SYSTEM REQUIREMENTS WELL TESTING SYSTEMS · Each and any individual component in the process plant...

NORSOK STANDARD

SYSTEM REQUIREMENTS

WELL TESTING SYSTEMS

D-SR-007Rev.1, January 1996

Please note that whilst every effort has been made to ensure the accuracy of the NORSOK standardsneither OLF nor TBL or any of their members will assume liability for any use thereof.

Well testing systems D-SR-007Rev. 1, January 1996

NORSOK standard 1 of 38

CONTENTS

1 FOREWORD 2

2 SCOPE 2

3 NORMATIVE REFERENCES 2

4 DEFINITIONS AND ABBREVIATIONS 34.1 Definitions 34.2 Abbreviations 3

5 FUNCTIONAL REQUIREMENTS 35.1 General 35.2 Products/services 35.3 Equipment/schematic 45.4 Performance/output 55.5 Regularity 55.6 Process/ambient conditions 55.7 Operational requirements 55.8 Maintenance requirements 75.9 Isolation and sectioning 75.10 Layout requirements 75.11 Interface requirements 75.12 Commissioning requirements 7

6 INFORMATIVE REFERENCES 8

ANNEX A SERVICE DATA SHEETS 9

ANNEX B EQUIPMENT DATA SHEET 19



1 FOREWORDNORSOK (The competitive standing of the Norwegian offshore sector) is the industry initiative toadd value, reduce cost and lead time and remove unnecessary activities in offshore fielddevelopments and operations.

The NORSOK standards are developed by the Norwegian petroleum industry as a part of theNORSOK initiative and are jointly issued by OLF (The Norwegian Oil Industry Association) andTBL (The Federation of Norwegian Engineering Industries). NORSOK standards are administeredby NTS (Norwegian Technology Standards Institution).

The purpose of this industry standard is to replace the individual oil company specifications for usein existing and future petroleum industry developments, subject to the individual company's reviewand 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standardisation process.Subject to implementation into international standards, this NORSOK standard will be withdrawn.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 SCOPEThis standard describes functional, performance and operational requirements for well testingequipment and systems.

3 NORMATIVE REFERENCESAPI Spec, 5CT Specification for casing and tubingAPI RP 7G Recommended practice for drill stem design and operating limitsAPI Spec. 6A Specification for valves and wellhead equipmentAPI Spec. 14A Specification for sub surface safety valve equipmentAPI RP 14C Recommended practice for analysis, design, installation and

testing of basic surface safety systems on offshore productionplatforms

API RP 14E Recommended practice for design and installation of offshoreproduction platform piping systems

API 17B Recommended practise for flexible pipesAPI RP 44 Recommended practice for sampling petroleum reservoir fluidsAPI RP 520 Recommended practice for sizing, selection and installation of

pressure-relieving devices in refineriesAPI RP 521 Recommended practice for pressure-relieving and depressuring

systemsDnV Certification Note 2.7-1 Offshore freight containers. Design and certificationASME Section VIII Div. 1 and 2 Rules for construction of pressure vesselsANSI/ASME B31.3 Chemical plant and petroleum refinery pipingNACE MR-01-75 Sulphide stress cracking resistant metallic materials for oil field

equipment



4 DEFINITIONS AND ABBREVIATIONS

4.1 DefinitionsNormative 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 AbbreviationsNone.

5 FUNCTIONAL REQUIREMENTS

5.1 GeneralSI units and Imperial units are used in this specification. SI units with imperial units in bracketsshall be used in all documentation.

5.2 Products/servicesThe well testing equipment is grouped in 5 categories:

5.2.1 Drill stem test toolsThe downhole equipment shall be able to control test production of reservoir fluids into the testtubing, alternatively injection of fluids from tubing into formation. It shall also provide means toestablish a permanent or closeable communication between tubing and annulus.

5.2.2 Landing string equipmentThe landing string equipment shall constitute the safety elements in the test string enabling shuttingin the well stream and perform a controlled disconnect at sea floor level. It shall also provide meansto lubricate working tools into the test string.

5.2.3 Surface equipmentThe surface equipment shall be able to receive high pressure well fluid, perform 3 phase separationof the fluid and accurately measure the individual flow stream. Produced water and hydrocarbonsshall be disposed off without spill to sea.

