well test procedures manual

108
ARPO ENI S.p.A. Agip Division ORGANISING DEPARTMENT TYPE OF ACTIVITY' ISSUING DEPT. DOC. TYPE REFER TO SECTION N. PAGE. 1 OF 108 STAP P 1 M 7130 The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given TITLE WELL TEST PROCEDURES MANUAL DISTRIBUTION LIST Eni - Agip Division Italian Districts Eni - Agip Division Affiliated Companies Eni - Agip Division Headquarter Drilling & Completion Units STAP Archive Eni - Agip Division Headquarter Subsurface Geology Units Eni - Agip Division Headquarter Reservoir Units Eni - Agip Division Headquarter Coordination Units for Italian Activities Eni - Agip Division Headquarter Coordination Units for Foreign Activities NOTE: The present document is available in Eni Agip Intranet ( http://wwwarpo.in.agip.it ) and a CD- Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue: Issued by P. Magarini E. Monaci C. Lanzetta A. Galletta 28/06/99 28/06/99 28/06/99 REVISIONS PREP'D CHK'D APPR'D 28/06/99

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Page 1: Well Test Procedures Manual

ARPOENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 108STAP P 1 M 7130

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was given

TITLE

WELL TEST PROCEDURES MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion Units

STAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni -Agip Division Headquarter)

Date of issue:

� Issued by P. MagariniE. Monaci

C. Lanzetta A. Galletta

28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99

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INDEX

1. INTRODUCTION 7

1.1. Purpose of the manual 7

1.2. Objectives 7

1.3. Drilling Installations 8

1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION 9

2. TYPES OF PRODUCTION TEST 10

2.1. Drawdown 10

2.2. Multi-Rate Drawdown 10

2.3. Build-up 10

2.4. Deliverability 10

2.5. Flow-on-Flow 11

2.6. Isochronal 11

2.7. Modified Isochronal 11

2.8. Reservoir Limit 11

2.9. Interference 12

2.10. Injectivity 12

3. GENERAL ROLES AND RESPONSIBILITIES 13

3.1. Responsibilities and Duties 133.1.1. Company Drilling and Completion Supervisor 143.1.2. Company Junior Drilling and Completion Supervisor 143.1.3. Company Drilling Engineer 143.1.4. Company Production Test Supervisor 143.1.5. Company Well Site Geologist 153.1.6. Contractor Toolpusher 153.1.7. Contract Production Test Chief Operator 153.1.8. Contractor Downhole Tool Operator 153.1.9. Wireline Supervisor 153.1.10. Company Stimulation Engineer 153.1.11. Company Reservoir Engineer 15

3.2. Responsibilities And Duties On Short Duration Tests 163.2.1. Company Drilling and Completion Supervisor 163.2.2. Company Junior Drilling and Completion Supervisor 163.2.3. Company Well Site Geologist 163.2.4. Contractor Personnel 16

4. WELL TESTING PROGRAMME 17

4.1. Contents 17

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5. SAFETY BARRIERS 18

5.1. Well Test Fluid 18

5.2. Mechanical Barriers - Annulus Side 195.2.1. SSTT Arrangement 195.2.2. Safety Valve Arrangement 21

5.3. Mechanical Barriers - Production Side 225.3.1. Tester Valve 225.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV) 23

5.4. Casing Overpressure Valve 23

6. TEST STRING EQUIPMENT 24

6.1. General 24

6.2. Common Test Tools Description 296.2.1. Bevelled Mule Shoe 296.2.2. Perforated Joint/Ported Sub 296.2.3. Gauge Case (Bundle Carrier) 296.2.4. Pipe Tester Valve 296.2.5. Retrievable Test Packer 296.2.6. Circulating Valve (Bypass Valve) 296.2.7. Pipe Tester Valve 306.2.8. Safety Joint 306.2.9. Hydraulic Jar 306.2.10. Downhole Tester Valve 306.2.11. Single Operation Reversing Sub 306.2.12. Multiple Operation Circulating Valve 306.2.13. Drill Collar 316.2.14. Slip Joint 316.2.15. Crossovers 31

6.3. High Pressure Wells 31

6.4. Sub-Sea Test Tools Used On Semi-Submersibles 316.4.1. Fluted Hanger 316.4.2. Slick Joint (Polished Joint) 316.4.3. Sub-Sea Test Tree 316.4.4. Lubricator Valve 32

6.5. Deep Sea Tools 326.5.1. Retainer Valve 326.5.2. Deep Water SSTT 32

7. SURFACE EQUIPMENT 33

7.1. Test Package 337.1.1. Flowhead Or Surface Test Tree 337.1.2. Coflexip Hoses And Pipework 337.1.3. Data/Injection Header 347.1.4. Choke Manifold 347.1.5. Steam Heater And Generator 357.1.6. Separator 357.1.7. Data Acquisition System 367.1.8. Gauge/Surge Tanks And Transfer Pumps 367.1.9. Diverter Manifolds, Burners and Booms 37

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7.2. Emergency Shut Down System 38

7.3. Accessory Equipment 397.3.1. Chemical Injection Pump 397.3.2. Sand Detectors 397.3.3. Crossovers 40

7.4. Rig Equipment 40

7.5. Data Gathering Instrumentation 407.5.1. Offshore Laboratory and Instrument Manifold Equipment 407.5.2. Separator 417.5.3. Surge Or Metering Tank 417.5.4. Steam Heater 41

8. BHP DATA ACQUISITION 428.1.1. Quartz Crystal Gauge 428.1.2. Capacitance Gauge 428.1.3. Strain Gauge 428.1.4. Bourdon Tube Gauge 43

8.2. Gauge Installation 438.2.1. Tubing Conveyed Gauges 438.2.2. Gauge Carriers 438.2.3. SRO Combination Gauges 448.2.4. Wireline Conveyed Gauges 448.2.5. Memory Gauges Run on Slickline 448.2.6. Electronic Gauges Run on Electric Line 45

9. PERFORATING SYSTEMS 46

9.1. Tubing Conveyed Perforating 46

9.2. Wireline Conveyed Perforating 46

9.3. Procedures For Perforating 46

10. PREPARING THE WELL FOR TESTING 48

10.1. Preparatory Operations For Testing 4810.1.1. Guidelines For Testing 7ins Liner Lap 4810.1.2. Guidelines For Testing 95/8ins Liner Lap 4810.1.3. General Technical Preparations 48

10.2. Brine Preparation 4910.2.1. Onshore Preparation of Brine 4910.2.2. Transportation and Transfer of Fluids 4910.2.3. Recommendations 4910.2.4. Rig Site Preparations 5010.2.5. Well And Surface System Displacement To Brine 5210.2.6. Displacement Procedure 5210.2.7. On-Location Filtration And Maintenance Of Brine 52

10.3. Downhole Equipment Preparation 5310.3.1. Test tools 53

10.4. TUBING PREPARATION 5410.4.1. Tubing Connections 5410.4.2. Tubing Grade 55

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10.4.3. Material 5510.4.4. Weight per Foot 5510.4.5. Drift 5510.4.6. Capacity 5510.4.7. Displacement 5510.4.8. Torque 5610.4.9. AGIP (UK) Test String Specification 5610.4.10. Inspection 5710.4.11. After Testing/Prior To Re-Use 5810.4.12. Tubing Movement 58

10.5. Landing String Space-Out 5810.5.1. Landing String space-Out Procedure 60

10.6. GENERAL WELL TEST PREPARATION 6110.6.1. Crew Arrival on Location 6110.6.2. Inventory of Equipment Onsite 6210.6.3. Preliminary Inspections 62

10.7. Pre Test Equipment Checks 63

10.8. Pressure Testing Equipment 6510.8.1. Surface Test Tree 66

11. TEST STRING INSTALLATION 68

11.1. General 68

11.2. TUBING HANDLING 69

11.3. RUNNING AND PULLING 70

11.4. Packer And Test String Running Procedure 71

11.5. Running the Test String with a Retrievable Packer 71

11.6. Running a Test String with a Permanent Packer 72

12. WELL TEST PROCEDURES 74

12.1. Annulus Control And Pressure Monitoring 74

12.2. Test Execution 74

13. WELL TEST DATA REQUIREMENTS 76

13.1. General 76

13.2. Metering Requirements 77

13.3. Data Reporting 78

13.4. Pre-Test Preparation 78

13.5. Data Reporting During the Test 78

13.6. Communications 79

14. SAMPLING 80

14.1. Conditioning The Well 80

14.2. Downhole Sampling 80

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14.3. Surface Sampling 8114.3.1. General 8114.3.2. Sample Quantities 8214.3.3. Sampling Points 8214.3.4. Surface Gas Sampling 83

14.4. Surface Oil Sampling 85

14.5. Sample Transfer And Handling 86

14.6. Safety 8714.6.1. Bottom-hole Sampling Preparations 8714.6.2. Rigging Up Samplers to Wireline 8714.6.3. Rigging Down Samplers from Wireline 8714.6.4. Bottomhole Sample Transfer And Validations 8814.6.5. Separator/Wellhead Sampling 8814.6.6. Sample Storage 88

15. WIRELINE OPERATIONS 89

16. HYDRATE PREVENTION 90

17. NITROGEN OPERATIONS 91

18. OFFSHORE COILED TUBING OPERATIONS 92

19. WELL KILLING ABANDONMENT 93

19.1. Routine Circulation Well Kill 9319.1.1. Circulation Well Kill Procedure 93

19.2. Bullhead Well Kill 9519.2.1. Bullhead Kill procedure 95

19.3. Temporary Well Kill For Disconnection On Semi Submersibles 96

19.4. Plug And Abandonment/Suspension Procedures 97

19.5. Plug and Abandonment General Procedures 97

20. HANDLING OF HEAVYWATER BRINE 98

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1. INTRODUCTION

The main objective when drilling a well is to test and evaluate the target formation. The normalmethod of investigating the reservoir is to conduct a well test. There are two types of well testmethods available:

• Drill Stem Test (DST). The scope is to define the quality of the formation fluid.Where drillpipe/tubing in combination with downhole tools is used as a short termtest to evaluate the reservoir. The formation fluid may not reach or only just reachthe surface during the flowing time.

• Production Test. The scope is to define the quality and quantity of the formationfluid. Many options of string design are available depending on the requirements ofthe test and the nature of the well.

Many designs of well testing strings are possible depending on the requirements of the testand the nature of the well and the type of flow test to be conducted but basically it consists ofinstalling a packer tailpipe, packer, safety system and downhole test tools and a tubing or drillpipe string then introducing a low density fluid into the string in order to enable the well to flowthrough surface testing equipment which controls the flow rate, separates the fluids andmeasures the flow rates and pressures.

A short description of the types of tests which can be conducted and generic test stringconfigurations for the various drilling installations, as well as the various downhole toolsavailable, surface equipment, pre-test procedures and test procedures are included in thissection.

Well test specific wireline and coiled tubing operations are also included.

1.1. PURPOSE OF THE MANUAL

The purpose of the manual is to guide technicians and engineers, involved in Eni-Agip’sDrilling & Completion worldwide activities, through the Procedures and the TechnicalSpecifications which are part of the Corporate Standards.

Such Corporate Standards define the requirements, methodologies and rules that enable tooperate uniformly and in compliance with the Corporate Company Principles. This, however,still enables each individual Affiliated Company the capability to operate according to locallaws or particular environmental situations.

The final aim is to improve performance and efficiency in terms of safety, quality and costs,while providing all personnel involved in Drilling & Completion activities with commonguidelines in all areas worldwide where Eni-Agip operates.

1.2. OBJECTIVES

The test objectives must be agreed by those who will use the results and those who willconduct the test before the test programme is prepared. The Petroleum Engineer shoulddiscuss with the geologists and reservoir engineers about the information required and makethem aware of the costs and risks involved with each method. They should select the easiestmeans of obtaining data, such as coring, if possible. Such inter-disciplinary discussionsshould be formalised by holding a meeting (or meetings) at which these objectives areagreed and fixed.

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The objectives of an exploration well test are to:

• Conduct the testing in a safe and efficient manner.• Determine the nature of the formation fluids.• Measure reservoir pressure and temperature.• Interpret reservoir permeability-height product (kh) and skin value.• Obtain representative formation fluid samples for laboratory analysis.• Define well productivity and/or injectivity.• investigate formation characteristics.• Evaluate boundary effects.

1.3. DRILLING INSTALLATIONS

Well tests are conducted both onshore and offshore in either deep or shallow waters. Thedrilling units from which testing can be carried out include:

Land Rigs,

Swamp Barges

Jack-Up Rigs

The preferred method for testing on a land rig installationnecessitates the use of a permanent/retrievable type productionpacker, seal assembly and a conventional flowhead or test tree withthe test string hung of in the slips. In wells where the surfacepressure will be more than 10,000psi the BOPs will be removedand testing carried out with a tubing hanger/tubing spool and aXmas tree arrangement. This requires all the necessaryprecautions of isolation to be taken prior to nippling down the BOPs

Semi-Submersible The preferred method for testing from a Semi-submersible is byusing a drill stem test retrievable packer. However wheredevelopment wells are being tested, the test will be conductedutilising a production packer and sealbore assembly so that the wellmay be temporarily suspended at the end of the test. When testingfrom a Semi-submersible the use of a Sub-Sea Test Treeassembly is mandatory.

It consists of hanger and slick joint which positions the valve/latchsection at the correct height in the BOP stack and around which thepipe rams can close to seal of the annulus. The valve sectioncontains two fail-safe valves, usually a ball and flapper valve types.

At the top of the SSTT is the hydraulic latch section which containsthe operating mandrels to open the valves and the latchingmechanism to release this part of the tree from the valve section inthe event that disconnection is necessary.

Drill Ship Same as Semi-Submersible above.

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1.4. UPDATING, AMENDMENT, CONTROL & DEROGATION

This is a ‘live’ controlled document and, as such, it will only be amended and improved by theCorporate Company, in accordance with the development of Eni-Agip Division and Affiliatesoperational experience. Accordingly, it will be the responsibility of everyone concerned in theuse and application of this manual to review the policies and related procedures on anongoing basis.

Locally dictated derogations from the manual shall be approved solely in writing by theManager of the local Drilling and Completion Department (D&C Dept.) after theDistrict/Affiliate Manager and the Corporate Drilling & Completion Standards Department inEni-Agip Division Head Office have been advised in writing.

The Corporate Drilling & Completion Standards Department will consider such approvedderogations for future amendments and improvements of the manual, when the updating ofthe document will be advisable.

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2. TYPES OF PRODUCTION TEST

2.1. DRAWDOWN

A drawdown test entails flowing the well and analysing the pressure response as the reservoirpressure is reduced below its original pressure. This is termed drawdown. It is not usual toconduct solely a drawdown test on an exploration well as it is impossible to maintain aconstant production rate throughout the test period as the well must first clean-up. During atest where reservoir fluids do not flow to surface, analysis is still possible. This was theoriginal definition of a drill stem test or DST. However, it is not normal nowadays to plan a teston this basis.

2.2. MULTI-RATE DRAWDOWN

A multi-rate drawdown test may be run when flowrates are unstable or there are mechanicaldifficulties with the surface equipment. This is usually more applicable to gas wells but can beanalysed using the Odeh-Jones plot for liquids or the Thomas-Essi plot for gas.

It is normal to conduct a build-up test after a drawdown test.

The drawdown data should also be analysed using type curves, in conjunction with the buildup test.

2.3. BUILD-UP

A build-up test requires the reservoir to be flowed to cause a drawdown then the well isclosed in to allow the pressure to increase back to, or near to, the original pressure which istermed the pressure build-up or PBU. This is the normal type of test conducted on an oil welland can be analysed using the classic Horner Plot or superposition.

From these the permeability-height product, kh, and the near wellbore skin can be analysed.

On low production rate gas wells, where there is a flow rate dependant skin, a simple form oftest to evaluate the rate dependant skin coefficient, D, is to conduct a second flow and PBU ata different rate to the first flow and PBU. This is the simplest form of deliverability testdescribed below.

2.4. DELIVERABILITY

A deliverability test is conducted to determine the well’s Inflow Performance Relation, IPR,and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependantskin coefficient, D.

The AOFP is the theoretical fluid rate at which the well would produce if the reservoir sandface was reduced to atmospheric pressure.

This calculated rate is only of importance in certain countries where government bodies setthe maximum rate at which the well may be produced as a proportion of this flow rate.

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There are three types of deliverability test:

• Flow on Flow Test.• Isochronal Test.• The Modified Isochronal Test.

2.5. FLOW-ON-FLOW

Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilises andthen repeating this at several different rates. Usually the rate is increased at each stepensuring that stabilised flow is achievable. The durations of each flow period are equal. Thistype of test is applicable to high rate gas well testing and is followed by a single pressure buildup period.

2.6. ISOCHRONAL

An Isochronal test consist of a similar series of flow rates as the flow-on-flow test, each rateof equal duration and separated by a pressure build-up long enough to reach the stabilisedreservoir pressure. The final flow period is extended to achieve a stabilised flowing pressurefor defining the IPR.

2.7. MODIFIED ISOCHRONAL

The modified isochronal test is used on tight reservoirs where it takes a long time for the shut-in pressure to stabilise. The flow and shut-in periods are of the same length, except the finalflow period which is extended similar to the isochronal test. The flow rate again is increasedat each step.

2.8. RESERVOIR LIMIT

A reservoir limit test is an extended drawdown test which is conducted on closed reservoirsystems to determine their volume. It is only applicable where there is no regional aquifersupport. The well is produced at a constant rate until an observed pressure drop, linear withtime, is achieved. Surface readout pressure gauges should be used in this test.

It is common practice to follow the extended drawdown with a pressure build-up. Thedifference between the initial reservoir pressure, and the pressure to which it returns, is thedepletion. The reservoir volume may be estimated directly from the depletion, also the volumeof produced fluid and the effective isothermal compressibility of the system. The volumeproduced must be sufficient, based on the maximum reservoir size, to provide a measurablepressure difference on the pressure gauges, these must therefore be of the high accuracyelectronic type gauges with negligible drift.

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2.9. INTERFERENCE

An interference test is conducted to investigate the average reservoir properties andconnectivity between two or more wells. It may also be conducted on a single well todetermine the vertical permeability between separate reservoir zones.

A well-to-well interference test is not carried out offshore at the exploration or appraisal stageas it is more applicable to developed fields. Pulse testing, where the flowrate at one of thewells is varied in a series of steps, is sometimes used to overcome the background reservoirpressure behaviour when it is a problem.

2.10. INJECTIVITY

In these tests a fluid, usually seawater offshore is injected to establish the formation’sinjection potential and also its fracture pressure, which can be determined by conducting astep rate test. Very high surface injection pressures may be required in order to fracture theformation.

The water can be filtered and treated with scale inhibitor, biocide and oxygen scavenger, ifrequired. Once a well is fractured, which may also be caused by the thermal shock of thecold injection water reaching the sandface, a short term injection test will generally not providea good measure of the long term injectivity performance.

After the injectivity test, the pressure fall off is measured. The analysis of this test is similar toa pressure build-up, but is complicated by the cold water bank.

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3. GENERAL ROLES AND RESPONSIBILITIES

Well testing is potentially hazardous and requires good planning and co-operation/co-ordination between all the parties involved.

The most important aspect when planning a well test, is the safety risk assessment process.To this end, strict areas of responsibilities and duties shall be defined and enforced, detailedbelow.

3.1. RESPONSIBILITIES AND DUTIES

The following Company’s/Contractor’s personnel shall be present on the rig:

• Company Drilling and Completion Supervisor.• Company Junior Drilling and Completion Supervisor.• Company Drilling Engineer.• Company Production Test Supervisor.• Company Well Site Geologist.• Contractor Toolpusher.• Contract Production Test Chief Operator.• Contractor Downhole Tool Operator.• Wireline Supervisor (slickline & electric line ).• Tubing Power Tong Operator.• Torque Monitoring System Engineer.

Depending on the type of test, the following personnel may also be required on the rig duringthe Well test:

• Company Stimulation Engineer.• Company Reservoir Engineer.

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3.1.1. Company Drilling and Completion Supervisor

The Company Drilling and Completion Supervisor retains overall responsibility on the rigduring testing operations. He is assisted by the Company Production Test Supervisor, DrillingEngineer, Well Site Geologist and Company Junior Drilling and Completion supervisor. Whenone of the above listed technicians is not present, the Company Drilling and CompletionSupervisor, in agreement with Drilling and Completion Manager and Drilling Superintendent,can perform the test, after re-allocation of the duties and responsibilities according to the WellTest specifications. If deemed necessary he shall request that the rig be inspected by aCompany safety expert prior to starting the well test.

