring of hydrocarbons shall take place with the least possible impact on the environment. 5.6.4.7 Bunding The main process equipment area shall have a bund high enough to contain an expected leak in the process area. The bund shall be sized to contain 110 % of the volume contained in the largest volume vessel inside the area, with a minimum wall height of 10 cm. A system for the handling and disposal of fluids from the enclosed area shall be in place. Any hatches and deck drains inside the enclosed area shall have sufficient coaming or be sealed off during operation. 5.6.4.8 PSD and control systems The well test or production clean-up system shall be equipped with PSD and blow down protection. The system shall automatically close in the well at the production flow wing valve and the stand alone safety valve (PSD 1). Separation vessels in the well test or production clean-up system shall in addition be equipped with a blow down function (PSD 2). The PSD 1 activation shall minimum allow for manual activation at the driller floor, in the separator area and at the lifeboat stations. The PSD system shall be electronically operated and monitored from a safe area. The rig ESD system shall, independently of the PSD system, be able to shut in the well. NOTE There is a normative requirement for conforming to IEC 61508 and IEC 61511 (SIL) for the PSD system. A transition period until 01.07.2017 is granted for getting this requirement fully implemented for NORSOK D-007 equipment.

5.6.4.9 Isolation Downstream of the choke manifold there shall be a means for bying and isolating each of the main components in the process plant. 5.6.4.10 Interfaces The list below includes the typical interfaces for a well test / clean-up system:      

steam; electrical power; compressed air (for instrument use); seawater; piping hook-up connections; ESD/PSD.

NOTE 1

The rig drilling system shall not be permanently connected to the well test or clean-up system.

NOTE 2

It is forbidden to use rig air for the well test burners.

NOTE 3 The rig systems, including but not limited to the following; steam generator, diverter lines, main relief line, burner booms, electricity system, fire and gas detection and firewater system, follows the requirements in NORSOK D-001.

5.6.5 Data acquisition and fluid sampling 5.6.5.1 General The extent of reservoir data gathering will normally be specified by the oil company. Electronic data shall be read, processed and presented on site. 5.6.5.2 Location of laboratory, control and sampling cabins The test laboratory and control cabin shall be located in a safe area.

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5.6.5.3 Downhole gauges Gauge operating procedure shall include positive verification of gauge recorder operation prior to installation. Any gauge element that could accumulate an accidental pressure build-up inside shall be so designed that ejection of components shall not be possible during disassembly. All gauges shall have a valid calibration certificate. A pressure gauge calibration check shall include the full pressure range at the expected downhole temperature. Calibration certificates shall be included in the worksite files. A post job calibration check may be carried out at the same temperature and repeating the pressure steps used in the pre job calibration check. 5.6.5.4 Sample bottles Certification documents shall be available with each bottle. 5.6.5.5 Data acquisition All sensors and metering devices shall have valid calibration certificates. Documentation shall be available on site. 5.6.6 Test tubing The tubing string shall be selected to allow handling and running with the drilling unit’s standard pipe handling system and tools. All tubulars shall be clean and inspected before use. Inspection shall be documented, per t. All tubing shall be drifted with an API standard drift prior to shipping. All tubulars being run in hole shall be drifted prior to running, with an API standard drift. 5.7 Maintenance requirements All well test equipment shall be properly maintained. Such maintenance shall be according to the vendor’s specifications and documented. Any measuring device shall be calibrated according to the vendor’s specification, documented and verified by a qualified third party. Sufficient spares or back-up equipment shall be available to ensure operational continuity. Any permanently installed equipment shall be maintained and preserved according to site-specific procedures. The maintenance shall be documented. 5.8 Layout and sea fastening requirements The test system shall be configured to ensure ease of access, proper maintainability and minimum two escape routes. The maximum permissible deck load shall not be exceeded. Components shall have ladders, stairways and railings as required for safe and convenient access for operation and maintenance. Sea fastening of temporary equipment shall comply with the class organization’s requirements. Sea fastening calculations shall be included in the WTDR (see section 5.9) 5.9 Well test design report The well test service contractor shall issue a WTDR covering the planned operations. The document structure shall be such:

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Table 5 – Well test design report Well test contractor

