ENI Well Test Procedures Manual.pdf

S P E O ENI S.p.A. E&P Division

ORGANIZING

DEPARTMENT

TYPE OF ACTIVITY'

ISSUING

DEPT.

DOC. TYPE

REF. N.

PAG. 1 OF 115

STAP P 1 M 7130

The present document is CONFIDENTIAL and it is the property of Eni It shall not be shown to third parties nor shall it be used for reasons different from those owing to which it was given.

Eni S.p.A. Exploration & Production division

Drilling Completion & Production Optimization Well Operating Standards

WELL TEST PROCEDURES MANUAL

Date of validity: 01-01-2005

Revision/Reproduction Record:

2 1 01-12-2004 0 General Issue 28-06-1999

Rev.No Reason for revision/reproduction Date Technical Validation

P repared P. Magarini

Signature(s): Date: 02-11-2004

C ontrolled C Lanzetta


A pproved F Trilli


Endorsement

V erified C Lanzetta


E ndorsed F. Trilli


I ssued A. Calderoni



IDENTIFICATION CODE PAG 2 OF 115

REVISION STAP-P-1-M-7130 0 1

INDEX 1. INTRODUCTION .............................................................................................................. 8

1.1 PURPOSE OF THE MANUAL .............................................................................. 8 1.2 IMPLEMENTATION .............................................................................................. 8 1.3 UPDATING, AMENDMENT, CONTROL & DEROGATION................................... 9 1.4 OBJECTIVES........................................................................................................ 9 1.5 DRILLING INSTALLATIONS ................................................................................ 10

2. TYPES OF PRODUCTION TEST ..................................................................................... 11 2.1 DRAWDOWN........................................................................................................ 11 2.2 MULTI-RATE DRAWDOWN ................................................................................. 11 2.3 BUILD-UP ............................................................................................................. 11 2.4 DELIVERABILITY................................................................................................. 11

2.4.1 FLOW-ON-FLOW.................................................................................. 12 2.4.2 ISOCHRONAL ...................................................................................... 12 2.4.3 MODIFIED ISOCHRONAL .................................................................... 12 2.4.4 RESERVOIR LIMIT ............................................................................... 12

2.5 INTERFERENCE .................................................................................................. 13 2.6 INJECTIVITY......................................................................................................... 13

3. GENERAL ROLES AND RESPONSIBILITIES................................................................. 14 3.1 RESPONSIBILITIES AND DUTIES....................................................................... 14

3.1.1 COMPANY DRILLING AND COMPLETION SUPERVISOR ................. 14 3.1.2 COMPANY JUNIOR DRILLING AND COMPLETION

SUPERVISOR....................................................................................... 15 3.1.3 COMPANY DRILLING ENGINEER....................................................... 15 3.1.4 COMPANY PRODUCTION TEST SUPERVISOR ................................. 15 3.1.5 COMPANY WELL SITE GEOLOGIST .................................................. 15 3.1.6 CONTRACTOR TOOLPUSHER ........................................................... 16 3.1.7 CONTRACT PRODUCTION TEST CHIEF OPERATOR ....................... 16 3.1.8 CONTRACTOR DOWNHOLE TOOL OPERATOR ............................... 16 3.1.9 WIRELINE SUPERVISOR..................................................................... 16 3.1.10 COMPANY STIMULATION ENGINEER................................................ 16 3.1.11 COMPANY RESERVOIR ENGINEER................................................... 16

3.2 RESPONSIBILITIES AND DUTIES ON SHORT DURATION TESTS ................... 17 3.2.1 COMPANY DRILLING AND COMPLETION SUPERVISOR ................. 17 3.2.2 COMPANY JUNIOR DRILLING AND COMPLETION

SUPERVISOR....................................................................................... 17 3.2.3 COMPANY WELL SITE GEOLOGIST .................................................. 17 3.2.4 CONTRACTOR PERSONNEL .............................................................. 17

4. WELL TESTING PROGRAMME ...................................................................................... 18




4.1 CONTENTS........................................................................................................... 18

5. SAFETY BARRIERS........................................................................................................ 19 5.1 WELL TEST FLUID............................................................................................... 19 5.2 MECHANICAL BARRIERS - ANNULUS SIDE ..................................................... 20

5.2.1 SSTT ARRANGEMENT ........................................................................ 20 5.2.2 SAFETY VALVE ARRANGEMENT....................................................... 22

5.3 MECHANICAL BARRIERS - PRODUCTION SIDE............................................... 23 5.3.1 TESTER VALVE ................................................................................... 23 5.3.2 TUBING RETRIEVABLE SAFETY VALVE (TRSV) OR (SSSV) ........... 24 5.3.3 CASING OVERPRESSURE VALVE ..................................................... 24

6. TEST STRING EQUIPMENT ............................................................................................ 25 6.1 GENERAL............................................................................................................. 25 6.2 COMMON TEST TOOLS DESCRIPTION ............................................................. 30

6.2.1 BEVELLED MULE SHOE ..................................................................... 30 6.2.2 PERFORATED JOINT/PORTED SUB .................................................. 30 6.2.3 GAUGE CASE (BUNDLE CARRIER) ................................................... 30 6.2.4 PIPE TESTER VALVE .......................................................................... 30 6.2.5 RETRIEVABLE TEST PACKER ........................................................... 30 6.2.6 CIRCULATING VALVE (BYPASS VALVE) .......................................... 30 6.2.7 SAFETY JOINT..................................................................................... 31 6.2.8 HYDRAULIC JAR ................................................................................. 31 6.2.9 DOWNHOLE TESTER VALVE ............................................................. 31 6.2.10 SINGLE OPERATION REVERSING SUB............................................. 31 6.2.11 MULTIPLE OPERATION CIRCULATING VALVE ................................ 31 6.2.12 DRILL COLLAR.................................................................................... 31 6.2.13 SLIP JOINT........................................................................................... 32 6.2.14 CROSSOVERS ..................................................................................... 32