3.1.2. Company Junior Drilling and Completion Supervisor

The Company Junior Drilling and Completion Supervisor will assist the Company Drilling andCompletion Supervisor in well preparation and in the test string tripping operation. He will co-operate with the Company Production Test Supervisor to verify the availability of downholedrilling equipment, to carry out equipment inspections and tests and to supervise theDownhole Tool Operator and the Contractor Production Chief Operator. In co-operation withthe Drilling Engineer, he will prepare daily reports on equipment used. In the absence of theCompany Junior Drilling and Completion Supervisor, his function will be performed by theCompany Drilling and Completion Supervisor.

3.1.3. Company Drilling Engineer

The Drilling Engineer will assist the Company Drilling and Completion Supervisor in the wellpreparation and in the test string tripping operation. He will co-operate with the CompanyProduction Test supervisor to supervise the downhole tool Operator and the ContractorProduction Chief Operator. He shall be responsible for supplying equipment he is concernedwith (downhole tools) and for preliminary inspections. He shall provide Contractor personnelwith the necessary data, and prepare accurate daily reports on equipment used in co-operation with the Company Junior Drilling and Completion Supervisor.

3.1.4. Company Production Test Supervisor

The Company Production Test Supervisor is responsible for the co-ordination and conductingof the test. This includes well opening, flow or injection testing, separation and measuring,flaring, wireline, well shut in operations and all preliminary test operations required on specificproduction equipment. In conjunction with the Reservoir Engineer, he shall makerecommendations on test programme alterations whenever test behaviour is not as expected.The final decision to make any programme alterations will be taken by head office.

The Company Production Test Supervisor will discuss and agree the execution of eachphase of the test with the Company Drilling and Completion Supervisor. He will then inform rigfloor and test personnel of the actions to be performed during the forthcoming phase of thetest. He will be responsible for co-ordination the preparation of all reports and telexes,including the final well test report.

He is responsible for arranging the supply of all equipment necessary for the test i.e. surfaceand down hole testing tools, supervising preliminary inspections as per procedures. He willsupervise contract wireline and production test equipment operator’s, as well as the downholetool operator and surface equipment operators. He will be responsible in conjunction with theCompany Well site Geologist for the supervision of perforating and cased hole loggingoperations, as per the test programme.

The Company Production Test Supervisor is responsible for the preparation of all reports,

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including the final field report previously mentioned.

3.1.5. Company Well Site Geologist

The Well Site Geologist is responsible for the supervision of perforating operations (for welltesting) cased hole logging when the Company Production Test Supervisor is not present onthe rig. If required he will co-operate with the Company Production Test Supervisor for the testinterpretation and preparation of field reports.

3.1.6. Contractor Toolpusher

The Toolpusher is responsible for the safety of the rig and all personnel. He shall ensure thatsafety regulations and procedures in place are followed rigorously. The Toolpusher shallconsistently report to the Company Drilling and Completion supervisor on the status of drillingcontractors material and equipment.

3.1.7. Contract Production Test Chief Operator

The Production Test Chief Operator shall always be present to co-ordinate and assist the welltesting operator and crew. He will be responsible for the test crew to the Company ProductionTest Supervisor and will draw up a chronological report of the test.

3.1.8. Contractor Downhole Tool Operator

The downhole tool operator will remain on duty, or be available, on the rig floor from the timethe assembling of the BHA is started until it is retrieved. He is solely responsible for downholetool manipulation and annulus pressure control during tests.

On Semi-Submersibles the SSTT operator will be available near the control panel on the rigfloor from the time when the SSTT is picked up until it is laid down again at the end of the test.During preliminary inspections of equipment, simulated test (dummy tests), tools tripping inand out of the hole and during the operations relating to the well flowing (from opening toclosure of tester ), he will report to the Company Production Test Supervisor.

3.1.9. Wireline Supervisor

The Wireline Supervisor will ensure all equipment is present and in good working order. Hewill report directly with the Company Production Test Supervisor.

3.1.10. Company Stimulation Engineer

If present on the rig, the Stimulation Engineer will assist the Company Production TestSupervisor during any stimulation operations. He will provide the Company Production TestSupervisor with a detailed programme for conducting stimulation operations, including thedeck layout for equipment positioning, chemical formulations, pumping rates and datacollection. He will monitor the contractors during the stimulation to ensure the operation isperformed safely and satisfactorily.

The Stimulation Engineer will also provide the Company Production Test Supervisor with areport at the end of the stimulation operation.

3.1.11. Company Reservoir Engineer

If present on the rig, the Reservoir Engineer shall assist the Company Production Test

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Supervisor during the formation testing operation. His main responsibility is to ensure that therequired well test data is collected in accordance to the programme and for the quality of thedata for analysis. He will provide a quick look field analysis of each test period and on thisbasis he will advise on any necessary modifications to the testing programme.

3.2. RESPONSIBILITIES AND DUTIES ON SHORT DURATION TESTS

As a general rule the only company personnel present on the rig shall be the Company Drillingand Completion Supervisor, the Company Junior Drilling and Completion Supervisor and thewell site Geologist, the Company Drilling Manager/Superintendent shall evaluate, in eachindividual case, the opportunity of providing a company Drilling Engineer. The responsibilitiesand duties of the Company Drilling and Completion Supervisor and Well Site Geologist will beas follows:

3.2.1. Company Drilling and Completion Supervisor

The Company Drilling and Completion Supervisor retains overall responsibility on the rigduring testing operations assisted by the Company Junior Drilling and Completion Supervisorand the well site Geologist. He is responsible for the co-ordination of testing operations, wellpreparation for tests, shut-in of the well, formation clean out, measuring, flaring and wirelineoperations. The Company Drilling and Completion Supervisor is responsible for the availabilityand inspection of the testing equipment. He shall supervise the contractor Production ChiefOperator, Wireline Operator and Production Test Crew, as well as the Downhole ToolOperator and Surface Tool Operator.

3.2.2. Company Junior Drilling and Completion Supervisor

The Company Junior Drilling and Completion Supervisor shall assist the Company Drillingand Completion Supervisor to accomplish his duties. He shall also prepare accurate dailyreports on equipment used.

3.2.3. Company Well Site Geologist

The Well Site Geologist is responsible for the supervision of perforating operations and forcased hole logging operations. He is responsible for the final decision making to modify thetesting programme, whenever test behaviour would be different than expected. He shall drawup daily and final reports on the tests and is responsible for the first interpretation of the test.

3.2.4. Contractor Personnel

For the allocation of responsibilities and duties of contractor’s Personnel (Toolpusher,Production Chief Operator, Downhole Tool Operator), refer to long test responsibilities.

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4. WELL TESTING PROGRAMME

When the rig reaches Total Depth (TD) and all the available data is analysed, the companyReservoir/Exploration Departments shall provide the Company Drilling/Production andEngineering departments with the information required for planning the well test (type,pressure, temperature of formation fluids, intervals to be tested, flowing or sampling test,duration of test, type of completion fluid, type and density of fluid against which the well will beopened, type of perforating gun and number of shots per foot, use of coiled tubing stimulation,etc.).

The Drilling, Production and Engineering departments shall then prepare a detailed testingprogramme verifying that the testing equipment conforms to these procedures. The duty ofthe Engineering Department is also to make sure that the testing equipment is available at therig in due time.

Company and contractor personnel on the rig shall confirm equipment availability andprogramme feasibility, verifying that the test programme is compatible with general andspecific rules related to the drilling unit.

Governmental bodies of several countries lay down rules and regulations covering the entiredrilling activity. In such cases , prior to the start of testing operations a summary programmeshall be submitted for approval to national agencies, indicating well number, location,objectives, duration of test and test procedures.

Since it is not practical to include all issued laws within the company general statement thecompany (Drilling, Production, Engineering departments and rig personnel) shall verify theconsistency of the present procedures to suit local laws, making any modifications that wouldbe required. However, at all times, the most restrictive interpretation shall apply.

4.1. CONTENTS

The programme shall be drawn up in order to acquire all necessary information taking intoaccount two essential factors:

• The risk to which the rig and personnel are exposed during testing.• The cost of the operation.

A detailed testing programme shall include the following points:

• A general statement indicating the well status, targets to be reached, testingprocedures as well as detailed safety rules that shall be applied, should they differfrom those detailed in the current procedures.

• Detailed and specific instructions covering well preparation, completion andcasing perforating system, detailed testing programme field analysis on test dataand samples, mud programme and closure of the tested interval.

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5. SAFETY BARRIERS

Barriers are the safety system incorporated into the structure of the well and the test stringdesign to prevent uncontrolled flow of formation fluids and keep well pressures off the casing.

It is common oilfield practice to ensure there are at least two tested barriers in place oravailable to be closed at all times. A failure in any barrier system which means the wellsituation does meet with this criteria, then the test will be terminated and the barrier replaced,even if it entails killing of the well to pull the test string.

To ensure overall well safety, there must be sufficient barriers on both the annulus side andthe production or tubing side. Some barriers may actually contain more than one closuremechanism but are still classified as a single barrier such as the two closure mechanism in aSSTT, etc.

Barriers are often classified as primary, secondary and tertiary.

This section describes the barrier systems which must be provided on well testingoperations.

5.1. WELL TEST FLUID

The fluid which is circulated into the wellbore after drilling operations is termed the well testfluid and conducts the same function as a completion fluid and may be one and the same ifthe well is to be completed after well testing. It provides one of the functions of a drilling fluid,with regards to well control, in that it density is designed to provide a hydrostatic overbalanceon the formation which prevents the formation fluids entering the wellbore during the times itis exposed to the test fluid during operations. The times that the formation may be exposed tothe test fluid hydrostatic pressure are when:

• A casing leak develops.• The well is perforated before running the test string.• There is a test string leak during testing.• A circulating device accidentally opens during testing.• Well kill operations are conducted after the test.

During the testing operation when the packer is set and the well is flowing, the test fluid is onlyone of the barriers on the annulus side.

The test fluid density will be determined form log information and calculated to provide ahydrostatic pressure, generally between 100-200psi, greater than the formation pressure.completion. As the test fluid is usually a clear brine for damage prevention reasons, highoverbalance pressures may cause severe losses and alternatively, if the overbalancepressure is too low, any fluid loss out of the wellbore may quickly eliminated the margin ofoverbalance. When using low overbalance clear fluids, it is important to calculate thetemperature increase in the well during flow periods as this decreases the density.

An overbalance fluid is often described as the primary barrier during well operations.

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A modern test method used on wells which have high pressures demanding high density testfluids which are unstable an extremely costly, is to design the well test with an underbalancedfluid which is much more stable and cheaper. In this case there will be one barrier less thanoverbalance testing. This is not a problem providing the casing is designed for the staticsurface pressures of the formation fluids and that all other mechanical barriers are availableand have been tested.

5.2. MECHANICAL BARRIERS - ANNULUS SIDE

On the annulus side, the mechanical barriers are:

• Packer/tubing envelope.• Casing/BOP pipe ram/side outlet valves envelope.

Therefore, under normal circumstances there are three barriers on the annulus side with theoverbalance test fluid. If one of these barriers (or element of the barrier) failed then therewould still be two barriers remaining.

An alternate is when the BOPs are removed and a tubing hanger spool is used with a Xmastree. In this instance the barrier envelope on the casing side would be casing/hangerspool/side outlet valves.

The arrangement of the BOP pipe ram closure varies with whether there is a surface orsubsea BOP stack. When testing from a floater, a SSTT is utilised to allow the rig to suspendoperations and leave the well location for any reason. On a jack-up, a safety valve is installedbelow the mud line as additional safety in the event there is any damage caused to theinstallation (usually approx. 100m below the rig floor). Both systems use a slick joint spacedacross the lower pipe rams to allow the rams to be closed on a smooth OD.

5.2.1. SSTT Arrangement

A typical SSTT arrangement is shown in figure 5.a. The positioning of the SSTT in the stack isimportant to allow the blind rams to be closed above the top of the SSTT valve sectionproviding additional safety and keeping the latch free from any accumulation of debris whichcan effect re-latching.

Note: The shear rams are not capable of cutting the SSTT assembly unless asafety shear joint is installed in the SSTT across the shear ram position.

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Figure 5.A - SSTT Arrangement

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5.2.2. Safety Valve Arrangement

On jack-ups where smaller production casing is installed, the safety valve may be too large inOD (7-8ins) to fit inside the casing. In this instance a spacer spool may be added between thestack and the wellhead to accommodate the safety valve. This is less safe than having thevalve positioned at the mud line as desired (Refer to figure 5.b )

Figure 5.B - Safety Valve Arrangement

PIPE RAMS

SHEAR RAMS

5” PIPE RAMS

5” SLICK JOINT

8 ” O . D .

S A F E T Y V A L V E

9 5/8” CASING

TUBINGTUBING SPOOL

ALL WELLS WITH 9 5/8”PROD. CASING

TUBING

1 3 3 / 8 ” o r 1 1 ” 5 0 0 0 - 1 0 0 0 0 - 1 5 0 0 0 p s i W . P . B O P S T A C K S

TUBING SPOOL

TUBING SPOOL TUBING SPOOL

TUBING SPOOL

5.25” O.D.SAFETY VALVE

8” O.D.SAFETY VALVE

8” O.D.SAFETY VALVE

8” O.D.SAFETY VALVE

7” CASING 7” CASING 7” CASING

7” CASING

5” SLICK JOINT

5” SLICK JOINT

5” SLICK JOINT 5” SLICK JOINT

JACK UP, FIXED PLATFORMS and ON-SHORE RIGS WITH 7” PRODUCTION CASING ALL WELLS WITH 7”PROD. CASING

PIPE RAMS

SPACER SPOOL0.6 to 1.0 metre long

SPACER SPOOL0.6 to 1.0 metre long

SPACER SPOOLminimum 1 metre longfor fixed platforms

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5.3. MECHANICAL BARRIERS - PRODUCTION SIDE

On the production side there are a number of barriers or valves which may be closed to shut-off well flow. However some are solely operational devices. The barriers used in well controlare:

Semi-submersible string - Latched

• Tester valve• SSTT• Surface test tree.

Semi-submersible string - Unlatched

• Tester valve• SSTT.

Jack-Up

• Tester valve• Safety valve• Surface test tree.

Land well

• Tester valve• Safety valve• Surface test tree.

5.3.1. Tester Valve

The tester valve is an annulus pressure operated fail safe safety valve. It remains open bymaintaining a minimum pressure on the annulus with the cement pump. Bleeding off thepressure or a leak on the annulus side closes the valve.

The tester may have an alternate lock open cycle device and it is extremely important that thistype of valve is set in the position where the loss of pressure closes the valve. It is unsafe toleave the tester valve in the open cycle position as in an emergency situation there may notbe sufficient time to cycle the valve closed.

The tester valve may be considered as the primary barrier during the production phase.

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5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV)

This is a valve normally installed about 100m below the wellhead or below the mud line inpermanent on-shore and off-shore completions respectively.

This type of valve can also be installed inside the BOP for well testing as an additionaldownhole barrier on land wells or on jack-up rigs, see figure 5.b for the various configurationsof BOP stacks combinations relating to the production casing size.

Due to the valve OD (7-8ins) available today in the market, its use with 7” production casing isonly possible by installing a spacer spool between the tubing spool and the pipe rams closedon a slick joint directly connected to the upper side of the valve itself. A space of at least twometres between pipe rams and top of tubing spool is required.

The valve OD must be larger than the slick joint to provide a shoulder to prevent upward stringmovement.

A small size test string with a 5.25ins OD safety valve can be used with 7ins casing, asindicated.

In all cases the valve is operated by hydraulic pressure through a control line and is fail safewhen this pressure is bled off. The slick joint body has an internal hydraulic passage for thecontrol line.

The safety valve can be considered the secondary barrier during production.

5.4. CASING OVERPRESSURE VALVE

A test string design which includes an overpressure rupture disk, or any other systemsensible to casing overpressure, should have an additional single shot downhole safety valveto shut off flow when annulus pressure increases in an uncontrolled manner.

This additional safety feature is recommended only in particular situations where there arevery high pressures and/or production casing is not suitable for sudden high overpressuresdue to the test string leaking.

This valve is usually used with the single shot circulating valve which is casing pressureoperated and positioned above the safety valve, hence will open at the same time the safetyvalve closes. This allows the flow line to bleed off the overpressure.

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6. TEST STRING EQUIPMENT

6.1. GENERAL

The well testing objectives, test location and relevant planning will dictate which is the mostsuitable test string configuration to be used. Some generic test strings used for testing fromvarious installations are shown over leaf:

In general, well tests are performed inside a 7ins production liner, using full opening test toolswith a 2.25ins ID. In larger production casing sizes the same tools will be used with a largerpacker. In 5-51/2ins some problems can be envisaged: availability, reliability and reduced IDlimitations to run W/L. tools, etc. smaller test tools will be required, but similarly, the toolsshould be full opening to allow production logging across perforated intervals. For a barefoottest, conventional test tools will usually be used with a packer set inside the 95/8ins casing.

If conditions allow, the bottom of the test string should be 100ft above the top perforation toallow production logging, reperforating and/or acid treatment of the interval.

In the following description, tools which are required both in production tests and conventionaltests are included. The list of tools is not exhaustive, and other tools may be included.However, the test string should be kept as simple as possible to reduce the risk ofmechanical failure. The tools should be dressed with elastomers suitable for the operatingenvironment, considering packer fluids, prognosed production fluids, temperature and thestimulation programme, if applicable.

The tools must be rated for the requested working pressure (in order to withstand themaximum forecast bottom-hole/well head pressure with a suitable safety factor).

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Figure 6.A - Typical Jack Up/Land Test String - Packer With TCP Guns On Packer

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Figure 6.B - Typical Test String - Production Packer With TCP Guns Stabbed Through

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Figure 6.C - Typical Jack Up/Land Test String - Retrievable Packer

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Figure 6.D - Typical Semi-Submersible Test String - Retrievable Packer

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6.2. COMMON TEST TOOLS DESCRIPTION

6.2.1. Bevelled Mule Shoe

If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top.The bevelled mule shoe also facilities pulling wireline tools back into the test string.

If testing with a permanent packer, the mule shoe allows entry into the packer bore.

6.2.2. Perforated Joint/Ported Sub

The perforated joint or ported sub allows wellbore fluids to enter the test string if the tubingconveyed perforating system is used. This item may also be used if wireline retrievablegauges are run below the packer.

6.2.3. Gauge Case (Bundle Carrier)

The carrier allows pressure and temperature recorders to be run below or above the packerand sense either annulus or tubing pressures and temperatures.

6.2.4. Pipe Tester Valve

A pipe tester valve is used in conjunction with a tester valve which can be run in the openposition in order to allow the string to self fill as it is installed. The valve usually has a flappertype closure mechanism which opens to allow fluid bypass but closes when applying tubingpressure for testing purposes. The valve is locked open on the first application of annuluspressure which is during the first cycling of the tester valve.

6.2.5. Retrievable Test Packer

The packer isolates the interval to be tested from the fluid in the annulus. It should be set byturning to the right and includes a hydraulic hold-down mechanism to prevent the tool frombeing pumped up the hole under the influence of differential pressure from below the packer.

6.2.6. Circulating Valve (Bypass Valve)

This tool is run in conjunction with retrievable packers to allow fluid bypass while running inand pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. Itcan also be used to equalise differential pressures across packers at the end of the test. It isautomatically closed when sufficient weight is set down on the packer.

This valve should ideally contain a time delay on closing, to prevent pressuring up of theclosed sump below the packer during packer setting. This feature is important when runningtubing conveyed perforating guns which are actuated by pressure. If the valve does not have adelay on closing, a large incremental pressure, rather than the static bottomhole pressure,should be chosen for firing the guns

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6.2.7. Pipe Tester Valve

A pipe tester valve is used in conjunction with a tester valve which can be run in the openposition in order to allow the string to self fill as it is installed. The valve usually has a flappertype closure mechanism which opens to allow fluid bypass but closes when applying tubingpressure for testing purposes.

The valve is locked open on the first application of annulus pressure which is during the firstcycling of the tester valve.

6.2.8. Safety Joint

Installed above a retrievable packer, it allows the test string above this tool to be recovered inthe event the packer becomes stuck in the hole. It operates by manipulating the string (usuallya combination of reciprocation and rotation) to unscrew and the upper part of the stringretrieved. The DST tools can then be laid out and the upper part of the safety joint run back inthe hole with fishing jar to allow more powerful jarring action.

6.2.9. Hydraulic Jar

The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an overpull to betaken on the string which is then suddenly released, delivering an impact to the stuck tools.