Well tests

Production clean-up

Well intervention/ bleed-off jobs

1.1 Layout drawing

Each well

Each project

Optional per project

1.2 Hazardous zone

Each well

Each project

Optional per project

1.3 Equipment and deck

Each well

Each project

Optional per project

2.1 System description

Each well

Each project

Optional per project

2.2 Well test data

Each well

Each project

Optional per project

2.3 Pressure drop calculations

Each well

Each project

Optional per project

2.4 P&ID

Each well

Each project

Optional per project

2.5 Safety philosophy

Each well

Each project

Optional per project

2.6 ESD-PSD logic

Each well

Each project

Optional per project

2.7 Risk analysis report

Each well

Each project

Optional per project

2.8 PSD button layout

Each well

Each project

Optional per project

2.9 Risk

Each well

Each project

Optional per project

2.10 Risk matrix

Each well

Each project

Optional per project

3.1 Process line data

Each well

Each project

Optional per project

3.2 Safety systems

Each well

Each project

Optional per project

4.1 Pressure and velocity calculations

Each well

Each project

Optional per project

4.2 Pressure relief calculations

Each well

Each project

Optional per project

4.3 Separator blowdown calculations

Each well

Each project

Optional per project

4.4 Calibration tank blowdown calculations

Each well

Each project

Optional per project

5.1 Commissioning plan

Each well

Each project

Each project

5.2 Acceptance test plan

Each well

Each project

Each project

6.1 Rig hazardous zone chart

Each well

Each project

Optional per project

6.2 Rig equipment and deck

Each well

Each project

Optional per project

6.3 Rig well test area

Each well

Each project

Optional per project

6.4 Heat radiation study

Each well

Each project

Optional per project

7.1 ESD strategy

Each well

Each project

Optional per project

7.2 ESD system risk analysis

Each well

Each project

Optional per project

7.3 Fire and gas system

Each well

Each project

Optional per project

7.4 Firewater system

Each well

Each project

Optional per project

8.1 Relief valve discharge dispersion

Each well

Each project

Optional per project

Rig specific information

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WTDR’s shall be verified and approved by the relevant rig classification company, or by the operator company.

6 Specific requirements 6.1 General The sub-clauses below cover requirements for:   

testing in DP mode; production clean-up; bleed-off operations.

6.2 Non-anchored operations – dynamic positioning operations This covers additional steps for DP operations. These steps also apply to for addressing anchor-chain parting for anchored operations, and for thruster-assisted well test operations. Response times for subsea DODO (Drive-Off, Drift-Off) situations. 

Clearly defined operational envelopes for rig station keeping shall be established.



The station keeping envelopes shall be present on the drill floor at all times.

The subsea equipment response times shall be included in the test program and shall be available on the drill floor during operations. Response rehearsals shall be conducted in conjunction with the rig floor and DP operations prior to perforating the well. 6.2.1 Disconnect philosophy A disconnect philosophy shall be established for each DP operation and included in the test program. The disconnect philosophy (cut with BOP shear ram, or disconnect on subsea test tree first) is equipment specific, driven by considerations including, but not limited to: 

maximum disconnect angle for the subsea test tree;



maximum disconnect string tension for the subsea test tree;



minimum disconnect time for the subsea test tree.

The content of the above bullets must be communicated to all involved personnel prior to operations and the required time for controlled disconnect must be stated. If a "disconnect subsea test tree first" philosophy is adopted for an operation, the full disconnect sequence shall be considered tested before opening the well, i.e. a disconnect, re-connect shall be considered conducted to operational times ensuring these meet pre-established minimum timings. The disconnect philosophy adopted shall be subject to a rigorous risk assessment. 6.2.2 Retainer valve philosophy For DP rig operations a retainer valve philosophy shall be developed and be evaluated during the planning phase for the operations. The first step shall be to determine if a retainer valve is required or not. If deemed required, considerations including but not limited to the following shall be addressed: 

failure of valve (fail open, fail closed, or fail as is);



pump through capability or not;



bleed down of pressure inside the landing string after emergency disconnect;



hydrocarbon liquid handling when pulling the landing string back to surface after a disconnect.

