ENI Well Test Procedures Manual

SPEO

ENI S.p.A.

ORGANIZING DEPARTMENT

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REF. N.

OF

E&P Divisio Division n

STAP

P

1

M

7130

Eni S.p.A. Exploration & Production division Drilling Completion & Production Optimization Well Operating Standards

WELL TEST TEST PROCEDUR PROCEDURES ES MANUAL

Date of validity: 01-01-2005

Revision/Re Revision/Reproductio productio n Record: Record:

2 1 0 Rev.No

01-12-2004 28-06-1999 Date

General Issue Reason for revision/reproduction

Technical Validation P repared

P. Magarini

Signature(s):

Date: 02-11-2004

C ontrolled

C Lanzetta

Signature(s):

Date: 02-11-2004

F Trilli

Signature(s):

Date: 02-11-2004

V erified

C Lanzetta

Signature(s):

Date: 30-11-2004

E ndorsed

F. Trilli

Signature(s):

Date: 30-11-2004

I ssued

A. Calderoni

Signature(s):

Date: 30-11-2004

A pproved

PAG.

Endorsement

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.

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REVISION STAP-P-1-M-7130

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INDEX 1.

2.

3.

4.

INTRODUCT INTRODUCTION ION ................................... ..................................................... .................................... .................................... .................................... ..................... ... 8 1.1

PURPOSE PURPOSE OF OF THE MANUAL ................................... ..................................................... .................................... ......................... ....... 8

1.2

IMPLEMENTATION IMPLEMENTATION ..................................... ....................................................... ..................................... ..................................... .................... .. 8

1.3

UPDATING, UPDATING, AMENDMENT, AMENDMENT, CONTROL & DEROGATION............................ DEROGATION................................... ....... 9

1.4

OBJECT OBJ ECTIVES........ IVES.......................... .................................... .................................... .................................... .................................... ........................ ...... 9

1.5

DRILLING INSTALL INSTALLATIONS ATIONS .................................. .................................................... .................................... ............................ .......... 10

TYPES OF PRODUCT PRODUCTION ION TEST .................................. ................................................... ................................... .................................. ................ 11 2.1

DRAWDOWN............................. DRAWDOWN............................................... ................................... .................................. ................................... ....................... ..... 11

2.2

MULTI-RATE DRAWDOWN ................................... .................................................... ................................... ............................. ........... 11

2.3

BUILD-UP .................................. .................................................... .................................... .................................... .................................... ..................... ... 11

2.4

DELIVERABILITY .................................. .................................................... .................................... .................................... ........................... ......... 11 2.4.1 FLOW-ON-FLOW......................... FLOW-ON-FLOW........................................... ................................... ................................... ...................... .... 12 2.4.2 ISOCHRONAL ISOCHRONAL ................................. ................................................... ................................... ................................... .................. 12 2.4.3 MODIFIED MODIFIED ISOCHRONAL ISOCHRONAL .................................. ................................................... .................................. ................. 12 2.4.4 RESERVOIR RESERVOIR L IMIT .................................... ...................................................... .................................... ......................... ....... 12

2.5

INTERFER INTERFERENCE ENCE ................................... ..................................................... .................................... ................................... ........................... .......... 13

2.6

INJECTIVITY............ INJECTIVITY.............................. .................................... .................................... .................................... .................................... ..................... ... 13

GENERAL GENERAL ROLES AND A ND RESPONSIBILITIES.................. RESPONSIBILITIES.................................... ..................................... ............................. .......... 14 3.1

RESPONSIBILITIES RESPONSIBILITIES AND DUTIES................... DUTIES..................................... ................................... .................................. ................. 14 3.1.1 COMPANY DRILLING DRILLING AND COMPLETION SUPERVISO SUPERVISOR R ................. ................. 14 3.1.2 COMPANY JUNIOR DRILLING AND COMPLETION SUPERVISO SUPERVISOR R ................................... ..................................................... .................................... .................................. ................ 15 3.1.3 COMPANY DRILLING ENGINEER ENGINEER .................................. .................................................... ..................... ... 15 3.1.4 COMPANY PRODUCT PRODUCTION ION TEST SUPERVISOR SUPERVISOR .............................. ................................. ... 15 3.1.5 COMPANY WELL SITE GEOLOGIST ................................... .................................................. ............... 15 3.1.6 CONTRACTOR CONTRACTOR TOOLPUSHE TOOLPUSHER R ................................... ..................................................... ........................ ...... 16 3.1.7 CONTRACT CONTRACT PRODUCTION PRODUCTION TEST CHIEF CHIEF OPERATOR ....................... ....................... 16 3.1.8 CONTRACTOR CONTRACTOR DOWNHOLE DOWNHOLE TOOL TOOL OPERATOR ............................... ............................... 16 3.1.9 WIRELINE SUPERVISO SUPERVISOR....................... R......................................... .................................... ............................ .......... 16 3.1.10 COMPANY STIMULATION ENGINEER ENGINEER.................. .................................... .............................. ............ 16 3.1.11 COMPANY RESERVOIR RESERVOIR ENGINEER....................................... ENGINEER................................................... ............ 16

3.2

RESPONSIBILITIES RESPONSIBILITIES AND DUTIES DUTIES ON SHORT DURATION DURATION TESTS ................... ................... 17 3.2.1 COMPANY DRILLING DRILLING AND COMPLETION SUPERVISO SUPERVISOR R ................. ................. 17 3.2.2 COMPANY JUNIOR DRILLING AND COMPLETION SUPERVISO SUPERVISOR R ................................... ..................................................... .................................... .................................. ................ 17 3.2.3 COMPANY WELL SITE GEOLOGIST ................................... .................................................. ............... 17 3.2.4 CONTRACTOR CONTRACTOR PERSONNE PERSONNEL L .................................... ..................................................... .......................... ......... 17

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

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CONTENTS.. CONTENTS.................... .................................... .................................... .................................... .................................... ................................. ............... 18

SAFETY BARRIER BA RRIERS S ................................... .................................................... ................................... .................................... .................................. ................ 19 5.1

WELL TEST FLUID......................................... FLUID.......................................................... ................................... ................................... ................... .. 19

5.2

MECHANICAL MECHANICAL B ARRIERS ARRIERS - ANNULUS ANNULUS SIDE .................................... ..................................................... ................. 20 5.2.1 SSTT ARRANGEMENT ARRANGEMENT .................................. .................................................... .................................... .................... .. 20 5.2.2 SAFETY VALVE ARRANGEMENT.................. ARRANGEMENT...................................... ..................................... ................. 22

5.3

MECHANICAL MECHANICAL BA RRIERS RRIERS - PRODUCTI PRODUCTION ON SIDE.......................................... SIDE............................................... ..... 23 5.3.1 TESTER TESTER VALVE ..................................... ....................................................... ..................................... ............................ ......... 23 5.3.2 TUBING RETRIE RETRIEVABL VABL E SAFETY VALVE (TRSV) OR (SSSV) (SSSV) ........... 24 5.3.3 CASING OVERPRES OVERPRESSURE SURE VALVE .................................... ..................................................... ................. 24

TEST STRING STRING EQUIPMENT EQUIPMENT ................................... ..................................................... .................................... ..................................... ..................... .. 25 6.1

GENERAL GENERAL .................................. .................................................... .................................... .................................... .................................... ..................... ... 25

6.2

COMMON COMMON TEST TOOLS DESCRIPTI DESCRIPTION ON .................................... ...................................................... ......................... ....... 30 6.2.1 BEVELLED MULE SHOE SHOE ................................... .................................................... .................................. ................. 30 6.2.2 PERFORATED PERFORATED JOINT/PORTED JOINT/PORTED SUB ................................... .................................................. ............... 30 6.2.3 GAUGE CASE (BUNDLE CARRIER) CARRIER) ................................... ................................................... ................ 30 6.2.4 PIPE TESTE TESTER R VALVE ..................................... ........................................................ ..................................... .................. 30 6.2.5 RETRIEVABLE RETRIEVABLE TEST PACKER .................................... ....................................................... ....................... .... 30 6.2.6 CIRCULATING CIRCULATING VALVE (BYPASS (BYPASS VALVE) ................................. .......................................... ......... 30 6.2.7 SAFETY JOINT.............................. JOINT................................................ .................................... .................................... .................... 31 6.2.8 HYDRAULIC HYDRAULIC JAR .................................. ..................................................... ..................................... ............................ .......... 31 6.2.9 DOWNHOLE DOWNHOLE TESTER TESTER VALVE .................................... ....................................................... ......................... ...... 31 6.2.10 SINGLE OPERATION REVERSIN REVERSING G SUB................................. SUB............................................. ............ 31 6.2.11 MULTIPLE OPERATION OPERATION CIRCULATING CIRCULATING VALVE VALVE ............................... ................................. 31 6.2.12 DRILL COLL COLL AR ................................... ..................................................... .................................... ............................... ............. 31 6.2.13 SLIP JOINT............................... JOINT................................................. ................................... ................................... ......................... ....... 32 6.2.14 CROSSOVER CROSSOVERS S .................................... ...................................................... .................................... ............................... ............. 32

6.3

HIGH PRESSUR PRESSURE E WELLS .................................. ................................................... ................................... ................................ .............. 32

6.4

SUB-SEA TEST TOOLS TOOLS USED ON SEMI-SU SEMI-SUBMERSIBLES BMERSIBLES ............................... ............................... 32 6.4.1 SUB-SEA TEST TREE........................................ TREE.......................................................... .................................. ................ 32 6.4.2 FLUTED HANGER............................ HANGER............................................. ................................... ................................... ................. 33 6.4.3 SLICK JOINT (POLISHED (POLISHED JOINT) ................................... ..................................................... .................... .. 33 6.4.4 SSTT VALVE ASSEMBLY .................................... ...................................................... ................................ .............. 34 6.4.5 LATCH ASSEMBLY.................... ASSEMBLY...................................... .................................... ..................................... ...................... ... 34 6.4.6 BLEED BL EED OFF VALVE AND RETAINER RETAINER VALVE ..................................... ..................................... 34

6.5

FISHING FISHING TOOL................. TOOL ................................... .................................... .................................... .................................... .............................. ............ 35

6.6

LUBRICATOR VAL VE................. VE ................................... ................................... .................................. ................................... ..................... ... 35

6.7

TOOLS FOR DYNAMIC POSITIONING POSITIONING RIG......................... RIG........................................... ................................ .............. 36 6.7.1 SHEAR JOINT .................................. .................................................... .................................... .................................. ................ 36 6.7.2 ELECTRO-HYD ELECTRO-HYDRAULIC RAULIC CONTROL CONTROL SYSTEM ............................... ..................................... ...... 36 6.7.3 REAL-TIME SURFACE READ-OUT OF SUB SEA PRESSURE AND TEMPERATURE............ TEMPERATURE... .................. .................. .................. .................. .................. .................. .................. ......... 37

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

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TEST PACKAGE PACKA GE ................................... ..................................................... ..................................... ..................................... .......................... ........ 38 7.1.1 FLOWHEAD OR SURFACE SURFACE TEST TREE TREE .................................... ............................................. ......... 38 7.1.2 FLEXIBLE FL OW LINES AND PIPING.................... PIPING...................................... ............................. ........... 38 7.1.3 DATA/INJECTION HEADER........................ HEADER.......................................... ..................................... ....................... .... 39 7.1.4 CHOKE MANIFOLD....................... MANIFOLD......................................... .................................... .................................... .................... 39 7.1.5 STEAM GENERATOR AND HEAT EXCHANGER / INDIRECT HEATER........................ HEATER.......................................... .................................... ................................... ................................... .................... 40 7.1.6 SEPARATOR................................................... SEPARATOR................................. .................................... .................................... .................... 41 7.1.7 DATA ACQUISITION ACQUISITION SYSTEM............................. SYSTEM............................................... ................................ .............. 43 7.1.8 GAUGE/SURGE GAUGE/SURGE TANKS .................................... ...................................................... .................................. ................ 43 7.1.9 TRANSFER TRANSFER PUMP............................ PUMP.............................................. .................................... .................................. ................ 44 7.1.10 DIVERTER DIVERTER MANIFOLDS ................................... ..................................................... ................................... ................. 44 7.1.11 BURNERS.................... BURNERS...................................... ................................... ................................... ................................... .................... ... 44 7.1.12 BOOMS........................................... BOOMS......................... .................................... .................................... ................................... ................... 45 7.1.13 GAS TORCHES TORCHES ................................. .................................................. ................................... .................................. ................ 45 7.1.14 STORAGE TANKS TANKS FOR LIGHT AND HEAVY OIL OIL ............................... ............................... 45 7.1.15 TANKER TRUCK TRUCK CHARGING SYSTEM SYSTEM ................................. .............................................. ............. 46

7.2

EMERGENC EMERGENCY Y SHUT DOWN SYSTEM SYSTEM ................................. ................................................. ................................ ................ 50

7.3

ACCESSORY EQUIPMENT................... EQUIPMENT.......... .................. ................... ................... .................. .................. ................... ................. ....... 50 7.3.1 CHEMICAL CHEMICAL INJECTION PUMP .................................. .................................................... .......................... ........ 50 7.3.2 SAND DETECTORS DETECTORS .................................... ....................................................... ..................................... ...................... .... 50 7.3.3 CROSSOVER CROSSOVERS S .................................... ...................................................... .................................... ............................... ............. 51

7.4

RIG EQUIPMENT........... EQUIPMENT............................. .................................... .................................... .................................... ................................. ............... 51

7.5

DATA GATHERING GATHERING INSTRUME INSTRUMENTATION NTATION................. .................................... ..................................... ....................... ..... 51 7.5.1 OFFSHORE LABORATORY AND INSTRUMENT MANIFOLD EQUIPMENT EQUIPMENT .................................. .................................................... .................................... .................................... .................... 51 7.5.2 SEPARATOR................................................... SEPARATOR................................. .................................... .................................... .................... 52 7.5.3 SURGE SURGE OR METERING TANK ................................... ..................................................... .......................... ........ 52 7.5.4 STEAM HEATER .................................... ...................................................... .................................... ............................ .......... 52

BOTTOM HOLE DATA ACQUISITION ACQUISITION .................................... ...................................................... ..................................... ...................... ... 53 8.1