6.2.10. Downhole Tester Valve

The downhole tester valve provides a seal from pressure from above and below. The valve isoperated by pressuring up on the annulus. The downhole test valve allows downhole shut inof the well so that after-flow effects are minimised, providing better pressure data. It also hasa secondary function as a safety valve.

6.2.11. Single Operation Reversing Sub

Produced fluids may be reversed out of the test string and the well killed using this tool. It isactuated by applying a pre-set annulus pressure which shears a disc or pins allowing amandrel to move and expose the circulating ports. Once the tool has been operated it cannotbe reset, and therefore must only be used at the end of the test.

This reversing sub can also be used in combination with a test valve module if a further safetyvalve is required. One example of this is a system where the reversing sub is combined withtwo ball valves to make a single shot sampler/safety valve.

6.2.12. Multiple Operation Circulating Valve

This tool enables the circulation of fluids closer to the tester valve whenever necessary as itcan be opened or closed on demand and is generally used to install an underbalance fluid forbrining in the well.

This tool is available in either annulus or tubing pressure operated versions. The tubingoperated versions require several pressure cycles before the valve is shifted into thecirculating position. This enables the tubing to be pressure tested several times while runningin hole. Eni-Agip’s preference is the annulus operated version.

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6.2.13. Drill Collar

Drill collars are required to provide a weight to set the packer. Normally two stands of 43/4insdrill collars (46.8lbs/ft) should be sufficient weight on the packer, but should be regarded asthe minimum.

6.2.14. Slip Joint

These allow the tubing string to expand and contract in the longitudinal axis due to changes intemperature and pressure. They are non-rotating to allow torque for setting packers oroperating the safety joint.

6.2.15. Crossovers

Crossovers warrant special attention They are of the utmost importance as they connectevery piece of equipment in the test string which have differing threads. If crossovers have tobe manufactured, they need to be tested and fully certified. In addition, they must be checkedwith each mating item of equipment before use.

6.3. HIGH PRESSURE WELLS

If the SBHP >10,000psi a completion type test string and production Xmas tree isrecommended to test the well.

6.4. SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES

The sub-sea test tree (SSTT) assembly includes a fluted hanger, slick joint, and sub-sea testtree.

6.4.1. Fluted Hanger

The fluted hanger lands off and sits in the wear bushing of the wellhead and is adjustable toallow the SSTT assembly to be correctly positioned in the BOP stack so that when the SSTTis disconnected the shear rams can close above the disconnect point.

6.4.2. Slick Joint (Polished Joint)

The slick joint (usually 5ins OD) is installed above the fluted hanger and has a smooth (slick)outside diameter around which the BOP pipe rams can close and sustain annulus pressurefor DST tool operation or, if in an emergency disconnection, contain annulus pressure. Theslick joint should be positioned to allow the two bottom sets of pipe rams to be closed on itand also allow the blind rams to close above the disconnect point of the SSTT.

6.4.3. Sub-Sea Test Tree

The SSTT is a fail-safe sea floor master valve which provides two functions; the shut off ofpressure in the test string and; disconnection of the landing string from the test string due toan emergency situation or for bad weather. The SSTT is constructed in two parts; the valveassembly consisting of two fail safe closed valves and; a latch assembly. The latch containsthe control ports for the hydraulic actuation of the valves and the latch head.

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The control umbilical is connected to the top of the latch which can, under mostcircumstances be reconnected, regaining control without killing the well. The valves holdpressure from below, but open when a differential pressure is applied from above, allowingsafe killing of the well without hydraulic control if unlatched.

6.4.4. Lubricator Valve

The lubricator valve is run one stand of tubing below the surface test tree. This valveeliminates the need to have a long lubricator to accommodate wireline tools above thesurface test tree swab valve. It also acts as a safety device when, in the event of a gasescape at surface, it can prevent the full unloading of the contents in the landing string afterclosing of the SSTT. The lubricator valve is hydraulic operated through a second umbilical lineand should be either a fail closed or; fail-in-position valve. When closed it will contain pressurefrom both above and below

6.5. DEEP SEA TOOLS

6.5.1. Retainer Valve

The retainer valve is installed immediately above the SSTT on tests in extremely deep watersto prevent large volumes of well fluids leaking into the sea in the event of a disconnect. It ishydraulic operated and must be a fail-open or fail-in-position valve. When closed it will containpressure from both above and below. It is usually run in conjunction with a deep water SSTTdescribed below.

6.5.2. Deep Water SSTT

As exploration moves into deeper and remote Subsea locations, the use of dynamicpositioning vessels require much faster SSTT unlatching than that available with the normalhydraulic system on an SSTT. The slow actuation is due to hydraulic lag time when bleedingoff the control line against friction and the hydrostatic head of the control fluid. This isovercome by use of the deepwater SSTT which has an Electro-Hydraulic control system.

The Hydraulic deep water actuator is a fast response controller for the deepwater SSTTand retainer valve. This system uses hydraulic power from accumulators on the treecontrolled electrically from surface (MUX). The fluid is vented into the annulus or anatmospheric tank to reduce the lag time and reducing closure time to seconds.

If a programme required deepwater test tools, the tool operating procedures would beincluded in the test programme.

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7. SURFACE EQUIPMENT

This sub-section contains the list of surface equipment and the criteria for use.

7.1. TEST PACKAGE

7.1.1. Flowhead Or Surface Test Tree

Modern flowheads are of solid block construction, i.e. as a single steel block, as opposed tothe earlier modular unit which was assembled from various separate components.Irrespective of the type, both should contain:

• Upper Master Valve for emergency use only.• Lower Master Valve situated below the swivel for emergency use only.• Kill Wing Valve on the kill wing outlet connected to the cement pump or the rig

manifold.• Flow Wing Valve on the flow wing outlet, connected to the choke manifold, which

is the ESD actuated valve.• Swab Valve for isolation of the vertical wireline or coil tubing access.• Handling Sub which is the lubricator connection for wireline or coiled tubing and is

also for lifting the tree.• Pressure Swivel which allows string rotation with the flow and kill lines connected.

With the rig at its operating draft, the flowhead should be positioned so that it is at a distanceabove the drill floor which is greater than the maximum amount of heave anticipated, plus anallowance for tidal movement, i.e. 5ft and a further 5ft safety margin.

Coflexip hoses are used to connect from the flowhead kill wing and flow wing to the rigmanifold and the test choke manifold. A permanently installed test line is sometimes availablewhich leads from the drill floor to the choke manifold location.

7.1.2. Coflexip Hoses And Pipework

Coflexip hoses must be installed on the flowhead correctly so as to avoid damage. They mustbe connected so that they hang vertically from the flowhead wings. The hoses should neverbe hung across a windwall or from a horizontal connection unless there is a pre-formedsupport to ensure they are not bent any tighter than their minimum radius of 5ft.

Hoses are preferred to chiksan connections because of their flexibility, ease of hook up andtime saving. They are also less likely to leak due to having fewer connections. On floaters,they connect the stationary flowhead to the moving rig and its permanent pipework.

Permanently installed surface lines should be used with the minimum of temporaryconnections supplied from the surface testing contractor. Ideally these temporaryconnections should be made-to-measure pipe sections with welded connections, howeverchiksans can be used but must be tied down to the deck.

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Additional protection can be given by installing relief valves in the lines. Is now commonpractice to have a relief valve on the line between the heater and the separator to cater for anyblockage downstream which may cause over-pressure in the line. If there is further risk fromplugging of the burner nozzles by sand carry-over, then consideration should be given toinstalling further relief valves downstream of the separator to protect this lower pressure ratedpipework.

Note: Ensure that the Coflexip hoses are suitable for use with corrosive brines.

7.1.3. Data/Injection Header

This item is usually situated immediately upstream of the choke. The data/injection header ismerely a section of pipe with several ports or pockets to mount the following items:

• Chemical injection• Wellhead pressure recording• Temperature recording• Wellhead pressure recording with a dead weight tester• Wellhead sampling• Sand erosion monitoring• Bubble hose.

Most of the pressure and temperatures take off points will be duplicated for the DataAcquisition System sensors.

7.1.4. Choke Manifold

The choke manifold is a system of valves and chokes for controlling well flow and usually hasone adjustable and one fixed choke. Some choke manifolds may also incorporate a bypassline. The valves are used to direct the flow through either of the chokes or the bypass. Theyalso provide isolation from pressure so that the choke changes can be made.

A well shall be brought in using the adjustable or variable choke. This choke should never befully closed against well flow. The flow should then be redirected to the appropriately sizedfixed choke for stable flow conditions. The testing contractor should ensure that a full range offixed chokes are available in good condition.

Due to the torturous path of the fluids through the choke, flow targets are positioned where theflow velocities are high and impinge on the bends. Ensure these have been checked duringthe previous refurbishment to confirm they were still within specification.

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7.1.5. Steam Heater And Generator

Heat is required from the steam heater, or heat exchanger, to:

• Prevent hydrate formation on gas wells• Prevent wax deposition when testing high waxy, paraffin type crudes• Break foams or emulsions• Reduce viscosity of heavy oils.

For use on high flow rate wells, a 4ins bore steam heater should be used to reduce high backpressures.

The heat required to raise a gas by 1oF can be estimated from the formula:

2,550 x Gas Flow (mmscf/day) x Gas Specific Gravity (air = 1.000), BTU/hr/oF

The heat needed to raise an oil by 1oF can be estimated from:

8.7 x Oil Flow (bbls/day) x Oil Density (gms/cm3), BTU/hr/oF

Always use the largest steam heater and associated generator that space or deck loading willallow as the extra output is contingency for any serious problem which may arise. The rigsteam generator will not usually have the required output and therefore diesel-fired steamgenerator in conjunction with the steam heat exchanger should be supplied by the surfacetest contractor.

7.1.6. Separator

The test separator is required to:

• Separate the well flow into three phases; oil, gas and water• Meter the flow rate of each phase, at known conditions• Measure the shrinkage factor to correct to standard conditions• Sample each phase at known temperature and pressure.

The standard offshore separator is a horizontal three phase, 1,440psi working pressure unit.This can handle up to 60mmscf/day of dry gas or up to 10,000bopd and associated gas at itsworking pressure Other types of separator, such as the vertical or spherical models and two-phase units may be used.

Gas is metered using a Daniel’s or similar type orifice plate gas meter. The static pressure,pressure drop across the orifice plate and the temperature are all recorded. From this datathe flow rate is calculated.

The liquid flowrates are measured by positive displacement or vortex meters.

The oil shrinkage factor is physically measured by allowing a known volume of oil, undercontrolled conditions, to de-pressurise and cool to ambient conditions. The shrinkage factor isthe ambient volume, divided by the original volume. The small volume, however, of theshrinkage meter means that this is not an accurate measurement.

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The oil flow rate is corrected for any volume taken up by gas, water, sand or sediment. Thisvolume is calculated by multiplying the combined volume by the BS&W measurement and thetank/meter factor. Oil meters are calibrated onshore but it is also necessary to divert the oilflow to a gauge tank for a short period to obtain a combined shrinkage/meter factor as themeter calibration is subject to discrepancy with varying oil gravity and viscosity.

The separator relief system is calibrated onshore and should never be function testedoffshore, hence the separator should only be tested to 90% of the relief valve setting.

It is important that the separator bypass valves, diverter valves for the vent lines leading fromthe separator relief valve, rupture disc or back-up relief valve, are checked for ease ofoperation.

7.1.7. Data Acquisition System

It is now common custom to use computerised Data Acquisition Systems (DAS) on offshorewell tests. However, it is essential that manual readings are still separately recorded forcorrelation of results and contingency in the event of problems occurring to the system.

These systems can collect, store and provide plots of:

• Surface data• Downhole data from gauges• Memory gauge data.

The main advantage of DAS is that real time plots can be displayed at the well site fortroubleshooting. Another advantage is that all of the surface (and possibly downhole) data iscollected into one system and can be supplied on a floppy disk for the operator to analyse andsubsequently prepare well reports.

7.1.8. Gauge/Surge Tanks And Transfer Pumps

A gauge tank is an atmospheric vessel whereas a surge tank is usually rated to 50psi WPand is vented to the flare. A surge tank is essential for safe working if H2S production isanticipated. Therefore, surge tanks should always be used on wildcat wells and gauge tanksused only in low risk situations.

Tanks are used for checking the oil meter/shrinkage factors and for measuring volumes atrates which are too low for accurate flow meter measurement. They usually have a capacityof one hundred barrels and some with twin compartments so that one compartment can befilled while the other is pumped to the burner via the transfer pump.

Tanks can also be used for collecting large atmospheric samples of crude for analysis orused as a secondary separator for crudes which require longer separation times. Some tankscan have special features such as steam heating elements for heavy/viscous oil productiontests etc.

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7.1.9. Diverter Manifolds, Burners and Booms

Burner heads are mounted on the end of the booms which are usually installed on opposingsides of the rig to take maximum advantage of wind direction changes, i.e. to keep at leastone burner heading downwind. The oil and gas flowlines, including the tank and relief ventlines, from the test area to the booms, must have diverter manifolds for directing flow to theleeward boom.

Most recent designs of burners are promoted as ‘green’ or ‘clean’ type burners. This isindicative of them being less polluting to the environment by having superior burningtechnology. Although still not ‘ideal’ their ability is much improved over previous models.

The burner has a ring of atomisers or nozzles which break up the flow for completecombustion. This is assisted by pumping air into the flow stream. Rig air must not be used forthis purpose as there is a risk of hydrocarbons leaking back into the rig air system. Twoportable air compressors, one as back-up, are required, suitably fitted with check valves. It isrecommended that the air compressors are manifolded together to provide a continuoussupply of air in the event of a compressor failure.

Green style burners are very heavy users of air and consideration must be given for deckspace for additional air compressors.

Water must be pumped to the burner head which forms a heat shield in the form of a sprayaround the flare to protect the installation from excessive heat. It also aids combustion andcools the burner head. Water must also be sprayed on the rig to keep it cool and specialattention must be given to the lifeboats. It is now normal for a rig to have a permanent spraysystem installed and water may be provided by the rig pumps.

The burners have propane pilot lights which are ignited using a remote spark ignition system.For heavy/viscous oil tests a large quantity of propane may be required. If this is the case,mud burners should be requested, as they are specially designed to handle oil-based mud.They can also better handle the clean-up flow. Alternatively, diesel can be spiked in at the oilmanifold using the cement pumps to assist combustion but, if there is only partialcombustion, carry over can cause pollution. Oil slicks can also be ignited and be a hazard tothe rig. If a heavy/viscous oil production test is planned, sufficient gauge tanks should be onhand to conduct a test without flaring the oil.

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Figure 7.A - Surface Equipment Layout

7.2. EMERGENCY SHUT DOWN SYSTEM

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The Emergency Shut Down (ESD) system is the primary safety system in the event of anuncontrolled escape of hydrocarbons at surface. The system consists of a hydraulically orpneumatically operated flowhead flow wing valve, control panel and a number of remotely airoperated pilot valves. When a pilot or the main valve in the panel is actuated, it causes a lossof air pressure in turn dropping out the main hydraulic valve which releases the pressure fromthe flowhead ESD valve actuator.

The push button operated pilot valves are strategically placed at designated accessible areaswhere the test crew and/or rig crew can actuate them by pushing the button when theyobserve an emergency situation. Other pilots may be high or low pressure actuated pilotsinstalled at critical points in the system to protect equipment from over-pressure or under-pressure which would indicate an upstream valve closure, blockage or leak etc. The systemis also actuated if a hose is cut or melted by heat from a fire, also releasing the air pressure.

7.3. ACCESSORY EQUIPMENT

7.3.1. Chemical Injection Pump

The main chemicals that are injected into the production flow are hydrate inhibitors, de-foamers, de-emulsifiers and wax inhibitors. The chemicals are injected by an air drivenchemical injection pump at, either the data/injection header, flowhead or at the SSTT/sub-surface safety valve. Chemicals must be supplied with toxicological and safety data sheetsas per regulations.

7.3.2. Sand Detectors

Sonic type sand detectors can be installed at the data/injection header upstream of the chokeif sand production is expected to cause erosion. These devices operate by detecting theimpingement of sand on a probe inserted into the flowstream. The accuracy is reasonable insingle phase gas flow but less consistent in multi-phase flow.

The simplest approach to sand detection is to take frequent BS&W samples at thedata/injection manifold to monitor for sand production. If the flow rates are low, samples takenfrom the high side of flowline might incorrectly show little or no sand, therefore a suitablesample point must also be available on the low side of the manifold. Samples should then becollected from both points. The problem with this method is determining if the sand is causingerosion or not. An erosion coupon or probe can also be installed on the manifold which willindicate if erosion is occurring.

When sand production is anticipated on a test, sand traps should be employed. These large,high pressure vessels would be situated upstream of the choke manifold and remove thesand before it reaches the higher velocity flow rates at the choke. Control of the flowrate alsocan prevent erosion by keeping it below the point where sand is lifted up the wellbore tosurface; however, this inflicts severe limitations on the test design.

Erosion can eventually cause:

• Reduced pipe wall thickness and cutting of holes in pipework, including valvesand chokes.

• Damaging (sandblasting) the separator and filling it with sand.• Cutting out of burner nozzles.• Sanding up the well and possibly plugging of downhole test tools.

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7.3.3. CrossoversCrossovers warrant special attention They are of the utmost importance as they connectevery piece of equipment in the test string which have differing threads. If crossovers have tobe manufactured, they need to be tested and fully certified. In addition, they must be checkedwith each mating item of equipment before use.

7.4. RIG EQUIPMENT

The main items of rig equipment used for testing, such as the permanent pipework and waterspray system have been addressed previously. However, it is essential that all the necessaryrig equipment which is to be used, has been checked. This includes the rig water pumps,cement pumps, mud pumps and the BOPs. The BOP rams must be dressed in accordancewith the test programme.

Also there are some smaller items of equipment required which must be made available.These include; long bails for rigging up equipment above the flowhead, rabbits for drifting thetubulars, TIW type safety valves with crossovers, tongs and other pipe-handling equipment,accurate instrumentation for monitoring annulus pressure, etc.

7.5. DATA GATHERING INSTRUMENTATION

This section describes the instrumentation required for measuring flow rates, pressures,temperatures, gas and fluid properties which is listed below:

7.5.1. Offshore Laboratory and Instrument Manifold Equipment

• Hydrometer for measuring gravity of produced liquids.• Manometer for calibrating DP meters.• Shrinkage tester to allow the calculation of production in stock tank barrels.• Dead-weight tester for pressure gauge checking and calibration.• Gas gravitometer to measure gas gravity.• Centrifuge for determining BS&W content.• Selection of pressure gauges.• Draeger tubes for measuring H2S and CO2 concentrations.• Chemical injection pump.• Surface pressure recorder.• Water composition analysis test kit.• Vacuum pump for evacuating sample containers.• Downhole sampling kit.

Some instrumentation is mounted on the test equipment such as:

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7.5.2. Separator

• Oil flow meters on both separator oil lines.• Gas flow meter.• Thermometers.• Pressure gauges.

7.5.3. Surge Or Metering Tank

• Sight glasses and graduated scales.• Thermometer.• Pressure Gauge.

7.5.4. Steam Heater

• Temperature controller.

Other special instrumentation must be listed in the specific test programme.

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8. BHP DATA ACQUISITION

The two of the most important parameters measured during well testing are downholepressures and temperatures. This data is obtained from BHP gauges installed as close to theperforations as is practicable. BHP gauges are either mechanical or electronic type gauges.

The mechanical BHP gauge is rarely used today as it accuracy does not generally meet thedemands of engineers for modern analysis. It does still have uses on high temperature wellswhere the temperature is above the limit of electronic gauges or when simple low costsurveys are required; for instance, to obtain bottom hole pressure before a workover. Theyare cheaper due to the lower gauge purchase cost and because it is not necessary to have agauge specialist to run them.

The electronic gauge is used in most circumstances and there are a number of differentmodels on the market with a wide range of accuracy and temperature specifications to meetvarious test demands. It is critical to ensure that the gauge selected is fit for purpose as someof the higher accuracy gauges are more susceptible to damage like the crystal gauge andalso more expensive. The criteria used should be to select the most robust and costcompetitive gauge which meets the test requirements. Currently there are three basic typesof pressure sensors used in electronic gauges available: Quartz Crystal, Capacitance, andStrain.

The electronic gauge can operate through an electric cable for surface read out in real timebut more generally is run with an memory section which stores the data electronically onchips. The early gauges had a very limited storage capacity of around 2.5K data points butthis has dramatically increased where gauges now have up to 500K. They can also beprogrammed to change the sampling speed at various times and/or on pressure change(∆p). This provides the reservoir engineer with accurate data at the desired and most criticalpoints in the test.