5.2.4 Reservoir information acquisitionShall perform acquisition of representative and accurate surface and downhole pressure andtemperature measurements during flow production testing of the well. Shall also acquirerepresentative bottom hole and/or surface samples for detailed analysis.



5.2.5 Test tubingShall 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.

5.3.2 Surface equipment• 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.



• Trace element and wellsite chemistry analysis.• Data acquisition system.• Sand detection equipment.

5.3.5 Test tubingTest tubing.

5.4 Performance/outputThe provided equipment shall be mobilised, installed, commissioned, operated, maintained anddemobilised by competent personnel provided by the contractor.

5.5 RegularityN/A

5.6 Process/ambient conditionsStandard eqt. HPHT eqt.

Maximum reservoir pressure 690 Bar 1035 BarMaximum annulus downhole pressure 1035 Bar 1379 BarMaximum downhole temperature 150ºC 210ºCMaximum wellhead temperature 100ºC 130ºC (175ºC for jack-up’s)Maximum operating temperature -20ºC -20ºCH2S Service Yes YesCO2 Service Yes Yes

All equipment shall be designed for offshore environment with corrosive and salt containingatmosphere. 100 % relative humidity and surface temperature of -20 to 30ºC.

5.7 Operational requirements

5.7.1 Surface equipmentThe pressure relief system from all relief devices shall be routed to relief headers for high or lowpressure relief. It is vendors responsibility to ensure that the relief system is suitably sized todischarge the maximum gas and/or liquid design flow rate. Discharge shall by preference bedirected to the flareboom. Alternatively can discharge be routed to dedicated safe area minimum 3meter below lower deck area.

Vessels designed for, or potentially operated as atmospheric vessels shall be equipped with devicesor designed so that return of air causing an explosive mixture or backfire into the vessel isprevented.

The interconnecting piping system shall by preference be permanently installed with an effort tominimise elastomers in the connections. Permanently installed piping shall be covered with gratingwhere appropriate to provide a safe working environment.

Any water dumped overboard shall contain less that 40ppm of hydrocarbons. Discharged water shallbe sampled and quantity measured.



Burning of hydrocarbons shall take place without pollution to sea. An effort shall be made tominimise 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 andSAT charts shall be presented.

The main process equipment area shall be equipped with coaming to prevent oil spill fromspreading outside the dedicated area.

Heat radiation calculations shall be presented to Company upon request displaying maximumexposure 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 shallbe adequately protected against overpressure. Double isolation valves shall be installed wherepractical.

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 bycontractor.

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 forsafe and convenient access for operation and maintenance. The equipment and layout design shallallow 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 easemovement and installation.

Equipment permanently installed on deck shall be fastened to deck to withstand a survival statesimilar 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 arrangementsuitably designed to withstand dynamic loads. DnV 2.7-1 is recommended used to comply with theregulatory requirements.

5.7.2 Downhole test toolsShall be annulus or tubing pressure operated.

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

Downhole test tools shall have a safety factor of minimum 1,1 included when quoting maximumworking pressure at working temperature. (I.e. quoting 15000 psi working pressure shall mean acalculated maximum design pressure of 16500 psi).



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 operatorand not exceeded during operation. Safety factors for tools employed shall be documented and madeavailable upon request.

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

5.8 Maintenance requirementsContractor shall carry out calibration of all measuring devices before and after each job. Contractorshall carry with him necessary spare parts to resume operation in case of malfunction. Anypermanently installed equipment shall be put in good storage order after the jobs, prior to thecontractor crew leaving the location.

5.9 Isolation and sectioningEach and any individual component in the process plant downstream the choke manifold shall havethe ability to be bypassed.

5.10 Layout requirementsContractor shall compress the equipment layout as much as possible while at the same time ensuresufficient 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 requirementsAcceptance test programme shall be made and performed with use of air and water as testingmedium. Programme shall include sequence for initial and pre-job pressure testing.



6 INFORMATIVE REFERENCESN/A

Well testing systems D-SR-007Annex A Rev. 1, January 1996


ANNEX A SERVICE DATA SHEETS

SERVICE DATA SHEETTITLE: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 fishshall 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 tomechanically 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.



SERVICE DATA SHEETTITLE: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 latchedsubsea tree assembly.

• The subsea tree assembly shall be equipped with a shearable sub located across the rig BOPshear-ram. Required force to shear shall be documented.

