well testing recommended practices

8/21/2019 Well Testing Recommended Practices

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NORSOK STANDARD

SYSTEM REQUIREMENTS

WELL TESTING SYSTEMS

D-SR-007

Rev.1, January 1996


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Please note that whilst every effort has been made to ensure the accuracy of the NORSOK standards

neither OLF nor TBL or any of their members will assume liability for any use thereof.


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Well testing systems D-SR-007

Rev. 1, January 1996

NORSOK standard 1 of 38

CONTENTS

1 FOREWORD 2

2 SCOPE 2

3 NORMATIVE REFERENCES 2

4 DEFINITIONS AND ABBREVIATIONS 3

4.1 Definitions 3

4.2 Abbreviations 3

5 FUNCTIONAL REQUIREMENTS 3

5.1 General 3

5.2 Products/services 3

5.3 Equipment/schematic 4

5.4 Performance/output 55.5 Regularity 5

5.6 Process/ambient conditions 5

5.7 Operational requirements 5

5.8 Maintenance requirements 7

5.9 Isolation and sectioning 7

5.10 Layout requirements 7

5.11 Interface requirements 7

5.12 Commissioning requirements 7

6 INFORMATIVE REFERENCES 8

ANNEX A SERVICE DATA SHEETS 9

ANNEX B EQUIPMENT DATA SHEET 19


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1

FOREWORD

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.

The NORSOK standards are developed by the Norwegian petroleum industry as a part of the

NORSOK initiative and are jointly issued by OLF (The Norwegian Oil Industry Association) and

TBL (The Federation of Norwegian Engineering Industries). NORSOK standards are administered

by NTS (Norwegian Technology Standards Institution).

The purpose of this industry standard is to replace the individual oil company specifications for use

in existing and future petroleum industry developments, subject to the individual company's review

and application.

The NORSOK standards make extensive references to international standards. Where relevant, thecontents of this standard will be used to provide input to the international standardisation process.

Subject to implementation into international standards, this NORSOK standard will be withdrawn.

2 SCOPE

This standard describes functional, performance and operational requirements for well testing

equipment and systems.

3 NORMATIVE REFERENCES

API Spec, 5CT Specification for casing and tubing

API RP 7G Recommended practice for drill stem design and operating limits

API Spec. 6A Specification for valves and wellhead equipment

API Spec. 14A Specification for sub surface safety valve equipment

API RP 14C Recommended practice for analysis, design, installation and

testing of basic surface safety systems on offshore production

platforms

API RP 14E Recommended practice for design and installation of offshore

production platform piping systems

API 17B Recommended practise for flexible pipes

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

API RP 521 Recommended practice for pressure-relieving and depressuring

systems

DnV Certification Note 2.7-1 Offshore freight containers. Design and certification

ASME Section VIII Div. 1 and 2 Rules for construction of pressure vessels

ANSI/ASME B31.3 Chemical plant and petroleum refinery piping

NACE MR-01-75 Sulphide stress cracking resistant metallic materials for oil field

equipment


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4 DEFINITIONS AND ABBREVIATIONS

4.1 Definitions

Normative references Shall mean normative in the application of NORSOK standards.

Informative references Shall mean informative in the application of NORSOK standards.

Shall Shall is an absolute requirement which shall be followed strictly in order

to conform with the standard.

Should Should is a recommendation. Alternative solutions having the same

functionality and quality are acceptable.

May May indicates a course of action that is permissible within the limits of

the standard (a permission).

Can Can requirements are conditional and indicates a possibility open to the

user of the standard.

4.2

Abbreviations None.

5 FUNCTIONAL REQUIREMENTS

5.1 General

SI units and Imperial units are used in this specification. SI units with imperial units in brackets

shall be used in all documentation.

5.2 Products/services

The well testing equipment is grouped in 5 categories:

5.2.1 Drill stem test tools

The downhole equipment shall be able to control test production of reservoir fluids into the test

tubing, alternatively injection of fluids from tubing into formation. It shall also provide means to

establish a permanent or closeable communication between tubing and annulus.

5.2.2 Landing string equipment

The landing string equipment shall constitute the safety elements in the test string enabling shutting

in the well stream and perform a controlled disconnect at sea floor level. It shall also provide means

to lubricate working tools into the test string.

5.2.3 Surface equipment

The surface equipment shall be able to receive high pressure well fluid, perform 3 phase separation

of the fluid and accurately measure the individual flow stream. Produced water and hydrocarbons

shall be disposed off without spill to sea.

5.2.4 Reservoir information acquisition

Shall perform acquisition of representative and accurate surface and downhole pressure and

temperature measurements during flow production testing of the well. Shall also acquire

representative bottom hole and/or surface samples for detailed analysis.


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5.2.5 Test tubing

Shall provide a gastight mean to transport hydrocarbons to surface.

5.3 Equipment/schematic

5.3.1 Drill stem test tools

• Packer of permanent or retrievable type.

• Tester valve.

• Circulating valves.

• Slip joint.

• Hydraulic jar.

• Safety joint.

• Auxiliary valves.

• Integrated Downhole Data Acquisition Tool.

•

Subs and x-overs.