Both mechanical and electronic types of gauges are listed below in order of decreasingaccuracy.

8.1.1. Quartz Crystal Gauge

The principle of the gauge is the change in capacitance of the sensor crystal when pressureis applied. The gauge has two quartz crystals, one sensor and one reference crystal. Thechange in capacitance of the sensor crystal is measured by the change in frequency of anoscillating circuit. The resultant frequency is converted to a pressure.

This type of gauge is the most accurate available. Poor temperature resolution used to be theAchilles’ heel of the crystal gauge but modern gauges have overcome this problems byhaving the temperature sensor built into the crystal assembly. The tool is comparativelydelicate because of the fragility of the crystals.

8.1.2. Capacitance Gauge

The principle of this gauge is similar to the quartz crystal gauge. The difference is that aquartz substrate is used instead of a crystal. The gauge accuracy is between that of thequartz and the strain gauge but is much more robust than the crystal gauge. It did not sufferfrom poor temperature resolution like the earlier crystal gauges as the temperature sensor isan integral part of the pressure diaphragm.

8.1.3. Strain Gauge

The strain gauge principle works on the deflection of a diaphragm. Pressure acting one side

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of the diaphragm causes the deflection which is measured and translated into pressure. Theaccuracy of the gauge is lower than the quartz or the capacitance. This type of gauge isextremely robust and is not affected by temperature changes.

8.1.4. Bourdon Tube Gauge

This is a mechanical gauge and was the first type of pressure gauge and is very robust. Themost common manufacturers were Amerada and Kuster. The well pressure elasticallydeforms a Bourdon tube, the deflection of which is scribed directly on a time chart. Afterrecovery of the chart it is read and translated into pressure. Charts can be read with handoperated chart reader or electronically by a computerised chart reader. The gauge accuracyis much lower than any of the electronic gauges.

8.2. GAUGE INSTALLATION

As pointed out in the previous section, the gauges should be installed as deep as possible inthe well in order to obtain pressure and temperature data as near to formation conditions aspossible. On a well test this can be done by one of two methods: tubing conveyed or onwireline.

8.2.1. Tubing Conveyed Gauges

The normal means of running gauges on the test string is in gauge carriers but other SROsystems have been developed to obtain data from downhole gauges without having to pull thestring. This is an advancement in technology which means the data can be verified beforecurtailing the test. This is extremely useful in very tight reservoirs where the end of the flow orbuild up periods is difficult to predict and determine. In these tools the gauges are mounted ina housing which is ported to below the tester valve.

8.2.2. Gauge Carriers

Gauges may be placed in gauge carriers, which are installed in the test string as it is beingrun and are retrieved at the end of the test when the string is pulled. A minimum of two gaugecarriers with at least four gauges should be run.

Depending upon the test string design, they may be installed above the packer sensing tubingpressure or possibly with one below the packer to sense pressure as close as possible to thereservoir. Irrespective of the position relative to the packer, they must be run below the testervalve to obtain build up data. Below packer gauges are of simpler design as they are notpressure containing or require porting to the tubing.

Each carrier should contain at least two gauges, and at least two of the total should be of thecapacitance type of gauge. By running at least one carrier above a retrievable type packer,some data can be retrieved if the packer becomes stuck by backing the string off at the safetyjoint. Also, the packer absorbs some shock from tubing conveyed guns providing protectionfor the upper gauges.

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8.2.3. SRO Combination Gauges

Systems which allow the databanks of the gauges run in the upper gauge case to be readhave been developed. The disadvantages of the SRO system are thus eliminated as thegauges may be read continually or periodically. However is not good practice to run theinterrogating tool until the well has been cleaned up. In the early days, these systems provedto be very unreliable but great advances have since been made.

The latest systems use tried and proven tester valves for the downhole closure which areported to above the valve to a bank of memory gauges or transducers. The tool gathers andstores the data until the interrogation tool is run by electric line into the memory sectionhousing where it can communicate with the memory section to download the data. Thesedata are usually transmitted through an inductive coupling or similar type device.

Obviously the tool must be run during a shut-in period. It is advisable that the tool is notstationed in the well, i.e. latched into the housing, during flow periods unless absolutelynecessary. This reduces the risk from becoming stuck due to sand production or the wiregetting cut through flow erosion.

8.2.4. Wireline Conveyed Gauges

There are two systems for running memory gauges using wireline techniques. The first is toplace a nipple below the perforated tailpipe and to run and set the gauges in this nipple prior toperforming the test.

The second method is to use an SRO electronic gauge run and positioned in the well onelectric line which gives a real time direct readout of parameters at surface. A version of thismethod can provide build up data in conjunction with a downhole shut-in tool, similar to theSRO systems described earlier, except they use wire tension to open and close a separateshut-in mechanism, usually a sliding sleeve type device.

8.2.5. Memory Gauges Run on Slickline

A number of memory gauges, usually three but can be as many a physically possible, may berun in on slickline and set in a nipple positioned below the perforated joint. The advantages ofthis system are that the well may be shut-in downhole, eliminating after flow effects. Also thegauges may be recovered, e.g. after the first build-up, and the data interpreted beforecompleting the test.

This system should be considered in wells producing fluids which are corrosive to the electricline, and where long exposure is to be avoided. Gauges are generally run with a shockabsorber to avoid damage from shock during the trip or when setting the wireline BHP gaugehanger.

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8.2.6. Electronic Gauges Run on Electric Line

Gauges may be run on electric line to give a ‘real-time’ readout of data at surface. This iscalled surface readout (SRO). In some versions the well must be shut-in at surface confusingthe build-up data with after flow effects. However, there are now systems which allow the wellto be shut-in downhole and still have SRO. The disadvantages of this method are that theelectric line must remain in the hole during the test, unless using a SRO combination tooldescribed above.

Considerable difficulty may be encountered in landing this type of tool in its receptacle afterperforating the well. The tool is not robust enough to be landed before perforating and debrismay obstruct the nipple after the initial flow. It is highly desirable to clean up the well beforerunning this type of equipment.

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9. PERFORATING SYSTEMS

Two methods are currently used to perforate wells: wireline conveyed guns or tubingconveyed guns. Tubing conveyed perforating is the Eni-Agip preferred method for well testoperations, as the zones to be tested can be perforated underbalanced in one run, with largecharges. However, under some circumstances wireline conveyed guns may still be preferred.Both methods are described in the following sections.

The type of explosive to be used is dependant mainly on the bottomhole temperature and thelength of time the guns are likely to be on bottom before firing (Refer to the ‘CompletionManual-Perforating Section’)

9.1. TUBING CONVEYED PERFORATING

With this method the guns are run in the hole on the bottom of well testing string. Therefore,the guns and charge size can be maximised for optimum perforation efficiency and longperforation intervals can be fired in a single run. If required, a bull nose can be installed on thebottom of guns to allow the test string to enter liner tops. Various methods of detonation canbe utilised, depending on well conditions.

9.2. WIRELINE CONVEYED PERFORATING

There are two alternatives when perforating using wireline conveyed guns: casing guns orthrough-tubing guns. In both cases depth control is provided by running a Casing CollarLocator (CCL) above the guns and the guns are fired by electrical signal.

Casing guns are large diameter perforators which cannot be run through normal tubing size.Therefore they must be used prior to run the test string and in overbalance conditions.

Through-tubing guns are small diameter guns run through the test string. They can be used toperforate underbalance, reducing the risk of damaging the formation with brine or mudinvasion immediately after perforating. The largest gun which can be safety run through thestandard test tools (2.25ins ID) is a 111/16”.

9.3. PROCEDURES FOR PERFORATING

Procedures to be observed when perforating a production casing/liner are the following:

a) Operations involving the use of explosives shall only be performed by Contractor'sspecialised personnel in charge for casing perforation. The number of personinvolved shall be as low as possible. Only the Contractor's operator is allowed tocontrol electric circuits, to load and unload guns.

b) Nobody else, except for Contractor's operators, is allowed to remain in thehazardous area during gun loading and tripping in and out of the hole.

c) Explosives shall be kept on the rig for the shortest possible time and during suchtime they shall be stored in a designated locked container, marked withinternational recognised explosive signs.

d) Any remainder at the end of the test shall be returned to shore.

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e) Maximum care shall be taken during transportation, loading and back-loading of

explosive. Explosive and detonators shall always be transported and stored inseparate containers. This also applies to defective detonators which have beenremoved from a misfired gun. Transportation of primed gun is not allowed;explosive shall be transported unarmed.

f) Explosive should never be stored in the vicinity of other hazardous materials, e.g.flammable or combustible liquids, compressed gases and welding equipment.

g) Precise record must be kept of all explosives received, stowed or off-loaded.h) Warning signals shall surround the hazardous area where explosives are used.i) As an electric potential could trigger the detonators, any source of such potential

shall be switched off to avoid premature detonation. Such sources include anyradio transmitter (including crane radios) and welding equipment.The Company Drilling and Completion Supervisor shall collect all portable radiosinside company office in order to avoid any possibility of untimely use.

Radio silence shall be observed while guns are being primed and while primedguns are above seabed.

j) The following shall be advised prior to radio silence being in force:• Stand by vessel.• Helicopter operations.• Company Shore Base.• Other nearby installations.

k) In the event of uncontrollable sources of potential such as thunderstorms,operations involving the use of explosive shall be suspended. The only exceptionto the precaution mentioned above is the SAFE (Slapper Activated FiringEquipment) which can be operated, under any weather condition, during radiotransmissions and welding operations.

l) Inspections shall be done to make sure that no electric field is generated betweenthe well and the rig (max. allowable potential difference is 0.25 V). In the event thisvoltage is exceeded, all sources of electrical energy must be switched off (thismay preclude perforating at night).

m) When the casing is perforated before running the DST string, mud level in the wellshall be visually monitored.

n) When the casing is perforated before running the DST string, the well must befilled with a fluid whose density shall be equal to the mud weight used for drilling,unless reliable information would indicate a formation pressure allowing for alower density.

o) The same principle applies for the weight of the fluid in the tubing/casing annuluswhen perforating after the DST string has been run.

p) The first casing perforation shall be performed in daylight. Subsequent series ofshots can be carried out at any time.

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10. PREPARING THE WELL FOR TESTING

This section describes the operations necessary to prepare the well for well testing.

10.1. PREPARATORY OPERATIONS FOR TESTING

10.1.1. Guidelines For Testing 7ins Liner Lap

1) While waiting on cement, test the BOP stack according to the Eni-Agip Well ControlPolicy Manual procedures. Pull out of the hole with the test tool.

2) Run a 6ins bit/mill and clean out the 7ins liner to the landing collar (PBTD). The drillingprogramme must allow for sufficient rat hole to enable TCP guns to be dropped off, ifrequired.

3) Run a cement bond/correlation log from PBTD to top of 7ins liner.4) Run in hole with 95/8ins packer assembly and perform positive and negative tests on

liner lap as per the Company Drilling and Completion Supervisor’s instructions. As aguideline, conduct a positive test of the liner lap by applying approximately 400psipressure. Ensure that the burst rating of the 95/8ins casing is not exceeded. Displacethe required amount of fluid from the drillpipe with base oil to give an approximatedrawdown on the liner lap and liner of 500psig in excess of maximum drawdownpressure planned for the individual wells. Set the packer and monitor the well headpressure for influx for 1hr. If the liner lap or liner is found to be leaking then a remedialcementing programme will be advised.

10.1.2. Guidelines For Testing 95/8ins Liner Lap

1) While waiting on cement, test the BOP stack according to the Eni-Agip Well ControlPolicy Manual procedures. Pull out of the hole with the test tool.

2) Run a 81/2ins bit/mill and clean out the 95/8ins casing to the landing collar (PBTD). Thedrilling programme must allow for sufficient rat hole to enable TCP guns to be droppedoff, if required.

3) Run a cement bond/correlation log from PBTD to above the packer setting depth.

10.1.3. General Technical Preparations

1) Surface well testing equipment should be installed and pressure tested as per theprocedures in Section 7.

2) DST tools should be laid out and tested on the pipe desk (Refer to Section 10.8).3) Ensure that all downhole components of the test string are the proper size, i.e. OD, ID,

thread type and that the items are clean and clear of any rust, debris, junk, etc. Allthreads and collars are to be cleaned properly on the rack. Make sure all crossovers arecorrectly bevelled inside and outside.

4) Make a visual inspection to verify the condition of packer rubbers and all DSTequipment.

5) Drift all DST equipment to ensure full ID for wireline, coiled tubing or Surface Read Out(SRO) tools to be run in the hole.

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10.2. BRINE PREPARATION

In order to efficiently utilise the completion brine system and achieve optimum results, thebrine should be treated and handled according to the recommendations outlined in thefollowing sections.

10.2.1. Onshore Preparation of Brine

1. Filter and recondition any (suitable) brine which is in stock.

2. Following the final filtration/reconditioning cycle of this stored fluid, re-weigh and adjustas necessary to suit the conditions of the well.

3. Prepare balance of fluid from sacked material or liquid, as appropriate. Filter andcondition as necessary.

10.2.2. Transportation and Transfer of Fluids

The primary objective is to transport and transfer the fluid without losing density due todilution, losing volume, or contaminating of the fluid.

10.2.3. Recommendations

An independent surveyor should be engaged to perform the following duties:

1) Onshore Brine Tanks• Dip storage tanks before transferring fluids.• Take samples of brine at beginning, middle and end of pumping. If required,

submit to the district office.• Check samples for SG at 60oF; centrifuge for solids content, check clarity.• Dip storage tanks after brine is loaded onto transport vessel.• Record and submit report the volume and density of brine provided by brine

supplier.

2) Pumping into Vessel• The independent surveyor should ensure that all transport tanks were/are

chemically cleaned.• Visually inspect tanks for cleanliness, residue, any fluids not completely drained

from tanks, inspect pumps/manifolds if applicable.• Dip vessel tanks and check volume as per vessel calibration charts versus

suppliers brine tank volumes.• Close and seal all hatches on transport tanks.

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1) Off-loading Brine at Rig-Site• Inspect pontoons/tanks/pits for cleanliness, report any residual solids or fluids and

ensure their removal prior to off-loading. Obtain calibration charts in order tomeasure volume of fluid received.

• Sample brine received into pontoons/pits and check density and solids to verifythat fluid has not been diluted or contaminated during transport. Report anyvariation from original quality.

• Ensure that required volumes are removed from transport tanks on vessel.Report any residual fluid not transferred to the rig.

• Report and record final volume and density received on the rig.

10.2.4. Rig Site Preparations

The importance of initial cleanliness of mud/brine tanks, pumps, lines, etc. can not be over-emphasised. The following procedures are recommended:

1) Brine Tanks and Lines• All mud/brine tanks, sand traps, ditches, pumps, etc. that will be used for the brine

should be previously cleaned of solids and/or residual contaminants. All linesshould be pre-flushed with water and, if necessary, a chemical wash.

• If feasible, mixing lines and valves should be pressure tested against the mixingpumps. Leaking valves should be replaced.

• The mud/brine tanks, ditches, lines and pumps can be given a final cleaning withappropriate chemical cleaner and flushed with water. This final cleaning shouldinclude all equipment surfaces which will come in contact with the brine.

• Finally ensure that all tanks, lines, pumps etc., are dry to avoid dilution of thebrine.

The mud pits should be cleaned as follows using seawater, prior to transferringcompletion brine from storage tanks to the pits.

• When all the mud has been emptied from the pit tanks to be used, clean the mudtanks as thoroughly as possible to avoid any brine contamination. Clean initiallyusing buckets and shovels.

• Wash the first mud pit with 50bbls seawater pill containing descaler and oil mudremovers.

• Pump pill into second pit and make up second 50bbls pill containing lowerconcentration descaler/oil mud remover.

• Pump second pill into first pit and first pill into third pit. Continue the system untilall pits are clean, including slug and premix pits, and all the surface lines.

• Prepare a third 50bbls pill and pump again through all pits if required.

2) Dump ValvesPrior to receiving the brine, ensure all ‘O’ rings and seats are functioning correctly.Leaking valves can cause significant brine losses.

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3) Ditch Gates - Slide TypeAll gates should be sealed prior to receiving brine. Two layers of ‘Densotape’ appliedacross edge of slide should insure a good seal. Additional sealing can be obtained witha fillet of ‘Slick grease’ on the upstream side.

Barites, bentonites and polymers should not be used in an attempt to seal possibleleaking areas. They do not provide adequate sealing, and also contaminate the brine.

4) Water LinesAll water lines should be taped or chained off.

5) Pump PackingReplace all work mixing pump packing.

6) TrippingSignificant losses of brine can be avoided during tripping by:

• Using wiper plugs• Using collection box and drip pan• Slugging of pipe with heavier weight brine.

7) Rig ShakersShould it be necessary to pass brine over rig shakers when circulating, ensureequipment is operating properly. Avoid diluting brine by washing down or cleaningscreens with water.

8) Settling PitTank or tanks should be dedicated to be used as settling/separation tanks for brine thatbecame abnormally contaminated during the course of the testing operation. Brinescontaminated with solids, oil, cement, or other should be placed in tanks and chemicallytreated as required. For oil and solids and/or polymer-contamination, pilot testing shouldbe performed to determine treatments of flocculants and/or oil separation chemicals,viscosity breakers, etc. Following chemical treatment, the brine should be filtered andreturned to the active system, and re-weighted if necessary.

9) Sand TrapsIf used to contain brine during the operation, these traps should be thoroughly cleanedprior to the introduction of the brine system. It should also be pre-determined that fluidcan be completely removed when required.

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10.2.5. Well And Surface System Displacement To Brine

Most oil and water based drilling fluids, are incompatible with solids-free brines; therefore aneffective displacement/chemical wash should be planned to:

• Remove mud solids and contaminants from the well bore.• Maintain the integrity of the mud and brine.• Separate the mud and brine during displacement.• Reduce filtration time and cost.

10.2.6. Displacement Procedure

Extensive displacement procedures will be issued by the Brine Contractor. The procedureswill be contained as part of the detailed well specific test programme.

The technique utilised may be one of two types:

• Indirect Displacement (of which a key ingredient is flushing the wellbore with largevolumes of water).

• Direct Displacement (where minimal seawater flushing is utilised).

Reference must be made to individual fluid companies procedures.

The completion brine can be prepared at base or at the well site according to circumstances.Use a filtering system as required during the testing operations to keep brine in requiredcondition. Required completion fluid weight should be confirmed based on RFT and offsetwell data. Once the hole has been displaced to completion brine, continue circulating ifnecessary until completion brine returns are within specification as regards weight andfiltration quality.

10.2.7. On-Location Filtration And Maintenance Of Brine

Considering rig surface equipment and availability of space, every effort should be made tofollow procedures:

1) Install filtration equipment in order to operate at its maximum efficiency.2) Filtration service company should advise proper DE filter aids and cartridge size to

ensure maximum filtration efficiency and economics based on type of fluid to be filtered,anticipated contaminants such as barite solids, mud solids, oil, etc.

3) Brine in suction tank should be maintained at proper density and filtered prior to beingpumped into hole.

4) Returns of brine should be placed in adequate settling/separation tank to allow properchemical treatments and filtration before being placed into the active brine system.

5) If considered more economical and feasible, severely contaminated brine should bereturned to the brine supplier for reclamation and reconditioning. Whenever possible, asample of the contaminated brine should be sent to the brine supplier for evaluation todetermine if the fluid should be treated offshore or onshore.

6) Avoid dilution of brines caused by water hoses, water lines, washing down or rig and/orfiltration equipment, etc.

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7) Pick up bit for casing and drill out cement to the top of the liner. If it is planned to

perform a pressure or inflow test on the liner lap, a casing scraper should be run withthe bit unless excessive drilling is expected.

8) Run in the hole with bit for liner and drill out the liner to landing collar which is then thePBTD (Refer to section 10.1).

9) Run and record CBL/VDL or CET from the landing collar to the top of the liner.10) If there are reasons to believe that the integrity of the seal on the liner lap is not effective,

a pressure and/or inflow test should be performed (Refer to section 10.1).11) If the liner lap is found to be leaking then a remedial cementing job is advised.

10.3. DOWNHOLE EQUIPMENT PREPARATION

10.3.1. Test tools

Downhole test equipment must be included in the preparation of the test string as theybecome an integral part of the string. On both the primary and back-up sets, the followingtests and checks must be completed by the relevant service company crew:

1) Layout all of the tools on the pipe deck for inspection.2) Measure the tools and provide a dimensional sketch for each, giving:

• Identification number• Length• Maximum outside diameter• Minimum inside diameter• Thread connection up• Thread connection down• Fishing neck dimensions.