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6.3 Production clean-up 6.3.1 WOCS interface The well test PSD system shall interface with the WOCS unit. The PSD system shall shut in the production flow wing valve and the WOCS shall provide as to the actual position of the valve, not merely confirm that the command signal has been sent. The rig's ESD system shall, independently of the WOCS and PSD systems, be able to shut in the production flow wing valve. 6.3.2 ESP interface For production clean-ups or testing using ESP pumps, the pump shall be protected against overpressure as per API RP 14C. The ESP pump shall be interfaced with the well test PSD system. To protect the system from overpressure and stop well flow in case of a leak the PSD system shall also shut down the ESP pump. The rig ESD system shall also shut down the ESP pump. 6.4 Bleed-off Bleed-off equipment is intended for safe handling of minor hydrocarbon volumes produced during well intervention work. Design of such packages shall be in accordance with clause 5.9 and other relevant sections of NORSOK D-007. The equipment shall be suitable for handling relevant hydrocarbons and shall route the fluids to either a platform relief KO drum, or on mobile drilling units to flare (gas) and/or tank storage (liquids). Where well test equipment, in a bleed-off capacity, is used in of a well intervention operation the PSD system becomes as ing system for the overall well intervention PSD system, hence a pneumatic or hydraulic PSD is sufficient for the bleed-off package.

7 Exceptions to standards 7.1 Exceptions to NORSOK standards Table 6 – Exceptions to NORSOK standards Standard th

Exception

NORSOK P-001, 5 Ed., 6 - all sub-clauses

If electronic non-intrusive solids detection systems are used, erosional velocities shall not exceed the values given in API RP 14E. Intermittent solids free flow is allowed for NORSOK D-007 equipment. Wall thickness measurement equipment shall be in place and used for spot checking exposed flowline bends for erosion.

NORSOK P-001, 5th Ed., 6.1

Calculation models equivalent to ISO 13703 are acceptable.

NORSOK P-100, rev. 3, 16.1

Not applicable

NORSOK P-100, rev. 3, 16.3-6

Not applicable

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NORSOK standard

NORSOK standard D-007

Edition 2, September 2013

7.2 Exceptions to other standards Table 7 – Exceptions to other standards Standard ISO 23251 (API RP 521)

NORSOK standard

Exception For well testing and clean-up operations the API RP 521, clause 7.3.2.1 requirement for use of flare KO drums does not apply. Provided that nd clause 6.3.2.4, 2 paragraph is satisfied (relief and blowdown valves mounted in gas part of vessels) in combination with continuously manned equipment and PSD shutdown, this minimises the risk of a liquid pool fire under the rig to an acceptable level

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NORSOK standard D-007

Edition 2, September 2013

Annex A (normative) Drill stem test tools system requirements A.1 Equipment List of equipment typically used for well testing operations when drill stem test tools are called for. Downhole drill stem test tools:           

packer of permanent or retrievable type; tester valve; circulating valves; slip ts; hydraulic jar; safety t; auxiliary valves; drain valves; crossovers; tubing tester valve; downhole safety valve.

A.2 Design factor Downhole test tools shall have a design factor of minimum 1,10. The test assembly shall be designed to withstand the expected loads during all phases of the operation. Actual safety factors for the tools employed shall be documented in the well test design report, see sub-clause 5.9.

A.3 Design Internal profiles shall have no sharp edges.

A.4 Retrievable packer   

The retrievable packer shall be suitable for the planned operation. The packer shall be set by manipulation (including weight) of the string and/or pressuring up the well. For mechanically (weight) set packers it shall be possible to do multiple sets without any change in performance, and it shall hold pressure from above and below as required.

A.5 Tester valve 

Shall be surface operated. o Normally by means of annulus pressure. o If operated by other means, a back-up operating method shall be incorporated.



In normal operating mode, the loss of annulus operating pressure shall cause the tester valve to close. Lock open capability shall not be used unless an acceptable well barrier risk level can be documented. It shall be possible to open the tester valve with a pressure differential from above or below.

 

A.6 Circulating valves  

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A minimum of two circulating valves shall be run in the test strings. One of the valves shall have a multi-operation feature

NORSOK standard AnnexA

NORSOK standard D-007

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Edition 2, September 2013

One of the valves shall be single shot and remain open once activated. The flow ports shall have sufficient flow allow for adequate circulation without unintentional operation of any pressure activated tool.