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EQUIPMENT EQUIPMENT DESCRIPT DESCRIPTION ION................ .................................. .................................... .................................... ............................ .......... 53 8.1.1 WIRELINE UNIT.................. UNIT.................................... .................................... .................................... .............................. ............ 53 8.1.2 ADAPTER ADA PTER FLANGE.......... FLA NGE................... .................. .................. .................. .................. .................. .................. .............. ..... 53 8.1.3 BOP .................................... ...................................................... .................................... .................................... .............................. ............ 53 8.1.4 TOOL TRAP....................................... TRAP........................................................ ................................... .................................. ................ 53 8.1.5 LUBRICATOR RISERS.................... RISERS..................................... .................................. .................................. ................... .. 54 8.1.6 FLOW TUBE TYPE STUFFING BOX................................... BOX.................................................... ................. 54 8.1.7 SAFETY CHECK CHECK VALVE VAL VE................. .................................... ..................................... .................................. ................ 54 8.1.8 INJECTION NIPPLE NIPPLE .................................. .................................................... .................................... ......................... ....... 54 8.1.9 TOOL CATCHER CATCHER .................................... ...................................................... .................................... ............................ .......... 55 8.1.10 DOWN HOLE PRESSUR PRESSURE E AND TEMPERATURE TEMPERATURE GAUGES ............... 55 8.1.10.1 GAUGE TYPES................ TYPES.................................. ................................... ................................. ................ 55 8.1.10.2 GAUGE INSTALLATIO INSTALLATION N .................................... ..................................................... ................. 56 8.1.11 PRODUCTION PRODUCTION LOGGING TOOL ................................. .................................................. ......................... ........ 58 8.1.12 DOWN HOLE SAMPLING TOOL........................................ TOOL.......................................................... .................. 58

PERFORATING PERFORATING SYSTEMS........................... SYSTEMS............................................ ................................... ................................... ................................ ............... 59 9.1

TUBING CONVEYED CONVEYED PERFORATING PERFORATING .................................. ................................................... ............................... .............. 59

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WIRELINE WIRELINE CONVEYED CONVEYED PERFORATING PERFORATING ................................. .................................................. ............................ ........... 59

9.3

PROCEDU PROCEDURES RES FOR PERFORATING PERFORATING................ .................................. .................................... ................................ .............. 59

PREPARING PREPARING THE WELL FOR TESTING........................ TESTING.......................................... .................................... ............................... ............. 61 10.1

PREPARATORY PREPARATORY OPERATIONS FOR TESTING TESTING.................. .................................... ................................ .............. 61 10.1.1 GUIDELINES GUIDELINES FOR TESTI TESTING NG 7INS LINER LAP ................................... ................................... 61 5 10.1.2 GUIDELINES FOR TESTING 9 /8INS LINER LAP ................................ ................................ 61 10.1.3 GENERAL GENERAL TECHNICAL TECHNICAL PREPARATION PREPARATIONS S ................................. .......................................... ......... 61

10.2

BRINE PREPARATION .................................... ...................................................... .................................... .................................. ................ 62 10.2.1 ONSHORE ONSHORE PREPARATION OF B RINE........................... RINE............................................. ..................... ... 62 10.2.2 TRANSPORTATION TRANSPORTATION AND TRANSFER OF FLUIDS............................. FLUIDS............................. 62 10.2.3 RECOMMEND RECOMMENDATIONS ATIONS ................................... ..................................................... .................................... .................... .. 62 10.2.4 RIG SITE PREPARATIONS................................................. PREPARATIONS.................................................................. ................. 63 10.2.5 WELL AND A ND SURFACE SURFACE SYSTE SYSTEM M DISPLACEMENT DISPLACEMENT TO TO BRINE ........... 64 10.2.6 DISPLACEMENT DISPLACEMENT PROCEDUR PROCEDURE.......................... E........................................... ................................. ................ 65 10.2.7 ON-LOCATION FILTRATION FILTRATION AND MAINTENANCE OF BRINE.......... BRINE.......... 65

10.3

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

10.4

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

10.5

LANDING STRING STRING SPACE-OUT........................... SPACE-OUT............................................. ..................................... ............................. .......... 70 10.5.1 LANDING STRING SPACE-OUT SPACE-OUT PROCE PROCEDUR DURE E .............................. .................................. .... 73

10.6

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

10.7

PRE TEST EQUIPMENT EQUIPMENT CHECKS.................................................... CHECKS....................................................................... ................... 75

10.8

PRESSURE PRESSURE TESTING EQUIPMENT EQUIPMENT ..................................... ....................................................... ............................... ............. 76 10.8.1 SURFACE TEST TREE........................... TREE............................................. .................................... ............................ .......... 77

TEST STRING STRING INSTALLA TION .................................... ....................................................... ..................................... ................................ .............. 80 11.1

GENERAL GENERAL .................................. .................................................... .................................... .................................... .................................... ..................... ... 80

11.2

TUBING HANDLING........................... HANDLING............................................. .................................... ..................................... .............................. ........... 81

11.3

RUNNING RUNNING AND PULLING ................................. .................................................. ................................... .................................. ................ 81

11.4

PACKER A ND TEST STRING STRING RUNNING RUNNING PROCEDURE PROCEDURE ............................... ..................................... ...... 82

11.5

RUNNING RUNNING THE TEST TEST STRING STRING WITH A RETRIEVABLE PA CKER ...................... ...................... 82

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

WELL TEST PROCED PROCEDURES URES .................................. .................................................... .................................... .................................... ..................... ... 85 12.1

ANNULUS CONTROL AND PRESSURE MONITORING ................. ........ .................. .................. ........... .. 85

12.2

TEST EXECUTION EXECUTION ................................... ..................................................... .................................... ..................................... ........................ ..... 85

WELL TEST DATA REQUIREMENT REQUIREMENTS S .................................. ................................................... ................................... .......................... ........ 87 13.1

PRE-TEST PRE-TEST PREPARATION........................ PREPARATION......................................... ................................... .................................... ....................... ..... 87

13.2

METERING METERING REQUIREM REQUIREMENTS............................. ENTS............................................... .................................... ............................... ............. 87

13.3

DATA REPORTING REPORTING .................................... ...................................................... .................................... .................................... ...................... .... 88

13.4

WELL TEST DATA ACQUSITION ACQUSITION PROCEDUR PROCEDURE............... E................................ .................................. ................. 89

SAMPLING.......................................... SAMPLING........................ .................................... ................................... ................................... .................................... ........................ ...... 90 14.1

CONDITIONIN CONDITIONING G THE WELL ................................... ..................................................... .................................... ............................ .......... 90

14.2

DOWNHOLE DOWNHOLE SAMPLING ................................. ................................................... .................................... .................................. ................ 90

14.3

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

14.4

SURFACE SURFACE OIL SAMPLING .................................... ...................................................... .................................... ............................ .......... 94

14.5

SAMPLE TRANSFER AND HANDLING............................................... HANDLING............................................................... ................ 95

14.6

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

15.

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

16.

HYDRATE PREVENTIO PREVENTION N ................................... ..................................................... .................................... .................................... ......................... ....... 100

17.

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

18.

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

19.

WELL KIL LING ABANDONME AB ANDONMENT NT .................................. ................................................... ................................... ................................ .............. 103 19.1

WELL KILLING................................ KIL LING.................................................. ................................... ................................... .................................. ................ 103

19.2

WELL KIL LING ABANDONMENT..................................... ABANDONMENT...................................................... ................................... .................. 103

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

APPENDIX A - REPORT FORMS .................. ......... .................. .................. .................. .................. .................. .................. .................. .................. ............ ... 105 A.1.

DAILY REPORT (ARPO 02) ................................... ..................................................... .................................... ............................ .......... 105

A.2.

WELL TEST REPORT REPORT “ GENERAL GENERAL DATA” (ARPO 10/A)............................... 10/A).................................... ..... 106

A.3.

WELL TEST REPORT REPORT “ DST DATA” (ARPO 10/B) 10/B) ................................... .............................................. ........... 107

A.4.

WELL TEST REPORT REPORT “ RECORD RECORD DATA” (ARPO 10/C)...................... 10/C)...................................... ................ 108

A.5.

WASTE REPORT (ARPO 6) ................................... .................................................... ................................... ............................. ........... 109

A.6.

WELL PROBL EM REPORT REPORT (ARPO 13) 13) .................................. .................................................... ............................. ........... 110

A.7.

MALFUNCTION & FAILURE REPORT REPORT (FB-1) (FB-1) .................................... ..................................................... ................. 111

A.8.

CONTRACTOR CONTRACTOR EVAL UATION (FB -2)........................................ -2).......................................................... .......................... ........ 112

APPENDIX B – ABBREVI AB BREVIATIONS. ATIONS........... ................... .................. .................. ................... ................... .................. .................. ................... ................. ....... 113 APPENDIX C – BIB LIOGRAPHY LIOGRA PHY........ ................. .................. .................. .................. .................. .................. .................. .................. .................. .............. ..... 115

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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 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 t ypes 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 MANUA L 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.

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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 page 105. and Reporting Forms’ from well operations refer to Appendix A, page

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.

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1.5

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DRILLING INSTALL ATIONS 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

SemiSubmersible

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.

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2.

TYPES OF PRODUCTION TEST

2.1

DRAWDOWN

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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 cleanup. 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 well’s Inflow Performance Relation, R elation, 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.

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There are three types of deliverability test: • • •

2.4.1

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

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.

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2.5

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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 formation’s 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 fa ll off is measured. The analysis ana lysis of this test is similar to a pressure build-up, but is complicated by the cold water bank.

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3.

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GENERAL GENERAL ROLES AND RESPONSIBIL RESPONSIBILITIES ITIES Well testing is potentially hazardous and requires good planning and co-operation/coordination 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

RESPONSIBIL ITIES 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 during the Well test: • •

3.1.1

Company Stimulation Engineer. Company Reservoir Engineer.

COMPANY DRILLING AND COMPLETION SUPERVISOR 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.

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3.1.2

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COMPANY JUNIOR DRILLING AND COMPLETION SUPERVISOR 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.

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3.1.6

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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 OPERATO R

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 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 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.

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3.2

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RESPONSIBIL ITIES 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 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 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 contractor’s Personnel (Toolpusher, Production Chief Operator, Downhole Tool Operator), refer to long test responsibilities.

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4.

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WELL TESTING TESTING PROGRAMME 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.

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5.

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SAFETY B ARRIERS 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.

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5.2

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MECHANICAL BARRIERS BA RRIERS - 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 t ypical 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 cutt ing the SSTT SSTT assembly unless a safety shear joint is installed in the SSTT across the shear ram position.

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Figur e 5-15-1- SSTT SSTT Arr angement

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5.2.2

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SAFETY VAL VE 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).

13 3/8” or 11” 5000 - 10000 - 15000 psi W.P. B OP STACKS

TUBING

PIPE RAMS

SHEAR RAMS

5” SLICK JOINT 5” PIPE RAMS

SPACER SPOOL 0.6 to 1.0 metre long 5” SLICK JOINT

5” SLICK JOINT

TUBING SPOOL

SPACER SPOOL 0.6 to 1.0 metre long 8” O.D. SAFETY VALVE

8” O.D. SAFETY VALVE

5” SLICK JOINT

5” SLICK JOINT

TUBING SPOOL 8” O.D. SAFETY VALVE 8” O.D. SAFETY VALVE

PIPE RAMS

5.25” O.D. SAFETY VALVE

SPACER SPOOL minimum 1 metre long for fixed platforms

7” CASING

9 5/8” CASING TUBING SPOOL

TUBING SPOOL

TUBING SPOOL

7” CASING

7” CASING

7” CASING

TUBING

ALL WELLS WITH 9 5/8” PROD. CASING

JACK UP, FIXED PLATFORMS and ON-SHORE RIGS WITH 7” PRODUCTION CASING

Figur e 5-2 5-2 - Safety Safety Valve Arrang ement

ALL WELLS WITH 7” PROD. CASING

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5.3

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MECHANICAL MECHANICA L B ARRIERS - 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-submersibl Semi-submersibl e string - Latched • • •

Tester valve SSTT Surface test tree.

Semi-submersibl Semi-submersibl e string - Unlatched Unlatched • •

Tester valve SSTT.

Jack-Up • • •

Tester valve Safety valve Surface test tree.

Land well • • •

5.3.1

Tester valve Safety valve Surface test tree.

TESTER VAL VE

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.

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5.3.2

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TUBING RETRIEVAB RETRIEVAB LE SAFETY VAL VE (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 OVERPRESSURE VAL VE

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.

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6.

TEST STRING EQUIPMENT

6.1

GENERAL

0 1

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.

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IDENTIFICATION CODE

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26

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115



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Figur e 6-1 6-1 - Typical Jack Up/Land Test Strin g - Packer Packer Wit h TCP Guns On Packer

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27

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115



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

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IDENTIFICATION CODE

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28

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115



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Figur e 6-3 6-3 - Typic al Jack Up/Land Test Stri ng - Retri Retri evable Packer Packer

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IDENTIFICATION CODE

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29

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115



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Figur e 6-4 6-4 - Typical Semi-Submersi ble Test Stri ng - Retri Retri evable Packer Packer

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IDENTIFICATION CODE

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30

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115



6.2

COMMON TEST TOOLS DESCRIPTION

6.2.1

BEVELL ED MULE SHOE

0 1

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 PERFORAT ED JOINT/PORTED JOINT/PORT ED 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 VAL VE

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 PACK ER

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

CIRCULA CIRCULA TING VAL VE (BYPA SS VAL VE)

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.

SPEO

IDENTIFICATION CODE

PAG

31

OF

115



6.2.7

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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 JA R

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 DOWNHOLE TESTER VAL VE

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 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 CIRCULA CIRCULA TING VAL VE

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 COLL AR

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.

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IDENTIFICATION CODE

PAG

32

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115



6.2.13

0 1

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 WELL S 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 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 in the wear wear bushing of the sub sea well head, Valve assembly to be located below the lower 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

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IDENTIFICATION CODE

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33

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115



0 1

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: • • •

6.4.3

Be equipped with a locking device 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 complete test string string to the subsea well head.

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 will normally be closed 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)

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34

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6.4.4

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SSTT VALVE ASSEMBL Y

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 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 suff icient).

External Collapse Pressure rating: 690 bar (10.000 psi). 6.4.5

LATCH ASSEMBL Y

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: •

• • •

6.4.6

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. 4°angle, A mechanical or pressure actuated, preferably 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 in the hole.

BL EED OFF VAL VE AND RETAINER VAL VE

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.

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IDENTIFICATION CODE

PAG

35

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115



0 1

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: •

•

•

• • •

6.5

Be fail safe safe closed and fail safe cut 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 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 llatch atch nose nose prior to relatching, or relatch with closed RV and BOV open (to avoid compressing fluids when latching. BOV to be closed after latching.).

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

• •

6.6

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.

LUBRICATOR LUB RICATOR VALVE VAL VE 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 remain o pen and and serve as back up f or t he upper one.

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IDENTIFICATION CODE

PAG

36

OF

115



6.7

0 1

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: • •

6.7.2

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.

ELECTRO-HYDRAULIC ELECTRO-HYDRAULIC CONTROL CONTROL SYSTEM

The Hydraulic Hydraulic deep 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 ESD 2

Close SSTT valves. 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 readout of the sub sea accumulator pressure.

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37

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

• •

Clamps to support the umbilical to the landing string, 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 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.