3) Conduct a body pressure test to a minimum of 1,000psi above the maximum expecteddifferential pressure, or 1,000psi above the maximum wellhead pressure, whichever isthe greatest.

4) Pressure test, from direction of flow, all test string valves to a minimum of 1,000psiabove either the maximum expected differential pressure, or wellhead pressure,whichever is the greatest.

5) Pressure test, from above, all test string valves, if appropriate, to a minimum of1,000psi above either the maximum differential pressure, or wellhead pressure,whichever is the greatest.

6) Where appropriate, the downhole test equipment should be function tested.7) The test string components must be drifted to the 2.25ins maximum drift size to cater

for all contingencies.8) These tests should be carried out on the pipedeck and the tools dressed with the

correct value shear pins or rupture discs, as per programme.9) Check that the appropriate crossovers are available and make up to the downhole test

equipment.

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This equipment includes, but is not limited to:

• Lubricator Valve• Retainer Valve• Sub-sea Test Tree• Circulating Valve(s)• Tester Valve (with Hydraulic Reference Section, if appropriate)• Gauge Carriers• Permanent Packer Seal Assembly or Retrievable Packer and associated

Jars, Safety Joint and Slip Joints.

10.4. TUBING PREPARATION

Careful consideration of the tubing to be selected and how it is handled, checked and tallied isessential in well testing operations. The following sub-sections provide a short description ofthe important tubing aspects which need to be considered for a well test.

10.4.1. Tubing Connections

One of the important aspects to be considered in a well test is the type of thread connectionto be used for the tubing string.

Premium connections generally have better sealing properties compared with APIconnections and can also have other special features such as:

• Higher strength• Higher torque (good for use in horizontal wells)• Faster make-up speeds• Internally streamlined and recess free to prevent erosion• Multi-reusable (less galling)• Reduced connection stresses to reduce Hydrogen Sulphide attack.

The primary seal is metal-to-metal but some connections also have a secondary metal-to-metal seals or a Teflon packing ring.

Some premium connections are superior to others regarding being gas tight or good for highpressure and temperatures etc., therefore an operator must make a thorough investigation tofind the connection which is best fit for purpose. It is normally agreed that premium threadswith a torque shoulder such as Hydril is ideal for testing as it has low refurbishment costs andis quick to make up and reasonably robust against handling damage, however it is limited tothe number of thread re-cuts that can be machined before requiring to be sent back to the millfor upsetting again.

Typically, as an example of a good well test tubing, is Eni-Agip’s (UK) Affiliate who use a 41/2”15.5lbs/ft grade with the D95 SPJD-6 (Hydril compatible) thread connection for well testing.The specification for this tubing is given in the following sub-sections.

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10.4.2. Tubing Grade

Specifies the type and strength of the steel. Standard tubing is generally covered by the APIspecifications, e.g. J 55, C 75, L 80, N 80, C 95. The letter signifies the properties of the steeland the number signifies its minimum tensile strength in 1,000lbs per sq inch, i.e. N 80signifies a normalised and tempered carbon steel with 80,000lbs/ins2 minimum yield. Thecross-sectional area of the tubing multiplied by the minimum yield stress provides the jointyield strength, e.g. Agip (UK) tubing 41/2ins 15.5lbs/ft C 95 body section is 4.407ins2 x95,000lbs/ins2 - 419,000lbs. Tubing is manufactured in a variety of steel grades to cater forthe full range of well conditions and well effluents which may be encountered.

10.4.3. Material

The choice of tubing material should take into account the expected produced fluids. If sourfluids are expected the material should be no harder than 22 HRC. This limits the choice toC75 or N 80 as the toughest grades. However, special grades up to C 95 may be used if theyare specified for sour service and have passed the NACE sulphide stress cracking tests (APISPEC 5AC).

Safety factors in axial tension should ideally not be less than 1.7, but a lower limit of 1.4 canbe accepted if a triaxial stress envelope is used. Agip (UK)’s test string is grade D 95 SG(Dalmine designation, equivalent to C 95) and is suitable for tests where H2S is present.

10.4.4. Weight per Foot

Is a the term used in conjunction with the tubing OD in order to signify the thickness, e.g. 41/2ins 15.5lbs/ft has a wall thickness of 0.337ins hence an ID of 4.5 - (2 x 0.337) - 3.826ins.

10.4.5. Drift

Is slightly less than ID and represents maximum effective available bore diameter for thepassage of tools. API Spec 5A specifies the dimensions of mandrels to be used in drifttesting. All tubulars to be run in a well, i.e. casing, tubing, nipples, packers etc. must be driftedprior to running.

10.4.6. Capacity

This is the amount of fluid required to fill a measured distance inside the tubing, e.g. the Agip(UK) tubing has a capacity of 0.01422bbl/ft, sometimes expressed as 14.22 barrels perthousand feet.

10.4.7. Displacement

This is the volume occupied by the tubing material, or the volume of fluid which the tubing willdisplace.

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10.4.8. Torque

Is the amount of rotational force applied to connect the pin and the box connections tooptimise the mechanical and sealing performance of the connections, e.g. the values for theAgip (UK) string are as follows:

• Minimum - 6,800ft/lbs• Optimum - 7,650ft/lbs• Maximum - 8,500ft/lbs.

10.4.9. AGIP (UK) Test String Specification

Agip (UK) has its own full test string which is 41/2ins OD with Dalmine SPJD 6 connections(compatible with Hydril PH6 of the same size). The grade of this tubing is D 95-SG (equivalentto C 95) which denotes Dalmine, 95,000psi minimum yield strength, Sour Gas service.

table 10.a provides dimensional strength and performance data for the Agip (UK) string.

TYPE: 41/2OD - 15.5lbs/ft Grade D 95 Dalmine SPJ D - 6 (Hydril PH 6 Compatible)

Pipe Connection

ID 3.826ins 3.765ins

Drift 3.701ins

Torque ValuesMinOptMax

6,800ft/lbs7,650ft/lbs8,500ft/lbs

Capacity0.01422bbls/ft

or14.22bbls/1,000 ft

Displacement0.00564bbls/ft

or5.64bbls/1,000 ft

Burst 12,450psi

Collapse 12,760psi

Yield 419,000lbs

Table 10.A - AGIP (UK) Tubing Data

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10.4.10. Inspection

Prior To Running (On Board Visual Inspection And Field Repair)

Ensure all connections are dried after cleaning and before inspection.

Check the starting threads to ensure they have no small slivers or edges of steel which couldindicate galling or over-torque.

Visual inspection should concentrate on the primary metal to metal seal surface of the pin andbox. These seals should be free from corrosion and defects.

The sealing mechanism is based on having sufficient pin-to-box metal-to-metal contactstress around the full circumference of the connection. The pin and box seal surfaces shouldbe examined for any seal irregularity.

Check seal surface for:

• Longitudinal cuts and scratches• Out-of-roundness• Corrosion pits, rust and scale• Galling.

Some type tubing connections have an external shoulder which is the primary shoulder onthese connections, controlling the position of the pin relative to the box. The proper location ona fully made-up connection of all other seals and shoulders is determined by the position ofthis shoulder.

The surface is also intended to be a secondary pressure seal. This requires that visualinspection criteria similar to those used for the internal seal be used for the shoulder.

Check shoulder for:

• Radial cuts and scratches• Out-of -roundness• Corrosion pits, rust and scale• Galling.

If the visual inspection detects some light corrosion/rust on the seal surface then this must beremoved before running. To alleviate this problem the rust or discoloration can be easilyremoved by a light rubbing action using No 400 emery cloth or steel wool.

Minor thread damage (not seal) may be repaired with a fine needle file or No 400 emery cloth.

If any joints or connection show ovality then they should not be run.

If possible, note whether the pipe is straight, this may not be possible until the joint is beingrun.

Drift pipe with correct size (OD and length) drift.

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10.4.11. After Testing/Prior To Re-Use

After a series of tests and before re-utilisation in another well, that part of the tubing used shallbe inspected onshore.

• Magnetic particle inspection, throughout the whole length• Callipering• Thread visual inspection• Full length body log for cracking (e.g. Tuboscope)• Hardness check.

10.4.12. Tubing Movement

As part of the design process for the testing string, calculations should be performed by theDST contractor and confirmed by Agip to determine the likely maximum contraction andexpansion of the string during the various phases and operations of the test, i.e. circulation,production, injection (acid or water injection test), killing, etc. This is to confirm the tubingdesign is adequate for the test and to determine the optimum type and quantitative design ofany devices included in the string to accommodate tubing movement, e.g. slip joints or sealassembly and sealbore packer.

10.5. LANDING STRING SPACE-OUT

This procedure is applicable to testing from Semi-submersibles.

The purpose of this procedure is to check the space-out of the fluted hanger, slick joint andSSTT inside the Subsea BOPs and determine the length of landing string required to providethe required height of the flowhead above the drill floor referred to a stick-up. It is vital that theSSTT body does not lie across the shear/blind rams and that the surface tree is situatedsufficiently high enough above the drill floor so that on no account can the bottom of the treecome into contact with the drill floor or the flow and kill lines become bound or trapped even atthe compound of the lowest tide with the greatest heave.

It is not necessary to run the actual SSTT and the backup hanger and slick joint may be used,run on drillpipe. However, if space allows for the SSTT assembly, retainer valve and landingstring tubing to be set back in the derrick, it should be run and set back to save time later.With some designs of trees the control hoses must be run to prevent accidental unlatching. Ajoint of tubing, without a thread protector, should always be run beneath the SSTT.

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Figure 10.A - SSTT Arrangement

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Figure 10.B - Typical Safety Valve Arrangement for a Jack-up

10.5.1. Landing String space-Out Procedure

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The procedure is:

1) Check that the rig is at operating draft.2) Make up the fluted hanger to the slick joint, with the appropriate adjustment, to give the

correct length according to the stack drawing dimensions.3) Pick up the fluted hanger and slick joint assembly and paint the slick joint with white

paint.4) Run in to immediately above the BOPs and engage the compensator.5) Land the hanger in the wellhead. Pick up slightly and turn to the right to ensure the

hanger has fully landed out.6) Carefully close the rams on the slick joint, checking the volume of fluid taken to confirm

that they are fully closed.7) Mark the string at the drill floor at mid-heave.8) Record the tide level.9) Open the rams and strap out to the first connection to obtain the depth to the hang-off

point at this tide level.10) Pull the pipe and lay out the hanger and slick joint being careful not to smudge the paint

marks.11) Check where the ram marks are positioned on the slick joint. If the measure from the

centre of the rams to the wellhead housing does not correlate, then re-check the stackdimensions.

12) Adjust the primary assembly for the dimensions obtained.

Note: Ensure that either choke or kill line is connected below pipe ram that is tobe used on slick joint. This is necessary for annulus control andmonitoring during DST operations.

10.6. GENERAL WELL TEST PREPARATION

10.6.1. Crew Arrival on Location

Contractor Service Specialist is to meet with the Company Representative and discuss thetest programme and any updates to the original programme. At this point potential problemareas should be identified with the goal of preventing such problems or at least eliminating theelement of surprise. This policy should continue throughout the test as new informationbecomes available or as conditions change.

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10.6.2. Inventory of Equipment Onsite

The contractor shall:

1) Obtain all possible information and preferably a well schematic of the hole regarding thehole conditions such as:• Total depth• True vertical depth• Mud/brine type• Mud /brine weight• Maximum deviation• Mud viscosity• Depth to top of liner• Cushion type• Bottomhole temperature• Maximum casing/liner test pressure• Anticipated production rates.

2) Consult with the Mud Engineer about the performance of the mud/brine system underconditions of static temperature and pressure for the anticipated duration of the test andthe compatibility of the mud/brine system to the cushion.

3) Confer with the Tool Pusher concerning testing requirements during the test, such as:• Procedures for pressure testing and functioning equipment and the necessity of

doing this in a restricted area within easy access to air and water points.• Pressure control and monitoring of the annulus. In particular, the presence of non

return valves in the rig manifolding needs to be discussed and how they can beremoved or bypassed. Potential tie-in points on the rig manifold for a pressuremonitor etc.

• Availability of handling equipment (e.g. lift subs, elevators).• Procedures for picking up test tools.

10.6.3. Preliminary Inspections

The following preliminary inspections, shall be carried out before starting testing operation,under the direct responsibility of the Company Drilling and Completion Supervisor who canavail himself of Company Drilling Engineer (if Present) and drilling contractor personnel(Toolpusher):

1) All tubular goods not required for the execution of the test and for the preparatoryoperations (scraping, setting of bridge plugs, etc.), shall be laid down from the derrickfloor prior to start the test.

2) Fishing tools for all equipment to be used during testing shall be on rig.3) Working area on the rig floor and around the separator, heater, tank and flare shall be

clear of obstructions and flammable substance.4) An adequate platform shall be available to operate the valves on the flowhead.5) Inspections shall be performed on masks, self breathing apparatus, resuscitators and

extinguishers in order to check their efficiency and location on the rig.

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1) Electric installations placed within area classified as ‘hazardous’ shall be ‘explosionproof’.

2) It shall be checked that all access doors and escape ways, fire doors and vent linevalves of pressurised tanks are in the position prescribed by the rig procedures during‘production tests’.

3) Fuel tanks, oxygen bottles and other pressurised bottles shall be placed far from thearea classified as ‘hazardous’ and cooled with water, if necessary.

4) It shall be checked that the amount of water available to the burners water spray and tothe sprinkler system is sufficient to protect the burners and the rig from heat radiationgenerated by the combustion.

5) Inspection shall be performed on anti-pollution equipment and chemical (dispersant)stored on rig in order to cope with any oil spill which may occur, particularly duringformation clean out.

6) The accuracy of the data supplied by the anemometer (wind speed and direction) shallbe checked before opening the well.

7) Prior to start well testing operations, drills shall be performed for fire-fighting andpollution prevention.

8) Inspection shall be made on operating conditions of the communication system amongrig floor, flares area and production equipment area.

9) Complete BOP test shall be carried out before starting well testing operations.

The following additional inspections shall be performed prior to start testing operations, underthe direct responsibility of Company Drilling and Completion Supervisor, who can availhimself of production test equipment operators:

1) It shall be ascertained that the separator is equipped with safety valves (pop valvesand/or rupture plate outlets) in top operating conditions. The outlets of separator and thevent lines of production tank(s) shall be free from obstructions and secured to fixedstructure of the rig. These lines shall usually be connected to the flares.

2) Inspections shall be carried out on the flares (blow-off lines), on the burners/flaresbooms and on the burners igniting system.For the ignition of burners/flares, a back-up system shall be available in addition to themain fixed system.

A test on burners shall be performed using diesel oil as fuel.

An adequate supply of propane or butane should be available, if such fuel is used for theigniting system.

Due to their dangerous nature, propane or butane bottles shall be stored in protectedarea.

3) Each burner shall be capable of burning the whole amount of hydrocarbon produced,that is to say their capacity shall be compatible with the maximum possible production.Inspections shall be made on the water sprinkler system for the protection of the rigfrom heat radiation in the area where burners are installed. In addition to this fixedinstallation, special fire-fighting hoses with adjustable nozzles shall always be availableto cool any part of the rig that would happen to remain outside the protection of thewater sprinkler system.

10.7. PRE TEST EQUIPMENT CHECKS

1) Lay out the appropriate downhole tools, observing correct handling and slinging

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procedures. Tools must be positioned in a manner so that they are secure and causeminimal obstruction.

2) Visually inspect all tools to ensure no damage was sustained in transit particularly tothreads and sealing surfaces.

3) Function and pressure test tools according to procedures laid out in the servicecompanies operations manual which will be made available on the rig.

4) Ensure that all tool dimensions are accurately measured and lengths of extendingmandrels recorded etc.

5) Ensure all required crossovers have been sent and physically checked for correctthreads. Measure crossovers and note length, ODs and IDs. Particular attention shouldbe paid to the IDs of rented crossovers.

6) Ensure all tubulars are drifted, cleaned internally and the connections have beeninspected prior to running.

7) Lengths, ODs, IDs and thread connections of all downhole tools should be checked forcorrect size and a list produced. All tools should be clean, free of any dirt or debris andthe connections cleaned properly on the rack. All crossovers should be properlybevelled inside and out.

8) All downhole tools should be drifted to 2.125ins to allow running of surface read out orany other wireline or coil tubing tool.

9) The pipe tester valve (PTV) should be made up to the packer on the deck and testedfrom below to it’s working pressure prior to running in the hole.

10) A visual inspection should be made of the packer elements prior to running. The packershould be set appropriately above the perforated interval to allow safe wirelineoperations such as production logging, if required (i.e. ensure the bottom of the tailpipeis positioned approximately 100ft above the top perforation).

11) The packer should never be set across a casing collar.12) All downhole test tools should be pressure tested at surface to a minimum of 1,000psi

above maximum anticipated pressure.13) A list of all pressure gauges and serial numbers should be compiled and submitted to

the Company Production Test Supervisor.14) Only API 5A Modified thread lubricant should be used on tools, tubing and drill collar

connections.15) The lubricant should be applied to the pin end only with a paint brush. Apply sparingly.16) Check the brine weight as accurately as possible and ensure that it is correct, based on

the RFT results.

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10.8. PRESSURE TESTING EQUIPMENT

All surface and downhole testing equipment shall be fully pressure tested prior to send to therig. Testing equipment shall also be pressure tested on the rig before starting a well test; inparticular:

1) For all pressure test, the area outside accommodation must be clear of non-essentialpersonnel.

2) Pressure tests shall be carried out using water. Each pressure test shall be recordedon a record sheet and the pressure shall be held for a minimum of 15min.

3) Test pressures shall be specified on testing program. However, devices protected byrupture discs should not be tested to more than 90% of working pressure.

4) BOPs, choke manifold, choke and kill lines shall be pressure tested as per Agip WellControl Policy.

5) The following equipment of the surface package shall be pressure tested:• To end of burners.• To gas and oil diverter manifolds.• Through test separator to outlet valves and bypass valves.• To inlet valves and bypass valves on test separator.• To outlet and bypass valve on heater.• High pressure side of the heater up to blank choke and bypass valve.• To inlet valves and bypass valves on heater.• Two upstream valves on production choke manifold.• Two downstream valves on production choke manifold.

The test shall be repeated whenever a connection on a line is broken out.

In case of long duration tests or in critical condition (presence of sand, H2S, etc.), theopportunity of performing pressure tests at regular time intervals shall be evaluated.

Steam lines of the heater shall be pressure tested with steam according to manufacturer'sspecification.

It is common practice to make up one full single joint of tubing from the landing string to theflowhead in the rotary table and lay out the entire assembly on the pipedeck. This connectionmust be done before running the test string as it cannot be torqued later due to being too highwhen the string is finally landed.

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10.8.1. Surface Test Tree

The flowhead should be prepared on the catwalk in accordance to the contractors procedureswhich should be as follows:

1) With master and swab valves open, drift the flowhead to it’s maximum diameter toaccommodate any wireline or coiled tubing tools to be run.

2) Function test the ESD actuator on the flow wing valve. The ESD is a fail-safe valve.3) Make up one joint of the landing string to the flowhead with chain tongs.4) After the SSTT and landing string dummy run has been made and has been racked

back in the derrick, pick up the flowhead with the single joint of tubing and torque it up inthe rotary table to the correct torque.

5) Check the torque on the swivel and any other flowhead service connection and thenpaint a white band across them.

6) Ensure that the swivel is free to rotate completely in both directions.7) Lay the assembly back down on the deck. Make up the test caps, complete with needle

valves, on all four outlet connections. Open all the flowhead valves and pressure testthe flowhead body from the bottom to test pressure

8) Close the swab, kill wing and flow wing valves. Open the respective needle valves in thetest subs downstream. Pressure test against the upper valves.

9) Close the upper master valve, open the kill wing valve and pressure test against theupper master valve from below to test pressure.

10) Close the lower master valve, open the upper master valve and pressure test againstthe lower master valve from below to test pressure.

11) Bleed off pressure below the lower master valve and leave the needle valve open. Openthe swab valve and pressure test against the lower master valve from above.

12) Close the upper master and pressure test from above.13) Remove the test caps.14) Clean and grease the connections.15) Fit protectors and store the flowhead in a convenient place until ready to use.

The flowhead shall be pressure tested before installed it on the well with a tubing pup jointassembled on bottom in the followed way:

1) Plug the kill side, the flow side and close the swab valve; pressure test the internal offlowhead pumping through the pup joint.

2) Bleed off pressure and remove plugs from kill and flow side, close kill valve ,flow sidefail-safe valve and pressure test the gates from inside.