A.7 Slip ts (for well test use)  

They shall have no internal obstructions. They shall be of internal balance type.

A.8 Jar It shall be of a repeatable hydraulic type.

A.9 Safety t   

It shall enable a mechanical separation of the test string from the packer assembly. The lower half shall have a design that enhances fishing of the string. Alternative release mechanisms can be considered but shall be qualified as per DNV-RP-A203 - Qualification of New Technology.

A.10 Tubing tester valve The tubing tester valve shall:   

provide means to test the tubing string. have a lock-out capability. have minimum specification as per other DST Tools.

A.11 Downhole safety valve The downhole safety valve shall:  

be a single-shot ball valve; have pump-through capability.

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NORSOK standard D-007

Edition 2, September 2013

Annex B (normative) Landing string equipment system requirements B.1 Equipment List of equipment typically used for well testing operations when landing string equipment is called for. Landing string equipment:     

subsea test tree with fluted hanger and slick t; lubricator valve; retainer valve; BOP safety valve; crossovers.

B.2 Subsea test tree              

The fluted hanger shall have a range of adjustment to allow for variation in the slick t spaceout. The subsea test tree shall be installed to allow for closure of the BOP middle pipe-ram on the slick t and closure of the shear-blind ram above the latched subsea tree assembly. The subsea tree assembly shall include a shear sub compatible with the BOP shear rams. It shall be possible to retrieve the latch after shearing. The subsea tree control system shall include remote stations for emergency closure of the tree, minimum in the driller’s cabin and an additional safe area. The subsea test tree shall be equipped with a chemical injection system with double non return valves. The principal injection line shall be an integral part of the control hose bundle. The control hose bundle shall be one single continuous length. If required the subsea test tree shall have the capacity to cut coiled tubing with any internal monoconductor cable or any logging cable. It shall be possible to unlatch the subsea tree under tension. Unintentional unlatching during handling shall not be possible. The subsea tree shall have two independent means of unlatching. The subsea tree shall have the ability to transmit torque for downhole tool operation. The subsea test tree valves shall fail to safe closed position on shearing and in the event of loss of hydraulic pressure. The subsea test tree valve systems shall allow for pressure testing of the landing string following a reconnection. The subsea test tree shall have a pump through capability. The subsea test tree operating system shall be such that it automatically go to safe closed position if the shearable sub is sheared.

B.3 Lubricator valve    

The lubricator valve shall be hydraulically operated and fail as is. It shall be possible to pump through the valve from above for well killing and it shall be possible to pressure test the valve from above and below. Where multiple valves are run in combination trapping pressure between the valves shall not be possible. If used as a well-intervention barrier a minimum of two shall be run, and both shall be inflow pressure tested.

B.4 Retainer valve  20

The valve shall retain landing string fluid under pressure following disconnect. NORSOK standard

NORSOK standard D-007

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Edition 2, September 2013

The valve shall be designed for multiple operations. Operation of the valve shall not impair system disconnect time. The retainer valve systems shall allow for pressure testing of the landing string following reconnection. The use of the retainer valve or not follows the requirement in sub-clause 6.2 – Non-anchored operations (dynamic positioning).

B.5 BOP safety valve If a BOP safety valve is used the following shall apply:     

The BOP safety valve shall be fail safe close. The BOP safety valve shall be installed in the test string such that BOP pipe rams can be closed on a t made up to the valve, and the BOP shear ram can be operated. The valve shall be of a pump through type. The BOP safety valve shall have the capacity for shearing coiled tubing with internal cable or a logging cable. The valve shall be equipped with a chemical injection system with a double non return valve. The principal injection line shall be an integral part of the control hose bundle.

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NORSOK standard D-007

Edition 2, September 2013

Annex C (normative) Surface equipment system requirements C.1 Equipment List of equipment typically used for well testing, clean-up and bleed-off operations when surface equipment is called for. Surface equipment:                       

surface test tree; flexible flowline; fixed pipe flowline; flowline manifold; dataheader; chemical injection pumps; stand-alone safety valve; choke manifold; heat exchanger; well test separator; calibration tank; surge tank; transfer pump; oil burner heads; LP knock out pot; gas flare silencers; control cabin; laboratory; PSD system; interconnecting piping; instrumentation; slop handling system, including tank; sand control equipment auxiliary equipment.