• Surface test tree.

• Flexible flowline (for floaters).

• Rigid flowline (for jack up’s).

• Flowline manifold/dataheader.

• Chemical injection pumps.

• Stand-alone safety valve.

• Choke manifold.

•

Heat exchanger.

• Three phase separator.

• Surge tank.

• Transfer pump.

• Crude oil burners.

• Control cabin/laboratory.

• PSD/ESD system.

• Interconnecting piping.

• Instrumentation.

• Auxiliary equipment.

5.3.3 Landing string equipment

• Subsea test tree w/fluted hanger and slick joint.

• Lubricator valve.

• Retainer valve.

• BOP safety valve (for jack-up’s).

• Subs and x-over.

5.3.4 Reservoir information acquisition

• Pressure and temperature recorders.

•

Bottom hole sampling equipment.• Surface sampling equipment.


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• Trace element and wellsite chemistry analysis.

• Data acquisition system.

• Sand detection equipment.

5.3.5

Test tubingTest tubing.

5.4 Performance/output

The provided equipment shall be mobilised, installed, commissioned, operated, maintained and

demobilised by competent personnel provided by the contractor.

5.5 Regularity

N/A

5.6

Process/ambient conditionsStandard eqt. HPHT eqt.

Maximum reservoir pressure 690 Bar 1035 Bar

Maximum annulus downhole pressure 1035 Bar 1379 Bar

Maximum downhole temperature 150ºC 210ºC

Maximum wellhead temperature 100ºC 130ºC (175ºC for jack-up’s)

Maximum operating temperature -20ºC -20ºC

H2S Service Yes Yes

CO2 Service Yes Yes

All equipment shall be designed for offshore environment with corrosive and salt containing

atmosphere. 100 % relative humidity and surface temperature of -20 to 30ºC.

5.7 Operational requirements


The pressure relief system from all relief devices shall be routed to relief headers for high or low

pressure relief. It is vendors responsibility to ensure that the relief system is suitably sized to

discharge the maximum gas and/or liquid design flow rate. Discharge shall by preference be

directed to the flareboom. Alternatively can discharge be routed to dedicated safe area minimum 3

meter below lower deck area.

Vessels designed for, or potentially operated as atmospheric vessels shall be equipped with devices

or designed so that return of air causing an explosive mixture or backfire into the vessel is

prevented.

The interconnecting piping system shall by preference be permanently installed with an effort to

minimise elastomers in the connections. Permanently installed piping shall be covered with grating

where appropriate to provide a safe working environment.

Any water dumped overboard shall contain less that 40ppm of hydrocarbons. Discharged water shall

be sampled and quantity measured.


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Burning of hydrocarbons shall take place without pollution to sea. An effort shall be made to

minimise smoke and pollution to air where this is not impairing the burning efficiently.

API 14C shall be used as a guideline to safeguard the surface process equipment. SAFE, SAC and

SAT charts shall be presented.

The main process equipment area shall be equipped with coaming to prevent oil spill from

spreading outside the dedicated area.

Heat radiation calculations shall be presented to Company upon request displaying maximum

exposure at maximum production rate in a worst case scenario.

When the piping installation has a change of pressure rating (spec. break), the lower rated pipe shall

be adequately protected against overpressure. Double isolation valves shall be installed where

practical.

All surface pressure containing piping and vessels shall be mounted in such a manner that blow-

down of the equipment is possible form safe area through a manual activation feature provided by

contractor.

Process control shall be through local pneumatic control.

The PSD system shall be electronically operated and monitored form contractors control room.

Permanently installed equipment shall be fitted with ladders, stairways and railing as required for

safe and convenient access for operation and maintenance. The equipment and layout design shall

allow for normal maintenance and service to be carried out between test periods, while hooked upon the rig.

The equipment necessary for executing the work shall be skid or container mounted to ease

movement and installation.

Equipment permanently installed on deck shall be fastened to deck to withstand a survival state

similar to that of the rig it is installed on. Fastening shall be calculated and documented.

Equipment which is shipped frequently to the offshore installation shall have lifting arrangement

suitably designed to withstand dynamic loads. DnV 2.7-1 is recommended used to comply with theregulatory requirements.

5.7.2 Downhole test tools

Shall be annulus or tubing pressure operated.

All test string components shall be so designed that all handling on deck and drill floor can be

performed safely and efficiently.

Downhole test tools shall have a safety factor of minimum 1,1 included when quoting maximum

working pressure at working temperature. (I.e. quoting 15000 psi working pressure shall mean a

calculated maximum design pressure of 16500 psi).


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Internal profiles shall have no sharp edges or obstructions.

All downhole tools are to be drifted with an API standard drift.

The equipment shall be designed to withstand loads and pressure downhole, including maximumapplied annulus pressure in addition to the specified maximum working pressure for the tool.

Contractor shall make sure that the design load limits of the equipment are known to the operator

and not exceeded during operation. Safety factors for tools employed shall be documented and made

available upon request.

A bleed off function shall be provided wherever pressure may be trapped.