6.3 HIGH PRESSURE WELLS ................................................................................... 32 6.4 SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES ............................... 32

6.4.1 SUB-SEA TEST TREE.......................................................................... 32 6.4.2 FLUTED HANGER................................................................................ 33 6.4.3 SLICK JOINT (POLISHED JOINT) ....................................................... 33 6.4.4 SSTT VALVE ASSEMBLY.................................................................... 34 6.4.5 LATCH ASSEMBLY.............................................................................. 34 6.4.6 BLEED OFF VALVE AND RETAINER VALVE..................................... 34

6.5 FISHING TOOL..................................................................................................... 35 6.6 LUBRICATOR VALVE.......................................................................................... 35 6.7 TOOLS FOR DYNAMIC POSITIONING RIG......................................................... 36

6.7.1 SHEAR JOINT ...................................................................................... 36 6.7.2 ELECTRO-HYDRAULIC CONTROL SYSTEM ..................................... 36 6.7.3 REAL-TIME SURFACE READ-OUT OF SUB SEA PRESSURE

AND TEMPERATURE........................................................................... 37

7. SURFACE EQUIPMENT .................................................................................................. 38




7.1 TEST PACKAGE .................................................................................................. 38 7.1.1 FLOWHEAD OR SURFACE TEST TREE............................................. 38 7.1.2 FLEXIBLE FLOW LINES AND PIPING................................................. 38 7.1.3 DATA/INJECTION HEADER................................................................. 39 7.1.4 CHOKE MANIFOLD.............................................................................. 39 7.1.5 STEAM GENERATOR AND HEAT EXCHANGER / INDIRECT

HEATER................................................................................................ 40 7.1.6 SEPARATOR........................................................................................ 41 7.1.7 DATA ACQUISITION SYSTEM............................................................. 43 7.1.8 GAUGE/SURGE TANKS ...................................................................... 43 7.1.9 TRANSFER PUMP................................................................................ 44 7.1.10 DIVERTER MANIFOLDS ...................................................................... 44 7.1.11 BURNERS............................................................................................. 44 7.1.12 BOOMS................................................................................................. 45 7.1.13 GAS TORCHES .................................................................................... 45 7.1.14 STORAGE TANKS FOR LIGHT AND HEAVY OIL............................... 45 7.1.15 TANKER TRUCK CHARGING SYSTEM .............................................. 46

7.2 EMERGENCY SHUT DOWN SYSTEM................................................................. 50 7.3 ACCESSORY EQUIPMENT.................................................................................. 50

7.3.1 CHEMICAL INJECTION PUMP ............................................................ 50 7.3.2 SAND DETECTORS ............................................................................. 50 7.3.3 CROSSOVERS ..................................................................................... 51

7.4 RIG EQUIPMENT.................................................................................................. 51 7.5 DATA GATHERING INSTRUMENTATION........................................................... 51

7.5.1 OFFSHORE LABORATORY AND INSTRUMENT MANIFOLD EQUIPMENT ......................................................................................... 51

7.5.2 SEPARATOR........................................................................................ 52 7.5.3 SURGE OR METERING TANK............................................................. 52 7.5.4 STEAM HEATER .................................................................................. 52

8. BOTTOM HOLE DATA ACQUISITION ............................................................................ 53 8.1 EQUIPMENT DESCRIPTION................................................................................ 53

8.1.1 WIRELINE UNIT.................................................................................... 53 8.1.2 ADAPTER FLANGE.............................................................................. 53 8.1.3 BOP ...................................................................................................... 53 8.1.4 TOOL TRAP.......................................................................................... 53 8.1.5 LUBRICATOR RISERS......................................................................... 54 8.1.6 FLOW TUBE TYPE STUFFING BOX.................................................... 54 8.1.7 SAFETY CHECK VALVE...................................................................... 54 8.1.8 INJECTION NIPPLE ............................................................................. 54 8.1.9 TOOL CATCHER .................................................................................. 55 8.1.10 DOWN HOLE PRESSURE AND TEMPERATURE GAUGES............... 55

8.1.10.1 GAUGE TYPES................................................................... 55 8.1.10.2 GAUGE INSTALLATION..................................................... 56

8.1.11 PRODUCTION LOGGING TOOL.......................................................... 58 8.1.12 DOWN HOLE SAMPLING TOOL.......................................................... 58

9. PERFORATING SYSTEMS.............................................................................................. 59 9.1 TUBING CONVEYED PERFORATING................................................................. 59




9.2 WIRELINE CONVEYED PERFORATING ............................................................. 59 9.3 PROCEDURES FOR PERFORATING.................................................................. 59

10. PREPARING THE WELL FOR TESTING......................................................................... 61 10.1 PREPARATORY OPERATIONS FOR TESTING.................................................. 61

10.1.1 GUIDELINES FOR TESTING 7INS LINER LAP ................................... 61 10.1.2 GUIDELINES FOR TESTING 95/8INS LINER LAP................................ 61 10.1.3 GENERAL TECHNICAL PREPARATIONS .......................................... 61

10.2 BRINE PREPARATION ........................................................................................ 62 10.2.1 ONSHORE PREPARATION OF BRINE................................................ 62 10.2.2 TRANSPORTATION AND TRANSFER OF FLUIDS............................. 62 10.2.3 RECOMMENDATIONS ......................................................................... 62 10.2.4 RIG SITE PREPARATIONS.................................................................. 63 10.2.5 WELL AND SURFACE SYSTEM DISPLACEMENT TO BRINE ........... 64 10.2.6 DISPLACEMENT PROCEDURE........................................................... 65 10.2.7 ON-LOCATION FILTRATION AND MAINTENANCE OF BRINE.......... 65

10.3 DOWNHOLE EQUIPMENT PREPARATION ........................................................ 66 10.3.1 TEST TOOLS........................................................................................ 66