3) Close master valve and bleed off the down stream pressure to pressure test the gatefrom below.

This procedure may be adjusted to the actual flowhead configuration.

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Figure 10.C - Flowhead Schematic

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11. TEST STRING INSTALLATION

Detailed individual well programmes will be issued for all wells to be tested, which includesdevelopment, appraisal and exploration wells.

Each programme will include contents, the exact details of which will be well specificdependent upon the well status and expected well parameters. The following is the contentsof a typical test programme.

a) Test Objectives.b) General well data and perforating details.c) Summary of test programme.d) Guidelines for liner lap test and space-out calculations.e) Sequence of operations for running downhole tools and surface equipment rig up.f) Flowing procedures for each test conducted.

Also included will be the following, possibly as appendices:

• Hole cleaning and displacement to brine procedure.• Stimulation programme (if applicable, e.g. coil tubing rig up).• Sampling requirements.

Detailed string diagrams and equipment layout diagrams will be included, as well as allrelevant pressure testing procedures and equipment ratings.

11.1. GENERAL

a) The testing string shall normally be made up of tubing. The use of drill pipe is onlyallowed in limited fluid entry test (DST).

b) All equipment and material used in production tests shall be H2S service.c) Governmental bodies charged with the control of drilling activity and/or other state

agencies shall be notified, if required, on test execution with advanced notice.d) Before starting and upon completion of flaring operations, company shall give notice to

competent authorities.e) Prior to the start of casing perforating, visitors and non essential personnel shall leave

the rig and rig personnel shall be limited to the minimum.f) Prior to start well testing operations a meeting shall be held by wellsite Company Drilling

and Completion Supervisor and Drilling Contractor Toolpusher to make all personnelinvolved are acquainted with detailed operating program (procedures and rules).

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11.2. TUBING HANDLING

a) Tubing must always have the pin and box protectors in place while being handled.b) Tubing should always be handled with either certified nylon or cable slings or with

single joint elevators when picking up or running out the tubing from the Vee door.Never Use Hook Ends

c) Avoid rough handling of the tubing which may damage the joint.d) Never allow the tubing to be dropped when loading and or moving.e) Never bundle tubing in greater quantities than ten.f) Tubing joints will be supplied in singles with protectors fitted and should be laid

down on deck in even layers, no more than 10 levels high.g) After removing the protectors, the connections should be thoroughly cleaned and

inspected after drifting. One of the following Agip approved methods of cleaningshould be used:• Use of non-metallic brush and a recommended solvent.• Steam clean using a high pressure jet of steam and solvent.• A rotary bristle brush jetted water and cleaning solvent.

h) The pins and boxes should be visually inspected for any damage by a qualifiedTubing Inspector.

i) Reject and damaged joints should be painted red and documented and thenreturned to the onshore base for remedial work if necessary.

j) The tubing should then be drifted/measured, and each joint numbered in themiddle of the joint with white paint and strapped and tally recorded (drift the pipebox to pin at all times).

k) After the threads have been cleaned and inspected it is important they beprotected from corrosion. Never leave the threads for longer than two hourswithout corrosion protection.

l) If the connections are cleaned more than two hours but less than 12hrs prior tothe joint being run, then a light oil should be used to prevent corrosion. If it is to belonger than 12hrs then a light film of dope and protectors should be reapplied.

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11.3. RUNNING AND PULLING

a) Any protective coating which has been applied to the tubing for storage should becleaned off before the tubing is run for a DST. This can probably be done mostconveniently during the procedures for casing cleaning and displacement to brine.With the tubing string in the hole, proprietary cleaning fluids can be circulated toremove the coating material.

b) Ensure all accessories/tools are on the rig floor and are in prime condition readyto run the tubing, i.e. pup joints, crossovers, stabbing guides, single jointelevators, modified pipe dope, dog collar, slip type elevators.

c) Ensure the safety clamp (dog collar) is correctly sized ready for the 41/2” tubing(the dog collar should be used above the rotary table slips until the first 20 joints oruntil the Company Production Test Supervisor thinks enough weight is available toproperly set slips.

d) Slip type elevators to be used at all times. Check the elevator setting plate forproper operation. This will ensure the elevators set on the body of the pipe, not onthe upset or connection area.

e) Check the alignment of the rotary table and the elevators.f) During make-up, the tubing must be allowed to spin freely, which may necessitate

slacking off on the blocks until the weight is off the elevators.g) Use power tongs and integral hydraulic back-up for all make-up and break-outs at

recommended optimum torque valves. The use of a torque/turn analysis system,such as Weatherford’s ‘Jam’ system, is recommended.

h) The power tong lead line should be attached to a back-up post and should belabelled. Ideally the angle with the tong arm should be 90o.

i) When pulling the tubing, always use a wiper rubber.j) Always install the pin protector fully before standing the tubing in the derrick.k) Never use a sledge hammer on connections to assist the break-out.l) Ensure tubing set back in the derrick is properly supported with a belly band to

prevent undue bending.m) Always use the manufacturers recommendations for running, pulling or make-up.n) Check that the calibration of the torque machine is valid.o) A tubing inspector or the Company Production Test Supervisor must be on the rig

floor witnessing the make-up of all the joints that make-up the test string.p) If there is insufficient space in the derrick to store both drillpipe (51/2”, 31/2”) and

tubing, then lay down drill pipe in preference.

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11.4. PACKER AND TEST STRING RUNNING PROCEDURE

Before running the test string all the earlier procedures should have been carried out toprepare the well, tubing and tools for the test. The procedure for running the test string willvary depending upon the equipment used.

The main difference in running the string is due to the type of packer being used and whetherit is from a floater or a Jack-up rig. Example test string running procedures are given below forrunning strings with both types of packers from a semi-submersible drilling unit. For a Jack-up, the SSTT would be replaced by the sub-surface safety valve.

The specific running procedures will always be detailed in the well specific test programme.

11.5. RUNNING THE TEST STRING WITH A RETRIEVABLE PACKER

1) Run a junk basket on wireline to below the packer setting depth.2) Before running the test string, hold a brief safety meeting on the drill floor and re-

emphasise the precautions that should be taken during operations.3) Ensure a Kelly Cock is situated on the drill floor for emergency use.4) The downhole gauges should be programmed and installed into the gauge carrier(s) in

advance.5) Make up and run the TCP gun assembly.6) Install the packer assembly as per the string diagram.7) Continue making up the string using a back-up tong to ensure that the packer is not

turned to the right.8) Pick up the test tools in reverse running order and make them up to the correct torque.

Care should be taken that no connections are backed out and that the packer is notturned to the right.

9) Run the tools into the well and make up the crossover and first joint(s) of intervening drillcollars.

10) Ensure the BOP blind rams are open before the test tools reach them.11) Continue running the minor string as per the string diagram, until all the collars and slip

joints have been made up. Note the string weight.12) When the first tubing joint of the major string has been run, pressure test the minor

string.13) Run the tubing.14) When the test string has been run half way into the well, the tubing should again be

pressure tested (optional).15) If there is a liner hanger above the packer setting depth, run the tailpipe and packer

through the liner hanger slowly.16) When all major string has been run, it is recommended that the string should again be

pressure tested.17) Pick up the SSTT assembly and make up to the tubing and function test.18) Continue running the landing string, strapping the SSTT hoses to the tubing.19) Install the lubricator valve.20) Continue running the landing string and the space-out pup joints, strapping all hoses to

the pipe.

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21) Install the surface test tree and 50ft bails or CTU lifting frame.22) Run a GR/CCL log to verify the packer setting depth. (Refer to appropriate section

according to gun type).23) Set the packer and set down weight until the fluted hanger lands out in the wellhead.24) Set the packer and set down weight until the fluted hanger lands out in the wellhead.25) Run a GR/CCL log to verify the packer setting depth. (Refer to appropriate section

according to gun type).26) Carry out the hook-up and final pressure testing.27) The well is now ready to be perforated and tested.

11.6. RUNNING A TEST STRING WITH A PERMANENT PACKER

1) Run a junk basket to below the packer setting depth2) A safety meeting should first be held on the drill floor.3) If the TCP guns are being run below the packer, make up the TCP gun assembly.4) Install the packer and packer tailpipe assembly as per the programme. The packer

should be spaced out so that it is at least 5ft away from a casing collar.5) Run the packer/TCP assembly on drillpipe with a radioactive marker sub, one stand

above the setting tool.6) Open the blind rams before the test tools reach them.7) Rig up and run a GR/CCL and correlation gun setting depth.8) Rig down the wireline. Adjust the setting depth as required.9) Set and pressure test the packer. Pull the work string.10) Ensure a Kelly Cock is situated on the drill floor for emergency use.11) The downhole gauges should be programmed and installed into the gauge carrier(s) in

advance.12) If the TCP guns are to be run on the string, make up the gun assembly.13) Install the space out tubing and then the seal assembly.14) Continue and pick up the DST tools in reverse running order and make them up to the

correct torque. Care should be taken that no connections are backed out.15) Continue running the minor string as per the string diagram, until all the collars and slip

joints have been made up. Record the string weight.16) When the first tubing joint of the major string has been run pressure test the minor

string.17) Run the tubing.18) When the test string has been run half way into the well, the tubing should again be

pressure tested (optional).19) If there is a liner hanger above the packer setting depth, run the end of the string slowly

through the liner hanger.20) When approaching the permanent packer, pick up by one tubing joint to check the up

weight and slack back down to check the down weight.21) Run in slowly and tag the packer. Mark the pipe and calculate the spacing out.22) It is recommended that the string be pressure tested.

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23) Pull slowly out of the packer and pull back the pipe to install the SSTT.24) Space out and pick up the SSTT assembly, install onto the tubing and function test.25) Continue running the landing string, strapping the SSTT hoses to the tubing.26) Install the lubricator valve.27) Continue running the landing string, strapping all hoses to the pipe.28) With the seal assembly still out of the packer, install the surface test tree attached to

the final joint. Rig up the 50ft bails or CTU lifting frame.29) Carry out the hook-up pressure test.30) Slowly lower the seal assembly into the packer and land the SSTT hanger.31) Conduct the final string pressure tests.32) The well is now ready to be perforated and tested.

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12. WELL TEST PROCEDURES

12.1. ANNULUS CONTROL AND PRESSURE MONITORING

An important aspect of any well test is the continuous monitoring of the annulus pressure.This responsibility shall be delegated to the Driller who will maintain a log of pressures andtool functioning throughout the test.

The well conditions during flow periods will affect the temperature and, therefore, the fluidvolume in the annulus. These temperature effects should be closely monitored and pressuresadjusted throughout the flow period by the Driller to keep them within the parameters given bythe DST specialist.

Note: Annulus pressure should always be controlled by the rig choke manifold.and any hydrocarbons vented to the poor-boy de-gasser.

The following aspects for annulus monitoring must be planned beforehand:

• At least two independent measurement points should be made available so that acomparison of the two can be made at regular intervals.

• Two bleed-off/top up ports should be available to bleed down/top up the pressurefrom the thermal expansion/contraction.

• The monitor should be tied into the surface data gathering system.• A test tool operator should be present on the drill floor at all times to advise the

Driller of the test tool parameters and optimum operating pressures.• It is important that the Driller maintains a frequent check and records all bleed off/

top up times and volumes.

12.2. TEST EXECUTION

a) Welding, cutting and any other operation involving the use of open flame shall beforbidden, unless express, nominal written permission is given and signed by theCompany Drilling and Completion Supervisor and Drilling Contractor Toolpusher.

b) A suitable amount of mud shall be available during casing perforations and formationtesting. The amount of mud shall be 1,5 times the volume of the well.

c) Mud pumps shall be lined up to reserve mud and all relevant valves from the pumps tothe flow head's kill line should be in open position.

d) The test string shall include as a minimum the following downhole and surfaceequipment (from bottom to surface):• Tailpipe• Packer• Safety joint• Jar• Tester• Two reverse circulation valves• Slip joints• Flowhead.

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a) Initial opening and/or initial flow through separator shall be carried out in daylight only. Allsubsequent flow/build-up operations can be performed at night under favourableweather conditions.

b) Wind speed and direction shall constantly be monitored before formation clean out andduring the flow to avoid smoke vapour, gas and heat invading the rig.To this purpose, Company and Contractor personnel shall continuously and directlymonitor the flame behaviour at the flares to be able to intervene in case of suddenchanges in wind direction.

g) Initial opening shall be avoided in windless condition. The decision to suspend a testdue to windless conditions shall be taken by Contractor's Toolpusher after consultationwith Company's Drilling and Completion Supervisors.

h) The test shall be suspended whenever the normal course of operations is hampered ordrilling unit's safety is jeopardised (heating of the structures, presence of smokes, gason the rig).

i) Wireline operations inside a test string shall be limited as much as possible.j) Downhole pressure build-up (shut-in) shall be obtained by closing the tester valve.k) Well shut-in at the surface shall only be limited to extreme case.l) Upon flow beginning, the presence of H2S into the formation fluid shall be detected as

soon as possible.If H2S is present, procedures to operate in sour gas contaminated environments shallbe strictly observed (Refer to the Drilling Procedures Manual).

Frequent test on H2S presence shall be carried out on the rig floor, productionequipment and flares area, near pumps and engines.

Any indication of H2S presence shall immediately be notified to Contractor's Toolpusherand Company's Drilling and Completion Supervisor.

m) It is forbidden to release to the atmosphere non-combusted hydrocarbons.Only the use of production stock tanks shall be allowed.

n) All stimulation jobs and subsequent formation clean out operations, shall be performedin daylight.

o) During acid jobs, at least two water hoses shall be available to dilute any possible acidspills.

p) During acidizing, surface pressure’s shall not exceed the surface equipment testingpressure or the working pressure of the weakest joint of the test string, whichever islowest.

q) During acid job must be definite and marked all the pressure areas.

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13. WELL TEST DATA REQUIREMENTS

13.1. GENERAL

The following is the procedure for gathering well test data:

1) Monitor all data points with the electronic surface data acquisition system as shown intable 13.a.

2) Take manual separator and manifold readings every 30min during the well test and asdirected during clean-up.

3) Flow to the gauge tank for liquid flow rates and meter calibration.4) Take manual H2S and CO2 Draeger readings every hour during the clean-up.5) Maintain detailed records on all well flow characteristics and operational changes with

description, e.g. ‘fluid to surface’, ‘direct flow to test equipment’ etc.6) Take BS&W samples every 30min and the mud logger is to perform laboratory analysis

of water for chlorides and any other ions such as Ca, Mg, sulphates, TDS, pH anddensity.

7) Record the specific gravity of the gas, oil and condensate every 30min.8) Take pressurised combination gas, oil or condensate samples from the separator for

every main flow period for PVT analysis or as required by the Reservoir Engineer. Makedetailed records and complete the sample forms to give type of sample, wellparameters, at sampling time, time sample take, bottle numbers etc. Dispatch all PVTsamples immediately for analysis.

9) Collect other fluids samples as detailed in the Well Testing Programme. Dispatch theseto the district warehouse for storage until their disposition is decided.

10) During a water test, collect water samples every hour during clean-up and stable flowperiods and perform onsite analysis, initially to monitor clean-up from contaminated totrue formation water and then to confirm the continued production of clean formationwater. Onsite analysis is to be conducted to check for chloride and equivalent sodiumchloride levels, sediment, resistivity, pH, total dissolved solids and specific gravity.

11) Collect samples of true produced formation water in plastic or pressurised containers,as instructed by the Reservoir Department for laboratory analysis. Dispatch as per step6) above.

12) Foreign or unidentified materials produced from the well should be kept in a marked upplastic sample packet for onshore analysis.

13) All samples must be clearly identified and logged.14) In addition to Draeger readings and, if required, monitor constantly for CO2 and H2S

presence throughout the test using Orsat (UOP 172/59) and cadmium sulphate titration(ASTM D2385).

15) Monitor sand production by sand detection system and take samples as necessary.16) Take manual pressure and temperature readings upstream and downstream of the

choke, initially every five minutes, during the clean-up.17) Monitor bottomhole flowing and shut-in pressures and temperatures with surface

readout system as appropriate.

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13.2. METERING REQUIREMENTS

Prior to the commencement of testing, the separator flow meters and Barton differentialpressure recorder should have been calibrated.

All personnel involved in the operation of metering devices and gauges must keep a detailedlog of the test sequence, as this is very important to the final interpretation of the test data.

A surface data acquisition system should be utilised permitting more frequent data collection.However, if for any reason this system is not utilised, the recording intervals of table 13.a shallapply.

Note: These intervals may be altered at the discretion of the well site CompanyProduction Test Supervisor.

Readings Timing

1 Well Pressure 1st Flow Every 1 min for 10 minsEvery 2 mins for 20 mins

Every 5 mins until endFurther Flow Periods Every 5 mins for 1 hour

Every 15 mins until endMonitor THP during build up in case tester valve is leaking

2 Wellhead Temperature 1st Flow as aboveFurther Flow Periods as above

3 SRO Pressure andTemperature(Print-outs)

Further Flow Periods Every 15 secs for 10 mins

Every 1 min for 20 minsEvery 5 mins until end

Each build up Every 15 secs for 15 minsEvery 1 min for 45 mins

Every 5 mins until end of build up4 Separator Flow Rates Every 30 mins5 Shrinkage Every 2 hours6 Oil and Gas Gravities Every 1 hour7 BS&W As frequent as possible to determine if sand is

being produced8 H2S Determination 1st Flow As frequent as possible with detector tubes at

choke manifold bubble hoseFurther Flow Periods Every 2 hours by chemical analysis of separator

gas9 CO2 Determination As for H2S

10 Downhole Memory Gauges Minimum 4 gauges, preferably 6-8 gauges, to berun. Minimum 2 different types of gauge to be run.Seek advice from Reservoir Engineers during test

planning for special requirements.

Table 13.A - Data Gathering Timings

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13.3. DATA REPORTING

Second only to safety, the task of data gathering and reporting is the most important activityduring a well test and is the prime responsibility of the Company Production Test Supervisor.The data will generally be recorded by the service companies, but it is the responsibility of theCompany Production Test Supervisor to ensure it is collected correctly, accurately and thendistributed.

13.4. PRE-TEST PREPARATION

After the test programme has been finalised, the following points should be discussed withthe participating service companies:

a) The type of downhole gauges to be run taking into consideration the range ofpressures and temperatures to be encountered, the planned length of the test andthe accuracy required. The responsibility for onsite interpretation of data shouldalso be decided.

b) The range of surface flowrates expected should be discussed so that the correctinstruments and orifice plates can be selected. The frequency of datameasurement and the report presentation should also be decided, if acomputerised data acquisition unit is to be used.

c) The frequency and locations to take samples for fluid identification during the testshould be decided. These include samples for water, sand and H2S production.Responsibility for onsite analysis of samples should also be determined.

d) The schedule for sampling for retention should also be discussed.e) The Well Testing Contractor must submit their Safety Procedures Manual for

approval.

13.5. DATA REPORTING DURING THE TEST

Data collected during the well test will be reported in the following formats, in addition to thedaily drilling reports:

a) Company Production Test Supervisor’s reports:• Daily Telex of summary of operations• Detailed Daily Diary of operations prepared daily by Company Production

Test Supervisor on the rig and eventually returned to shore for placing in thewell file.

b) Composite data acquisition system report (if used)c) BHP gauge contractor’s reports (both hard copy and on compatible 5.25ins disk)d) Surface test facilities contractor’s reporte) Sampling contractor’s report (downhole sampler)f) Stimulation contractor’s report (if used)

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13.6. COMMUNICATIONS

(Also refer to the Company ‘Drilling Procedures Manual’.)

During the course of the test, it is important that information flows freely from the rig to theonshore base. The following telexes should be sent to the base to reduce the risk ofmisunderstanding and ensure a smooth operation.

• A daily telex should be prepared on the rig for transmission in the morningcovering the last 24hr period ending at 24.00hrs. This should be on the desk ofbase personnel when they arrive in the morning and will be used to keep partnersinformed. An afternoon telex should also be prepared covering the period to15.00hrs. These telexes should include operations on an hour-by-hour basis withdetails of tools run in hole, flowrates, pressures etc.

• A telex should be sent at the end of each test briefly summarising the dailyoperations and main results of the test. This is a ready source of data on the testwhich may be used for parent Company reports and reports to partners.

• Samples taken during the test should be sent to shore as soon as the test hasbeen completed. A telex should be sent listing all the samples, the boat used fortransportation when the boat leaves the rig and the ETA. If offshore, do notsend all the samples taken during a single test on the same boat; splitsamples into complete sets and dispatch on different vessels.