5.8 Maintenance requirements

Contractor shall carry out calibration of all measuring devices before and after each job. Contractor

shall carry with him necessary spare parts to resume operation in case of malfunction. Any permanently installed equipment shall be put in good storage order after the jobs, prior to the

contractor crew leaving the location.

5.9 Isolation and sectioning

Each and any individual component in the process plant downstream the choke manifold shall have

the ability to be bypassed.

5.10 Layout requirements

Contractor shall compress the equipment layout as much as possible while at the same time ensure

sufficient escape ways.

Contractor shall ensure that the maximum permissible deck load is not exceeded and if required,

supply necessary spreader beams below the equipment.

P&ID drawing with valve numbering and component specifications shall be made available.

General arrangement drawings shall be made available after installation of equipment.

Flow diagrams shall be made available after installation of equipment.

5.11

Interface requirements• Steam.

• Electrical power.

• Compressed air.

• Sea water.

• Piping connections.

• Requirements will be described in the data sheets.

5.12 Commissioning requirements

Acceptance test programme shall be made and performed with use of air and water as testing

medium. Programme shall include sequence for initial and pre-job pressure testing.


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6 INFORMATIVE REFERENCES

N/A


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Annex A Rev. 1, January 1996


ANNEX A SERVICE DATA SHEETS

SERVICE DATA SHEET

TITLE:ANNEX 1 DRILL STEM TEST TOOLS SYSTEM REQUIREMENTS

Retrievable packer:

• The packer shall be set by a simple manipulation of the string.

• It shall be possible to unseat and reset the packer without any change in performance.

• Shall hold pressure form above and below as specified in Data sheet.

Tester Valve:

• Shall be operated by annulus pressure.

• Unless otherwise specified by the Operator, the tester valve shall close if the annulus pressure is

bled off.

• It shall be possible to open the tester valve with a pressure differential of 50% of working

pressure from below.

Circulating valves:

• A minimum of two circulating valves shall be run in the test strings.

• One of the valves shall have the possibility of being operated an unlimited number of times.

• One of the valves shall be single shot. I.e. remain open once activated.

•

The flow ports shall have sufficient area and resistance to erosion to permit circulation at an

effective rate with a pressure that does not cause operation of other tools.

Slip joints:

• Shall have no internal obstructions in which wireline can be stuck due to internal movement.

• Shall be of internal balance type.

Jar:

• Shall be of a hydraulic type, and it shall be possible to repeat the jarring operation.

Safety joint:

•

Shall when required cause a mechanical separation of the test string from the packer assembly

when exceeding the tensile strength limit in the joint. The lower half remaining with the fish

shall have a design which enhances fishing of the string.

• The safety joint shall not be of a rotation type if this interfere with right hand rotation to

mechanically unlatch the subsea test tree.

Integrated downhole data acquisition tool:

• Shall be concentric and have no internal obstructions.

• Shall be equipped with means to check for and safely release any internal pressure build-up

caused by downhole use or pressure testing.


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SERVICE DATA SHEET

TITLE:

ANNEX 2 LANDING STRING EQUIPMENT SYSTEM REQUIREMENTS

Subsea test tree:

• The fluted hanger shall have an adjustable feature to allow the slick joint to be varied over a

given range.

• It shall be possible to position the subsea tree in the rig’s BOP stack so that middle piperams can

be closed on the slick joint and it shall be possible to close shear/blindram above the latched

subsea tree assembly.

• The subsea tree assembly shall be equipped with a shearable sub located across the rig BOP

shear-ram. Required force to shear shall be documented.• The subsea tree control system shall be equipped with a remote station for emergency closure of

the tree.

• The subsea test tree shall be equipped with a chemical injection system with a double non return

valve located in tool assembly. The injection line shall be an integral part of the control hose

bundle.

• The control hose bundle shall be one single length without splices or intermediate connections.

• The subsea test tree shall be able to cut coiled tubing with internal monoconductor cable and/or

7/16” logging cable.

•

The subsea tree shall be able to unlatch under tension. It shall however not be possible toaccidentally unlatch the tree while running in hole.

• The subsea tree shall be equipped with a mechanical unlatch feature to be operated as a

secondary mean in case of lost hydraulic power.

• The subsea tree shall be able to transmit any torque required to operate downhole equipment.

BOP safety valve:

• Shall be installed in the test string such that BOP rams can be closed on a slick joint above the

valve.

• The safety valve assembly shall be equipped with a shearable sub located across the rig BOP

shear-ram. Required force to shear shall be documented.

• The valve shall be of a pump through type.

• The valve shall be able to cut coiled tubing with internal monoconductor cable and/or 7/16”

logging cable.

• The valve shall be equipped with a chemical injection system with a double non return valve

located in tool assembly. The injection line shall be an integral part of the control hose bundle.

Lubricator valve:

• The lubricator valve shall be designed to be hydraulically pumped open and closed, without

failing to any position in case of lost control pressure. It shall be possible to pump through thevalve and also to pressure test against the valve from both below and above.


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SERVICE DATA SHEET

TITLE:

ANNEX 2 LANDING STRING EQUIPMENT SYSTEM REQUIREMENTS

• Pressure lock between multiple valves run in combination shall not be possible.

Retainer valve:

• The valve shall retain landing string fluid under pressure following a disconnect.