C.2 Surface test tree    

   

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The surface test tree shall be equipped with crown, master, kill and flow valves. A swivel shall be included above the master valve, to allow for rotation of the string. Hang off of the surface test tree shall be by means of a standard drill pipe elevator. The surface test tree shall have connections for kill and flow lines facing down. The kill and flow valves shall be hydraulically operated and fail safe close. 1) Maximum closing time: 5 seconds at atmospheric pressure. 2) Valves control system shall include a remote station for emergency closure of the tree. The tree shall be equipped with a protective frame for valve stems and actuators. The flow wing valve control system shall be connected to the well test PSD and the rig ESD system. The ESD system control function shall be as close as possible to the valve actuator. The test tree should be prepared for installation of pressure and temperature sensors upstream of the production wing valve. If a flow check valve is in use on the kill side, this should be remote operated and have a lockopen facility.

NORSOK standard

NORSOK standard D-007

Edition 2, September 2013

C.3 Flexible flowline   

The flexible line shall be compatible with the expected well fluids. Each end shall be equipped with means to fit safety slings. The flowline connections shall be of the hub type.

C.4 Flexible kill line   

The flexible line shall be compatible with the expected fluids. Each end shall be equipped with means to fit safety slings. The end connections shall be of the hub type.

C.5 Rigid flowline   

For fixed installation and jack-up operations, temporary rigid flowlines may be used. Rigid flowline shall not be installed instead of permanent flowlines from the drill floor to the test area for other rig types than jack-up rigs. The temporary rigid flowline shall have metal to metal seal connections.

C.6 Data headers (upstream and downstream choke manifold)  

The manifold shall have sufficient connecting points for pressure monitoring, data acquisition sensors, sand erosion probe, fluid sampling and chemical injection. All shall be equipped with double block and bleed valves. Temperature probes shall be non-intrusive. The end connections shall be of the hub or flange type.

C.7 Chemical injection pumps     

Pumps for chemicals injection shall be equipped with filtration device. The pumps shall be suitable for the required service and chemical(s). The pumps shall have adequate overpressure protection. Any bled off chemicals shall be returned to the supply tank. Block valve and double flow check valves shall be installed at the injection point. The chemical tank shall be fit for purpose and equipped with adequate safety devices.

C.8 Stand-alone safety valve     

The valve shall be included in all surface well test systems for both well testing and production clean-up. For bleed-off operations the valve is optional if an acceptable risk level can be proven without the valve installed. The valve shall be operated simultaneous with the surface test tree production wing valve. The valve closing time shall be maximum 7 seconds. It shall be possible to override the operating system for pressure testing purposes.

C.9 Choke manifold   

A choke manifold shall have two flow paths. Each flow path shall have minimum two closing valves, one upstream and one downstream, with bleed off facilities between the valves and ports for pressure measurements both up and down stream of the chokes. All valves in the choke manifold shall have the same pressure rating. Adjustable chokes shall be designed to allow for accurate adjustments, maintaining accuracy over time and shall prevent accidental plugging of the flow path.

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NORSOK standard D-007

Edition 2, September 2013

C.10 Heat exchangers Coil and shell type heat exchangers shall:       

  

be arranged with an external heating source, preferably steam; have a minimum of two coils with interconnected by a choke box, inside or on the outside of the vessel; have a choke assembly that shall have pressure test capabilities for testing of the high pressure coil tubes; be equipped with a temperature control system to control the fluid discharge temperature; be equipped with pressure and temperature sensors up- and down-stream of choke, and overpressure protection as per API RP 14C; be equipped with by- line on inlet and outlet of coils; be equipped with a gas detection system in the steam discharged from the heater. This system shall be connected to an automatic shut-off device to stop gas loaded condensate to return into the steam supply. Preferably sampling shall be done before the gas loaded condensate is allowed to enter into the condensate system; be protected by a pressure relief valve, in the event that the secondary coil has a lower pressure rating than the primary coil and/or the downstream valve; have a steam inlet be equipped with a flow check valve valve; have sufficient pressure relief capacity allow for relief of 100 % of the design flow.