10.4 TUBING PREPARATION...................................................................................... 66 10.4.1 TUBING CONNECTIONS ..................................................................... 66 10.4.2 TUBING GRADE................................................................................... 67 10.4.3 MATERIAL............................................................................................ 67 10.4.4 WEIGHT PER FOOT............................................................................. 67 10.4.5 DRIFT.................................................................................................... 68 10.4.6 CAPACITY ............................................................................................ 68 10.4.7 DISPLACEMENT .................................................................................. 68 10.4.8 TORQUE............................................................................................... 68 10.4.9 INSPECTION ........................................................................................ 68 10.4.10 TUBING MOVEMENT ........................................................................... 69

10.5 LANDING STRING SPACE-OUT.......................................................................... 70 10.5.1 LANDING STRING SPACE-OUT PROCEDURE .................................. 73

10.6 GENERAL WELL TEST PREPARATION ............................................................. 73 10.6.1 CREW ARRIVAL ON LOCATION......................................................... 73 10.6.2 INVENTORY OF EQUIPMENT ONSITE................................................ 73 10.6.3 PRELIMINARY INSPECTIONS............................................................. 74

10.7 PRE TEST EQUIPMENT CHECKS....................................................................... 75 10.8 PRESSURE TESTING EQUIPMENT .................................................................... 76

10.8.1 SURFACE TEST TREE......................................................................... 77

11. TEST STRING INSTALLATION ....................................................................................... 80 11.1 GENERAL............................................................................................................. 80 11.2 TUBING HANDLING............................................................................................. 81 11.3 RUNNING AND PULLING .................................................................................... 81 11.4 PACKER AND TEST STRING RUNNING PROCEDURE ..................................... 82 11.5 RUNNING THE TEST STRING WITH A RETRIEVABLE PACKER...................... 82




11.6 RUNNING A TEST STRING WITH A PERMANENT PACKER............................. 83

12. WELL TEST PROCEDURES ........................................................................................... 85 12.1 ANNULUS CONTROL AND PRESSURE MONITORING ..................................... 85 12.2 TEST EXECUTION ............................................................................................... 85

13. WELL TEST DATA REQUIREMENTS ............................................................................. 87 13.1 PRE-TEST PREPARATION.................................................................................. 87 13.2 METERING REQUIREMENTS.............................................................................. 87 13.3 DATA REPORTING .............................................................................................. 88 13.4 WELL TEST DATA ACQUSITION PROCEDURE................................................. 89

14. SAMPLING....................................................................................................................... 90 14.1 CONDITIONING THE WELL................................................................................. 90 14.2 DOWNHOLE SAMPLING ..................................................................................... 90 14.3 SURFACE SAMPLING ......................................................................................... 91

14.3.1 GENERAL............................................................................................. 91 14.3.2 SAMPLE QUANTITIES ......................................................................... 92 14.3.3 SAMPLING POINTS ............................................................................. 92 14.3.4 SURFACE GAS SAMPLING................................................................. 93

14.4 SURFACE OIL SAMPLING .................................................................................. 94 14.5 SAMPLE TRANSFER AND HANDLING............................................................... 95 14.6 SAFETY................................................................................................................ 96

14.6.1 BOTTOM-HOLE SAMPLING PREPARATIONS ................................... 96 14.6.2 RIGGING UP SAMPLERS TO WIRELINE ............................................ 97 14.6.3 RIGGING DOWN SAMPLERS FROM WIRELINE ................................ 97 14.6.4 BOTTOMHOLE SAMPLE TRANSFER AND VALIDATIONS................ 97 14.6.5 SEPARATOR/WELLHEAD SAMPLING ............................................... 98 14.6.6 SAMPLE STORAGE............................................................................. 98

15. WIRELINE OPERATIONS................................................................................................ 99

16. HYDRATE PREVENTION ................................................................................................ 100

17. NITROGEN OPERATIONS .............................................................................................. 101

18. COILED TUBING OPERATIONS ..................................................................................... 102

19. WELL KILLING ABANDONMENT ................................................................................... 103 19.1 WELL KILLING..................................................................................................... 103 19.2 WELL KILLING ABANDONMENT........................................................................ 103




20. HANDLING OF HEAVYWATER BRINE........................................................................... 104

APPENDIX A - REPORT FORMS ............................................................................................. 105 A.1. DAILY REPORT (ARPO 02) ................................................................................. 105 A.2. WELL TEST REPORT GENERAL DATA (ARPO 10/A).................................... 106 A.3. WELL TEST REPORT DST DATA (ARPO 10/B) .............................................. 107 A.4. WELL TEST REPORT RECORD DATA (ARPO 10/C)...................................... 108 A.5. WASTE REPORT (ARPO 6) ................................................................................. 109 A.6. WELL PROBLEM REPORT (ARPO 13) ............................................................... 110 A.7. MALFUNCTION & FAILURE REPORT (FB-1) ..................................................... 111 A.8. CONTRACTOR EVALUATION (FB-2).................................................................. 112

APPENDIX B ABBREVIATIONS............................................................................................ 113

APPENDIX C BIBLIOGRAPHY.............................................................................................. 115




1. INTRODUCTION

The main objective of drilling a well is to test and evaluate the target formation. The usual method of investigating the reservoir is to conduct a well test and there are two methods which are available:

Drill Stem Test (DST). The scope is to define the quality of the formation fluid. This is a short term test which uses a combination of drillpipe/tubing and downhole tools to evaluate the reservoir. The formation fluid may not reach or only just reach the surface during the flowing period.

Production Test. The scope is to define both the quality and quantity of the formation fluid. The formation fluid, in this case, is flowed to surface.

Many designs of well test strings are possible depending on the requirements of the test and the nature of the well and the type of flow test to be conducted.

In fact, the production test can be performed either through a temporary completion string made up of DST down hole tools or through the final permanent completion string.

Basically, a completion string consists of a tailpipe, packer, safety system, downhole test tools and a tubing or drill pipe work string; by introducing a low density fluid into the work string, formation fluids can flow to the surface testing equipment which controls the flow rate, separates the different phases and measures the flow rates and pressures.