• The valve shall be multi-shot.

• The valve shall when included on the string not impair disconnect time.

• The subsea test tree and retainer valve operating mechanism shall be such that both automatically

go to a safe closed position if the shearable sub is severed.

•

The subsea test tree and retainer valve systems shall include a system to allow pressure testing of the landing string following reconnection.


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SERVICE DATA SHEET

TITLE:

ANNEX 3 SURFACE EQUIPMENT SYSTEM REQUIREMENTS

Surface test tree:

• The surface test tree shall be equipped with swab, master, kill and flow valves. A swivel,

positioned above the master valve, shall also be incorporated to allow rotation of the string.

• The surface test tree shall be able to be hung off in a standard drillpipe elevator and shall have

connections for kill and flow lines facing down.

• The kill and flow valve on the surface test tree shall be hydraulically operated and fail to closed

position: They shall be able to close in less than 5 seconds at temperature down to minimum

operating temperature. The control system shall be equipped with a remote station for emergency

closure of the tree.• The tree shall be equipped with a frame for protection of valve stems and actuators.

• It shall be possible to interface the wing flow valve with the PSD/ESD system.

• It is recommended that the tree is equipped for installation of pressure and temperature sensors

upstream of the prod. Wing valve.

Flexible flowline:

• The flexible line shall be compatible with the well fluid chemistry.

• The end connections shall be equipped with safety slings for attachment to the flowhead and

standpipe/flowline manifold.

• The end connections shall be of the hub type.

Flowline manifold:

• The manifold shall have sufficient points for analogue pressure and temperature monitoring,

electronic data acquisition sensors, dead weight tester, sand erosion probe, sampling and

injection, each equipped with double block and bleed valves.

• The end connections shall be of the hub or flange type.

Chemical injection pumps:

• Pumps used to inject chemicals (methanol, glycol, separation enhancement additives) shall have

full redundancy and be equipped with filtration device.

• The pumps shall have a trim suitable for the required service and chemical.

Stand alone safety valve:

• If installed, shall operate in parallel with surface test tree production wing valve.

•

Shall have possibility to be overridden for pressure testing purposes.

Choke manifold:

• The choke manifold shall have two flow paths, one with facilities to install and change fixed

chokes an done with an adjustable choke. Each flow path shall have minimum two closing valves

with bleed off facilities between the valves and ports for pressure measurements both up and

down stream of chokes. All valves in the choke manifold shall have the same pressure rating.

Provision for installation of fixed chokes in both flow paths shall be arranged.

• Adjustable choke shall be so designed as to allow accurate adjustments in 4/64” increments,

maintain accuracy over time in use and shall not cause accidental plugging of the flow path.

Heat exchanger:

•

The heat exchanger shall be arranged with an external heating source, preferably steam.

• The heat exchanger shall have a minimum of two coils with interconnection by means of a choke


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SERVICE DATA SHEET

TITLE:


box either submerged inside the vessel or by an external connection.

• Bleeding off coils for the purpose of changing choke shall be possible through double isolation

valves, with the discharge led to the low pressure relief header of safe area.

• The adjustable choke assembly shall have pressure test capabilities for the purpose of testing

high pressure coil tubes.

• Shall be equipped with a temperature control system regulating the external heating source based

on the required well fluid discharge temperature.

• Shall be equipped with pressure and temperature sensors up- and down-stream of choke.

• Shall be equipped with by-pass line with double valve arrangement together with isolation valves

on inlet and outlet of coils.

•

Shall be equipped with two independent pressure relief devices protecting the steam vessel

against rupture. Each individual device shall be capable of discharging the maximum well

production rate in case of coil or tube rupture.

• Shall be equipped with gas detection system for the steam-condensate discharged from the

heater. This system shall be connected to an automatic shut-off device preventing gas laden

condensate returning back to the supplying boiler. By preference this detection shall be sampled

from the main vessel before the gas is allowed to enter into the condensate system.

• If the secondary coil has a lower pressure rating than the primary coil and/or the downstream

valve, the coil shall be equipped with a pressure relief device.

• The steam inlet shall be equipped with a non return valve.

Separator:

• The separator shall be suitable for three phase gas/oil/water separation.

• The following features shall be included:

− Pressure control system

− Oil and water level control system with liquid level glasses for water/oil and oil gas interface.

− Positions for both data acquisition and analogue pressure and temperature measurement on

vessel, gas and oil line.

− Oil, water and gas metering facilities to cover the full flow capacity range of the separator.

− Injection point for:

− Chemical at inlet manifold

−

Methanol or glycol downstream gas metering device, upstream of pressure control valve.

− Sampling outlets at oil-, gas- and water-lines.

− Flange connection for isokinetic sampling.

− Shall be equipped with shrinkage tester to assess gas content in oil leaving the separator.

− Shall be equipped with manhole situated so that internal visual inspection and cleaning can be

performed while the skid is still hooked up on the rig.

− Inlet manifold shall enable by-pass of fluid to either oil or gas discharge line. The manifold

shall be equipped with sufficient valves to isolate the vessel itself.