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IDENTIFICATION CODE

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38

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115



7.

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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 PACK AGE

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 cement pump or the rig manifold. Flow Wing Valve on the flow wing 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

FLEXIBL E 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.

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IDENTIFICATION CODE

PAG

39

OF

115



0 1

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. g round. Note:

7.1.3

Ensure that the flexible flow lines are suitable for use with corro sive brines.

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 ad justable choke and this t his choke should never be fully fu lly closed against well flow.

SPEO

IDENTIFICATION CODE

PAG

40

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115



0 1

The flow should then be redirected to the appropriately sized fixed choke for stable flow conditions. The testing contractor should ensure that a full range of fixed chokes sizes are available in good condition. Due to the torturous path of the fluids through the choke, flow targets are positioned where the flow velocities are high and impinge on the bends. Ensure that these have been checked during the previous refurbishment to confirm they are still within specification. Downstream choke manifold lines will preferably not be less than 3” OD. 7.1.5

STEAM GENERATOR AND HEAT EXCHANGER / INDIRECT INDIRECT HEATER

Heat is required from a steam generator and a heat exchanger or from an indirect heater to: • • • •

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

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/°F The heat needed to raise oil by 1°F can be estimated from: 8.7 x Oil Flow (bbls/day) (b bls/day) x Oil Density (gms/cm3), BTU/hr/°F. The heat exchanger is set up with an external heating source, which should preferably be steam from a steam generator. The heat exchanger must be equipped with the following features: • • • • • •

•

A minimum of two two coils with interconnection by means of a choke box either enclosed in the vessel or by an external connection. Isolation valves valves to enable bleeding off the coils coils for the purpose of of changing the choke. A temperature control system regulating the external heating source based on the required well fluid discharge temperature. Pressure and temperature sensors both upstream and downstream of the choke. By-pass line with double valve arrangement together with isolation valves on inlet and outlet of coils. Two independent pressure relief devices protecting the steam vessel against rupture. Each individual device shall be capable of discharging the maximum well production rate in case of coil or tube rupture. Gas detection system for the steam-condensate discharged from the heater. This system shall be connected to an automatic shut-off device to prevent gas-laden condensate returning to the supplying boiler.

SPEO

IDENTIFICATION CODE

PAG

41

OF

115



•

•

0 1

If the secondary coil has a lower pressure rating than the primary primary coil or the down stream valve, the coil shall be equipped with a pressure relief device. A non-return valve for the steam inlet.

The indirect heater is set up with an internal heating source, consisting of a combustion chamber, in contact with but hydraulically separated from the vessel. The indirect heater must be equipped with the following features: • • • • • • • •

• •

A minimum of two two coils with interconnection by means of a choke box either enclosed in the vessel or by an external connection. Isolation valves valves to enable bleeding off the coils coils for the purpose of of changing the choke. The choke box shall be manufactured to receive both fixed choke and adjustable choke. The adjustable choke assembly shall have pressure capabilities for the purpose of testing high pressure coil tubing. A temperature control system regulating the internal heating source Pressure and temperature sensors both upstream and downstream of the choke. By-pass line with double valve arrangement together with isolation valves on inlet and outlet of coils. The internal heating source shall enable the burners to be fed with with diesel or gas coming from the well. The pilot light must be supplied by an independent source. The starter for both both the pilot light and the burners shall be electric. electric. The electric circuit shall be explosion proof. Shall be equipped with gas detector and combustion control device, in order to prevent the starting of burners in presence of gas inside the combustion chamber. Shall be provided by a fan in order to flow the combustion chamber.

On high flow rate wells, a 4 inches bore steam heater should be used to reduce high back pressures. Always use the largest steam heater and associated generator that t hat space or deck loading will allow as the extra output capacity will be a contingency for any serious problem which may arise. The rig steam generator will usually not have the sufficient output and therefore a diesel-fired steam generator in conjunction with the steam heat exchanger should be provided by the surface test contractor. 7.1.6

SEPARATOR

The test separator is required to: • • • •

Separate the well flow into three phases: water, oil and gas Measure the flow rate of each phase, at known conditions Measure the shrinkage factor Sample each phase at known temperature and pressure.

SPEO

IDENTIFICATION CODE

PAG

42

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115



0 1

The following features shall be included: • •

• • • • • •

•

• •

Pressure control system. Oil and water level level control system system with with liquid level glasses for water/oil and oil/gas interface; in oil well test, the oil level should be kept as low as possible. Position for both manual data acquisition and computerized data acquisition on vessel, gas line, oil line and water line. Oil, gas and water metering facilities to cover the full flow capacity range of the separator. Changing of the gas orifice shall be possible without interrupting the separation process. Injection point for chemicals at inlet manifold. Manhole so that internal visual inspection and cleaning can be performed. The inlet manifold shall allow the upstream fluid to be bypassed to either the oil, gas or water discharge line. The manifold shall be equipped with sufficient valves to isolate the vessel itself. Two independent pressure relief devices protecting the vessel against rupture. Each individual device shall be capable of discharging the design production rate in case of overpressure. The first intervention relief valve shall discharge in the outlet connected to the low pressure gas line. The second intervention relief valve shall discharge to the atmosphere. Drain line. The flow control instruments shall be operated by either air or gas.

The separator pressure has to be kept as low as the well performance allows but in any case lower than 50% of the upstream pressure (to maintain critical conditions). The standard offshore separator is a horizontal three phase, 1,440 psi working pressure unit. This can handle up to 60mmscf/day of dry gas or up to 10,000 bopd of oil and associated gas at its working pressure. Other types of separators, 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 data the gas flow rate is calculated. The liquid flow rates are measured by positive displacement or vortex meters. The oil shrinkage factor is physically measured by allowing a known volume of oil, under controlled conditions, to de-pressurise and cool to ambient conditions. The shrinkage factor is the ambient volume divided by the original volume. However, the small volume of the shrinkage meter means that this is not an accurate measurement. The oil flow rate is corrected for any volume taken up by gas, water, sand or sediment. This volume is calculated by multiplying the combined volume by the BS&W measurement and the tank/meter factor. Oil meters are calibrated onshore but it is also necessary to divert the oil flow to a gauge tank for a short period to obtain a combined shrinkage/meter factor as the meter calibration is subject to discrepancies arising from varying oil gravity and viscosity. The separator relief system is calibrated onshore and should never be function tested offshore; hence the separator should only be tested to 90% of the relief valve setting.

SPEO

IDENTIFICATION CODE

PAG

43

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115



0 1

It is important that the separator bypass valves, diverter valves for the vent lines leading from the separator relief valve, rupture disc or back-up relief valve, are checked for ease of operation. 7.1.7

DATA ACQUISITION SYSTEM

It is now common custom to use computerised Data Acquisition Systems (DAS) during offshore well tests. However, it is essential that manual readings are still recorded separately for correlation of results and as a contingency in the event of problems occurring to the DAS. These systems can collect, store and provide plots of: • • •

Surface data Downhole data from gauges Memory gauge data

The main advantage of the DAS is that real time plots can be displayed at the well site for troubleshooting. Another advantage is that all the surface (and possibly downhole) data is collected in one system and can be supplied on a floppy disk for the operator to analyse and subsequently prepare well reports. 7.1.8

GAUGE/SURGE GAUGE/SURGE TANK S

A gauge tank is an a n atmospheric vessel whereas a surge tank is usually rated to 50psi WP WP and is vented to the flare. A surge tank is essential for safe working if H2S production is anticipated. Consequently, surge tanks should always be used on wildcat wells and gauge tanks used only in low risk situations. Tanks are used for checking the oil meter/shrinkage factors and for measuring volumes at rates that are too low for accurate flow meter measurement. They usually have a capacity of one hundred barrels and some have twin compartments so that one compartment can be filled while the other is pumped to the burner/storage tank via the transfer pump. Gauge tanks shall also include the following features: • • • •

A double compartment, non pressurized vessel A gas vent line with adequate dimensions Inlet and outlet manifolds Sight glasses, calibration stripes and safety relief valve.

Surge tanks shall also include the following features: • • • • •

The tank shall be suitable for two phase gas/oil separation. Pressure control system. Position for both manual data acquisition and computerized data acquisition on vessel, gas line, oil line. Level glasses for oil/gas interface. The inlet manifold shall allow the upstream fluid to be bypassed to either oil and gas discharge line. The manifold shall be equipped with sufficient valves to isolate the vessel itself.

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44

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• •

• • •

0 1

Oil and gas metering facilities to cover cover the full flow capacity range of the separator. An independent pressure relief device protecting the vessel against rupture. The device shall be capable of discharging the liquid production rate with associated gas in case of over pressure due to liquid overfill or gas blow-by. Manhole so that internal visual inspection and cleaning can be performed Drain line. The flow control instruments shall be operated with either air or gas.

Tanks can also be used for collecting large atmospheric volumes of crude for analysis or acting as a secondary separator for crudes that require longer separation times. Some tanks can have special features such as steam heating elements for heavy/viscous oil production tests, etc. 7.1.9

TRANSFER PUMP

A transfer pump shall sha ll be installed to provide sufficient pressure at the t he expected production rate to enable the discharging of crude oil to the burners or to the stock tanks when operating the surge tank as second stage separator. The following features shall be included: • •

7.1.10

Proper safety safety devices devices and a remote control panel when used to discharge to the tanker trucks. Operated by an explosion proof electric motor.

DIVERTER MANIFOL DS

Oil and gas flowlines must have diverter manifolds for directing flow from the test area to the burner / storage tanks. These manifolds shall be provided with hand operated valves to divert the flow from the separator, to and from the tanks. Moreover, they shall have welded pipe hammer connections with a sealing ring and a pressure rating compatible with the application. 7.1.11

BURNERS

Burners have to provide combustion of crude oil/gas with minimum fall-out or pollution to the surrounding ground or sea. Most recent designs of burners are promoted as ‘green’ or ‘clean’ type burners. This is indicative of their being less polluting to the environment by having superior burning technology. Although still not ‘ideal’, their performance has greatly improved in comparison with previous models. The burner has a ring of atomisers or nozzles which break up the flow to provide a more complete combustion. This is assisted by pumping air into the flow stream. Oil and compressed air inlet lines on the burner shall be equipped with non-return valves if there is any remote possibility that the two media could enter the supply line of the other and develop a combustible mixture. Rig air must not be used for this purpose as there is a risk of hydrocarbons leaking back into the rig air system. Two portable air compressors, one as back-up, are required and they should be suitably fitted with check valves.

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It is recommended that the air compressors are manifolded together to provide a continuous supply of air in the event of one compressor failuring and that they are equipped with automatic shutdown device in case of exposure to hydrocarbon gases. Green style burners are very heavy users of air and consideration must be given for deck space for additional air compressors. Water must be pumped to the burner head and forms a heat shield in the form of a spray around the flare to protect the installation from excessive heat. It also aids combustion and cools the burner head. Water must also be sprayed on the rig to keep it cool and special attention must be given to the lifeboats. It is now normal for a rig to have a permanent spray system 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 oilbased mud. They can also better handle the clean-up flow. Alternatively, diesel can be spiked in at the oil manifold using the cement pumps to assist the combustion but, if there is only partial combustion, unburnt residue can cause pollution. Oil slicks may ignite and become a hazard to the rig. If a heavy/viscous oil production test is planned, sufficient gauge tanks should be on hand to conduct a test without flaring the oil. 7.1.12

BOOMS

Booms are used in offshore applications to move burners as far away as possible from the platform and to carry oil, gas, air and water pipes to the burners. Burner heads are mounted at the end of the booms which are usually installed on opposite sides of the rig to take the maximum advantage of changes in wind direction, i.e. to keep at least one burner heading downwind. The length of the boom shall be accepted by the rig contractor. 7.1.13

GAS TORCHES

The gas torch on the line from the three phase separator shall be capable to burn the designed production rate without overboosting. The gas torch on the line from the surge tank shall be capable to burn the designed production rate with air fan overboosting. The gas torch on the line from the storage tanks shall be capable to burn the drained gas rate with air fan overboosting. All gas torches must be provided with a pilot light supplied by an independent inde pendent source. 7.1.14

STORAGE TANK S FOR LIGHT AND HEAVY OIL

Tanks are used to store light and heavy oil coming from the test area. Tanks for both types of oils shall be equipped with inlet and outlet manifolds, sight glasses, calibration stripes and safety relief valves.

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46

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0 1

Storage tanks for light oil shall include the following additional features: • • •

a single compartment, pressurized vessel a gas vent line connected to a condensate recovering device an inert gas system fed by an external inert gas source. This system is used to fill the tank with inert gas before the start of the flowing period and at the moment of depletion in order to prevent any contact between the formation fluid and the air.

Storage tanks for heavy oil shall include the following additional features: • • •

7.1.15

a single compartment, non pressurized vessel a gas vent line connected to a condensate recovering device a heating coil, fed by an external heater. The coil coil is used to maintain the internal temperature of the tank above the pour point of the produced oil; the heating circuit shall have inlet and outlet manifolds outside the tank.

TANKER TRUCK CHARGING SYSTEM

This system shall include: • • • •

a filling sleeve built in anti-spark material a suitable device to connect electrically the tanker truck to the ground an appropriate fire extinguisher a dedicated transfer pump.

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47

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115



Vent

0 1

Inert Gas

Inert Gas

Stock Tanks for Light Oil

Vent

Inert Gas Vent

Inert Gas Transfer pump

to Tanker Truck Charging System

Steam Heat Exchanger

Figure 7-1 7-1 – Light Oil Surface Equipment Equipment Layout

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0 1

Figure 7-2 – Heavy Oil Surface Equipment Layout

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0 1

to Burner

Gas line

Water

to Burner

Steam Heat Exchanger

Figure 7-3 – Gas Surface Equipment Layout

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IDENTIFICATION CODE

PAG

50

OF

115



7.2

0 1

EMERGENCY SHUT DOWN SYSTEM The Emergency Shut Down (ESD) system is the primary safety system in the event of an uncontrolled escape of hydrocarbons at surface. The system consists of a hydraulically or pneumatically operated flowhead flow wing valve, control panel and a number of remotely air operated pilot valves. When a pilot or the main valve in the panel is actuated, it causes a loss of air pressure in turn dropping out the main hydraulic valve which releases the pressure from the flowhead ESD valve actuator. The push button operated pilot valves are strategically placed at designated accessible areas where the test crew and/or rig crew can actuate them by pushing the button when they observe an emergency situation. Other pilots may be high or low pressure actuated pilots installed 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 system is 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, defoamers, de-emulsifiers and wax inhibitors. The chemicals are injected by an air driven chemical injection pump at, either the data/injection header, flowhead or at the SSTT/subsurface safety valve. The pump shall have full redundancy and equipped with filtration device. Chemicals must be supplied with toxicological and safety data sheets as per regulations. 7.3.2

SAND DETECTORS

Sonic type sand detectors can be installed at the data/injection header upstream of the choke if sand production is expected to cause erosion. These devices operate by detecting the impingement of sand on a probe inserted into the flowstream. The accuracy is reasonable in single-phase gas flow but less consistent in multi-phase flow. The simplest approach to sand detection is to take frequent BS&W samples at the data/injection manifold to monitor for sand production. If the flow rates are low, samples taken from the high side of flowline might incorrectly show little or no sand; therefore a suitable sample point must also be available on the low side of the manifold. Samples should then be collected from both points. The problem with this method is determining if the sand is causing erosion or not. An erosion coupon or probe can also be installed on the manifold which will indicate 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 the sand before it reaches the higher velocity flow rates at the choke. Control of the flowrate also can prevent erosion by keeping it below the point where sand is lifted up the wellbore to surface; however, this inflicts severe limitations on the test design.