• The subsea tree control system shall be equipped with a remote station for emergency closure ofthe tree.

• The subsea test tree shall be equipped with a chemical injection system with a double non returnvalve located in tool assembly. The injection line shall be an integral part of the control hosebundle.

• 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 to

accidentally 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.



SERVICE DATA SHEETTITLE: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.



SERVICE DATA SHEETTITLE: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 minimumoperating temperature. The control system shall be equipped with a remote station for emergencyclosure 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 andinjection, 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 valveswith bleed off facilities between the valves and ports for pressure measurements both up anddown 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




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 wellproduction rate in case of coil or tube rupture.

• Shall be equipped with gas detection system for the steam-condensate discharged from theheater. This system shall be connected to an automatic shut-off device preventing gas ladencondensate returning back to the supplying boiler. By preference this detection shall be sampledfrom 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 downstreamvalve, 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 caseof overpressure.

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




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 gasin 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 beperformed 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 anddevelop 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 theoptimal number for the produced fluid content.

• If the pressure rating of the burners are less than that of the input source, the burners shall beequipped 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 sensorsinstalled as mutually agreed using API 14C as a guideline, or by manual activation of PSDbuttons 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 subseatest tree by manual activation of ESD buttons located at the following minimum places:− Outside Operator’s office




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



SERVICE DATA SHEETTITLE: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. Thesecertificates 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 repeatingthe pressure steps used in the pre job calibration check.

• If pre- or post-test calibrations indicates deviations from specified accuracy, a new mastercalibration 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 fortransportation to shore.

• The activation of the sampling mechanism shall be designed so that any accidental release ofsampling 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 radiosignal 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 befilled in a controlled manner (maximum 5 minutes) in order to prevent drawdown below bubblepoint.

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.



SERVICE DATA SHEETTITLE:ANNEX 4:RESERVOIR INFORMATION DATA SYSTEM REQUIREMENTS

• Simultaneous sampling of oil and gas from separator at controlled pressure and temperature shallbe possible. Pressure and temperature shall be monitored during sampling and shall be recordedon sample form to be included with bottle.

• Provisions shall be available for two phase sampling in gas outlet line from separator, or othersite 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 separatordownstream parameters.

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

available 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.



SERVICE DATA SHEETTITLE: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 repairshall be harmless to the pieces being inspected.

• After successful thread inspection, the threads shall be thoroughly cleaned, coated, doped, andthread protectors fitted. Anti-galling requirements will be specified in the Data sheet.

• The tubing shall be drifted using an API standard drift.

Well testing systems D-SR-007Annex B Rev. 1, January 1996


ANNEX B EQUIPMENT DATA SHEET

EQUIPMENT DATA SHEETTITLE:

6.1.1.1.1 DATASHEET 0: GENERAL INFORMATION

Well informationType 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, High Possibility 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 TopPerforating interval no 1 m, ft Perforating interval no. 2 m, ft

Perforating interval no. 3 m, ft




6.1.1.1.1 DATASHEET 0: GENERAL INFORMATIONDrilling unit informationPiping between drill floor and test areaNominal 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 boomHigh 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, utilityVoltage Volt Maximum current Amp Frequency Hz Maximum output power kW, hk Terminal connection

Other informationSteam 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




6.1.1.1.1 DATASHEET 0: GENERAL INFORMATIONCoaming of well test area available Yes, no Maximum load to be placed on deck area Metric ton/m2

Riser - BOP configurationBOP manufacturer Size Inch Minimum internal diameter mm, inch Pressure rating Bar, psi 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 configurationManufacturer Wear bushing size Inch Wear bushing taper angle degrees Distance datum to wear bushing nominal ID mm, inch




6.1.1.1.2 DATASHEET 1 DRILL STEM TEST TOOLSOperator’s min.

requirem. Vendors data

PackerType (brand name) For casing diameter mm, inch For casing grade (API) For casing weight lbs/ft Pressure rating Bar, psi 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 valveType (name) Pressure rating Bar, psi Temperature rating ºC, ºF 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 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 reference toolPressure rating Bar, psi Temperature rating ºC, ºF






Operating pressure range to close 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

Tubing operating circulating valveType Pressure rating Bar, psi Temperature rating ºC, ºF 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 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