A short description of the types of tests that can be conducted and the generic test string configurations for the various drilling installations, as well as the various downhole tools available, surface equipment, pre-test procedures and test procedures are included in this section.

Specific wire line and coiled tubing services for well test operations are also described.

1.1 PURPOSE OF THE MANUAL The purpose of the manual is to guide technicians and engineers, involved in Drilling & Completion activities, through the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Company Principles. This, however, still enables the Company capability to operate according to laws 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 common guidelines in all areas worldwide where Eni E&P operates.

1.2 IMPLEMENTATION The guideline and policies specified herein are applicable to all Eni E&P Drilling and Completion engineering activities.

All engineers engaged in Eni E&P casing design activities are expected to make themselves familiar with the contents of this manual and be responsible for compliance to its policies and procedures.




1.3 UPDATING, AMENDMENT, CONTROL & DEROGATION This manual is a live controlled document and, as such, it will only be amended and improved by the Company, in accordance with the development of Eni E&P operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis.

Derogations from the manual shall be approved solely in writing by the Company Well Operations Manager after the Company Manager and the Corporate Drilling & Production Optimisation Services Department in Eni E&P Division Head Office have been advised in writing.

The Corporate Drilling & Production Optimization Services Standards Department will consider such approved derogations for future amendments and improvements of the Corporate manual, when the updating of the document will be advisable.

Feedback for manual amendment is also gained from the return of completed Feedback and Reporting Forms from well operations refer to Appendix A, page 105.

1.4 OBJECTIVES The test objectives must be agreed by those who will use the results and those who will conduct the test before the test programme is prepared. The Petroleum Engineer should discuss with the geologists and reservoir engineers about the information required and make them aware of the costs and risks involved with each method. They should select the easiest means of obtaining data, such as coring, if possible. Such inter-disciplinary discussions should be formalised by holding a meeting (or meetings) to insure these objectives are agreed and fixed.

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.




1.5 DRILLING INSTALLATIONS Well tests are conducted both onshore and offshore in either deep or shallow waters. The drilling 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 installation necessitates the use of a permanent/retrievable type production packer, seal assembly and a conventional flowhead or test tree with the test string hung of in the slips. In wells where the surface pressure will be more than 10,000psi the BOPs will be removed and testing carried out with a tubing hanger/tubing spool and a Xmas tree arrangement. This requires all the necessary precautions of isolation to be taken prior to nippling down the BOPs

Semi-Submersible

The preferred method for testing from a Semi-submersible is by using a drill stem test retrievable packer. However where development wells are being tested, the test will be conducted utilising a production packer and sealbore assembly so that the well may be temporarily suspended at the end of the test. When testing from a Semi-submersible the use of a Sub-Sea Test Tree assembly is mandatory.

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

At the top of the SSTT is the hydraulic latch section, which contains the operating mandrels to open the valves and the latching mechanism to release this part of the tree from the valve section in the event that disconnection is necessary.

Drill Ship Same as Semi-Submersible above.




2. TYPES OF PRODUCTION TEST

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

2.2 MULTI-RATE DRAWDOWN A multi-rate drawdown test may be run when flowrates are unstable or there are mechanical difficulties with the surface equipment. This is usually more applicable to gas wells but can be analysed 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 build up test.

2.3 BUILD-UP A build-up test requires the reservoir to be flowed to cause a drawdown then the well is closed in to allow the pressure to increase back to, or near to, the original pressure, which is termed the pressure build-up or PBU. This is the normal type of test conducted on oil well and 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 of test to evaluate the rate dependant skin coefficient, D, is to conduct a second flow and PBU at a different rate to the first flow and PBU. This is the simplest form of deliverability test described below.

2.4 DELIVERABILITY A deliverability test is conducted to determine the wells Inflow Performance Relation, IPR, and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependant skin coefficient, D.

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

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




There are three types of deliverability test:

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

2.4.1 FLOW-ON-FLOW

Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilises and then repeating this at several different rates. Usually the rate is increased at each step ensuring that stabilised flow is achievable. The durations of each flow period are equal. This type of test is applicable to high rate gas well testing and is followed by a single pressure build up period.

2.4.2 ISOCHRONAL

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

2.4.3 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 final flow period which is extended similar to the isochronal test. The flow rate again is increased at each step.

2.4.4 RESERVOIR LIMIT

A reservoir limit test is an extended drawdown test which is conducted on closed reservoir systems to determine their volume. It is only applicable where there is no regional aquifer support. The well is produced at a constant rate until an observed pressure drop, linear with time, 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. The difference between the initial reservoir pressure, and the pressure to which it returns, is the depletion. The reservoir volume may be estimated directly from the depletion, also the volume of produced fluid and the effective isothermal compressibility of the system. The volume produced must be sufficient, based on the maximum reservoir size, to provide a measurable pressure difference on the pressure gauges; these must therefore be of the high accuracy electronic type gauges with negligible drift.




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

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

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

The water can be filtered and treated with scale inhibitor, biocide and oxygen scavenger, if required. Once a well is fractured, which may also be caused by the thermal shock of the cold injection water reaching the sandface, a short term injection test will generally not provide a 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 to a pressure build-up, but is complicated by the cold water bank.




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, detailed below.

3.1 RESPONSIBILITIES AND DUTIES The following Companys/Contractors 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 during the Well test:

Company Stimulation Engineer. Company Reservoir Engineer.

3.1.1 COMPANY DRILLING AND COMPLETION SUPERVISOR

The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations. He is assisted by the Company Production Test Supervisor, Drilling Engineer, Well Site Geologist and Company Junior Drilling and Completion supervisor. When one of the above listed technicians is not present, the Company Drilling and Completion Supervisor, 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 Well Test specifications. If deemed necessary he shall request that the rig be inspected by a Company 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 and Completion 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 downhole drilling equipment, to carry out equipment inspections and tests and to supervise the Downhole Tool Operator and the Contractor Production Chief Operator. In co-operation with the Drilling Engineer, he will prepare daily reports on equipment used. In the absence of the Company Junior Drilling and Completion Supervisor, his function will be performed by the Company Drilling and Completion Supervisor.