Double multi-tube type:  

For double multi-tube heaters with a HP and LP section (spec. break), the above requirements for coil and shell heaters apply. For double multi-tube heaters with two HP or LP sections (no spec. break), the following exceptions to the above coil and shell heater requirements apply:

o choke box is optional (if installed all choke requirements apply). Tube pressure relief system shall be according to API RP14C and WTDR. Single multi-tube type shall:          

be arranged with an external heating source, preferably steam; allow for bleeding off of tubes and shell pressure by means of fitting isolation valves. The discharge shall be led to the LP pressure relief return or to a safe area; be equipped with temperature control system controlling the discharge fluid temperature; be equipped with pressure and temperature sensors; be equipped with by- line on inlet and outlet of tubes; be protected by enough PSV’s as per API RP14C, protecting the steam vessel, and shall be capable of handling the maximum well production rate; be equipped with a gas detection system in the steam discharged from the heater. This system shall be connected to an automatic shut-off device to stop condensed water with gas returning to the steam supply; have PSV protecting the tubes; have a steam inlet with a flow check valve; have sufficient PSV relief capacity to relieve 100 % of the design flow.

C.11 Separator The test separator shall be equipped with the following:  

chemical injection points; provision for sampling at oil-, gas- and water-lines: o flange connection for isokinetic sampling should be considered. Shrinkage tester for determining shrinkage should be considered.

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NORSOK standard D-007

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Edition 2, September 2013

manhole to allow for internal visual inspection and cleaning; two PSV’s protecting the vessel against rupture. Each PSV shall have capacity to discharge the design production rate, as per the WTDR; a pressure control system; a flow check valve in inlet line to prevent back flow in case of line rupture upstream of the separator; connection points for data acquisition, pressure and temperature measurement on the vessel, the gas and the oil line; oil, water and gas metering facilities to cover the full flow capacity range of the separator; a pressure relief device protecting separator inlet/by- manifold; a blow down valve, routed to a safe discharge system Initiated by either the PSD system and/or ESD system; an inlet manifold that shall enable by- of fluid to either the oil or gas discharge line. The manifold shall be equipped with sufficient valves to isolate the vessel.

C.12 Calibration / surge tank The tank shall be equipped with:            

a flow check valve on inlet line to prevent back flow in case of a rupture upstream of the unit; an inlet manifold to enable by- of fluids to the oil discharge line; a manifold with sufficient valves to isolate the vessel; an inline choke if the calibration tank relief system does not handle the maximum blow-by gas flow from the separator liquid discharge lines; two independent PSV’s protecting the vessel against rupture. Each individual device shall have discharge capacity to handle the tank’s design flow capacity; a manhole allowing for internal visual inspection and cleaning while the skid is still hooked up; a blow down valve, routed to a safe discharge system initiated by either the PSD system and or ESD system; a pressure control system in the gas outlet line; level glasses for monitoring of the fluid - gas interface; volume measuring system; audible high level alarm or use of alternative protection shall be in place; safety devices as per API RP 14C.

C.13 Transfer pump The pump shall pump from the calibration tank to the burners allowing continuous separator operations. The pump shall:     

have an emergency shutdown function, at a safe distance from the pump; be connected and controlled via the PSD system; have a flow check valve on the outlet; have inlet and outlet isolation valves; have Atex and Zone 1, classification.

C.14 Crude oil burners   

Shall be designed for best possible combustion, regardless of flow rate. The oil and compressed air inlet lines shall be equipped with flow check valves. The burner shall be equipped with an ignition system and a pilot light.

C.15 Air compressors (and all other diesel fired units) 

They shall be instrumented for automatic shut-down in case of exposure to hydrocarbon gases.

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NORSOK standard D-007

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Edition 2, September 2013

They shall be controlled by the PSD system. They shall be controlled by the rig ESD system. They shall be equipped with ignition source control devices suited to the physical location of the units in relation to zone classification.

C.16 Test laboratory container and control cabin The test laboratory container and control cabin shall be in compliance with NORSOK Z-015.