• Shall be equipped with two independent pressure relief devices protecting the vessel against

rupture. Each individual device shall be capable of discharging the design production rate in case

of overpressure.

• Shall be equipped with pressure relief device protecting separator inlet/by-pass manifold.


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SERVICE DATA SHEET

TITLE:


Surge tank:

• Shall be equipped with pressure control system.

• Shall be equipped with level glasses for liquid/gas interface.

• Shall be equipped with positions for analog pressure and temperature measurement on vessel.

• Inlet manifold shall enable by-pass of fluid to oil discharge line. The manifold shall be equipped

with sufficient valves to isolate the vessel itself.

• Shall be equipped with an independent pressure relief device protecting the vessel against

rupture. The device shall be capable of discharging the liquid production rate with associated gas

in case of over pressure due to liquid overfill or gas blow-by.

• Shall be equipped with manhole situated so that internal visual inspection and cleaning can be

performed while the skid is still hooked up on the rig.

Transfer pump:

• Shall be installed to give sufficient NPSH to enable continuos operation of the pump if used to

discharge crude oil to burners when operating the surge tank as a 2nd stage separator.

Crude oil burners:

• Shall be capable of complete combustion of crude oil without fall-out or pollution to sea.

• The oil and compressed air inlet lines on the burner shall be equipped with non return valves if

there is any remote possibility that the two media could enter the opposite media line and

develop a combustible mixture.

•

The burners shall be equipped with remotely controlled rotation device, if required for burningefficiency, ignition system and a pilot light for each atomised fluid stream.

• The burners shall be equipped to remotely select number of heads or guns to effectively select the

optimal number for the produced fluid content.

• If the pressure rating of the burners are less than that of the input source, the burners shall be

equipped with a pressure relieving device.

Air compressors:

• Shall be suitable for installation in zone 2 area when indicated in data sheet.

• Shall be equipped with automatic shutdown device in case of exposure to hydrocarbon gases.

Test laboratory cabin:

• Shall be pressurised and equipped with gas sensors on the air intake, fire extinguishing system

and two escape routes.

PSD and ESD system:

• The PSD (Production Shut Down) system shall be capable of shutting in the well on the

flowhead production wing valve. Activation shall take place as automatic functions from sensors

installed as mutually agreed using API 14C as a guideline, or by manual activation of PSD

buttons located at the following minimum places:

− Driller cabin

− Separator area

− Inside or outside Operator’s office

• The ESD (Emergency Shut Down) system shall be capable of shutting in the well on the subsea

test tree by manual activation of ESD buttons located at the following minimum places:− Outside Operator’s office


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SERVICE DATA SHEET

TITLE:


− One additional convenient location

• The PSD and ESD buttons shall be separated, have protective cover and be clearly marked.

• The PSD and ESD system shall be equipped with two levels where level 1 shall be a PSD which

stops the flow by closure of in-line valves. Level 2 shall be an ESD which will blow down the

pressurised vessels in the plan after discontinuation of flow has been confirmed.


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SERVICE DATA SHEET

TITLE:

ANNEX 4:RESERVOIR INFORMATION DATA SYSTEM REQUIREMENTS

Downhole pressure and temperature gauges:

• The recorded data shall be read, processed and presented in hardcopy on site.

• Electronic gauges shall be able to secure storage of recorded data in case of power failure

downhole.

• Gauge operating procedure shall include positive verification of gauge recorder operation prior to

instalment in the carrier.

• Any cartridge that could accumulate an accidental pressure build-up inside shall be so designed

that projection of components shall not be possible during disassembly.

•

The recorded data shall be read, processed and presented in hardcopy and ASCII datafile on site.• All gauges shall have a valid calibration certificate describing both Master calibration and

Calibration check over the entire pressure range at the expected downhole temperature. These

certificates shall be made available to the Operator prior to shipment.

• After the job, a post calibration check shall be carried out at the same temperature and repeating

the pressure steps used in the pre job calibration check.

• If pre- or post-test calibrations indicates deviations from specified accuracy, a new master

calibration shall be performed.

• Calibration results shall be included in the final report.

Gauge carrier:

•

Gauges shall be installed in the carrier while on deck, and carrier pressure integrity tested.• Contractor shall provide means for pressure testing on deck with gauges installed. It must be

possible to connect the gauge carrier to the string without breaking tested seals.

• Gauge carriers shall be internally concentric.

Bottom hole sampling:

• Sampling equipment shall be of mercury free type.

• Shall be designed so that several samplers can be run in the well simultaneously and fired

individually by surface activation or by mechanical clocks.

• There shall be provisions for checking opening pressure and bubble point of the sample prior to

transferring it from the sampler to the shipping bottle, or preparing the sample chamber for

transportation to shore.

•

The activation of the sampling mechanism shall be designed so that any accidental release of

sampling valves is prevented. This includes release in case of mechanical shock.

• For electrically triggered samplers, sampling may not be initiated by any other electrical or radio

signal than that transmitted through the cable on which the sampler is run.

• The minimum volume of each sample shall be 0,6 litres. Once activated, the sample shall be

filled in a controlled manner (maximum 5 minutes) in order to prevent drawdown below bubble

point.