3.1.3 COMPANY DRILLING ENGINEER

The Drilling Engineer will assist the Company Drilling and Completion Supervisor in the well preparation and in the test string tripping operation. He will co-operate with the Company Production Test supervisor to supervise the downhole tool Operator and the Contractor Production Chief Operator. He shall be responsible for supplying equipment he is concerned with (downhole tools) and for preliminary inspections. He shall provide Contractor personnel with 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 conducting of 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 specific production equipment. In conjunction with the Reservoir Engineer, he shall make recommendations 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 each phase of the test with the Company Drilling and Completion Supervisor. He will then inform rig floor and test personnel of the actions to be performed during the forthcoming phase of the test. 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. surface and downhole testing tools, supervising preliminary inspections as per procedures. He will supervise contract wireline and production test equipment operator, as well as the downhole tool operator and surface equipment operators. He will be responsible in conjunction with the Company Well site Geologist for the supervision of perforating and cased hole logging operations, as per the test programme.

The Company Production Test Supervisor is responsible for the preparation of all reports, 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 well testing) cased hole logging when the Company Production Test Supervisor is not present on the rig. If required he will co-operate with the Company Production Test Supervisor for the test interpretation 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 that safety regulations and procedures in place are followed rigorously. The Toolpusher shall consistently report to the Company Drilling and Completion supervisor on the status of drilling contractors 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 well testing operator and crew. He will be responsible for the test crew to the Company Production Test 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 time the assembling of the BHA is started until it is retrieved. He is solely responsible for downhole tool manipulation and annulus pressure control during tests.

On Semi-Submersibles the SSTT operator will be available near the control panel on the rig floor 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 in and out of the hole and during the operations relating to the well flowing (from opening to closure 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. He will 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 Test Supervisor during any stimulation operations. He will provide the Company Production Test Supervisor with a detailed programme for conducting stimulation operations, including the deck layout for equipment positioning, chemical formulations, pumping rates and data collection. He will monitor the contractors during the stimulation to ensure the operation is performed safely and satisfactorily.

The Stimulation Engineer will also provide the Company Production Test Supervisor with a report 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 Supervisor during the formation testing operation. His main responsibility is to ensure that the required well test data is collected in accordance to the programme and for the quality of the data for analysis. He will provide a quick look field analysis of each test period and on this basis 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 Drilling and Completion Supervisor, the Company Junior Drilling and Completion Supervisor and the well site Geologist. The Company Well Operations Manager/ Superintendent shall evaluate, in each individual case, the opportunity of providing a Company Drilling Engineer. The responsibilities and duties of the Company Drilling and Completion Supervisor and Well Site Geologist will be as follows.

3.2.1 COMPANY DRILLING AND COMPLETION SUPERVISOR

The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations assisted by the Company Junior Drilling and Completion Supervisor and the well site Geologist. He is responsible for the co-ordination of testing operations, well preparation for tests, shut-in of the well, formation clean out, measuring, flaring and wireline operations. The Company Drilling and Completion Supervisor is responsible for the availability and inspection of the testing equipment. He shall supervise the contractor Production Chief Operator, Wireline Operator and Production Test Crew, as well as the Downhole Tool Operator and Surface Tool Operator.

3.2.2 COMPANY JUNIOR DRILLING AND COMPLETION SUPERVISOR

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

3.2.3 COMPANY WELL SITE GEOLOGIST

The Well Site Geologist is responsible for the supervision of perforating operations and for cased hole logging operations. He is responsible for the final decision making to modify the testing programme, whenever test behaviour would be different than expected. He shall draw up 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 contractors Personnel (Toolpusher, Production Chief Operator, Downhole Tool Operator), refer to long test responsibilities.




4. WELL TESTING PROGRAMME

When the rig reaches the Target Depth and all the available data are analyzed, the Company Reservoir/Exploration Departments shall provide the Company Drilling & Completion and Operative Geology 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 be opened, type of perforating gun and number of shots per foot, use of coiled tubing stimulation, etc.).

The Company Drilling & Completion department shall then prepare a detailed testing programme verifying that the testing equipment conforms to these procedures and also to make sure that the testing equipment is available at the rig in due time.

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

Governmental bodies of several countries lay down rules and regulations covering the entire drilling activity. In such cases, prior to the start of testing operations a summary programme shall 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 the Company Drilling & Production Optimisation Service department and rig personnel shall verify the consistency of the present procedures to suit local laws, making any modifications that would be 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 into account two essential factors:

a) The risk to which the rig and personnel are exposed during testing. b) The cost of the operation. c) A detailed testing programme shall include the following points:

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

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




5. SAFETY BARRIERS

Barriers are the safety system incorporated into the structure of the well and the test string design 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 or available to be closed at all times. A failure in any barrier system which means the well situation does meet with these 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 and the production or tubing side. Some barriers may actually contain more than one closure mechanism but are still classified as a single barrier such as the two-closure mechanism in a SSTT, etc.

Barriers are often classified as primary, secondary and tertiary.

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

5.1 WELL TEST FLUID The fluid which is circulated into the wellbore after drilling operations is termed the well test fluid and conducts the same function as a completion fluid and may be one and the same if the 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 overbalance on the formation which prevents the formation fluids entering the wellbore during the times it is exposed to the test fluid during operations. The times that the formation may be exposed to the 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.

The test fluid density will be determined from log information and calculated to provide a hydrostatic pressure, generally between 100-200psi, greater than the formation pressure. As the test fluid is usually clear brine for damage prevention reasons, high overbalance pressures may cause severe losses and alternatively, if the overbalance pressure is too low, any fluid loss out of the wellbore may quickly eliminated the margin of overbalance. When using low overbalance clear fluids, it is important to calculate the temperature 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.