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IDENTIFICATION CODE

PAG

51

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115



0 1

Erosion can eventually cause: • • • •

7.3.3

Reduced pipe wall thickness and cutting of holes in pipework, including valves and 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.

CROSSOVERS

Crossovers warrant special attention. They are of the utmost importance as they connect in the test string pieces of equipment having 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.

7.4

RIG EQUIPMENT The main items of rig equipment used for testing, such as the permanent pipework and water spray system, have been addressed previously. However, it is essential that all the necessary rig equipment that is to be used have been checked. This includes the rig water pumps, cement pumps, mud pumps and the BOPs. The BOP rams must be dressed in accordance with the test programme. Also there t here 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 the tubulars, 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 OFFSHORE LA BORATORY AND INSTRUMENT INSTRUMENT MANIFOLD EQUIPMENT EQUIPMENT • • • • • • • • • • • • •

Hydrometer for measuring gravity of produced liquids. Manometer for calibrating DP meters. Shrinkage tester to allow allow the calculation 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.

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Some instrumentation is mounted on the test equipment such as: 7.5.2

SEPARATOR • • • •

7.5.3

SURGE OR METERING TANK • • •

7.5.4

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

Sight glasses and graduated scales. Thermometer. Pressure Gauge.

STEAM HEATER •

Temperature controller.

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

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53

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115



8.

0 1

BOTTOM HOLE DATA ACQUISITION Bottom hole data acquisition equipment allows the recording and reading in real time of bottom hole data during the flowing and the build up periods of the well test. It will also enable the conduction of PLT logs and all the other bottom hole acquisition needed during the well test operation. The main items of equipment which can be used for the service are described below.

8.1

EQUIPMENT DESCRIPTION

8.1.1

WIRELINE UNIT

The wire line unit is a winch - motor coupling for running in and pulling out the tools in the well. For standard service, it shall have the following characteristics : • • •

8.1.2

“truck mounted” for land operations “skid mounted” for offshore operations the motor-to-winch motor-to-winch power power transmission shall be hydraulic hydraulic with with the possibility of continuous line speed regulation and of the setting of the maximum pull on the line.

ADAPTER FLA NGE

The adapter flange is the connecting component between the surface test tree/ Xmas tree top flange and the lower connection of the wireline BOP. This flange shall be machined from one block of forged and worked steel and its working pressure shall be equal to or higher than the surface test tree/ Xmas tree working pressure. Adapter flanges with a threaded API EUE bottom connection are not permitted. 8.1.3

BOP

The BOP shall perform the closure on the wire line cable with at least two series of rams; for HP-HT applications, four series of rams are required. Only BOPs with wire shaped rams are allowed. The control of the BOP shall be hydraulic and/or manual type and an equalizing valve shall be incorporated in the BOP. The hydraulic control pump must be equipped, downstream of the fluid end, with a check valve + “Tee” + bleed off valve of appropriate working pressure. 8.1.4

TOOL TRAP

The tool trap is defined as the section of the lubricator which prevents the wire line string from falling in the well during wire line operation. The Quick Union type connections must be in accordance with the specifications established for lubricator risers. The operating components should be hydraulically and manually activated. In addition, this tool shall have an opening/closing visual device.

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IDENTIFICATION CODE

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54

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8.1.5

0 1

LUBRICATOR RISERS

Lubricator risers are composed of pipe sections at least 8 ft. long. The Quick Union type connections shall have a hydraulic seal guaranteed by: Working Pressure 5.000 psi 10.000 psi 15.000 psi

Seal Seal type O-ring O-ring + Seal Protector Ring O-ring + Seal Protector Ring+Non-Extrusion Ring

The connection between the pipe and the quick union must be an integral or welded type. The use of threaded type connections between pipe and quick union is allowed for working pressure up to 5.000 psi. In the lower section the lubricator shall be equipped with at least 1/2" NPT hole to allow pressure bleed off. The bleeding-off pressure from the lubricator is conducted using one bleed-off valve for working pressures up to 5.000 psi, and two bleed-off valves for working pressure higher than 5.000 psi. A wear joint shall be applied at the lubricator bleed off point. 8.1.6

FLOW TUBE TYPE STUFFING STUFFING BOX

The “Stuffing box” is defined as the component which ensures the seal around the wire line cable which is run through the flow tubes during well operations. The operation of the stuffing box control must be activated hydraulically. The Quick Union connections must be in accordance with the specifications established for lubricator risers and a back-up rubber seal shall be installed in the stuffing box. 8.1.7

SAFETY CHECK CHECK VAL VE

The safety check valve is the component in the lubricator which automatically shuts off in a very short time the well flow through the stuffing box in the case where the wire breaks and is subsequently expelled from the well. The Quick Union type connections must be in accordance with the specifications established for lubricator risers. The main sealing device should be a ball valve and metal seal type. 8.1.8

INJECTION NIPPLE NIPPL E

The injection nipple enables the injection of chemical products in the well and directly on the wire during wire line operation. The Quick Union type connections must be in accordance with the specifications established for lubricator risers.

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55

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8.1.9

0 1

TOOL CATCHER

The tool catcher prevents the wire line string from falling in the well during wire line operations by engaging the rope socket. The Quick Union type connections must be in accordance with the specifications established for lubricator risers. The engaging feature shall be automatic and the releasing feature shall be hydraulically activated. This tool shall have an opening/closing indicating device. 8.1.10

DOWN HOLE PRESSURE AND TEMPERATURE GAUGES

Two of the most important parameters measured during well testing are downhole pressures and temperatures. These data are obtained from bottom hole gauges located as close to the perforations as is practicable. Bottom hole gauges may be either mechanical or electronic. The mechanical gauge is rarely used today as its accuracy does not generally meet the demands of modern analysis requested by engineers. It does still have some application in high temperature wells where the well temperature is greater than the temperature limitations of electronic gauges or when simple low cost surveys are required; for instance, to obtain bottom hole pressure before a workover operation. Mechanical gauges are cheaper because of their lower gauge purchase cost and because it is not necessary to have a gauge specialist to run them. The electronic gauge is used in most circumstances and there are a number of different models on the market with a wide range of accuracy and temperature specifications to meet various test demands. It is critical to ensure that the gauge selected is fit for purpose as some of the higher accuracy gauges, such as the crystal gauge, are more susceptible to damage and are also more expensive. The criteria used should be to select the most robust and cost competitive gauge that meets the test requirements. Currently there are three basic types of pressure sensors used in the electronic gauges which are available: Quartz Crystal, Capacitance and Strain. The electronic gauge can operate through an electric cable for surface read out in real time but it is more generally run with a memory section which stores the data electronically on chips. The early gauges had a very limited storage capacity of around 2.5K data points but this has dramatically increased to where gauges now have a capacity of up to 500K. They can also be programmed to change the sampling speed at various times and/or according to the pressure change (∆p). This provides the reservoir engineer with accurate data at the desired and most critical points in the test. Both mechanical and electronic types of gauges are listed below in order of decreasing accuracy. 8.1.10.1 GAUGE TYPES

Quartz Crystal Gauge: the principle on which this gauge is based on is the change in the capacitance of the sensor crystal when pressure is applied. The gauge has two quartz crystals, one sensor and one reference crystal. The change in capacitance of the sensor crystal is measured by the change in frequency of an oscillating circuit. The resultant frequency is converted to a pressure. This type of gauge is the most accurate available.

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56

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0 1

Poor temperature resolution used to be the Achilles’ heel of the crystal gauge but modern gauges have overcome these problems by having the temperature sensor built into the crystal assembly. The tool is relatively delicate because of the fragility of the crystals. Capacitance Gauge: the basic principle of this gauge is similar to the quartz crystal gauge. The difference is that a quartz substrate is used instead of a crystal. The gauge accuracy is between that of the quartz and the strain gauge but it is much more robust than the crystal gauge. It did not suffer from poor temperature resolution as the earlier crystal gauges since the temperature sensor is an integral part of the pressure diaphragm. Strain Gauge: the strain gauge principle works on the deflection of a diaphragm. Pressure acting one side of the diaphragm causes a deflection which is measured and translated into pressure. The accuracy of the gauge is lower than the quartz or the capacitance type of gauge but it is extremely robust and is not affected by temperature changes. Bourdon Tube Gauge: this is a mechanical gauge and was the first type of pressure gauge and is very robust. The most common manufacturers were Amerada and Kuster. The well pressure elastically deforms a Bourdon tube, the deflection of which is scribed directly on a time chart. After recovery of the chart it is read and translated into pressure. Charts can be read with a hand operated chart reader or electronically by a computerised chart reader. The gauge has much lower accuracy than any of the electronic gauges. 8.1.10.2 GAUGE INSTALLATION

As pointed out in the previous section, the gauges should be installed as deep as possible in the well in order to obtain the pressure and temperature data as close to the formation conditions as possible. On a well test this can be done by one of two methods: tubing conveyed or on wireline. Tubing Conveyed Gauges: the normal means of running gauges on the test string is in gauge carriers but other SRO systems have been developed to obtain data from downhole gauges without having to pull the string. This is an advance in technology which means that the data can be verified before curtailing the test. This is extremely useful in very tight reservoirs where the end of the flow or build up periods is difficult to predict and determine. In these tools the gauges are mounted in a housing which is ported to below the tester valve. Gauge Carriers: gauges may be placed in gauge carriers, which are installed in the test string as it is being run and are retrieved at the end of the test when the string is pulled. A minimum of two gauge carriers with at least four gauges should be run.

Depending upon the test string design, they may be installed above the packer sensing tubing pressure or possibly with one below the packer to sense pressure as close as possible to the reservoir. Irrespective of the position relative to the packer, they must be run below the tester valve to obtain build up data. Below packer gauges are of simpler design as they are not pressure 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 the capacitance 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 off the string at the safety joint. Also, the packer absorbs some shock from the tubing conveyed guns providing protection for the upper gauges.

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57

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0 1

SRO Combination Gauges: systems have been developed that allow the databanks of the gauges run in the upper gauge carrier to be read. The disadvantages of the SRO system are thus eliminated as the gauges may be read continuously or periodically. However, it is not good practice to run the interrogating tool until the well has been cleaned up. In the early days, these systems proved to be very unreliable but great advances have since been made.

The latest systems use the tried and proven tester valves for the downhole closure which are ported to a bank of memory gauges or transducers above the valve. The tool gathers and stores the data until the interrogation tool is run by electric line into the memory section housing where it can communicate with the memory section to download the data. These data 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 does not remain in the well, i.e. latched into the housing, during flow periods unless absolutely necessary. This reduces the risk of becoming stuck as a result of sand production or the wire being cut through flow erosion. Wireline Conveyed Gauges: there are two systems for running memory gauges using wire line techniques.

The first is to place a nipple below the perforated tailpipe and to run and set the gauges in this nipple prior to performing the test. The second method is to use an SRO electronic gauge run and positioned in the well on electric line which gives a real time direct readout of parameters at surface. A version of this method can provide build up data in conjunction with a downhole shut-in tool, similar to the SRO systems described earlier, except it uses wire tension to open and close a separate shut-in mechanism, usually a sliding sleeve type device. Memory gauges run on slickline: a number of memory gauges, usually three but as many as physically possible, may be run in on slickline and set in a nipple positioned below the perforated joint. The advantages of this system are that the well can be shut-in downhole, eliminating any after flow effects. Also the gauges may be recovered, e.g. after the first build-up, and the data can be interpreted before completing the test. This system should be considered in wells producing fluids which are corrosive to the electric line, and where long exposure is to be avoided. Gauges are generally run with a shock absorber to avoid damage from shock during the trip or when setting the wireline BHP gauge hanger. Electronic Gauges run on electric line: gauges may be run on electric line to give a ‘real-time’ readout of data at surface. This is called surface readout (SRO).

In some versions the well must be shut-in at surface confusing the build-up data with after flow effects. However, there are now systems available which allow the well to be shut-in downhole and still provide SRO. The disadvantages of this method are that the electric line must remain in the hole during the test, unless using a SRO combination tool described above. Considerable difficulty may be encountered in landing this type of tool in its receptacle after perforating the well. The tool is not robust enough to be landed before perforating and debris may obstruct the nipple after the initial flow. It is highly desirable to clean up the well before running this type of equipment.

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IDENTIFICATION CODE

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58

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8.1.11

0 1

PRODUCTION LOGGING TOOL

The tool shall include as a minimum a pressure gauge, temperature gauge, spinner, fluid density analyzer, correlation log and CCL . 8.1.12

DOWN HOLE SAMPL ING TOOL

Sampling equipment shall be of mercury free type and should be designed so that several samplers can be run in the well simultaneously and fired individually by surface activation or by mechanical clocks. There shall be provisions for checking opening pressure and bubble point of the sample chamber for transportation to base. The activation of the sampling mechanism shall be designed so that any accidental release of sampling valves is prevented: this includes release in case of mechanical shock. For electrically triggered samplers, sampling may not be initiated by any electrical or radio signal other than that transmitted through the cable on which the sampler is run. The minimum volume of each sample shall be 0,6 litres; once activated, the sample shall be filled in a controlled manner (maximum 5 minutes) in order to prevent drawdown below bubble point.

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IDENTIFICATION CODE

PAG

59

OF

115



9.

0 1

PERFORATING SYSTEMS Two methods are currently used to perforate wells: wireline conveyed guns or tubing conveyed guns. Tubing conveyed perforating is the Eni E&P preferred method for well test operations, as the zones to be tested can be perforated underbalanced in one run, with large charges. 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 the length of time the guns are likely to be on bottom before firing (Refer to the Perforating Section of the “Completion Design Manual”, STAP-P-1-M-7100 section 9 ).

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 long perforation intervals can be fired in a single run. If required, a bull nose can be installed on the bottom of guns to allow the test string to enter liner tops. Various methods of detonation can be utilised, depending on well conditions.