Surface sampling:

• Pressurised sampling equipment is to be of mercury free type.

• Sample containers for pressurised samples shall have been cleaned out and re-certified prior to

use. Certification documentation is to be available with bottle.• Provisions shall be made for single phase hydrocarbon sampling at wellhead.


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SERVICE DATA SHEET

TITLE:

ANNEX 4:RESERVOIR INFORMATION DATA SYSTEM REQUIREMENTS

• Simultaneous sampling of oil and gas from separator at controlled pressure and temperature shall

be possible. Pressure and temperature shall be monitored during sampling and shall be recorded

on sample form to be included with bottle.

• Provisions shall be available for two phase sampling in gas outlet line from separator, or other

site for monitoring of separator efficiency and carry over.

Trace element and wellsite chemistry analysis:

• Shall include on-site monitoring of well stream properties and components which influence well

stream processing and/or are of importance with respect to safety, health and environment.

• Shall provide onsite analysis of gas and fluid properties including densities adjusted to standard

temperature.

•

Shall provide chemical analysis of water with determination of density, resistivity, salinity and

quantification of essential ions.

Surface data acquisition:

• Provision shall be available for continuos monitoring of wellhead pressure and temperature at

surface test tree, upstream and downstream of choke, annulus pressure, sand detection sensor,

separator oil, gas and water flow rates, separator pressure and temperature and separator

downstream parameters.

• Monitoring system shall have 100% redundancy and shall be able to secure storage of recorded

data in case of power failure.

• All sensors and interconnecting cables shall be suitable for installation in a zone 2 environment.

•

All sensors and metering devices shall have valid calibration certificates. Documentation to beavailable on site.

• Original “raw data” and all parameters used in the calculations shall be available upon request.

• The data shall be available on-line in real-time. Printed reports and ASCII data file(s) shall be

available on site.


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SERVICE DATA SHEET

TITLE:

ANNEX 5 TEST TUBING SYSTEM REQUIREMENTS

Test tubing:

• The test tubing shall be equipped with connections providing a gas tight seal at rated pressure.

• Length of joints of test tubing shall be 100% inside the tolerance of the specified API range, but

with a minimum length of no less than 8,84m.

• All tubular goods shall be internally cleaned and all mill scale removed prior to inspection,

coating and delivery. All materials used to clean and/or prepare tubular for inspection or repair

shall be harmless to the pieces being inspected.

• After successful thread inspection, the threads shall be thoroughly cleaned, coated, doped, and

thread protectors fitted. Anti-galling requirements will be specified in the Data sheet.• The tubing shall be drifted using an API standard drift.


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Annex B Rev. 1, January 1996


ANNEX B EQUIPMENT DATA SHEET

EQUIPMENT DATA SHEET

TITLE:

6.1.1.1.1 DATASHEET 0: GENERAL INFORMATION

Well information

Type of well Wildcat, Exploration, Appraisal

Possibility of sand production Low, Medium, High

Max. Sand Free Rate Test Yes, No

Possibility of water production Low, Medium, High

Possibility of hydrate formation Low, Medium, High

Possibility of emulsion problems Low, Medium, HighPossibility of foaming problems Low, Medium, High

Maximum oil production rate m3/d, BOPD

Maximum gas production rate MSm3/d, MMSCF/d

Maximum water production rate m3/d, BWPD

Maximum H2S concentration ppm

Maximum CO2 concentration % (Vol, mol)

Maximum bottom hole pressure Bar, psi

Maximum bottom hole temperature ºC, ºF

Maximum wellhead pressure Bar, psi

Maximum wellhead temperature ºC, ºF

Maximum well inclination degrees

Maximum well depth m, ft

Mud system used during drilling OBM, WBM

Completion fluid / packer fluid

Completion fluid / packer fluid specific gravity

Cushion type

Casing diameter mm, inch

Casing grade (API)

Casing weight kg/m, lbs/ft

m, ft MD below RKB Bottom Top

Perforating interval no 1 m, ft

Perforating interval no. 2 m, ft

Perforating interval no. 3 m, ft


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TITLE:


Drilling unit information

Piping between drill floor and test area

Nominal diameter mm, inch

Pressure rating Bar, psi

Inlet connection (Hub, flange, dimension)

Outlet connection (Hub, flange, dimension)

Standpipe available Yes, no

Standpipe data Nominal ID/Rating/Connections/Height

Piping to burner boom

High pressure gas line (connection, size, rating)

Low pressure gas line (connection, size, rating)

Oil line (connection, size, rating)

Water line (connection, size, rating)

Air line (connection, size, rating)

Pressure relief system To burner/below well

Electrical power available for pumps and lab cabin, utility

Voltage Volt

Maximum current Amp

Frequency Hz

Maximum output power kW, hk

Terminal connection

Other information

Steam supply (capacity at pressure and temperature) kg/hr

Air supply for burners ltr/min

Water supply for burners m3/hr

Maximum burner head weight limitation kg, lbs

Remote control shutdown lines installed Yes, no


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Coaming of well test area available Yes, no