If any changes are to be made to the programme during testing operations, a telex or fax willbe sent from the rig to the base summarising the procedure that is proposed to be followedfor the next sequence of operations. This should be accordingly approved by shore baseProduction Superintendent who will ensure that all relevant personnel are informed of thechange in the programme.

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14. SAMPLING

14.1. CONDITIONING THE WELL

The well should be conditioned prior to sampling to ensure representative reservoir fluids arebeing produced.

The well should be flowing in a stable state, with correspondingly stable separator readingsfor at least 6 hours before the start of any sampling. The stability of the well may bedetermined by:

• Gas and Oil flow rates• GOR• Wellhead pressure• Downhole flowing pressure.

If the above measurements are stable then the well may be considered ready for separatorsampling.

Care should also be taken to ensure the well flow rate is in excess of the minimum at whichliquid fallback in gas wells occurs, otherwise surface samples will not be representative. Thisrate is dependent mainly upon the GLR and the tubing size.

If the well has been perforated close to the gas/oil contact, samples may be invalid andshould probably not be taken.

Surface sampling can be undertaken if the well is producing water but downhole sampling isnot recommended.

14.2. DOWNHOLE SAMPLING

After the well has been conditioned, it should be either shut-in or left to produce at a very lowflow rate. At least two bottomhole samplers in conjunction with a pressure and temperaturegauge are installed in the well on wireline. A short pressure and temperature gradient surveymust be performed above the sampling point e.g. at five different depths with 100ft intervals.This is to determine whether the sample taken will have been in single phase, i.e. below thelevel at which gas may be breaking out of solution, or above the OWC. Ideally, the samplingpoint should be above the perforations. When the samplers are on depth, the samples aretaken and the pressure and temperature at the sampling depth will be recorded by the gaugeat this time.

Samplers are either actuated mechanically by a clock or electrically by a signal from surface.If clock-type samplers are used, the samplers should be placed on depth before thescheduled actuation time for some period of time to allow for clock inaccuracies.

The samplers are then pulled out of the hole and the samples transferred into theshipping/storage bottles. The quality of each sample should be checked by bubble pointdetermination. It is recommended that at least two runs are made with two samplers each runand that at least one sample is transferred at 100oF using a heating element. If possible, eachsample should be transferred similarly to ensure that no wax is left on the wall of thecontainer. If not, this sample should be marked separately.

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Depending on conditions, sampling should continue until consistent quality checks areobtained on two separate samples.

Note: All sampling should utilise mercury-free systems and piston type samplebottles for safety of personnel.

For long term storage of Agip samples, all well effluent samples should be transferred toTeflon lined bottles and the mercury-free bottles returned off rental.

14.3. SURFACE SAMPLING

14.3.1. General

Surface samples are taken after the well has been conditioned for later recombination in thelaboratory. Gas and oil samples should be taken simultaneously forming paired or‘companion’ samples. It is important that accurate gas and oil production rates are known atthe time of taking the samples. Refer to API RP44 for further details.

Before any separator sampling begins, the following procedures should be carried out:

1) Sample bottles should be made ready by having the gas bottles checked to ensure thatthey have an absolute vacuum and plugs available for each port.

2) Oil sample bottles need to be checked to ensure they are evacuated above the piston,and that the piston is at the top of the bottle. The fluid below the piston should bechecked to make sure that there is no air present, as this can give extraneous readingswhen measuring the fluid flow whilst sampling is in progress. This will cause problemslater when an attempt is made to determine the pressure (Pb) in the PVT laboratory.

3) The sampling manifolds should be prepared with gauges to suit the expected samplingpressure already fitted. Liners should be cleansed and made ready. An oil sample bottlestand should be readily available, together with a 600cc measuring cylinder. Samplingmanifolds should be kept as simple as practically possible with as small an internalvolume as is reasonably possible but with liners that are long enough to avoid anypossibility of straining the connections to the sampling point and to the samplingmanifold.

4) A bucket of clean water and a supply of rags should also be readily available for leaktesting full sample bottles and for wiping clean the bottles before shipping to the PVTlaboratory.

5) For gas, sampling should be conducted using evacuated sample bottles. These areclean and easy to use as no flushing is required, hence contamination is unlikely. Avacuum pump is required and care should be taken that no valves become plugged withhydrates.

6) Oil should be sampled using piston bottles. These are clean, easy to use, have a knownvolume and are mercury-free. They are also relatively easy to use in forming the gascap for safety during transportation.

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7) All samples must be labelled immediately after being taken using Agip sample labels, ifavailable. The following information must be recorded:• Well number.• DST number.• Choke size.• Perforation interval.• Time of sampling and duration.• Oil/condensate and gas rate at time of sampling.• Stock tank oil/condensate, temperature, gravity and shrinkage, pressure.• Gas temp, gravity, static and differential pressures, orifice size and meter run

size.• BS&W.

8) All samples should be loaded into an empty container and shipped to base as soonafter the test as possible. Record on the morning report, the container in which thesamples are being shipped to shore. Do not ship all samples in one container, splitsamples into two representative batches and ship in separate containers.

9) It is vital when taking samples that any problems are recorded, highlighted and fullydocumented.

Note: More specific sampling requirements may be detailed on individual welltesting programmes.

14.3.2. Sample Quantities

Separator samples should always be taken simultaneously as matched sets of oil and gassamples, thus being sampled under identical conditions. At least two sets of separatorsamples (2 x oil and 2 x gas) should be taken, so that there is comparability between sets ofsamples. The ratio of gas samples to oil samples is dependent upon the GOR - hence beingone of the reasons stable separator conditions is required.

GOR equal or less than 1,500scf/stb = 1:1

GOR greater than 1,500scf/stb, but less than 3,000scf/stb = 3:2

GOR greater than 3,000scf/stb = 2:1

14.3.3. Sampling Points

The sampling points on a separator should be very carefully chosen as samples taken fromthe wrong point on a separator will not be truly representative of the produced fluids.

The gas sample point should be:

• Upstream of the Daniels box in the gas line.• As close to the separator vessel, as possible.• Not immediately downstream of thermal wells or ports in the flowline.• Not immediately after a bend in the flowline.• Ideally the sampling point should protrude into the centre of the gas flowline and

face upstream. However, a pipe into the stream is acceptable.

Note: The sampling point should not be on the lower half of the flowline cross

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section, due to any possibility of free liquid/liquid carryover beingpresent. If the sampling point has to be fitted flush to the inside surfaceof the flowline then it is preferable that it is on the top of the line and noton the side.

The oil sampling point should be:

• As close as possible to the exit of the oil flowline from the main vessel andupstream of meters.

• Not immediately downstream of thermal well or bends in the flowline.• Ideally the sampling point should protrude into the centre of the flowline with the

mouth facing upstream. However a pipe into the centre of the flowline isacceptable.

• It should be upstream of any increase in flowline diameter.• It is preferable that samples are not taken from the bottom of the oil sight glass,

as the level in the sight glass does sometimes falls, especially if there is much rigmovement which can allow free gas to enter the sampling line.

Note: The sampling point should not be on the upper half of the flowline crosssection, due to any possibility of there being free gas. If the samplingpoint is on the wall of the flowline then it is preferable that it is on theside, rather than on the top or the bottom, due to possibility of free gas orwater being in the flowline.

14.3.4. Surface Gas Sampling

The following is the procedure for taking a gas sample:

1) Any flushing should be done through a hose directly downwind, or to sea level, toprevent any risk of poisoning due to gasses such as H2S.

2) Record the bottle number.3) It is preferable, for the sake of safety, to take gas samples with the bottles lying

horizontally unless it can be securely fastened upright or held in a stand.4) The manifold should be flushed before use, then attached either to the top valve (V1), or

to one of the end valves (V1, V2) if the bottle is lying on its side (Refer to figure 14.a).The manifold valve (V3) should then be opened slowly to test for any leaks. If there is aleak, then close the manifold valve, and remake the connections to the bottle.

Note: No manifold or gauge should be attached to the second valve (V2) underany circumstances. This is to prevent the loss of any of the heaviercomponents of the gas which might have condensed in the bottle whenexposed to a vacuum.

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5) The bottle valve (V1) may now be slowly cracked open. Even with the noise around aseparator, it is still quite easy to hear the gas ‘hissing’ into the bottle and this can alsobe heard even when wearing a BA set. Sometimes the gauge needle can be seen toslightly dip on the initial opening.If there is just one gas bottle being filled to one oil bottle, then the sampling time shouldbe about 30 minutes. This length of time means there is less chance of an invalidsample being taken.

If the ratio of gas samples to oil samples is greater that 1:1, then the fill time should beworked out to still allow the oil samples to take about 30 minutes.

6) When the sample bottles are full and the sampling time has elapsed, shut the bottlevalve (V1) and the valve on the separator sampling point (V3).

7) Record the pressure on the gauge, and bleed off about 30psi (using V4) then open thebottle valve (V1). The gauge should now read the original sampling pressure. If it doesn’tthen check the manifold and the bottle valve for blockages or icing-up. If possible clearthe obstruction, take up a fresh bottle, and re-sample both the oil and gas samples. Ifthe pressure returns to near the original, then the sample is good and the separatorsampling point valve (V3) may be reopened for a few moments to allow the pressure inthe bottle to return to the sampling pressure.

8) Record the final sampling pressure and temperature, as they will be needed for thesampling sheets. The bottle and manifold valves (V1, V3) may now be closed, and theconnecting line broken.

9) Plug the valves, and both valves checked in a bucket of water for any leaks. Now placethe bottle safely aside.

10) Prepare for the next bottle for sampling.

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14.4. SURFACE OIL SAMPLING

The following is the procedure for taking an oil sample (a piston sample bottle is the preferredoption for liquid sampling):

1) First record the bottle number.2) The piston sample bottle should be stood in its custom built stand provided for the

purpose.3) The top manifold should be flushed to ensure that the line to the manifold and the

manifold filled with fresh fluid from the flowline.4) The manifold may now be connected to the top valve (V1) on the sample bottle.5) Connect the lower manifold to the bottom of the sample bottle, open the bottom bottle

valve (V2) and use the pump to pressurise the bottle below the piston to a pressureslightly in excess of the sampling pressure. This stops the piston moving as soon asthe bottle top valve is opened, so preventing any oil from flashing into the bottle. It alsoacts as a double check to ensure that the piston is still at the top of the bottle.

6) The next step may be performed in one of two ways:• Open the top manifold valve (V3), then connect a flushing line to the evacuation

port (V6) on the sample bottle. Open the top bottle valve (V1 to allow oil into thetop of the bottle) and slowly crack open the evacuation port (V6). This flushes theinitial flow of oil and gas which flashed into the bottle. Flush approx. 50cc of fluidthen close the evacuation port (V6). Remove the line and refit the plug, ensuringthat it is tight.

• Connect a vacuum pump to the evacuation port (V6) and check that there is stillan absolute vacuum. Ensure that the top manifold valve (V3) is closed. Open thetop bottle valve (V1) and evacuate the short line from the top manifold (V3) to thetop bottle (V1) valves. Close the top bottle valve (V1) and the evacuation port (V6).Remove the vacuum pumps, and refit the plug ensuring that it is tightly in place.Open the top manifold valve (V3) slowly. Now open the top bottle valve (V1)slowly and fill the crown of the piston. Place the tube from the bottom manifoldinto the top of a measuring cylinder, and slowly crack open the bottom bottle valve(V2). Now slowly crack open the flow regulating valve (V5), so as to take 30minutes to collect a 600cc sample (20cc /minute).

7) Remember that this sample must be taken in conjunction with the gas sample.8) When the sample bottle contains 600cc of separator fluid, close the flow regulating

valve (V5). Shut the top bottle (V1) and manifold valves (V3). Bleed off and disconnectthe top manifold from the bottle and plug the top bottle valve (V1).

9) The sample is now consolidated.10) A gas cap should now be formed to permit the safe shipping and storage of the bottle.

This is done by removing a portion of the buffer fluid equal to 10% of the samplevolume. This is called the Ullage.

11) The final pressure and temperature should now be recorded. This is vital for thelaboratory as it informs them what conditions to expect when they analyse the sampleand how much buffer fluid to inject to enable them to match the sampling conditions.

12) The bottom bottle valve (V2) should now be closed and the pressure in the bottommanifold valve bled off before removal.

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1) Fit a plug to the bottom valve (V2). Check the integrity of the valves and plugs byimmersing the bottle in a bucket of water and checking for bubbles. Remove from thewater, dry the bottle and fit the protective end caps.

2) Now place the bottle in its box and set aside.3) Prepare the next bottle for sampling.

14.5. SAMPLE TRANSFER AND HANDLING

Detailed instructions on shipment of samples from the rig, shore addressee(s) for thesamples, location of temporary and/or permanent storage facilities and instructions onsubsequent analysis of samples will be included in the Well Test Programme, or issued withseparate instructions.

Figure 14.A - Surface Sampling Typical Installation

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14.6. SAFETY

All equipment must be pressure tested and appropriately certified prior to dispatch.

Obtain and comply with any permit to work system before commencing any work.

14.6.1. Bottom-hole Sampling Preparations

Workscope Pressure testing and priming the tools with synthetic oil.

Work Area Rope off the work area and post pressure testing signs. Inform allrelevant personnel before commencing, and after completing,pressure testing. All non-essential personnel are to be kept clear.

Safety Gear Safety glasses and gloves must be worn.

Comments Tools will now contain high pressure dead synthetic oil and shouldbe stored and moved in a safe manner.

14.6.2. Rigging Up Samplers to Wireline

Workscope Attaching the samplers to the running toolstring.

Work Area Rig floor and wellhead area.

Safety Gear Additional gear may be required depending on mud type.

Comments Normal slickline/electric line safety procedures are to be followed.The tools will now contain high pressure dead synthetic oil and nopipe wrenches are to be used on the tool. The sampling engineerwill supervise the tool handling.

14.6.3. Rigging Down Samplers from Wireline

Work Scope Removing the samplers from the running toolstring.

Work Area Rig floor and wellhead area.

Safety Gear Safety glasses and gloves must be worn; additional gear may berequired depending on type of mud.

Comments Normal slickline/electric line safety procedures are to be followed.The tools will now contain high pressure oil/gas samples and nopipe wrenches are to be used on the tool. No source of ignition is tobe in vicinity. The sampling engineer will supervise the toolhandling.

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14.6.4. Bottomhole Sample Transfer And Validations

Work Scope High pressure transferring and validation of sub-surface samplesfrom tools to high pressure storage cylinders.

Work Area Indoors, well lit with a 100psi air supply, stable temperature andaway from any sources of ignition. Rope off the area and postpressure testing signs. Inform all relevant personnel beforecommencing, and after completing, transfers or validations. Allnon-essential personnel are to be kept clear.

Safety Gear Safety glasses and gloves must be worn.

Comments When high pressure oil/gas samples are transferred from tools tocylinders, leaks are highly unlikely but possible, thus there must beno sources of ignition in vicinity and no non-essential personnel inarea. If H2S in present, normal H2S operating procedures are to befollowed, i.e. breathing apparatus, buddy system etc. Personnelwork duration will not generally exceed 18hrs.

14.6.5. Separator/Wellhead Sampling

Work Scope High pressure transferring of hydrocarbons from separator to highpressure storage cylinders.

Work Area Well test area and rig floor. Rope off the area and post pressuretesting signs. Inform all relevant personnel before commencing,and after completing, sampling. All non essential personnel are tobe kept clear.

Safety Gear Hard hat, boots, coveralls, safety glasses, ear protection andgloves must be worn.

Comments When high pressure oil or gas samples are obtained, leaks arehighly unlikely but possible, thus there must be no sources ofignition in vicinity and no non-essential personnel in area. If H2S ispresent, normal H2S operating procedures are to be followed, i.e.breathing apparatus, buddy system etc. Personnel work durationwill not generally exceed 18hrs.

14.6.6. Sample Storage

Work Scope Storage and shipping of high pressure oil or gas samples.

Storage Area Must always be away from heat sources and sources of ignition.Must be well ventilated.

Comments Samples must be in two phases for storage and shipment, i.e.samples will have a gas cap. Samples must be labelled as beingflammable high pressure oil or gas samples.

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15. WIRELINE OPERATIONS

Although sometimes operationally necessary, wireline operations, both slickline or electricwireline, carry an inherent risk which is even greater on an offshore exploration well test dueto the configuration of the test string and the well conditions. If possible, running wirelinethrough the test string and especially the annulus pressure operated tester valve should beavoided. This must be avoided on deep, hot, high pressure wells.

Slickline tools are run for:

• Depth determination to check test string valves are fully open.• Bottomhole sampling which can be taken above or below the test tools.• Downhole pressure gauges, set in nipples or hung off.• Fluid interface check to establish fluid levels, e.g. frac gel.• Installing tubing plugs or downhole shut off tools which are set in nipples.• Circulation devices, i.e. opening or closing sliding sleeves.• Bailing to remove solids at a reverse circulating valve etc.• Fishing for other slickline or electric wireline toolstrings.

Electric wireline tools are run for:

• Depth determination, i.e. to check TCP guns are on depth.• Bottom hole sampling which can be taken above or below the test tools.• Production logging, to establish zonal contributions to flow.• Downhole pressure gauges which may be run with PLT tools.• Perforating or re-perforating with Through-Tubing guns.• Tubing punching to establish circulation.• Tubing cutting to free a test string from a stuck packer, etc.

Both types of wireline require the use of long bails, or a C/T (coiled tubing) lifting frame, tocater for the rigging up of the wireline BOPs and the lubricator on top of the flowhead.Pressure testing is to be carried out against the lubricator valve. The main difference betweena slickline and electric line rig up is that double BOPs and a grease flowtube must be used toachieve a seal on a braided cable.

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16. HYDRATE PREVENTION

Hydrates are complexes formed spontaneously by the combination of hydrocarbon gasmixtures with free water under certain conditions of temperature and pressure. Physicallythey are ice-like solids which can completely plug downhole tubing and/or surface lines.

Hydrates can form under both flowing or static conditions. The first indication of hydratesforming in the tubing is a drop in flowing wellhead pressure, followed by an initially slow butaccelerating drop in wellhead flowing temperature.

The formation of hydrates can be predicted and key to prevention is understanding theconditions under which they will form. These conditions are certain ranges of pressure andtemperature, with free water present. Under flowing conditions the expansion downstream ofa choke or other restrictions give a favourable regime for their formation. Under conditions ofno flow they can form as a kind of snow on the walls of tubing.

A downhole hydrate plug is potentially dangerous and should be avoided at all costs. The areaof most risks is in the string from the seabed upwards where the lowest temperature usuallyoccur.

It is of great importance to check the wellhead temperatures at frequent intervals andimmediately when the gas rate or flowing pressures are observed to decrease unexpectedly.

Hydrate prevention is based on the injection of triethylene glycol and/or methanol.

To prevent hydrate formation during the flow testing of high GOR (Gas/Oil Ratio) wells, pumpfacilities shall be connected up to the following points:

• Sub Sea Test Tree• Flowhead• Data header• Gas line downstream of the separator.

To prevent hydrate formations during shut-in periods, glycol should be injected continuouslyinto the vertical run of the flowhead as well as at the Sub Sea Test Tree.

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17. NITROGEN OPERATIONS

The main use of nitrogen on an exploration well test is to introduce a partial nitrogen cushioninto the test string by displacing the tubing contents through a tubing-annulus differentialpressure-operated circulation valve into the annulus. Fluid returns must be monitored toensure no nitrogen is allowed into the annulus.

The nitrogen cushion pressure can be rapidly reduced to give a very large drawdown whenperforating underbalance or bringing on a well which had already been perforatedoverbalance. This would be useful on tight or depleted reservoirs. It could also be used fordetonating TCP guns using a hydro-mechanical firing device operating at a given tubing-annulus differential by holding the annulus pressure and bleeding away the nitrogen cushionpressure.

Alternatively, with the well open, the nitrogen could be bled off very slowly to minimise thedrawdown, for instance, on a poorly consolidated sand. The disadvantage with this is that it isuncertain what is occurring downhole as the nitrogen is bled off. However the advantage is ifthe well does not flow to surface, the tubing contents can be reverse circulated out of the wellto determine the what the influx was and, if needed, a second nitrogen cushion could becirculated into placed in another attempt to bring the well in. If this failed, the well would haveto be gas lifted using a coiled tubing unit.

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18. OFFSHORE COILED TUBING OPERATIONS

Equipment for a coil tubing operation offshore for use on a well test is the same as on aplatform except that a lifting frame is installed to simplify the rig up. This must be rigged up onthe flowhead from the beginning as part of the landing string as this cannot be accomplishedafterwards.