A modern test method used on wells which have high pressures demanding high density test fluids which are unstable an extremely costly, is to design the well test with an underbalanced fluid which is much more stable and cheaper. In this case there will be one barrier less than overbalance testing. This is not a problem providing the casing is designed for the static surface pressures of the formation fluids and that all other mechanical barriers are available and 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 the overbalance test fluid. If one of these barriers (or element of the barrier) failed then there would still be two barriers remaining.

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

The arrangement of the BOP pipe ram closure varies with whether there is a surface or subsea BOP stack. When testing from a floater, a SSTT is utilised to allow the rig to suspend operations and leave the well location for any reason. On a jack-up, a safety valve is installed below the mud line as additional safety in the event there is any damage caused to the installation (usually approx. 100m below the rig floor). Both systems use a slick joint spaced across 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 5-1- SSTT Arrangement. The positioning of the SSTT in the stack is important to allow the blind rams to be closed above the top of the SSTT valve section providing additional safety and keeping the latch free from any accumulation of debris which can effect re-latching.

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




Figure 5-1- SSTT Arrangement




5.2.2 SAFETY VALVE ARRANGEMENT

On jack-ups where smaller production casing is installed, the safety valve may be too large in OD (7-8ins) to fit inside the casing. In this instance a spacer spool may be added between the stack and the wellhead to accommodate the safety valve. This is less safe than having the valve positioned at the mud line as desired (refer to Figure 5-2).

PIPE RAMS

SHEAR RAMS

5 PIPE RAMS

5 SLICK JOINT

8 O.D.SAFETY VALVE

9 5/8 CASING

TUBINGTUBING SPOOL

ALL WELLS WITH 9 5/8PROD. CASING

TUBING

13 3/8 or 11 5000 - 10000 - 15000 psi W.P. BOP STACKS

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 7PROD. 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

Figure 5-2 - Safety Valve Arrangement




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 control are:

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 by maintaining a minimum pressure on the annulus with the cement pump. Bleeding off the pressure 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 this type of valve is set in the position where the loss of pressure closes the valve. It is unsafe to leave the tester valve in the open cycle position as in an emergency situation there may not be sufficient time to cycle the valve closed.

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




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 in permanent on-shore and off-shore completions respectively.

This type of valve can also be installed inside the BOP for well testing as an additional downhole barrier on land wells or on jack-up rigs, see Figure 5-2 for the various configurations of 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 is only possible by installing a spacer spool between the tubing spool and the pipe rams closed on a slick joint directly connected to the upper side of the valve itself. A space of at least two metres 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 string movement.

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

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

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

5.3.3 CASING OVERPRESSURE VALVE

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

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

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




6. TEST STRING EQUIPMENT

6.1 GENERAL The well testing objectives, test location and relevant planning will dictate which is the most suitable test string configuration to be used. Some generic test strings used for testing from various installations are shown over leaf:

For well tests performed inside a 7ins production liner, use full opening test tools with a 2.25ins ID. In larger production casing sizes the same tools will be used with a larger packer. In 5-51/2ins some problems can be envisaged: availability, reliability and reduced ID limitations to run W/L. tools, etc. smaller test tools will be required, but similarly, the tools should be full opening to allow production logging across perforated intervals. For a barefoot test, 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 to allow production logging, reperforating and/or acid treatment of the interval.

In the following description are included tools that are required both in production tests and conventional tests. 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 of mechanical failure. The tools should be dressed with elastomers suitable for the operating environment, considering packer fluids, prognosed production fluids, temperature and the stimulation programme, if applicable.

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

In a well testing through a completion string, prior to flowing, the annulus will be pressurised to 500 psi and this pressure will be held, monitored and recorded throughout the entire test.




Figure 6-1 - Typical Jack Up/Land Test String - Packer With TCP Guns On Packer




Figure 6-2 - Typical Test String - Production Packer With TCP Guns Stabbed Through




Figure 6-3 - Typical Jack Up/Land Test String - Retrievable Packer




Figure 6-4 - Typical Semi-Submersible Test String - Retrievable Packer




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 tubing conveyed perforating system is used. This item may also be used if wireline retrievable gauges 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 packer and sense either annulus or tubing pressures or 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 open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure, 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 by turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from being 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 in and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It can also be used to equalise differential pressures across packers at the end of the test. It is automatically 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 the closed sump below the packer during packer setting. This feature is important when running tubing conveyed perforating guns which are actuated by pressure. If the valve does not have a delay on closing, a large incremental pressure, rather than the static bottom hole pressure, should be chosen for firing the guns.




6.2.7 SAFETY JOINT

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

6.2.8 HYDRAULIC JAR

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

6.2.9 DOWNHOLE TESTER VALVE

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

6.2.10 SINGLE OPERATION REVERSING SUB

Produced fluids may be reversed out of the test string and the well killed using this tool. It is actuated by applying a pre-set annulus pressure which shears a disc or pins allowing a mandrel to move and expose the circulating ports. Once the tool has been operated it cannot be 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 safety valve is required. One example of this is a system where the reversing sub is combined with two ball valves to make a single shot sampler/safety valve.

6.2.11 MULTIPLE OPERATION CIRCULATING VALVE

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

This tool is available in either annulus or tubing pressure operated versions. The tubing operated versions require several pressure cycles before the valve is shifted into the circulating position. This enables the tubing to be pressure tested several times while running in hole. Eni E&P preference is the annulus operated version.

6.2.12 DRILL COLLAR

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




6.2.13 SLIP JOINT

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

6.2.14 CROSSOVERS

Crossovers warrant special attention. They are of the utmost importance as they connect pieces of equipment of the test string which have different threads. If crossovers have to be manufactured, they need to be tested and fully certified. In addition, they must be checked with 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 is compulsory to test the well.