Maximum load to be placed on deck area Metric ton/m2

Riser - BOP configuration

BOP manufacturer

Size Inch

Minimum internal diameter mm, inch


BOP ram temperature rating ºC, ºF

Ram locations

Datum to centre lower pipe ram mm, inch

Datum to centre middle pipe ram mm, inch

Datum to centre upper pipe ram mm, inch

Datum to centre shear/blind ram mm, inch

Ram thickness mm, inch

Location of lowest choke line inlet/outlet

Wellhead configuration

Manufacturer

Wear bushing size Inch

Wear bushing taper angle degrees

Distance datum to wear bushing nominal ID mm, inch


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6.1.1.1.2

DATASHEET 1 DRILL STEM TEST TOOLS

Operator’s min.

requirem.Vendors data

Packer

Type (brand name)

For casing diameter mm, inch

For casing grade (API)

For casing weight lbs/ft


Temperature rating ºC, ºF

Maximum differential pressure (collapse) Bar, psi

Maximum differential pressure (burst) Bar, psi

External diameter/OD mm, inch

Internal diameter/ID mm, inch

Top connection (API/Hydril/Vam/etc.)

Bottom connection (API/Hydril/Vam/etc.)

Tensile strength kg, lbs

Tester valve

Type (name)



Maximum test pressure form above Bar, psi

Maximum differential opening pressure from below Bar, psi

Operating pressure range to open Bar, psi

Can valve be permanently closed by over pressure Yes, no






Tester valve reference tool




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6.1.1.1.2 DATASHEET 1 DRILL STEM TEST TOOLS

Operator’s min.


Operating pressure range to close Bar, psi






Tubing operating circulating valve

Type



Minimum differential opening pressure Bar, psi

Closing method

Number of operating cycles Single, no. multi cycles

Maximum rate tubing to annulus l/min, gpm

Maximum rate annulus to tubing l/min, gpm






Annulus operated circulating valve

Type 1



Maximum differential opening pressure Bar, psi



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Operator’s min.











Type 2



Maximum differential opening pressure Bar, psi











Slip joint



Total stroke required mm, inch

Total stroke pr. slip joint mm, inch






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Operator’s min.



Hydraulic jar



Force to activate (maximum pull before jar) kg, lbs

Stroke length mm, inch

Tensile strength (maximum pull after jar) kg, lbs






Safety joint

Type



Operating method

Torque required Nm, ft, lbs

Safety joint, continuation

Pull required kg, lbs






Tubing tester valve

Type (flapper/ball)




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Operator’s min.


Pressure to permanently open Bar, psi

Method to verify opening






Sampling tool

Type



Operating method

Maximum sample pressure rating Bar, psi

Closing means (ball/sleeve)

Pressure range to close Bar, psi


Sampling tool, continued





Downhole safety valve

Type



Pressure to activate Bar, psi






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Operator’s min.




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6.1.1.1.3

DATASHEET 2 LANDING STRING EQUIPMENTOperator’s min.


Fluted hanger

Type/model

Dimensions/OD mm, inch



Steel quality (DIN, ASTM, BS, etc.)

Top connection (type, dimension, etc.)

Bottom connection (type, dimension, etc.)

Tensile strength at zero pressure kg/lbs

Tensile strength at max. pressure kg/lbs

Slick joint



Length mm, inchExternal diameter/OD mm, inch




H2S; CO2, Acid service



Lubricator valve

Type/model



Length mm, inch

Lubricator valve, continued


Internal diameter/ID mm, inchTop connection (type, dimension, etc.)


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6.1.1.1.3 DATASHEET 2 LANDING STRING EQUIPMENT

Operator’s min.requirem.

Vendors data


H2S; CO2, Acid service Yes, no



Subsea test tree

Type/model



Overall length mm, inch

Length disconnected mm, inch

Transmittal torque range Nm, ft, lbs

Maximum working water depth m, ft

Maximum load carrying capacity at zero pressure kg, lbs

Maximum load carrying capacity at max. pressure kg, lbs






Chemical injection Yes, no

Close valve and unlatch time 150m water depth sec

350m water depth sec



Subsea test tree, continued

Coiled tubing w/7/32” cable cutting capabilities Yes, no

7/16” logging cable cutting capabilities Yes, no

Retainer valve

Type/model

Pressure rating Bar, psiTemperature rating ºC, ºF


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6.1.1.1.3 DATASHEET 2 LANDING STRING EQUIPMENT


Vendors data

Length mm, inch









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6.1.1.1.4

DATASHEET 3 SURFACE EQUIPMENTOperator’s min.


Surface test tree

Type/model


Maximum temperature rating ºC, ºF

Minimum temperature rating ºC, ºF




Steel quality (ASTM, DIN, BS)

Weight kg, lbs

Flowline connection (type, dimension, etc.)

Kill-line connection (type, dimension, etc.)




Tubing swivel

Type/model







Steel quality (ASTM, DIN, BS)

Weight kg, lbs




Flowline manifold/dataheaderPressure rating Bar, psi


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6.1.1.1.4 DATASHEET 3 SURFACE EQUIPMENT


Vendors data




Inlet connection (type, dimension, etc.)

Outlet connection (type, dimension, etc.)