The built-in lifting hoist must be a chain pulley type, which stops immediately the drive controlis released. It can also be used for the wireline rig-up making it easier and safer.

Coiled tubing on a well test is normally used for:

• Gas lifting using nitrogen• Spotting fluids i.e. accurately placing fluids for squeezing, perforating etc.• Logging (Stiff Wireline) in high deviations with cable inside the tubing.

The main limitation of coiled tubing is that it has a low burst and collapse pressure rating,therefore a pre-job computer analysis should be run using all the expected well parameterssuch as the expected well pressures and temperatures, internal pressures on the tubing, holeangles, depths and tubing data etc.

When coiled tubing is to be run on a well test, it is essential that the sub-sea test tree isdressed to be capable of cutting, whatever the size of the tubing.

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19. WELL KILLING ABANDONMENT

There are a number of methods for conducting a well kill operation in a well test situation,dependent upon the well hardware and configuration, taking into account of any well problemswhich have arisen. However, the two main methods under normal circumstances are;‘Reverse Circulation’ and ‘Bullheading’.

Note: Bullheading from surface should never be carried out as a routine killmethod without prior permission from Eni-Agip management. Proceduresfor any such method of well kill would be issued in the test programme.

Killing by reverse circulation is the preferred method of killing a well as it reduces the quantityof foreign materials coming into contact with and prevents over pressuring the formation.Bullheading is sometimes preferred in cases where the circulation method may not beefficient due to gas entrainment etc.

Other methods of well kill are used in circumstances where there has been a circulating valvefailure or a blockage in the tubing. These are; ‘Bleed off and Bullhead’, ‘Reverse Circulate andBullhead’ and ‘Lubricate’. These are so specialised in nature that it is not practical for them tobe used without first thoroughly examining the well situation and then producing a detailed wellspecific programme and are, therefore, not addressed in this manual.

On tests with Semi-Submersibles there is a well kill procedure for making the well safe for adisconnection due to bad weather etc.

19.1. ROUTINE CIRCULATION WELL KILL

The normal procedure for killing a well is the forward circulation method which displaces theformation fluids from the test string with kill weight fluid. This method can also be used in theevent of premature termination of an offshore test due to weather or any other reason whenthere is sufficient warning and time allows. This procedure requires DST tool operation toopen the circulating device and control of the circulating pressure using the well test chokemanifold.

19.1.1. Circulation Well Kill Procedure

The following procedure is the normal method of well kill following the termination of a testprogramme (Refer to figure 19.a).

1) After the final build up, or flow period, close the tester valve and pull any surface readout tools out of the hole if being used.

2) Open the multi-function circulating valve and reverse out string contents, collectingsamples if required. Circulate to condition and balance tubing and annulus. Close thecirculating valve.

3) Pressure up on the annulus to open the tester valve. Pressure up on kill wing valve withbrine to slightly less than shut in well head pressure then open the kill wing valve. Theproduction wing valve should be closed.

4) Pressure up on the test string with brine, checking the pump volume.

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5) Calculate the maximum the bottomhole pressure to be applied, which must be kept

below the formation frac pressure.6) If the formation takes the pumped fluid, continue bullheading down the test string and

liner below the packer to the bottom perforations. Check the volume of pumped brine.7) A variation in the pumping pressure should be detected when brine reaches the

formation. Record the leak-off rate.8) Carry out a 30min flow check. If static, proceed to step 14.9) If the well takes brine at more than 5bbl/hr, the displacement of a temporary plugging pill

to bottom may have to be considered.10) If the formation doesn’t take the pumped fluid or the injection rate is less than 0.1bpm

over a 3hrs period, close the kill side wing valve and tester valve.11) With the multi-function circulating valve in the test position, open the single shot

reversing valve and reverse circulate until the tubing and annulus are in balance.12) For tests using permanent packers, pull out seal assembly and reverse circulate at

least twice bottoms up, or until minimum gas returns.For conventional DST, unseat the packer and bullhead the hole contents below thepacker into the formation. Reverse circulate again, if necessary, until tubing andannulus are in balance.

13) Flow check the well.14) Once the well is stable, pull string out of hole while carefully monitoring the hole volume,

especially while DST tools are in 7ins liner as the swabbing effect is to be avoided.15) If the brine lost into formation is more than 5bbl/hr, the displacement of a temporary

plugging pill to bottom must be considered.This may be composed of CaCO3, HEC or MICA etc. and the material must beavailable on the rig to make up the appropriate weighted pill.

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19.2. BULLHEAD WELL KILL

Bullheading is only allowed by permission of Eni-Agip management.

If a well has good permeability, the simplest method of well kill is to bullhead from surface.

Bullheading is most effective when:

• The tubing contents are displaced without fracturing the formation• Mixing between the hydrocarbons and the kill fluid will be limited, e.g. with a small

diameter tubing and in a vertical well.

The drawback of bullheading is when the formation may be fractured, as with low permeabilityreservoirs. This can lead to a protracted well kill with hydrocarbons leaking back from thefracture into the well bore and migrating upwards in the well.

As a very rough way of estimating if bullheading will fracture the formation is as follows:

a) Estimate the productivity index (PI) of the well form surface pressure and flow rate data.b) Use the estimated of PI to calculate the injection pressure at a rate of 1bbl/min

(1,440bbl/d).c) Compare the estimated injection pressure with the prognosed formation fracture

pressure.

19.2.1. Bullhead Kill procedure

The Bullhead kill procedure is:

1) Calculated the volume to the perforations.2) Line up the cement pump with sufficient quantity of kill fluid.3) Pressure up with the pump to equalise across the wing valve and open the valve.4) At as fast a rate as possible, keeping below frac pressure, pump kill fluid.5) Monitor when the fluid first reaches the formation by observing a pump pressure rise.

Once kill fluid reaches over the whole perforated interval it will be more difficult tosqueeze away fluids and the pressure will increase.

6) Continue to pump until the hole volume calculated is pumped plus a few barrels excessto push away the kill fluid/well fluid interface.

7) Establish the circulation path, then unseat the packer (when a lock open tester valve isrun, unseating the packer will establish the circulation path).

8) Circulate bottoms up. If the well is taking losses, an LCM pill should be circulated in andbullheaded against the formation.

9) Only when the well is safe may the string be pulled.

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19.3. TEMPORARY WELL KILL FOR DISCONNECTION ON SEMI SUBMERSIBLES

This operation does not involve pulling the string out of hole and killing the well is limited onlyto filling up the string down to the tester valve, time allowing:

• Close the tester and kill the well by reverse circulation through the multi-functioncirculating valve and continue with operations to disconnect.

If in an emergency situation, when there is insufficient time to kill the well, disconnection willbe implemented without the well kill. In this eventuality, there will still be the requisite numberof barriers on the well for safety, although reconnection to a live well has it’s own particularrisks. This operation would be detailed in a separate programme.

Figure 19.A - Reverse Circulate Decision Tree

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19.4. PLUG AND ABANDONMENT/SUSPENSION PROCEDURES

Whenever feasible, a decision should be made on the disposition of the well as early aspossible, before any plugging operations are begun, whether or not the well is to besuspended for future production purposes. Well plugging procedures and equipment will differdepending upon the need for future well intervention. In particular, the choice of bridge plugsused for abandonment of test intervals will be affected, especially if perforating guns havebeen dropped into the sump below the plugs.

If the well is to be suspended, the course of action should be to install plugs which meetregulations but can protect the formation from any further damage during re-entry. Forinstance retrievable bridge plugs or packers can be used with a course of sand or saturatedsalt between the plug and the cement plug. This allows the cement to be drilled up with boththe cuttings and sand being circulated out and the well displaced to clean brine before theplug is pulled.

Often the ideal method of suspension is to use a permanent packer for the test which is alsoused as the completion packer. This allows the packer to be plugged by wireline, with oil orgas below, at the end of the test preventing any contamination of the formation.

Detailed plug and abandonment procedures will be issued by the Drilling and CompletionDepartment who are responsible for this part of the operation.

Note: If it is necessary, submit details of the methods and arrangements to beused to the proper authorities to obtain their written approval prior tocommencement of work.

19.5. PLUG AND ABANDONMENT GENERAL PROCEDURES

1) Rig up wireline and run in the hole with gauge ring and junk basket to 10ft above the topperforation/permanent packer. Pull out of the hole.

2) Run in the hole and set a bridge plug 10ft above top perforation/ permanent packer. Testthe bridge plug to 500psi above leak off pressure.

3) Run in the hole and set a second bridge plug immediately above the first. Test thisbridge plug to 500psi above the leak off pressure.

Note: Use of two bridge plugs instead of bridge plug and cement is to avoidcontamination of the completion brine.

Separate detailed procedures will be issued as part of the well specific drilling programme.

Pre-drilled development wells will also be covered by well specific drilling programmes.

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20. HANDLING OF HEAVYWATER BRINE

Both CaBr2/CaCl2, as brine and powder can cause skin irritation and even blistering if allowedto remain in contact with the skin. It is therefore important that personnel involved in workwhere they may be exposed to the brine or powder should be protected as follow:

a) Rubber gloves (gauntlet type to cover wrists)b) Waterproof slicker suits with hoodsc) Rubber boots (leather boots are shrivelled by the brine)d) Full face masks for use when mixing powdered CaBr2/CaCl2.e) Barrier cream (e.g. ‘Vaseline’) for use on exposed skin, particularly face, neck and

wrists, to prevent direct skin contact with the brine.

Additionally, whenever powder/brine is inadvertently splashed onto clothing, then the affectedclothes should be changed and washed forthwith. Never allow brine to dry on the skin orclothes.

If brine is splashed into the eyes, wash the eyes at once with copious amounts of fresh water.

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Appendix A - Report Forms

A.1. Daily Report (ARPO 02)

WELL NAME

FIELD NAME

District/Affiliate Company DATE: ARPO 02 Cost center

Rig Name RT Elevation [m] Well Code

Type of Rig Ground Lelel / Water Depth [m] Report N° of

Contractor RT - 1st flange / Top Housing [m] Permit / Concession N°

Well Last casing Next Casing BOP Type Ø w.p. [psi] M.D. (24:00) [m]

Ø nom.[in] Stack T.V.D. (24:00) [m]

Top [m] Diverter Total Drilled [m]

Bottom [m] Annular Rotating Hrs [hh:mm] Top of Cmt [m] Annular R.O.P. [m / h]

Last Survey [°] at m Upper Rams Progressive Rot. hrs [hh:mm]

LOT - IFT [kg/l] at m Middle Rams Back reaming Hrs [hh:mm]

Reduce Pump Strockes Pressure Middle Rams Personnel Injured

Pump N° 1 2 3 Middle Rams Agip Agip Liner [in] Lower Rams Rig Rig

Strokes Last Test Others Other Press. [psi] Total Total

Lithology

Shows

From (hr) To (hr) Op. Code OPERATION DESCRIPTION

Operation at 07:00

Mud type Bit N° Run N° N° Run N° Bottom Hole Assembly N° __________ Rot. hours Density [kg/l] Data Description Ø Part. L Progr.L Partial Progr. Viscosity [s/l] Manuf. P.V. [cP] Type Y.P. [g/100cm2] Serial No. Gel 10"/10' / IADC Water Loss [cc/30"] Diam. HP/HT [cc/30"] Nozzle/TFA Press. [kg/cm2] From [m] Temp. [°C] To [m] Cl- [g/l] Drilled [m] Salt [g/l] Rot. Hrs. pH/ES R.P.M. MBT [kg/m3] W.O.B.[t]

Solid [%] Flow Rate Stock Quantity UM Supply vessel Oil/water Ratio. Pressure Sand [%] Ann. vel. pm/pom Jet vel. pf HHP Bit mf HSI Total Cost Supervisor: Daily Losses [m3] I O D L I O D L Daily Progr. Losses [m3] B G O R B G O R Progr.

DAILY REPORT Drilling

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A.2. Waste Report (ARPO 6)

WELL NAME

FIELD NAMEDistrict/Affiliate Company

DATE: ARPO-06 Cost center

Report N° Depth (m) Mud Type From [m] Interval Drilled (m) Density (kg/l)

To [m] Drilled Volume [m3] Cl- concentration (g/l )

Phase size [in] Cumulative volume [m3]

Water consumption Phase /Period [m3] Cumulative [m3]

Usage Fresh water Recycled Total Fresh water Recycled Total

Mixing Mud

Others

Total

Readings / Truck Fresh water [m3] Recycled [m3]

Mud Volume [m3] Phase Cumulative Service Company Contract N°

Mixed Mud Company

Lost Waste Disposal

Dumped Transportation

Transported IN

Transported OUT

Waste Disposal Period Cumulative Remarks

Water base cuttings [t]

Oil base cuttings [t]

Dried Water base cuttings [t]

Dried oil base cuttings [t]

Water base mud [t]

Oil base mud transported IN [t]

Oil base mud transported OUT [t]

Drill potable water [t]

Dehidrated water base mud [t]

Dehidrated oil base mud [t]

Sewage water [t]

Transported Brine [t]

Remarks

Supervisor

Superintendent

WASTE DISPOSALManagement Report

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A.3. Well Problem Report (ARPO 13)

FIELD NAME

WELL NAMEDistrict/Affiliate Company

DATE: ARPO -13 Cost center

Problem Top [m] Start date

Code Bottom [m] End date

Well Ø Measured Depth Vertical Depth KOP [m] Mud in hole

Situation Top [m] Bottom [m] Top [m] Bottom [m] Max inclination [°] Type

Open hole @ m Dens.[kg/l]:

Last casing DROP OFF [m]

Well problem Description

Solutions Applied: Results Obtained:

Solutions Applied: Results Obtained:

Solutions Applied: Results Obtained:

Solutions Applied: Results Obtained:

Supervisor Supervisor Supervisor

Remarks at District level:

Superintendent

Lost Time hh:mm Loss value [in currency]

Remarks at HQ level Pag.Of

WELL PROBLEM REPORT

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A.4. Malfunction & Failure Report(FB-1)

MALFUNCTION & FAILURE REPORT(FEED BACK REPORT 01)

Report Date:

Well Name: Well Code:General Information

Contract No: Contract Type: Contractor:Service/Supply:

Drilling Completion

Workover Duration Dates of Failure: Distributed By:

RIG SITEDescription of Failure:

Drilling & Completions Company Man:Adopted or Suggested Solution(s):

Contractor Contingency Measures:

Contractor Representative:DISTRICT OR SUBSIDIARY NOTES:

Failure Classification Status Operations Manager:

Technical Normal

Management/Organisation Extreme Time Lost:

Safety/Quality Innovative

Adverse Estimated Cost of Failure:

MILAN HEAD OFFICE NOTES:

Analysis Code:

District/Subsidiary

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A.5. Contractor Evaluation (FB-2)

CONTRACTOR EVALUATION(FEED BACK REPORT 02)

Report Date: Well Name: Well Code:

General InformationContract No.: Contract Type: Contractor:Service/Supply: Distributed By:

R1 Technical RequirementsFB_01 REPORT REFERENCES

FB Report No.: Time Lost (Hr.Min): Economic Cost (£M):Category Evaluation Score (0-9)

Suitability of Equipment and MaterialsCompliance of Equipment and Materials to theAdequacy of PersonnelMeeting with Operational Programme RequirementsMeeting with Contract Operation TimingsEquipment Condition/Maintenance

R2 Management and Organisational RequirementsFB_01 REPORT REFERENCES

FB Report No.: Time Lost (Hr.Min): Economic Cost (£M):Category Evaluation Score (0-9)

Availability of Equipment and MaterialsTechnical and Operational Support to OperationsCapability and Promptness to Operational Requests

R3 Safety and Quality Assurance RequirementsFB_01 REPORT REFERENCES

FB Report No.: Time Lost (Hr.Min): Economic Cost (£M):Category Evaluation Score (0-9)

Meeting with the Contract Agreement DSSAvailability and Validity of Requested CertificatesMeeting with Contract Quality Assurance Terms

Event Support DocumentationType of

Document:Subject: Issued By: Date:

Notes:

Failure Status Operations Manager Drilling & Completions ManagerNormal Extreme Adverse Innovative

District/Subsidiary

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Appendix B - ABBREVIATIONS

AC/DC Alternate Current, Direct CurrentAPI American Petroleum InstituteBG Background gasBHA Bottom Hole AssemblyBHP Bottom Hole PressureBHT Bottom Hole temperatureBMT Blue Methylene TestBOP Blow Out PreventerBPD Barrel Per DayBPM Barrels Per MinuteBPV Back Pressure ValveBSW Base Sediment and WaterBUR Build Up RateC/L Control LineCBL Cement Bond LogCCL Casing Collar LocatorCDP Common Depth PointCET Cement Evaluation ToolCGR Condensate Gas RatioCR Cement RetainerCRA Corrosion Resistant AlloyC/T Coiled TubingDC Drill CollarDE Diatomaceous EarthDHM Down Hole MotorDHSV Down Hole Safety ValveD&CM Drilling & Completion ManagerDP Drill PipeDPHOT Drill Pipe Hang off ToolDST Drill Stem TestE/L Electric LineECD Equivalent Circulation DensityECP External Casing PackerEMS Electronic Multi ShotEMW Equivalent Mud WeightEP External PressureESD Electric Shut-Down SystemESP Electrical Submersible PumpETA Expected Arrival TimeFBHP Flowing Bottom Hole PressureFBHT Flowing Bottom Hole TemperatureFPI/BO Free Point Indicator / Back OffFTHP Flowing Tubing Head PressureFTHT Flowing Tubing Head TemperatureGLR Gas Liquid Ratio

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GOC Gas Oil ContactGOR Gas Oil RatioGP Gravel PackGPM Gallon (US) per MinuteGPS Global Positioning SystemGR Gamma RayHAZOP Hazard and OperabilityHHP Hydraulic HorsepowerHO Hole OpenerHP/HT High Pressure - High TemperatureHW/HWDP Heavy Weight Drill PipeIADC International Association of Drilling ContractorsIBOP Inside Blow Out PreventerID Inside DiameterIPR Inflow Performance RelationshipJAM Joint Make-up Torque AnalyserL/D Lay DownLAT Lowest Astronomical TideLC 50 Lethal Concentration 50%LCDT Last Crystal to Dissolve oCLCM Lost Circulation MaterialsLEL Lower Explosive LimitLN Landing NippleLOT Leak Off TestLQC Log Quality ControlLTA Lost Time AccidentM/D Martin DeckerM/U Make UpMAASP Max Allowable Annular Surface PressureMD Measured DepthMLH Mudline HangerMLS Mudline SuspensionMMS Magnetic Multi ShotMODU Mobile Offshore Drilling UnitMPI Magnetic Particle InspectionMSCL Modular Single Completion LandMSL Mean Sea LevelMUT Make up TorqueMW Mud WeightMWD Measurement While DrillingNACE National Association of Corrosion EngineersNDT Non Destructive TestNSG North Seeking GyroNTU Nephelometric Turbidity UnitOBM Oil Base MudOD Outside DiameterOH Open Hole

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OIM Offshore Installation ManagerOMW Original Mud weightOWC Oil Water ContactP&A Plugged & AbandonedP/U Pick upPBR Polished Bore ReceptaclePDM Positive Displacement MotorPI Productivity IndexPLT Production Logging ToolPOB Personnel On BoardPOOH Pull Out Of HolePPB Pounds per BarrelPPG Pounds per Gallonppm Part Per MillionPVT Pressure Volume TemperatureQ Flow RateQ/A Q/C Quality Assurance, Quality ControlR/D Rig downR/U Rig upRBP Retrievable Bridge PlugRCP Reverse Circulating PositionRFT Repeat Formation TestRIH Run In HoleRKB Rotary Kelly BushingROV Remote Operated VehicleRPM Revolutions Per MinuteRT Rotary TableS/N Serial NumberSBHP Static Bottom Hole PressureSBHT Static Bottom Hole TemperatureSCC Stress Corrosion CrackingSDE Senior Drilling EngineerSF Safety FactorSG Specific GravitySICP Shut-in Casing PressureSPM Stroke per MinuteSR Separation RatioSRG Surface Readout GyroSSC Sulphide Stress CrackingTCP Tubing Conveyed PerforationsTD Total DepthTG Trip GasTGB Temporary Guide BaseTOC Top of CementTOL Top of LinerTVD True Vertical DepthUR Under Reamer

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VBR Variable Bore Rams (BOP)VDL Variable Density LogVSP Velocity Seismic ProfileW/L Wire LineWBM Water Base MudWC Water CutWL Water LossWOC Wait On CementWOW Wait On WeatherWP Working PressureYP Yield Point

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Appendix C - BIBLIOGRAPHY

Document: STAP Number

Other

API Specification No 811-05CT5