Annulus operated circulating valveType 1 Pressure rating Bar, psi Temperature rating ºC, ºF Maximum differential opening pressure Bar, psi Operating pressure range to open Bar, psi






Operating pressure range to close Bar, psi Number of operating cycles Single, no. multi cycles Maximum rate tubing to annulus l/min, gpm Maximum rate annulus to tubing l/min, gpm 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 Type 2 Pressure rating Bar, psi Temperature rating ºC, ºF Maximum differential opening pressure Bar, psi Operating pressure range to open Bar, psi Operating pressure range to close Bar, psi Number of operating cycles Single, no. multi cycles Maximum rate tubing to annulus l/min, gpm Maximum rate annulus to tubing l/min, gpm 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

Slip jointPressure rating Bar, psi Temperature rating ºC, ºF Total stroke required mm, inch Total stroke pr. slip joint mm, inch 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

Hydraulic jarPressure rating Bar, psi Temperature rating ºC, ºF Force to activate (maximum pull before jar) kg, lbs Stroke length mm, inch Tensile strength (maximum pull after jar) kg, lbs 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

Safety jointType Pressure rating Bar, psi Temperature rating ºC, ºF Operating method Torque required Nm, ft, lbs

Safety joint, continuationPull required kg, lbs 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

Tubing tester valveType (flapper/ball) Pressure rating Bar, psi Temperature rating ºC, ºF






Pressure to permanently open Bar, psi Method to verify opening 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

Sampling toolType Pressure rating Bar, psi Temperature rating ºC, ºF Operating method Maximum sample pressure rating Bar, psi Closing means (ball/sleeve) Pressure range to close Bar, psi External diameter/OD mm, inch

Sampling tool, continuedInternal diameter/ID mm, inch Top connection (API/Hydril/Vam/etc.) Bottom connection (API/Hydril/Vam/etc.) Tensile strength kg, lbs

Downhole safety valveType Pressure rating Bar, psi Temperature rating ºC, ºF Pressure to activate 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



EQUIPMENT DATA SHEETTITLE:6.1.1.1.3 DATASHEET 2 LANDING STRING EQUIPMENT

Operator’s min.requirem. Vendors data

Fluted hangerType/model Dimensions/OD mm, inch Pressure rating Bar, psi Temperature rating ºC, ºF 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 jointPressure rating Bar, psi Temperature rating ºC, ºF Length mm, inch External diameter/OD mm, inch Internal diameter/ID mm, inch Top connection (type, dimension, etc.) Bottom connection (type, dimension, etc.) H2S; CO2, Acid service Tensile strength at zero pressure kg/lbs Tensile strength at max. pressure kg/lbs

Lubricator valveType/model Pressure rating Bar, psi Temperature rating ºC, ºF Length mm, inch

Lubricator valve, continuedExternal diameter/OD mm, inch Internal diameter/ID mm, inch Top connection (type, dimension, etc.)





Bottom connection (type, dimension, etc.) H2S; CO2, Acid service Yes, no Tensile strength at zero pressure kg/lbs Tensile strength at max. pressure kg/lbs

Subsea test treeType/model Pressure rating Bar, psi Temperature rating ºC, ºF 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 External diameter/OD mm, inch Internal diameter/ID mm, inch Top connection (type, dimension, etc.) Bottom connection (type, dimension, etc.) H2S; CO2, Acid service Yes, no Chemical injection Yes, no Close valve and unlatch time 150m water depth sec

350m water depth sec 600m water depth sec

1000m water depth sec

Subsea test tree, continuedCoiled tubing w/7/32” cable cutting capabilities Yes, no 7/16” logging cable cutting capabilities Yes, no

Retainer valveType/model Pressure rating Bar, psi Temperature rating ºC, ºF





Length mm, inch External diameter/OD mm, inch Internal diameter/ID mm, inch Top connection (type, dimension, etc.) Bottom connection (type, dimension, etc.) H2S; CO2, Acid service Yes, no Maximum load carrying capacity at zero pressure kg, lbs Maximum load carrying capacity at max. pressure kg, lbs



EQUIPMENT DATA SHEETTITLE:6.1.1.1.4 DATASHEET 3 SURFACE EQUIPMENT


Surface test treeType/model Pressure rating Bar, psi Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF Maximum load carrying capacity at zero pressure kg, lbs Maximum load carrying capacity at max. pressure kg, lbs Internal diameter/ID mm, inch Steel quality (ASTM, DIN, BS) Weight kg, lbs Flowline connection (type, dimension, etc.) Kill-line connection (type, dimension, etc.) Top connection (type, dimension, etc.) Bottom connection (type, dimension, etc.) H2S; CO2, Acid service Yes, no

Tubing swivelType/model Pressure rating Bar, psi Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF Maximum load carrying capacity at zero pressure kg, lbs Maximum load carrying capacity at max. pressure kg, lbs Internal diameter/ID mm, inch Steel quality (ASTM, DIN, BS) Weight kg, lbs Top connection (type, dimension, etc.) Bottom connection (type, dimension, etc.)