9.2

WIRELINE CONVEYED PERFORATING There are two alternatives when perforating using wireline conveyed guns: casing guns or through-tubing guns. In both cases depth control is provided by running a Casing Collar Locator (CCL) above the guns and the guns are fired by electrical signal. Casing guns are large diameter perforators that 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 to perforate underbalance, reducing the risk of damaging the formation with brine or mud invasion immediately after perforating. The largest gun which can be safety run through the standard 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's specialised personnel in charge for casing perforation. The number of person involved shall be as low as possible. Only the Contractor's operator is allowed to control electric circuits, to load and unload guns.

b)

Nobody else, except for Contractor's operators, is allowed to remain in the hazardous 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 such time they shall be stored in a designated locked container, marked with international recognised explosive signs.

d)

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

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0 1

e)

Maximum care shall be taken during transportation, loading and back-loading of explosive. Explosive and detonators shall always be transported and stored in separate containers. This also applies to defective detonators which have been removed 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 any radio transmitter (including crane radios) and welding equipment.

j)

The Company Drilling and Completion Supervisor shall collect all portable radios inside company office in order to avoid any possibility of untimely use.

k)

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

l)

The following shall be advised prior to radio silence being in force: • • • •

Stand by vessel Helicopter operations Company Shore Base Other nearby installations.

m)

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

n)

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

o)

When the casing is perforated before running the DST string, mud level in the well shall be visually monitored.

p)

When the casing is perforated before running the DST string, the well must be filled 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 a lower density.

q)

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

r)

The first casing perforation shall be performed in daylight. Subsequent series of shots can be carried out at any time.

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IDENTIFICATION CODE

PAG

61

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115



10.

0 1

PREPARING THE WELL WEL L FOR TESTING This section describes the operations necessary to prepare the well for well testing.

10.1

PREPARATORY PREPARA TORY OPERATIONS FOR TESTING

10.1.1

GUIDELINES GUIDELINES FOR TESTING 7INS LINER LA P

1)

2)

3) 4)

10.1.2

5

GUIDELINES FOR TESTING 9 /8INS LINER LAP

1)

2)

3) 10.1.3

While waiting on cement, test the BOP stack according to the “Well Control Policy Manual”, STAP-P-1-M-6150 section 7 procedures. Pull out of the hole with the test tool. Run a 6ins bit/mill and clean clean out the 7ins liner to the landing collar collar (PBTD). The drilling programme must allow for sufficient rat hole to enable TCP guns to be dropped off, if required. Run a cement bond/correlation log from PBTD to top of 7ins liner. 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 a guideline, conduct a positive test of the liner lap by applying approximately 400psi pressure. Ensure that the burst rating of the 95/8ins casing is not exceeded. Displace the required amount of fluid from the drillpipe with base oil to give an approximate drawdown on the liner lap and liner of 500psig in excess of maximum drawdown pressure planned for the individual wells. Set the packer and monitor the well head pressure for influx for 1hr. If the liner lap or liner is found to be leaking then a remedial cementing programme will be advised.

While waiting on cement, test the BOP stack according to the “Well Control Policy Manual”, STAP-P-1-M-6150 section 7 procedures. Pull out of the hole with the test tool. Run a 81/2ins bit/mill and clean out the 95/8ins casing to the landing collar (PBTD). The drilling programme must allow for sufficient rat hole to enable TCP guns to be dropped off, if required. Run a cement bond/correlation log from PBTD to above the packer setting depth.

GENERAL TECHNICAL TECHNICAL PREPARATIONS

1) 2) 3)

4)

Surface well testing equipment should be installed and pressure tested as per the procedures in section 10.8. DST tools should be laid out and tested on the pipe desk (Refer to section 10.8). Ensure that all downhole components 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. All threads and collars are to be cleaned properly on the rack. Make sure all crossovers are correctly bevelled inside and outside. Make a visual inspection to verify the condition of packer rubbers and all DST equipment.

SPEO

IDENTIFICATION CODE

PAG

62

OF

115



5)

10.2

0 1

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

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

10.2.1

ONSHORE ONSHORE PREPARATION OF BRINE

1) 2) 3)

10.2.2

Filter and recondition any (suitable) brine which is in stock. Following the final filtration/reconditioning cycle of this stored fluid, re-weigh and adjust as necessary to suit the conditions of the well. Prepare balance of fluid from sacked material or liquid, as appropriate. Filter and condition as necessary.

TRANSPORTATION AND TRANSFER OF FLUIDS

The primary objective is to transport and transfer the fluid without losing density due to dilution, losing volume, or contaminating of the fluid. 10.2.3

RECOMMENDATIONS

An independent surveyor should be engaged to perform the following duties: d uties: 1)

Onshore Brine Tanks • • • • •

2)

Dip storage tanks before transferring fluids. Take samples samples of of brine brine at beginning, middle middle and end of pumping. If required, submit to the district office. Check samples samples for SG at 60°F; centrifuge for solids content, check clarity. Dip storage tanks after brine is loaded onto transport vessel. Record and submit submit report the volume and density of brine provided by brine supplier.

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.

SPEO

IDENTIFICATION CODE

PAG

63

OF

115



3)

Off-loading Brine at Rig-Site •

•

• •

10.2.4

0 1

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 to measure volume of fluid received. Sample brine received into pontoons/pits and check density and solids to verify that fluid has not been diluted or contaminated during transport. Report any variation 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.

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 lines should be pre-flushed with water and, if necessary, a chemical wash. If feasible, mixing lines and valves should be pressure tested against the mixing pumps. Leaking valves should be replaced. The mud/brine tanks, ditches, lines lines and pumps can can be given given a final cleaning with appropriate chemical cleaner and flushed with water. This final cleaning should include 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 the brine.

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

• • • •

2)

When all all the mud has been emptied from the pit tanks to be used, clean clean the mud tanks as thoroughly as possible to avoid any brine contamination. Clean initially using buckets and shovels. Wash the first mud pit with 50bbls seawater pill containing descaler and oil mud removers. Pump pill into second pit and make up second 50bbls pill containing lower concentration descaler/oil mud remover. Pump second pill pill into first pit and first pill pill into third third pit. Continue until all 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.

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

SPEO

IDENTIFICATION CODE

PAG

64

OF

115



3)

0 1

Ditch Gates - Slide Type All gates should be sealed prior to receiving brine. Two layers of ‘Densotape’ applied across edge of slide should insure a good seal. Additional sealing can be obtained with a fillet of ‘Slick grease’ on the upstream side. Barites, bentonites and polymers should not be used in an attempt to seal possible leaking areas. They do not provide adequate sealing, and also contaminate the brine.

4)

Water Lines All water lines should be taped or chained off. off .

5)

Pump Packing Replace all work mixing pump packing.

6)

Tripping Significant losses of brine can be avoided during tripping by: • • •

10.2.5

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

7)

Rig Shakers Should it be necessary to pass brine over rig shakers when circulating, ensure equipment is operating properly. Avoid diluting brine by washing down or cleaning screens with water.

8)

Settling Pit Tank or tanks should be dedicated to be used as settling/separation tanks for brine that became abnormally contaminated during the course of the testing operation. Brines contaminated with solids, oil, oil, cement, or other should be placed in tanks and chemically treated as required. For oil and solids and/or polymer-contamination, pilot testing should be performed to determine treatments of flocculants and/or oil separation chemicals, viscosity breakers, etc. Following chemical treatment, the brine should be filtered and returned to the active system, and re-weighted if necessary.

9)

Sand Traps If used to contain brine during the operation, these traps should be thoroughly cleaned prior to the introduction of the brine system. It should also be predetermined that fluid can be completely removed when required.

WELL AND SURFACE SYSTEM DISPLACEMENT TO BRINE

Most oil and water based drilling fluids are incompatible with solids-free brines; therefore an effective 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.

SPEO

IDENTIFICATION CODE

PAG

65

OF

115



10.2.6

0 1

DISPL ACEMENT PROCEDURE

Extensive displacement procedures will be issued by the Brine Contractor. The procedures will 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 large volumes 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 required condition. Required completion fluid weight should be confirmed based on RFT and offset well data. Once the hole has been displaced to completion brine, continue circulating if necessary until completion brine returns are within specification as regards weight and filtration quality. 10.2.7

ON-LOCATION FILTRATION AND MAINTENANCE OF BRINE

Considering rig surface equipment and availability of space, every effort should be made to follow procedures: 1) 2)

3) 4)

5)

6) 7)

8) 9) 10) 11)

Install filtration equipment in order to operate at its maximum efficiency. 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. Brine in suction tank should be maintained at proper density and filtered prior to being pumped into hole. Returns of brine should be placed in adequate settling/separation tank to allow proper chemical treatments and filtration before being placed into the active brine system. If considered more economical and feasible, severely contaminated brine should be returned to the brine supplier for reclamation and reconditioning. Whenever possible, a sample of the contaminated brine should be sent to the brine supplier for evaluation to determine if the fluid should be treated offshore or onshore. Avoid dilution of brines brines caused by water hoses, water lines, washing down or rig and/or filtration equipment, etc. Pick up bit for casing and drill 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 with the bit unless excessive drilling is expected. Run in the hole with bit for liner and drill out the liner to landing landing collar, collar, which which is is then the PBTD (Refer to section 10.1). Run and record CBL/VDL or CET from the landing collar to the top of the liner. 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). If the liner lap lap is found to be leaking then a remedial cementing job is advised. advised.

SPEO

IDENTIFICATION CODE

PAG

66

OF

115



10.3

DOWNHOLE EQUIPMENT PREPARATION PREPARA TION

10.3.1

TEST TOOLS

0 1

Downhole test equipment must be included in the preparation of the test string, as they become an integral part of the string. On both the primary and back-up sets, the following tests and checks must be completed by the relevant service company crew: 1) 2)

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

3)

4)

5)

6) 7) 8) 9)

10.4

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

Conduct a body pressure test to a minimum of 1,000psi above the maximum expected differential pressure, or 1,000psi above the maximum wellhead pressure, whichever is the greatest. Pressure test, from direction of flow, all test string valves to a minimum of 1,000psi above either the maximum expected differential pressure, or wellhead pressure, whichever is the greatest. Pressure test, from above, all test string string valves, valves, if appropriate, to a minimum of 1,000psi above either the maximum differential pressure, or wellhead pressure, whichever is the greatest. Where appropriate, the downhole test equipment should be function tested. The test string components must be drifted to the 2.25ins maximum drift size to cater for all contingencies. 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. Check that the appropriate crossovers are available and make up to the downhole test equipment as per specific well characteristics (see section 6).

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

10.4.1

TUBING TUB ING CONNECTIONS

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

SPEO

IDENTIFICATION CODE

PAG

67

OF

115



0 1

Premium connections generally have better sealing properties compared with API connections 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-tometal seal or a Teflon packing ring. Some premium connections are superior to others regarding being gas tight or good for high pressure and temperatures etc., therefore an operator must make a thorough investigation to find the connection connection which is best fit for purpose. It is normally agreed that premium threads with a torque shoulder is ideal for testing, as it has low refurbishment costs and is quick to make up and reasonably robust against handling damage. However it is limited to the number of thread re-cuts that can be machined before requiring to be sent back to the mill for upsetting again. 10.4.2

TUBING GRADE

Specifies the type and strength of the steel. Standard tubing is generally covered by the API specifications, e.g. J 55, C 75, 75 , L 80, N 80, and C 95. The letter lett er states the properties of the steel and the number is its minimum tensile strength in 1,000lbs per sq inch, i.e. N 80 is a normalised and tempered carbon steel with 80,000lbs/ins2 minimum yield. The crosssectional area of the tubing multiplied by the minimum yield stress provides the joint yield strength, e.g. tubing 41/2ins 15.5lbs/ft C 95 body section is 4.407ins2 x 95,000lbs/ins2 419,000lbs. Tubing is manufactured in a variety of steel grades to cater for the 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 sour fluids are expected the material should be no harder than 22 HRC. This limits the choice to C75 or N 80 as the toughest grades. However, special grades up to C 95 may be used if they are specified for sour service and have passed the NACE sulphide stress cracking tests (API SPEC 5AC). Safety factors in axial tension should ideally not be less than 1.7, but a lower limit of 1.4 can be accepted if a triaxial stress envelope is used. 10.4.4

WEIGHT PER FOOT

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

SPEO

IDENTIFICATION CODE

PAG

68

OF

115



10.4.5

0 1

DRIFT

It is slightly less than ID and represents maximum effective available bore diameter for the passage of tools. API Spec 5A specifies the dimensions of mandrels to be used in drift testing. All tubulars to be run in a well, i.e. casing, tubing, nipples, packers etc. must be drifted prior to running. 10.4.6

CAPACITY

This is the amount of fluid required to fill a measured distance inside the tubing, e.g. a capacity of 0.01422bbl/ft, sometimes expressed as 14.22 barrels per thousand feet. 10.4.7

DISPLACEMENT

This is the volume occupied by the tubing material, or the volume of fluid which the tubing will displace. 10.4.8

TORQUE

Is the amount of torsional moment applied to connect pin and box to optimise the mechanical and sealing performance of the connections, e.g. the values for the Agip (UK) string are as follows:

10.4.9

Minimum

-

6,800ft*lbs

Optimum

-

7,650ft*lbs

Maximum

-

8,500ft*lbs.

INSPECTION

Prior to Running (On Board Visual Inspection And Field Repair) 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 could indicate galling or over-torque. Visual inspection should concentrate on the primary metal to metal seal surface of the pin and box. These seals should be free from corrosion and defects. The sealing mechanism is based on having sufficient pin-to-box metal-to-metal contact stress around the full circumference of the connection. The pin and box seal surfaces should be examined for any seal irregularity. Check seal surface for: • • • •

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

SPEO

IDENTIFICATION CODE

PAG

69

OF

115



0 1

Some type tubing connections have an external shoulder, which is the primary shoulder on these connections, controlling the position of the pin relative to the box. The proper location on a fully made-up connection of all other seals and shoulders is determined by the position of this shoulder. The surface is also intended to be a secondary pressure seal. This requires that visual inspection 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 be removed before running. To alleviate this problem the rust or discoloration can be easily removed 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 being run. Drift pipe with correct size (OD and length) drift. After Af ter Test in g/Pr io r To Re-Use

After a series of tests and before re-utilisation r e-utilisation in another well, that part of the tubing used shall be inspected onshore. • • • • •

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

10.4.10 TUBING MOVEMENT

As part of the design process for the testing string, calculations should be performed by the DST contractor and confirmed by Eni E&P Drilling and Completion Department to determine the likely maximum contraction and expansion 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 tubing design is adequate for the test and to determine the optimum type and quantitative design of any devices included in the string to accommodate tubing movement, e.g. slip joints or seal assembly and sealbore packer.