C.17 Process shut down (PSD) system The PSD system shall: 

automatically shut in the well on the production wing valve and the surface safety valve. API RP 14C shall be used as a guideline when setting up the PSD logic and place the sensors. Manual activation of PSD shall be arranged: o at the driller floor; o in the separator area; o lifeboat stations.



include two shut down levels via the PSD system logic: o Level 1 shall stop the flow by closing in-line valves. o Level 2 shall blow down the production system and stop the flow. o The PSD level 1 and 2 buttons shall be: i. ii. iii.



26

separated from each other; barrier to prevent unintentional operation; clearly marked.

be integrated with the ESD system, such that ESD system can shut down the well test plant, while the PSD system shall not activate the ESD system.

NORSOK standard

NORSOK standard D-007

Edition 2, September 2013

Annex D (normative) Reservoir information data system requirements D.1 Equipment List of equipment typically used for well testing operations when reservoir information data systems are called for. Data acquisition and fluid sampling:         

pressure and temperature recorders; gauge carriers; bottom hole sampling equipment; sampler carriers; surface sampling equipment; trace element and wellsite chemistry equipment; data handling and storage system; sand detection equipment; real-time downhole data transfer equipment.

D.2 Downhole pressure and temperature gauges  

Electronic gauges shall include safe storage of recorded data independent of downhole power failure. It shall be possible to gauge recorder operation prior to installation in carrier.

D.3 Gauge carrier  

Gauges shall be installed in the carrier before transport to the drill floor. Carrier pressure integrity shall be tested with gauges installed.

D.4 Bottom hole sampling  

Sampling equipment shall be mercury free. Sampling tools shall be set up such that: o sampler can be operated individually or grouped; o activation shall be surface controlled.



There shall be provisions to check the pressure and the bubble point of the sample prior to transfer from the sampler to the shipping bottle, or preparing the sample chamber for transport to shore. The sampler activation mechanism shall be designed such that the risk of accidental operation is prevented, including mechanical shock. Electrical activation systems shall be shielded to prevent unintentional inductive activation. Sampling shall be done in a controlled manner to prevent pressure draw down below the bubble point. It shall be designed with the option for installation in a tubing conveyed carrier.

  

D.5 Sampler carrier  

Bottom hole samplers shall be installed in the carrier before transport to the drill floor. Carrier pressure integrity shall be tested with samplers installed.

D.6 Surface sampling   

Pressurized sampling equipment shall be of mercury free. Sample containers shall be clean and certified. Provisions shall be made for single phase hydrocarbon sampling at wellhead.

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NORSOK standard D-007

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Edition 2, September 2013

Simultaneous sampling of oil and gas from separator at controlled pressure and temperature shall be possible. Pressure and temperature along with liquid and gas rate measurements shall be monitored during sampling and shall be recorded on sample form to be included with each bottle. Provisions shall be available for two phase sampling in gas outlet line for monitoring of separator efficiency and carry over.

D.7 Trace element and chemical composition analysis  

The well stream properties and components shall be analysed to detect elements that will influence the well stream processing and/or that may be harmful. The analysis shall include onsite analysis of gas and fluid properties adjusted to standard temperature. Chemical analysis of produced water with determination of density, resistivity, salinity and quantification of essential ions.

D.8 Surface data acquisition There shall be systems in place for continuous monitoring of:     

Pressure and temperature at: o wellhead, surface test tree, up and downstream of chokes, and annulus. sand detection sensor; separator oil, gas and water flow rates; separator pressure and temperature; separator downstream parameters.

The monitoring system shall have 100 % recording redundancy and shall include storage of recorded data also in case of a power failure. All sensors and interconnecting cables shall be suitable for installation in a Zone 2 environment. Original "raw data" and all parameters used in the calculations shall be available upon request. The data shall be available for transfer on-line in near real-time if required. Field reports in print and electronic format shall be available on site.

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NORSOK standard

NORSOK standard D-007

Edition 2, September 2013

Annex E (normative) Test tubing system requirements E.1 Equipment List of equipment typically used for well testing operations when tubing services are called for; Tubing string for testing:     

test tubing; test collars; pup ts and handling subs; handling equipment; crossovers.

E.2 Test tubing    

test tubing shall have gastight connections; length of test tubing shall be Range 2, as per API Spec 5CT; pup-ts can be used for space-out purpose; test collars shall have gastight connections.

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