H2S; CO2, Acid service Yes, no

Flowline manifold/dataheaderPressure rating Bar, psi





Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF Internal diameter/ID mm, inch Inlet connection (type, dimension, etc.) Outlet connection (type, dimension, etc.) Number of outlets Outlet threads/connections Type Connection point for sand detector Type H2S; CO2, Acid service Yes, no

Chemical injection pumps - High volume fluidsType/model Maximum output pressure Bar, psi Capacity at maximum pressure l/min, gpm Power kW

Chemical injection pumps - PPM fluidsType/model Maximum output pressure Bar, psi Capacity at maximum pressure l/min, gpm Power kW

Choke manifoldPressure rating Bar, psi Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF Nominal size mm, inch Maximum fixed choke size mm, inch

Choke manifold, continuation





Maximum adjustable choke size mm, inch Weight kg, lbs Inlet connection (type, dimension, etc.) Outlet connection (type, dimension, etc.) H2S; CO2, Acid service Yes, no

Heat exchangerType/model Pressure rating Bar, psi Pressure rating HP coil or tubes Bar, psi Pressure rating LP coil or tubes Bar, psi Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF 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 Inlet connection (type, dimension, etc.)

Heat exchanger, continueOutlet connection (type, dimension, etc.) Steam connection (type, dimension, etc.) Weight kg, lbs H2S; CO2, Acid service

Separator(s)Type/model (vertical/horizontal) Design code (ASME, DIN, BS, TBK) Pressure rating Bar, psi Maximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF





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 Inlet connection (type, dimension, etc.) 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 H2S; CO2, Acid service Yes, no Relief system capacity

Surge tankType/model (vertical/horizontal) Design code (ASME, DIN, BS, TBK) Pressure rating Bar, psi

Surge tank, continuationMaximum temperature rating ºC, ºF Minimum temperature rating ºC, ºF Volume m3, bbl Gas capacity Mm3/d, MMSCF/d Equipped for gas measurement Yes, no Equipped for liquid rate measurement Yes, no Inlet connection (type, dimension, etc.) 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 H2S; CO2, Acid service Yes, no Relief system capacity





Transfer pumpType/model Prime mover Output power kW, hp Power requirement (current, AC/DC, voltage, frequency) Capacity m3/hr, bbl/hr Inlet connection (type, dimension, etc.) Outlet connection (type, dimension, etc.) Weight kg, lbs H2S; CO2, Acid service Yes, no

Interconnecting piping safety systemType of system to guard against over pressure

BurnersNumber 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, ft3/min Water supply requirement m3/hr, bbl/hr Weight kg, lbs H2S; CO2, Acid service Yes, no



EQUIPMENT DATA SHEETTITLE:6.1.1.1.5 DATASHEET 4 RESERVOIR INFORMATION ACQUISITION


Recorder elementSensor type Pressure range Bar, psi Temperature rating ºC, ºF Memory capacity (sets of pressure, temperature, time) Type of memory Type of programming Minimum sampling interval sec

Pressure sensorRange Bar, psi Accuracy % FS Repeatability % FS Resolution (at sampling interval) mbar, psi Long term stability % FS Response time sec

Temperature sensorType ºC, ºF Accuracy ºC, ºF Resolution ºC, ºF

Power supply/battery sectionType Length mm, inch Maximum OD mm, inch

Gauge carrierType/model Pressure rating Bar, psi





Collapse pressure Bar, psi Burst pressure Bar, psi External diameter/OD mm, inch Drift diameter mm, inch Internal diameter/ID mm, inch Rotating diameter mm, inch Number of gauges Top connection Bottom connection

Sampling toolPressure rating Bar, psi 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 tubingNumber 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





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

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