SPEO

IDENTIFICATION CODE

PAG

70

OF

115



10.5

0 1

L ANDING 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 and SSTT inside the Subsea BOPs and determine the length of landing string required to provide the required height of the flowhead above the drill floor referred to a stick-up. It is vital that the SSTT body does not lie across the shear/blind rams and that the surface tree is situated sufficiently high enough above the drill floor, so that on no account can the bottom of the tree come into contact with the drill floor or the flow and kill lines become bound or trapped even at the 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 landing string 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. A joint of tubing, without a thread protector, should always be run beneath the SSTT.

SPEO

IDENTIFICATION CODE

PAG

71

OF

115



Figur e 10-1 10-1 - SSTT SSTT Arrangement

0 1

SPEO

IDENTIFICATION CODE

PAG

72

OF

115



0 1

Figure 10-2 - Typical Safety Valve Arrangement for a Jack-up

SPEO

IDENTIFICATION CODE

PAG

73

OF

115



10.5.1

0 1

LA NDING STRING SPACE-OUT SPAC E-OUT PROCEDURE

The procedure is: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

12)

Check that the rig is at operating draft. Make up the fluted hanger to the slick joint, with the appropriate adjustment, adjustment, to give the correct length according to the stack drawing dimensions. Pick up the fluted hanger and slick slick joint assembly and paint the slick slick joint with white paint. Run in to immediately above the BOPs and engage the compensator. Land the hanger in the wellhead. Pick Pick up slightly and turn to the right to ensure the hanger has fully landed out. Carefully close the rams rams on the slick joint, checking checking the volume volume of fluid taken to confirm that they are fully closed. Mark the string at the drill floor at mid-heave. Record the tide level. Open the rams and strap out to the first connection to obtain the depth to the hangoff point at this tide level. Pull the pipe and lay out the hanger and slick joint joint being careful not to smudge smudge the paint marks. 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 stack dimensions. Adjust the primary assembly for the dimensions obtained.

Note:

Ensure that either choke or kill line is connected below pipe ram that is to be used on slick joint. This is necessary for annulus control and monit oring duri ng DST DST operations. 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 the test programme and any updates to the original programme. At this point potential problem areas should be identified with the goal of preventing such problems or at least eliminating the element of surprise. This policy should continue throughout the test as new information becomes available or as conditions change. 10.6.2

INVENTORY OF EQUIPMENT ONSITE

The contractor shall: 1)

Obtain all possible information and preferably a well schematic of the hole regarding the hole conditions such as: • • • •

Total depth True vertical depth Mud/brine type Mud /brine weight

SPEO

IDENTIFICATION CODE

PAG

74

OF

115



• • • • • • •

2)

3)

Maximum deviation Mud viscosity Depth to top of liner Cushion type Bottomhole temperature Maximum casing/liner test pressure Anticipated production rates.

Consult with the Mud Engineer about the performance of the mud/brine system under conditions of static temperature and pressure for the anticipated duration of the test and the compatibility of the mud/brine system to the cushion. Confer with the Tool Pusher concerning testing requirements during the test, such as: •

•

• •

10.6.3

0 1

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 be removed or bypassed. Potential tie-in points on the rig manifold for a pressure monitor etc. Availability of handling equipment (e.g. lift subs, elevators). Procedures for picking up test tools.

PRELIMINARY PRELIMIN ARY 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 can avail himself of Company Drilling Engineer (if Present) and drilling contractor personnel (Toolpusher): 1)

2) 3) 4) 5) 6) 7)

8)

All tubular goods not required for the execution of the test and for the preparatory operations (scraping, setting of bridge plugs, etc.) shall be laid down from the derrick floor prior to start the test. Fishing tools for all equipment to be used during testing shall be on rig. Working area on the rig floor and around the separator, heater, tank and flare shall be clear of obstructions and flammable substance. An adequate platform shall be available to operate the valves on the flowhead. Inspections shall be performed on masks, self-breathing apparatus, resuscitators and extinguishers in order to check their efficiency and location on the rig. Electric installations placed within area classified as ‘hazardous’ shall be ‘explosion proof’. It shall shall be checked that all access doors and escape ways, fire doors and vent line valves of pressurised tanks are in the position prescribed by the rig procedures during ‘production tests’. Fuel tanks, oxygen bottles and other pressurised bottles shall be placed far from the area classified as ‘hazardous’ and cooled with water, if necessary.

SPEO

IDENTIFICATION CODE

PAG

75

OF

115



9)

10)

11) 12) 13) 14)

0 1

It shall be checked that the amount of water available to the burners water spray and to the sprinkler system is sufficient to protect the burners and the rig from heat radiation generated by the combustion. 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 during formation clean out. The accuracy of the data supplied by the anemometer (wind (wind speed and direction) shall be checked before opening the well. Prior to start well testing operations, drills drills shall be performed for fire-fighting and pollution prevention. Inspection shall be made on operating conditions of the communication system among rig floor, flares area and production equipment area. Complete BOP test shall be carried carried out before starting starting well testing operations.

The following additional inspections shall be performed prior to start testing operations, under the direct responsibility of Company Drilling and Completion Supervisor, who can avail himself of production test equipment operators: 1)

2)

It shall be ascertained that the separator is equipped with safety valves (pop valves and/or rupture plate outlets) in top operating conditions. The outlets of separator and the vent lines of production tank(s) shall be free from obstructions and secured to fixed structure of the rig. These lines shall usually be connected to the flares. Inspections shall be carried out on the flares (blow-off lines), on the burners/flares booms and on the burners igniting system. For the ignition of burners/flares, a back-up system shall be available in addition to the main fixed system. A test on burners shall be performed using u sing diesel oil as fuel. An adequate supply of propane or butane should be available, if such fuel is used for the igniting system. Due to their dangerous nature, propane or butane bottles shall be stored in protected area.

3)

4)

10.7

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 rig from heat radiation in the area where burners are installed. In addition to this fixed installation, special fire-fighting hoses with adjustable nozzles shall always be available to cool any part of the rig that would happen to remain outside the protection of the water sprinkler system.

PRE TEST EQUIPMENT CHECKS 1)

2)

Lay out the appropriate downhole tools, observing correct handling and slinging procedures. Tools must be positioned in a manner so that they are secure and cause minimal obstruction. Visually inspect all tools to ensure no damage was sustained in transit particularly to threads and sealing surfaces.

SPEO

IDENTIFICATION CODE

PAG

76

OF

115



3) 4) 5)

6) 7)

8) 9) 10)

11) 12) 13) 14) 15) 16)

10.8

0 1

Function and pressure test tools according to procedures laid out in the service companies’ operations manual which will be made available on the rig. Ensure that all tool dimensions are accurately measured and lengths of extending mandrels recorded etc. Ensure all required crossovers crossovers have been sent and physically checked for correct threads. Measure crossovers and note length, ODs and IDs. Particular attention should be paid to the IDs of rented crossovers. Ensure all tubulars are drifted, cleaned internally and the connections have been inspected prior to running. Lengths, ODs, IDs and thread connections of all downhole tools should be checked for correct size and a list produced. All tools should be clean, free of any dirt or debris and the connections cleaned properly on the rack. All crossovers should be properly bevelled inside and out. All downhole tools should be drifted to 2.125ins to allow running of surface read out or any other wireline or coil tubing tool. The pipe pipe tester valve (PTV) should be made up to the packer on the deck deck and tested from below to its working pressure prior to running in the hole. A visual visual inspection should be made of the packer elements prior to running. The packer should be set appropriately above the perforated interval to allow safe wireline operations such as production logging, if required (i.e. ensure the bottom of the tailpipe is positioned approximately 100ft above the top perforation). The packer packer should never never be set across a casing collar. All downhole test tools should be pressure tested at surface to a minimum minimum of 1,000psi above maximum anticipated pressure. A list list of all pressure gauges and serial numbers should be compiled and submitted to the Company Production Test Supervisor. Only API 5A Modified thread lubricant should be used on tools, tubing and drill collar connections. The lubricant should should be applied to the pin end only with with a paintbrush. Apply sparingly. Check the brine weight as accurately as possible and ensure that it is correct, based on the RFT results.

PRESSURE TESTING EQUIPMENT All surface and downhole testing equipment shall be fully pressure pre ssure tested prior to send to the rig. Testing equipment shall also be pressure tested on the rig before starting a well test; in particular: 1) 2) 3) 4)

For all pressure tests, the area outside accommodation must be clear of nonessential personnel. Pressure tests shall be carried out using water. Each pressure test shall be recorded on a record sheet and the pressure shall be held for a minimum of 15min. Test pressures shall be specified on testing program. However, devices protected by rupture discs should not be tested to more than 90% of working pressure. BOPs, choke manifold, choke and kill lines shall be pressure tested as per the “Well Control Policy Manual”, STAP-P-1-M-6150 section 7 .

SPEO

IDENTIFICATION CODE

PAG

77

OF

115



5)

0 1

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.), the opportunity 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's specification. It is common practice to make up one full single joint of tubing from the landing string to the flowhead in the rotary table and lay out the entire assembly on the pipedeck. This connection must be done before running the test string as it cannot be torqued later due to being too high when the string is finally landed. 10.8.1

SURFACE TEST TREE

The flowhead should be prepared on the catwalk in accordance to the contractors procedures, which should be as follows: 1)

11) 12)

With master and swab valves open, drift the flowhead to its maximum diameter to accommodate any wireline or coiled tubing tools to be run. Function test test the ESD actuator on the flow wing valve. The ESD ESD is a fail-safe valve. Make up one joint to the flowhead with chain tongs. Pick up the flowhead with with the single joint of tubing and torque itit up in the rotary table to the correct torque. Check the torque on the swivel and any other flowhead service connection. Ensure that the swivel is free to rotate completely in both directions. 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 test the flowhead body from the bottom to test pressure. Close the swab, kill wing and flow wing valves. Open the respective needle valves valves in the test subs downstream. Pressure test against the upper valves. Close the upper master valve, open the kill wing valve and pressure test against the upper master valve from below to test pressure. Close the lower master valve, open the upper master valve valve and pressure test against the lower master valve from below to test pressure. Bleed off pressure below the lower master valve valve and leave the needle valve open. Open the swab valve valve and pressure test against the lower master valve from above.

13)

Close the upper master and pressure test from above.

2) 3) 4) 5) 6) 7)

8) 9) 10)

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14) 15) 16)

0 1

Remove the test caps. Clean and grease the connections. 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 joint assembled on bottom in the followed way: 1) 2) 3)

Plug the kill side, the flow side and close close the swab swab valve; pressure test the internal of of flowhead pumping through the pup joint. Bleed off pressure pressure and remove plugs from kill and flow side, close kill valve, flow side fail-safe valve and pressure test the gates from inside. Close master valve and bleed off the down stream pressure to pressure test the gate from below.

This procedure may be adjusted to the actual flowhead configuration.

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Figur e 10-3 10-3 - Flowhead Schemati c

0 1

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11.

0 1

TEST STRING INSTALL ATION Detailed individual well programmes will be issued for all wells to be tested, which includes development, appraisal and exploration wells. Each programme will include contents, the exact details of which will be well specific dependent upon the well status and expected well parameters. The following is the contents of a typical test programme: 1) 2) 3) 4) 5) 6)

Test Objectives General well data and perforating details Summary of test programme Guidelines for liner lap test and space-out calculations Sequence of operations for running downhole tools and surface equipment rig up 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 all relevant 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 is only allowed 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 personnel involved 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 Never Use Hook Ends . Vee door. Never

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 approved methods of cleaning should be used: • • •

11.3

0 1

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 qualified Tubing Inspector.

i)

Reject and damaged joints should be painted red and documented and then returned to the onshore base for remedial work if necessary.

j)

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

k)

After the threads have been cleaned and inspected it is important they be protected from corrosion. Never leave the threads for longer than two hours without corrosion protection.

l)

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

RUNNING AND PULL ING a)

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

b)

Ensure all accessories/tools are on the rig floor and are in prime condition ready to run the tubing, i.e. pup joints, crossovers, stabbing guides, single joint elevators, 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 or until the Company Production Product ion Test Supervisor thinks enough weight is available to properly set slips.

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11.4

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d)

Slip type elevators to be used at all times. Check the elevator setting plate for proper operation. This will ensure the elevators set on the body of the pipe, not on the 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 breakouts 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 be labelled. Ideally the angle with the tong arm should be 90°.

i)

When pulling the tubing, always use a wiper rubber.

j)

Always install the pin protector fully before standing the tubing t ubing in the derrick.

k)

Never use a sledge hammer on connections to assist the breakout.

l)

Ensure tubing set back in the derrick is properly supported with a belly band to prevent undue bending.

m)

Always use the manufacturer recommendations for running, pulling or makeup.

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.

PACKER PACK ER AND TEST STRING RUNNING PROCEDURE Before running the test string all the earlier procedures should have been carried out to prepare the well, tubing and tools for the test. The procedure for running the test string will vary depending upon the equipment used. The main difference in running the string is due to the type of packer being used and whether it is for well with sub sea well head or for surface well head. Example test string running procedures are given below for running strings with both types of packers from a floating drilling unit. For a Jack-up or land rig, the SSTT would be replaced by the subsurface safety valve. The specific running procedures will always be detailed in the well specific test programme.

11.5

RUNNING THE TEST STRING WITH A RETRIEVAB LE PACKER PACK ER 1) 2) 3) 4) 5)

Run a junk basket on wireline to below the packer setting depth. Before running the test string, hold a brief safety safety meeting on the drill drill floor and reemphasise the precautions that should be taken during operations. Ensure a Kelly Cock is situated on the drill floor for emergency use. The downhole gauges should be programmed and installed into the gauge carrier(s) in advance. Make up and run the TCP gun assembly.

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6) 7) 8)

9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) 22) 23) 24) 25) 26)

11.6

0 1

Install the packer assembly as per the string diagram. The packer packer should be at least 5ft away from a casing collar. Continue making up the string using a back-up tong to ensure that the packer is not turned to the right. 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 not turned to the right. Run the tools into the well and make up the crossover and first joint(s) of intervening drill collars. Ensure the BOP blind rams are are open before the test tools reach them. 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. When the first tubing joint of the major string has been run, pressure test the minor string. Run the tubing. When the test string has been run half way into the well, the tubing should again be pressure tested (optional). If there is is a liner hanger above the packer setting depth, run the tailpipe and packer through the liner hanger slowly. When all major string has been run, it is recommended that the string should again be pressure tested. Pick up the SSTT SSTT assembly and make up to the tubing and function test. Continue running the landing landing string, string, strapping the SSTT hoses to the tubing. Install the lubricator valve. Continue running the landing string and the space-out pup joints, strapping all hoses to the pipe. Install the surface test tree tree and 50ft bails bails or CTU lifting frame. Run a GR/CCL log to verify verify the packer setting setting depth. (Refer to appropriate section according to gun type). Set the packer and set down weight until the fluted hanger lands out in the wellhead. Run a GR/CCL log to verify verify the packer setting setting depth. (Refer to appropriate section according to gun type). Carry out the hook-up and final pressure testing. The well is now ready to be perforated and tested.