6.4 SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES

6.4.1 SUB-SEA TEST TREE

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

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

The Sub Sea Test Tree (SSTT) system comprising from bottom upwards:

Adjustable fluted hanger to land in the wear bushing of the sub sea well head,

Valve assembly to be located below the lower BOP pipe rams or alternatively split one valve below the lower BOP pipe rams and one valve between the two lower BOP pipe rams,

Slick joint to be located across the two lower BOP pipe rams, Latch assembly to be located between the upper pipe ram and the lower

shear ram, Shear joint to be located across the two upper BOP shear rams, Bleed-Off-Valve and Retainer valve to be located above the upper shear

ram, Sub sea electro-hydraulic control pod to be located above the riser flex

joint, Electro-hydraulic control umbilical with chemical injection line and Surface control panel




It shall together with the BOP comprise the main barriers during testing and provide the means to, with the greatest possible emphasis on safety, fast and efficiently secure the well and disconnect from the well.

The SSTT system shall be able to effectively close, seal and disconnect in less than 15 seconds.

The SSTT system shall go to fail safe position following an emergency shear of the shear joint, i.e. the SSTT valves and Retainer Valve shall go to closed positions.

The SSTT system shall be able to disconnect under tension and min. 4 angle. A 4 angle of the SSTT may not be applicable in the BOP due to tight tolerances between the SSTT elements and the BOP. However max. angle versus friction must be considered case by case, as the SSTT disconnect angle have a dramatical effect on the DP rigs operating envelope).

6.4.2 FLUTED HANGER

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

The fluted hanger shall:

Be equipped with a locking device to ensure that position stays as adjusted,

Fit the 7, 7 5/8, 9 5/8 or 10 3/4 wear bushings of the 18 3/4 ID subsea well head,

Be able to transfer the weight of the complete test string to the subsea well head.

6.4.3 SLICK JOINT (POLISHED JOINT)

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

The slick joint shall:

Be designed and positioned such that the two BOP lower pipe rams can close and seal on the slick joint.

Have an upset below the pipe ram that will normally be closed during the test, tentatively the upper pipe ram, to limit possible upwards movement of the SSTT assembly. This is to ensure that the shear joint will always remain in position across the BOP shear rams.

Tentative dimension shall be:

5" or 5 1/2 OD External Collapse Pressure rating: 690 bar (10.000 psi)




6.4.4 SSTT VALVE ASSEMBLY

The SSTT valve assembly shall:

Be positioned below the lower two BOP pipe rams or alternatively split one valve below the lower BOP pipe rams and one valve between the two lower BOP pipe rams,

Have two normally (fail safe) closed, hydraulically operated, surface controlled valves,

Have pump through capability from above with hydraulic pressure bled off,

Be capable of failsafe cutting of 7/32" wireline and pressure assisted cutting of 11/2 OD, 0,156 wall thickness coiled tubing and seal afterwards,

Be designed not to damage valves or operating mechanism if attempting to open valves with excessive differential pressure across valves,

Have chemical injection facilities optionally between or below the valves with dual check valves at the injection point. The chemical for injection shall be methanol. Required methanol injection rate capacity shall be up to 5 litres/minute (a 1/4 chemical injection line will be sufficient).

External Collapse Pressure rating: 690 bar (10.000 psi).

6.4.5 LATCH ASSEMBLY

It is positioned between the BOP upper pipe ram and the lower shear ram, such that remnants of the shear joint has an adequate stick-up for retrieval/fishing after emergency cutting of the shear joint.

The latch assembly shall has:

A primary electro-hydraulically, surface controlled, unlatch system that is able to disconnect under up to 50.000 lbs. tension, 345 bar (5.000 psi) internal pressure and min. 4angle,

A mechanical or pressure actuated, preferably not by string rotation, secondary unlatch system,

A surface controlled hydraulically operated relatch system with positive indication on surface whether latching parts are in correct position or not,

A physical function to prevent accidental unlatch while running in the hole.

6.4.6 BLEED OFF VALVE AND RETAINER VALVE

The Bleed off Valve (BOV) and Retainer Valve (RV) shall be installed immediately above the latch assembly or shear joint (if present).

It is hydraulic operated and must be a fail-open or fail-in-position valve. When closed, it will contain pressure from both above and below.




It shall be able to contain high pressure hydrocarbons in the string and prevent their release into the marine riser in the event of an emergency disconnect of the SSTT (i.e. prevent U-tubing of gas into the marine riser that can result in riser collapse); it shall:

Be fail safe closed and fail safe cut up to 7/32 wireline such that above requirement is fulfilled also in the event of emergency cutting of the shear joint,

Be hydraulically operated in conjunction with the latch assembly such that the RV must be closed and the BOV must have opened prior to unlatching,

Provide a bleed-off function between the SSTT and RV to prevent explosive decompression of gas that can shoot the landing string up in the derrick,

Have pump through capability if failed in the closed position, Provide pressure testing facilities of the landing string when re-running

same after unlatching, Be able to optionally close BOV and open RV to spot glycol at latch nose

prior to relatching, or relatch with closed RV and BOV open (to avoid compressing fluids when latching. BOV to be closed after latching.).

6.5 FISHING TOOL The dedicated fishing equipment, for use after an eventual emergency shear of the shear joint, shall have the following capabilities:

Fit and interface the specific BOP, SSTT and remaining part of the shear joint (Ref. latch requirements: The latch shall be positioned between the BOP upper pipe ram and the lower shear ram, such that remnants of the shear joint has an adequate stick-up for retrieval/fishing after emergency cutting of the shear joint.)

Transmit high torque values (15.000 lbs./ft) to release secondary release mechanism if applicable.

Be designed to be released without use of rotation.

6.6 LUBRICATOR VALVE The lubricator valve is run 3 joints of tubing below the surface test tree and such that both valves will be below the drilling riser telescoping joint's inner barrel. This valve eliminates the need to have a long lubricator to accommodate wireline tools above the surface test tree swab valve. It also acts as a safety device when, in the event of a gas escape at surface, it can prevent the full unloading of the contents in the landing string after closing of the SSTT. The lubricator valve is operated by remote hydraulic control from surface through a second umbilical line and should be either a fail closed or a fail-in-position valve. When closed it will contain pressure from both above and below. It has: pump through capability if failed in the closed position, facilities for chemical (glycol or methanol) injection below the valves, hoses for hydraulic control and chemical injection of the type where all hoses are incorporated in one bundle.