Number of outlets

Outlet threads/connections Type

Connection point for sand detector Type


Chemical injection pumps - High volume fluids

Type/model

Maximum output pressure Bar, psi

Capacity at maximum pressure l/min, gpm

Power kW

Chemical injection pumps - PPM fluids

Type/model

Maximum output pressure Bar, psi

Capacity at maximum pressure l/min, gpm

Power kW

Choke manifold




Nominal size mm, inch

Maximum fixed choke size mm, inch

Choke manifold, continuation


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Vendors data

Maximum adjustable choke size mm, inch

Weight kg, lbs




Heat exchanger

Type/model


Pressure rating HP coil or tubes Bar, psi

Pressure rating LP coil or tubes Bar, psi



Dimension of HP coil or tubes mm, inch

Dimension of LP coil or tubes mm, inch

Submerged adj. choke between HP and LP coil/tube Yes, no

Maximum adjustable choke size mm, inch

Heating source

Heating power kW, BTU/day

Steam requirement (at pressure and temperature) kg/hr, lbs/hr


Heat exchanger, continue


Steam connection (type, dimension, etc.)

Weight kg, lbs

H2S; CO2, Acid service

Separator(s)

Type/model (vertical/horizontal)

Design code (ASME, DIN, BS, TBK)


Maximum temperature rating ºC, ºFMinimum temperature rating ºC, ºF


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Vendors data

Oil capacity m3/d, BOPD

Gas capacity at low liquid level Mm3/d, MMSCF/d

Gas capacity at high liquid level Mm3/d, MMSCF/d

Water capacity m3/d, BOPD


Gas outlet connection (type, dimension, etc.)

Oil outlet connection (type, dimension, etc.)

Water outlet connection (type, dimension, etc.)

Isokinetic sampling connection (type, dimension, etc.)

Weight kg, lbs


Relief system capacity

Surge tank

Type/model (vertical/horizontal)

Design code (ASME, DIN, BS, TBK)


Surge tank, continuation



Volume m3, bbl

Gas capacity Mm3/d, MMSCF/d

Equipped for gas measurement Yes, no

Equipped for liquid rate measurement Yes, no


Gas outlet connection (type, dimension, etc.)

Oil outlet connection (type, dimension, etc.)

Drain outlet connection (type, dimension, etc.)

Weight - empty kg, lbs

Weight - high liquid level kg, lbs


Relief system capacity


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Vendors data

Transfer pump

Type/model

Prime mover

Output power kW, hp

Power requirement (current, AC/DC, voltage, frequency)

Capacity m3/hr, bbl/hr



Weight kg, lbs


Interconnecting piping safety system

Type of system to guard against over pressure

Burners

Number of heads/nozzles

Oil flow rate m3/d, BOPD

Gas inlet connection (type, dimension, etc.)

Oil inlet connection (type, dimension, etc.)

Water inlet connection (type, dimension, etc.)

Air inlet connection (type, dimension, etc.)

Air supply requirement m3/min, ft

3/min

Water supply requirement m3/hr, bbl/hr

Weight kg, lbs



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TITLE:

6.1.1.1.5

DATASHEET 4 RESERVOIR INFORMATION ACQUISITIONOperator’s min.


Recorder element

Sensor type

Pressure range Bar, psi


Memory capacity (sets of pressure, temperature, time)

Type of memory

Type of programming

Minimum sampling interval sec

Pressure sensor

Range Bar, psi

Accuracy % FS

Repeatability % FS

Resolution (at sampling interval) mbar, psi

Long term stability % FSResponse time sec

Temperature sensor

Type ºC, ºF

Accuracy ºC, ºF

Resolution ºC, ºF

Power supply/battery sectionType

Length mm, inch

Maximum OD mm, inch

Gauge carrier

Type/model



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6.1.1.1.5 DATASHEET 4 RESERVOIR INFORMATION ACQUISITION


Vendors data

Collapse pressure Bar, psi

Burst pressure Bar, psi


Drift diameter mm, inch


Rotating diameter mm, inch

Number of gauges

Top connection

Bottom connection

Sampling tool


Temperature rating

External diameter mm, inch

Length mm, inch

Total sampler volume cc

Sampler activation mechanism

Delay (max./min)

Sampler chamber type

Shipping bottle volume

Shipping bottle maximum pressure capacity

Onsite sample transfer Yes, no

Heating bath and/or jacket included Yes, no

Transfer medium

Test tubing

Number of joints

Length of joints m, ft

Nominal outside diameter mm, inch

Wall thickness mm, inch

Weight per foot kg/m,lbs/ft

Steel grade


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TITLE:

6.1.1.1.5 DATASHEET 4 RESERVOIR INFORMATION ACQUISITION


Vendors data

Coupling types

Drift diameter mm, inch

External collapse pressure Bar, psi

Internal burst pressure Bar, psi

Tube body yield strength KdaN, 1000 lbs

Joint strength KdaN, 1000 lbs

Bore size mm, inch

Environments (H2S, CO2, Acid, etc.)

Ovality %

Anti galling treatment

Make-up torque Nm, ft, lbs

Type of thread protector

Type of thread compound

External/internal protection

Marking

X-overs

well testing recommended practices

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