RUNNING A TEST STRING WITH A PERMANENT PACKER PACK ER 1) 2) 3) 4) 5)

Run a junk basket to below the packer setting depth Before running the test string, hold a brief safety safety meeting on the drill drill floor and reemphasise the precautions that should be taken during operations. If the TCP guns are being run below the packer, make up the TCP gun assembly. assembly. 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. Run the packer/TCP assembly on drillpipe with a radioactive marker sub, one stand above the setting tool.

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6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) 22) 23) 24) 25) 26) 27) 28) 29) 30) 31) 32)

0 1

Ensure the BOP blind rams are open before the test tools reach them. Rig up and run a GR/CCL and correlation gun setting depth. Rig down the wireline. Adjust the setting depth as required. Set and pressure test the packer. Pull the work string. Ensure a Kelly Cock is situated on the drill floor for emergency use. use. The downhole gauges should be programmed and installed into the gauge carrier(s) in advance. If the TCP guns are to be run on the string, make up the gun assembly. Install the space space out tubing and then the seal assembly. Continue and pick 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. 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. When the first tubing joint joint of the major string has been run pressure test the minor string. Run the tubing. When the test string has been run half way into the well, the tubing should again be pressure tested (optional). If there is is a liner hanger above the packer setting depth, run the end of of the string string slowly through the liner hanger. 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. Run in slowly and tag the packer. Mark the pipe and calculate the spacing out. It is recommended that the string be pressure tested. Pull slowly out of the packer and pull back back the pipe to install the SSTT. SSTT. Space out and pick up the SSTT assembly, assembly, install onto the tubing and function test. Continue running the landing string, strapping the SSTT hoses to the tubing. Install the lubricator valve. Continue running the landing landing string, string, strapping all hoses to the pipe. pipe. 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. Carry out the hook-up pressure test. Slowly lower the seal assembly into the packer and land the SSTT SSTT hanger. Conduct the final string pressure tests. The well is now ready to be perforated and tested.

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0 1

12.

WELL TEST PROCEDURES

12.1

ANNULUS ANNUL US CONTROL AND PRESSURE MONITORING An important aspect of any well test t est is the continuous monitoring of the annulus pressure. This responsibility shall be delegated to the Driller who will maintain a log of pressures and tool functioning throughout the test. The well conditions during flow periods will affect the temperature and, therefore, the fluid volume in the annulus. These temperature effects should be closely monitored and pressures adjusted throughout the flow period by the Driller to keep them within the parameters given by the DST specialist. Note:

Annulu s pressure shou ld always be cont rolled by the rig choke manifold and any hydr ocarbons vented to the poor-boy de-gasser. de-gasser.

The following aspects for annulus monitoring must be planned beforehand: • • • •

•

12.2

At least two independent measurement measurement points should be made available so that a comparison of the two can be made at regular intervals. Two bleed-off/top up ports should be available to bleed down/top up the pressure from 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 check and records all bleed off/ top up times and volumes.

TEST EXECUTION a)

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

b)

A suitable amount of mud shall be available during casing perforations and formation testing. 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 to the flow head's kill line should be in open position.

d)

The test string shall include as a minimum the following downhole and surface equipment (from bottom to surface): • • • • • •

Tailpipe Packer Safety joint Jar Tester Two reverse circulation valves

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• •

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Slip joints Flowhead.

e)

Initial opening and/or initial flow through separator shall be carried out in daylight only. All subsequent flow/build-up operations can be performed at night under favourable weather conditions.

f)

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

g)

Initial opening shall be avoided in windless condition. The decision to suspend a test due to windless conditions shall be taken by Contractor's Toolpusher after consultation with Company's Drilling and Completion Supervisors.

h)

The test shall be suspended whenever the normal course of operations is hampered or drilling unit's safety is jeopardised (heating of the structures, presence of smokes, and gas on 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 shall be strictly observed (Refer to the “Well Control Policy Manual” STAP-P-1-M-6150 section 11 ). Frequent test on H2S presence shall be carried out on the rig floor, production equipment and flares area, near pumps and engines. Any indication of H2S presence shall immediately be notified to Contractor's Toolpusher and Company's Drilling and Completion Supervisor.

m)

It is forbidden to release to the atmosphere non-combusted hydrocarbons.

n)

Only the use of production stock tanks shall be allowed.

o)

All stimulation jobs and subsequent formation clean out operations shall be performed in daylight.

p)

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

q)

During acidizing, surface pressure’s shall not exceed the surface equipment testing pressure or the working pressure of the weakest joint of the test string, whichever is lowest.

r)

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

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13.

WELL TEST DATA REQUIREME REQUIREMENTS NTS

13.1

PRE-TEST PREPARATION PREPARA TION

0 1

After the test programme has been finalised, f inalised, the following points p oints should be discussed with the participating service companies:

13.2

a)

The type of downhole gauges to be run taking into consideration the range of pressures and temperatures to be encountered, the planned length of the test and the accuracy required. The responsibility for onsite interpretation of data should also be decided.

b)

The range of surface flowrates expected should be discussed so that the correct instruments and orifice plates can be selected. The frequency of data measurement and the report presentation should also be decided, if a computerised data acquisition unit is to be used.

c)

The frequency and locations to take samples for fluid identification during the test should 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.

METERING REQUIREMENTS Prior to the commencement of testing, the separator flow meters and Barton differential pressure recorder should have been calibrated. All personnel involved in the operation of metering devices and gauges must keep a detailed log 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 shall apply. Note:

These These intervals may be altered at the discr etion of the well site Company Produc Produc tion Test Test Supervisor .

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0 1

Readings 1

Timing

Well Pressure

1st Flow

Every 1 min for 10 mins Every 2 mins for 20 mins Every 5 mins until end

Further Flow Periods

Every 5 mins for 1 hour Every 15 mins until end

Monitor THP during build up in case tester valve is leaking

2 3

Wellhead Temperature SRO Pressure and Temperature

1st Flow

as above


as above


Every 15 secs for 10 mins

(Print-outs) Every 1 min for 20 mins Every 5 mins until end Each build up

Every 15 secs for 15 mins Every 1 min for 45 mins Every 5 mins until end of build up

4 5

Separator Flow Rates

Every 30 mins

Shrinkage

Every 2 hours

6 7

Oil and Gas Gravities

Every 1 hour

BS&W

As frequent as possible to determine if sand is being produced

8

H2S Determination

1st Flow

As frequent as possible with detector tubes at choke manifold bubble hose


Every 2 hours by chemical analysis of separator gas

9

CO2 Determination

As for H2S

10

Downhole Memory Gauges

Minimum 4 gauges, preferably 6-8 gauges, to be run. Minimum 2 different types of gauge to be run. Seek advice from Reservoir Engineers during test planning for special requirements.

Table Table 13-a - Data Data Gatheri Gatheri ng Tim ing s

13.3

DATA REPORTING Second only to safety, the task of data gathering and reporting is the most important activity during a well test and is the prime responsibility of the Company Production Test Supervisor. The data will generally be recorded by the service companies as stated in STAP-A-1-SS-1728 section 5.3 , but it is the responsibility of the Company Production Test Supervisor to ensure it is collected and distributed correctly as stated in STAP-G-1-F-9057 section 6.13.

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13.4

0 1

WELL TEST DATA ACQUSITION PROCEDURE The following is the procedure for gathering well test data: 1) 2) 3) 4) 5) 6)

7) 8)

9) 10)

11)

12) 13) 14)

15) 16) 17)

Monitor all data points with the electronic surface data acquisition system as shown in Table 13-a. Take manual separator and manifold readings every 30min during the well test and as directed during clean-up. Flow to the gauge tank for liquid flow rates and meter calibration. Take manual H2S and CO2 Draeger readings every hour during the clean-up. Maintain detailed records on all well flow characteristics and operational changes with description, e.g. ‘fluid to surface’, ‘direct flow to test equipment’ etc. Take BS&W BS&W samples every 30min and the mud logger is is to perform laboratory analysis of water for chlorides and any other ions such as Ca, Mg, sulphates, TDS, pH and density. Record the specific gravity of the gas, oil and condensate every 30min. 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. Make detailed records and complete the sample forms to give type of sample, well parameters, at sampling time, time sample take, bottle numbers etc. Dispatch all PVT samples immediately for analysis. Collect other fluids samples as detailed in the Well Testing Programme. Dispatch these to the district warehouse for storage until their disposition is decided. During a water test, collect water samples every hour during clean-up clean-up and stable flow periods and perform onsite analysis, initially to monitor clean-up from contaminated to true formation water and then to confirm the continued production of clean formation water. Onsite analysis is to be conducted to check for chloride and equivalent sodium chloride levels, sediment, resistivity, pH, total dissolved solids and specific gravity. Collect samples of true produced formation water water in plastic or pressurised containers, as instructed by the Reservoir Department for laboratory analysis. Dispatch as per step 6) above. Foreign or unidentified materials produced from the well should be kept in a marked up plastic sample packet for onshore analysis. All samples must be clearly identified and logged. 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). Monitor sand production by sand detection system and take samples as necessary. Take manual pressure and temperature readings upstream and downstream of of the choke, initially every five minutes, during the clean-up. Monitor bottomhole flowing and shut-in pressures and temperatures with surface readout system as appropriate.

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14.

SAMPLING

14.1

CONDITIONING THE WELL

0 1

The well should be conditioned prior to sampling to ensure representative reservoir fluids are being produced. The well should be flowing in a stable state, with correspondingly stable separator readings for at least 6 hours before the start of any sampling. The stability of the well may be determined 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 separator sampling. Care should also be taken to ensure the well flow rate is in excess of the minimum at which liquid fallback in gas wells occurs, otherwise surface samples will not be representative. This rate 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 and should probably not be taken. Surface sampling can be undertaken if the well is producing water but downhole sampling is not recommended.

14.2

DOWNHOLE DOWNHOLE SAMPLING After the th e well has been conditioned, it should be either e ither shut-in shut -in or left to produce at a very low flow rate. At least two bottomhole samplers in conjunction with a pressure and temperature gauge are installed in the well on wireline. A short pressure and temperature gradient survey must be performed above the sampling point e.g. at five different depths with 100ft intervals. This is to determine whether whether the sample taken will have been in single phase, i.e. below the level at which gas may be breaking out of solution, or above the OWC. Ideally, the sampling point should be above the perforations. When the samplers are on depth, the samples are taken and the pressure and temperature at the sampling depth will be recorded by the gauge at 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 the scheduled 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 the shipping/storage bottles. The quality of each sample should be checked by bubble point determination. It is recommended that at least two runs be made with two samplers each run and that at least one sample is transferred at 100°F using a heating element. If possible, each sample should be transferred similarly to ensure that no wax is left on the wall of the container. If not, this sample should be marked separately.

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0 1

Depending on conditions, sampling should continue until consistent quality checks are obtained on two separate samples. Note:

All sampling shoul d util ise mercury-free syst ems and pist on type sample bottles for s afety afety of p ersonnel.

For long term storage of Eni E&P samples, all well effluent samples should be transferred to Teflon 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 the laboratory. 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 at the 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) 2)

3)

4)

5)

6)

Sample bottles should be made ready by having the gas bottles checked to ensure that they have an absolute vacuum and plugs available for each port. 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 be checked to make sure that there is no air present, as this can give extraneous readings when measuring the fluid flow whilst sampling is in progress. This will cause problems later when an attempt is made to determine the pressure (Pb) in the PVT laboratory. The sampling manifolds should be prepared with with gauges to suit the expected sampling pressure already fitted. Liners should be cleansed and made ready. An oil sample bottle stand should be readily available, together with a 600cc measuring cylinder. Sampling manifolds should be kept as simple as practically possible with as small an internal volume as is reasonably possible but with liners that are long enough to avoid any possibility of straining the connections to the sampling point and to the sampling manifold. A bucket of clean water and a supply of rags should also be readily available for leak testing full sample bottles and for wiping clean the bottles before shipping to the PVT laboratory. For gas, sampling should be conducted using evacuated sample bottles. These are clean and easy to use, as no flushing is required, hence contamination is unlikely. A vacuum pump is required and care should be taken that no valves become plugged with hydrates. Oil should be sampled using piston bottles. These are clean, easy to use, have a known volume and are mercury-free. They are also relatively easy to use in forming the gas cap for safety during transportation.

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IDENTIFICATION CODE

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92

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115



7)

All samples must be labelled immediately after being taken using Eni E&P sample labels, if available. The following information must be recorded: • • • • • • • • •

8)

9)

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.

All samples should be loaded into into an empty container and shipped to base as soon after the test as possible. Record on the morning report, the container in which the samples are being shipped to shore. Do not ship all samples in one container; split samples into two representative batches and ship in separate containers. It is vital when taking samples that any problems are recorded, highlighted and fully documented.

Note:

14.3.2

0 1

More specific sampling requirements may be detailed on indivi dual well testing programmes.

SAMPLE QUANTITIES

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

1,500scf/stb

= 1:1

GOR

1,500scf/stb, but less than 3,000scf/stb

= 3:2

3,000scf/stb

= 2:1

greater than

GOR greater than

14.3.3

SAMPLING POINTS

The sampling points on a separator should be very carefully chosen as samples taken from the 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.

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•

Note:

0 1

Ideally the sampling sampling point should protrude into the centre of the gas flowline and face upstream. However, a pipe into the stream is acceptable. The sampling point should not be on the lower half of the flow line cross section, due to any possibility of free liquid/liquid carryover being present. If the sampling point has to be fitted flush to the inside surface of the flowline then it is preferable that it is on the top of the line and not on t he side.

The oil sampling point should be: • • •

• •

Note:

14.3.4

As close as possible possible to the exit exit of the oil flowline from the main vessel and upstream of meters. Not immediately downstream of thermal well or bends in the flowline. Ideally the sampling point should protrude into into the centre of the flowline with the mouth facing upstream. However a pipe into the centre of the flowline is acceptable. It should be upstream of any increase in flowline diameter. It is is preferable that samples are not taken from the bottom of the oil oil sight glass, as the level in the sight glass does sometimes falls, especially if there is much rig movement which can allow free gas to enter the sampling line. The sampling point should not be on the upper half of the flowli ne cross section, due to any possibility of there being free gas. If the sampling point is on the wall of the flowline then it is preferable that it is on the side, rather rather than on the top or the bottom, due to possibilit y of free gas or water being in th e flowli ne.

SURFACE GAS SAMPLING

The following is the procedure for taking a gas sample: 1) 2) 3) 4)

Note:

Any flushing should be done through a hose directly downwind, or to sea level, to prevent any risk of poisoning due to gasses such as H2S. Record the bottle number. It iis s 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. 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 14-1). The manifold valve (V3) should then be opened slowly to test for any leaks. If there is a leak, then close the manifold valve, and remake the connections to the bottle. No manifold or gauge shoul d be attached to the second valve (V2) (V2) under any circumstances. This is to prevent the loss of any of the heavier heavier compo nents of t he gas that might have condensed in the bott le when exposed to a vacuum.