Note: For standard operations only the upper valve will be closed. The lower one will remain open and serve as back up for the upper one.




6.7 TOOLS FOR DYNAMIC POSITIONING RIG As exploration moves into deeper and remote Subsea locations, the use of dynamic positioning vessels require much faster SSTT unlatching than that available with the normal hydraulic system on an SSTT. The slow actuation is due to hydraulic lag time when bleeding off the control line against friction and the hydrostatic head of the control fluid. To allow the faster SSTT unlatching, the following tools will be foreseen in the test string assembly.

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

6.7.1 SHEAR JOINT

If the well testing is carried out using Dynamic Positioning rig, the shear joint shall be used to allow an emergency disconnection.

It is positioned above the latch assembly, across the two BOP shear rams such that both shear rams can close and cut same in the latched position.

The shear joint shall be:

Designed to withstand the tension, compression and bending forces likely to be encountered during the test,

Traceable. Verification that the actual BOP will be able to shear the shear joint with external hydraulic control/injection lines and internal 7/32 electric wireline shall have been performed on the actual or identical BOP. The required shear pressure shall be documented.

6.7.2 ELECTRO-HYDRAULIC CONTROL SYSTEM

The Hydraulic deep water actuator is a fast response controller for the deepwater SSTT and retainer valve and controls all their functions using hydraulic power from accumulators on the tree controlled electrically from the surface control unit.

The fluid is vented into the annulus or an atmospheric tank to reduce the lag time and reducing closure time to seconds.

It includes one local (on the control unit) and two remote (in the drillers and DP operators control rooms) one-button ESD (Emergency Shut Down) functions:

ESD 1 Close SSTT valves. ESD 2 Close SSTT valves, close RV, open BOV and unlatch.

It gives clear warning, by both flashing light and audible alarm, whenever ESD 2 has been activated.

Clearly indicate:

Normal status of each function with green indicating lights Abnormal status of each function with red indicating lights.

It shall be powered through an uninterrupted power supply system to ensure SSTT system operability also during rig power black-out periods, and has the real time pressure read-out of the sub sea accumulator pressure.




The electro-hydraulic pod/control system shall be provided with:

Clamps to support the umbilical to the landing string, hold its position over the thermal tubing couplings, and protect the umbilical from the lateral movements of the marine riser.

Unique connections on the sub sea umbilical and surface jumper hose to prevent accidental miscoupling,

A hose bundle protective shield for rotary table.

The sub sea umbilical provided shall permit up to 5 litre/minute methanol injection at 690 bar sub sea injection pressure.

Red alert on the rig and SSTT control panels shall not be interfaced as trouble prone systems should not form part of a well control system. Simple BOP and SSTT control systems shall be independent - linked by procedures.

6.7.3 REAL-TIME SURFACE READ-OUT OF SUB SEA PRESSURE AND TEMPERATURE

To enable the proper measurements against hydrate problems to be taken at all times real-time surface read-out of sub sea pressure and temperature shall be provided.




7. SURFACE EQUIPMENT

This sub-section describes the components of the surface equipment and the criteria for its use; typical lay-outs of the surface equipment for light oil, heavy oil and gas production tests are respectively shown in Figure 7-1, Figure 7-2 and Figure 7-3. A test pressure programme for the surface layout equipment must be prepared by the contractor.

7.1 TEST PACKAGE

7.1.1 FLOWHEAD OR SURFACE TEST TREE

Modern flowheads are of solid block construction (a single steel block) as opposed to the earlier modular units which were assembled from various separate components. Irrespective of the type used, 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 used 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 distance above the drill floor which is greater than the maximum amount of heave anticipated, plus an allowance for tidal movement, for example 5 ft and an additional 5ft for a safety margin.

Flexible flow lines are used to connect the flowhead kill wing and flow wing outlets respectively to the rig manifold and the test choke manifold. A permanently installed test line is sometimes available which runs from the drill floor to the choke manifold location.

7.1.2 FLEXIBLE FLOW LINES AND PIPING

Flexible flow lines must be installed on the flowhead correctly so as to avoid damage. They must be connected so that they hang vertically from the flowhead wing outlets. The hoses should never be hung across a windwall or from a horizontal connection unless there is a pre-formed support 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 and time saving. They are also less likely to leak since they have fewer connections. On floaters, they connect the stationary flowhead to the moving rig and its permanent pipework.




Piping must have hammer connections with sealing devices and pressure rating compatible with the application.

The hammer connection shall be welded on pipe for upstream application; it should be welded on pipe for down stream application.

The connection for up stream application on HP-HT wells shall be flange type.

Additional protection can be provided by installing relief valves in the lines. It is now common practice to have a relief valve on the line between the heater and the separator to accommodate for any blockage downstream which may cause an over-pressure in the line. If there is a potential risk from plugging of the burner nozzles by sand production, then consideration should be given to installing additional relief valves downstream of the separator to protect this lower pressure rated pipework.

All surface lines from the wellhead to the flare manifold and vessels must be pressure tested using water; all pressures will be recorded on a Martin Decker type chart recorder.

All surface lines will be anchored to the platform deck or to the ground.

Note: Ensure that the flexible flow lines 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 is merely a section of pipe with several ports or connections to enable:

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

Each port shall be equipped with a block and bleed valve.

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

7.1.4 CHOKE MANIFOLD

The choke manifold is a system of valves and chokes for controlling the flow from the well and usually has two flow paths, one with facilities to install and change chokes of fixed sizes and the other with an adjustable choke. Some choke manifolds may also incorporate a bypass line.

Each flow path shall have a minimum of two closing valves which are used to direct the flow through either of the chokes or the bypass and to provide isolation from pressure when changing the fixed choke.

A well shall be brought in using the adjustable choke an

ENI Well Test Procedures Manual.pdf

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