SPEO

IDENTIFICATION CODE

PAG

94

OF

115



5)

6)

7) 8) 9)

10)

11) 12)

14.4

0 1

The bottle valve (V1) may now be slowly cracked open. Even Even with the noise around a separator, it is still quite easy to hear the gas ‘hissing’ into the bottle and this can also be heard even when wearing a BA set. Sometimes the gauge needle can be seen to slightly dip on the initial opening. If there is just one gas bottle being filled to one oil bottle, then the sampling sampling time should be about 30 minutes. This length of time means there is less chance of an invalid sample being taken. If the ratio of gas samples samples to oil samples is greater that 1:1, then the fill time should should be worked out to still allow the oil samples to take about 30 minutes. When the sample bottles are full and the sampling time has elapsed, shut the bottle valve (V1) and the valve on the separator sampling point (V3). Record the pressure on the gauge, and bleed off about 30psi (using V4) then open the bottle valve (V1). The gauge should now read the original sampling pressure. If it doesn’t then check the manifold and the bottle valve for blockages or icing-up. If possible clear the obstruction, take up a fresh bottle, and re-sample both the oil and gas samples. If the pressure returns to near the original, then the sample is good and the separator sampling point valve (V3) may be reopened for a few moments to allow the pressure in the bottle to return to the sampling pressure. Record the final sampling pressure and temperature, as they will will be needed for the sampling sheets. The bottle and manifold valves (V1, V3) may now be closed, and the connecting line broken. Plug the valves, valves, and both valves checked checked in a bucket of water for any leaks. Now place the bottle safely aside. Prepare for the next bottle for sampling.

SURFACE OIL SAMPLING The following is the procedure for taking an oil sample (a piston sample bottle is the preferred option for liquid sampling): 1) 2) 3) 4) 5)

First record the bottle number. The piston piston s sample ample bottle should be stood in its custom built stand provided for the purpose. The top manifold should be flushed to ensure that the line to the manifold and the manifold filled with fresh fluid from the flowline. The manifold may now be connected to the top valve (V1) on the sample bottle. 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 pressure slightly in excess of the sampling sampling pressure. This stops the piston moving moving as soon as the bottle top valve is opened, so preventing any oil from flashing into the bottle. It also acts as a double check to ensure that the piston is still at the top of the bottle.

SPEO

IDENTIFICATION CODE

PAG

95

OF

115



6)

The next step may be performed in one of two ways: •

•

7) 8)

9) 10)

11)

12) 13)

14) 15)

14.5

0 1

Open the top manifold 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 the top of the bottle) and slowly crack open the evacuation port (V6). This flushes the initial flow of oil and gas which flashed into the bottle. Flush approx. 50cc of fluid then close the evacuation port (V6). Remove the line and refit the plug, ensuring that it is tight. Connect a vacuum pump to the evacuation port (V6) and check that there is still an absolute vacuum. Ensure that the top manifold valve (V3) is closed . Open the top bottle valve (V1) and evacuate the short line from the top manifold (V3) to the top 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 manifold into 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 30 minutes to collect a 600cc sample (20cc /minute).

Remember that this sample must be taken in conjunction with the gas sample. 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 disconnect the top manifold from the bottle and plug the top bottle valve (V1). The sample is now consolidated. A gas cap should now be formed to permit permit the safe shipping and storage of the bottle. This is done by removing a portion of the buffer fluid equal equal to 10% of the sample volume. This is called the Ullage. The final pressure and temperature should now be recorded. This is vital for the laboratory as it informs them what conditions to expect when they analyse the sample and how much buffer fluid to inject to enable them to match the sampling conditions. The bottom bottle valve valve (V2) should now be closed and the pressure in the bottom manifold valve bled off before removal. Fit a plug to the bottom valve valve (V2). Check the integrity integrity of the valves and plugs by immersing the bottle in a bucket of water and checking for bubbles. Remove from the water, dry the bottle and fit the protective end caps. Now place the bottle in its box and set set aside. Prepare the next bottle for sampling.

SAMPLE TRANSFER AND HANDLING Detailed instructions on shipment of samples from the rig, shore addressee(s) for the samples, location of temporary and/or permanent storage facilities and instructions on subsequent analysis of samples will be included in the Well Test Programme, or issued with separate instructions.

SPEO

IDENTIFICATION CODE

PAG

96

OF

115



0 1

Figure 14-1 - Surface Sampling Typical Installation

14.6

SAFETY All equipment must be pressure tested and appropriately app ropriately 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 all relevant personnel before starting and after completing the pressure testing. All non-essential personnel has to be kept away.

Safety Gear

Safety glasses and gloves must be worn.

Comments

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

SPEO

IDENTIFICATION CODE

PAG

97

OF

115



14.6.2

14.6.3

14.6.4

0 1

RIGGING UP SAMPL ERS 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 no pipe wrenches are to be used on the tool. The sampling engineer will supervise the tool handling.

RIGGING DOWN SAMPL ERS 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 be required 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 no pipe wrenches are to be used on the tool. Any source of ignition has to be kept away. The sampling engineer will supervise the tool handling.

BOTTOMHOLE SAMPLE TRANSFER AND VAL IDATIONS

Work Scope

High pressure transferring and validation of sub-surface samples from tools to high pressure storage cylinders.

Work Area

Indoors, well lit with a 100psi air supply, stable temperature and away from any sources of ignition. Rope off the area and post pressure testing signs. Inform all relevant personnel before starting and after completing the transfers or validations. All non-essential personnel are to be kept away.

Safety Gear

Safety glasses and gloves must be worn.

Comments

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

SPEO

IDENTIFICATION CODE

PAG

98

OF

115



14.6.5

14.6.6

0 1

SEPARATOR/WELL HEAD SAMPLING

Work Scope

High pressure transferring of hydrocarbons from separator to high pressure storage cylinders.

Work Area

Well test area and rig floor. Rope off the area and post pressure testing signs. Inform all relevant personnel before starting and after completing the sampling. All non essential personnel has to be kept away.

Safety Gear

Hard hat, boots, coveralls, safety glasses, ear protection and gloves must be worn.

Comments

When high pressure oil or gas samples are obtained, leaks are highly unlikely but possible, thus there must be no sources of ignition in vicinity and no non-essential personnel in area. If H2S is present, normal H2S operating procedures are to be followed, i.e. breathing apparatus, buddy system etc. Work duration of personnel will not generally exceed 18hrs.

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 being flammable high pressure oil or gas samples.

SPEO

IDENTIFICATION CODE

PAG

99

OF

115



15.

0 1

WIRELINE WIREL INE OPERATIONS Although sometimes operationally necessary, wireline operations, both slickline and electric wireline, carry an inherent risk which is even greater on an offshore exploration well test due to the configuration of the test string and the well conditions. If possible, running wireline through the test string and especially the annulus pressure operated tester valve should be avoided. 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, to cater 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 between a slickline and electric line rig up is that double BOPs and a grease flowtube must be used to achieve a seal on a braided cable.

SPEO

IDENTIFICATION CODE

PAG

100

OF

115



16.

0 1

HYDRATE PREVENTION Hydrates are complexes formed spontaneously by the combination of hydrocarbon gas mixtures with free water under certain conditions of temperature and pressure. Physically they are ice-like solids which can completely plug downhole tubing and/or surface lines. Hydrates can form under either flowing or static conditions. The first indication of hydrates forming in the tubing is a drop in flowing wellhead pressure, followed by an initially slow but accelerating drop in wellhead flowing temperature. The formation of hydrates can be predicted and then prevented. The understanding of the conditions under which they will form plays a key role. These conditions are certain ranges of pressure and temperature, with free water present. Under flowing conditions the expansion downstream of a choke or other restrictions give a favourable regime for their formation. Under conditions of no flow they can form as a kind of snow on the walls walls of tubing. A downhole hydrate plug is potentially dangerous dan gerous and a nd should be avoided a voided at all costs. The area of most risks is in the string from the seabed upwards where the lowest temperature usually occurs. It is of great importance to check the wellhead temperatures at frequent intervals and immediately 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, pump facilities 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 continuously into the vertical run of the flowhead as well as at the Sub Sea Test Tree.

SPEO

IDENTIFICATION CODE

PAG

101

OF

115



17.

0 1

NITROGEN OPERATIONS The main use of nitrogen on an exploration well test is to introduce a partial nitrogen cushion into the test string by displacing the tubing contents through a tubing-annulus differential pressure-operated circulation valve into the annulus. Fluid returns must be monitored to ensure no nitrogen is allowed into the annulus. The nitrogen cushion pressure can be rapidly reduced to give a very large drawdown when perforating underbalance or bringing on a well that had already been perforated overbalance. This would be useful on tight or depleted reservoirs. It could also be used for detonating TCP guns using a hydro-mechanical firing device operating at a given tubingannulus differential by holding the annulus pressure and bleeding away the nitrogen cushion pressure. Alternatively, with the t he well open, o pen, the nitrogen could be bled off very slowly to minimise the drawdown, for instance, on poorly consolidated sand. The disadvantage with this is that it is uncertain what is occurring downhole while the nitrogen is bled off. However the advantage is, if the well does not flow to surface, the tubing contents can be reverse circulated out of the well to determine what the influx was, and, if needed, a second nitrogen cushion could be circulated into, placed in another attempt to bring the well in. If this failed, the well would have to be gas lifted using a coiled tubing unit.

SPEO

IDENTIFICATION CODE

PAG

102

OF

115



18.

0 1

COILED TUBING OPERATIONS OPERATIONS Coil tubing is a method by which continuous small diameter pipe can be run into a well; in well testing operations, coil tubing is used for the following applications: • • • • •

Spotting acid To displace lighter fluid in the tubing to reduce hydrostatic weight before perforating Through tubing gravel pack Paraffin and salt removal with chemical, hot oil or hot water Sand washing.

The equipment consists of a modular lightweight skid mounted design, allowing for easy lifting and quick connection on site. A coil tubing unit is made up of 5 basic components: • • • • •

Hydraulic power-drive unit Control console Coiled tubing reel Injector head Blow out preventer stack.

The heart of the coiled tubing unit is the injector head which is connected to the flowhead through the blow-out preventer and stuffing box. Injector heads are designed to perform three basic functions: • • •

Provide the thrust to snub coil tubing into into the well against pressure or to overcome wellbore friction. Control rate of tubing entry into the well under various well conditions. Support the full suspended weight of coil tubing when kept stationary.

The BOP stack is composed of four hydraulically operated rams, generally rated for a minimum working pressure of 10000 psi. The four BOP compartments are equipped with blind rams, tubing shear rams, slip rams and pipe rams. 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 parameters such as the expected well pressures and temperatures, internal pressures on the tubing, hole angles, depths and tubing data etc. In well testing operation with sub-sea test tree when coiled tubing is to be run, it is essential that the sub-sea test tree is dressed to be capable of cutting, whatever the size of the tubing.

SPEO

IDENTIFICATION CODE

PAG

103

OF

115



19.

WELL KILLING KIL LING ABANDO AB ANDONME NMENT NT

19.1

WELL KILLING KIL LING

0 1

There are a number of methods for conducting a well killing operation in a well test situation, dependent upon the well hardware and configuration, taking into account of any well problems which have arisen. However, the two main methods under normal circumstances are ‘Reverse Circulation’ and ‘Bullheading’. For these two main and other specific metods of well killing refer to “Completion Procedure Manual STAP-P-1-M-7120 section 17.4.1 ”.

19.2

WELL KILLING KIL LING ABANDONMEN AB ANDONMENT T For details on well abandonment procedures refer to “Drilling Procedures Manual STAPP-1-M-6140 section 18 ”.

SPEO

IDENTIFICATION CODE

104

PAG

OF

115



20.

0 1

HANDLING OF HEAVYWATER BRINE Both CaBr 2/CaCl2, as brine and powder can cause skin irritation and even blistering if allowed to remain in contact with the skin. It is therefore important that personnel involved in work where 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 hoods

c)

Rubber boots (leather boots are shrivelled by the brine)

d)

Full face masks for use when mixing powdered CaBr 2/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 affected clothes should be changed and washed forthwith. Never allow brine to dry on the skin or clothes. If brine is splashed into the eyes, wash the eyes at once with copious amounts of fresh water.

SPEO

IDENTIFICATION CODE

105

PAG

OF



0 1

Ap p end i x A - Repo r t For Fo r m s A.1.

Daily Report (ARPO 02)

DAILY REPORT

WELL NAME

Drilling

FIELD NAME

District/Affiliate Company

ARPO ARPO 02

DATE:

RT RT Elev ation

Rig Name

Cost center [m]

Ty Ty pe of Rig

Ground Lelel / Water Depth

[m]

Co Contr ac tor

RT - 1st fl f lange / Top Hous ing

[m]

Well

Last Last casi casing ng

BOP

Next ext Casin asing g

Type

Ø

w .p. [psi] [psi]

Well Code Report N°

of

Per mit / Conc es s ion N° M.D. .D. (24:00 (24:00))

[m] [m]

Ø nom.[in]

Stac k

T.V .D. ( 24:00)

[m]

To Top [m]

Div er ter

Total Dr illed

[m]

Bo Bottom [m]

A nnular

Rotating Hrs

[hh:mm]

To Top of Cmt [m]

A nnular

R.O.P.

[m / h]

Upper Rams

Pr ogres s iv e Rot. hrs

[hh:mm]

Middle Rams

Bac k reaming Hr s

La L as t Surv ey [°]

at m

LO L OT - IFT [kg/l]

at m

Reduce Pum Pum p Strock Strock es Press ure

Pump N°

Middle Rams

[hh:mm]

Pe r s o n n e l

In j u r e d

Mi Middle Rams

A gip

A gip

Li Liner [in]

Low er Rams

Rig

Rig

St Strokes

Las t Tes t

Others

Other

Total

Total

1

2

3

Pr Press . [ps i]

Lithology Shows

From (hr) (hr) To (hr (hr)) Op. Cod ode e OPERATION DESCRIPTION

Operation at 07:00 M u d t y p e

Density Vi Vis cos ity P.V . Y.P.

Bi t

[kg/l] [s/l] [ cP cP] [g/100cm2]

IA DC Diam.

HP HP/HT Pr Press .

[c c /30"] [kg/cm2]

Noz z le/TFA From rom [m] [m]

Te Temp. Cl-

[°C] [g [g/l /l]]

Sa Salt

[g/l]

Rot. Hrs .

[kg/m3]

R.P.M. W.O.B.[t]

Run N°

Bottom Hole Ass em bly N° _____ ________ _____ __

Description

Ø

Part. art. L

Rot. hours Progr rogr.L .L Parti artial a l Progr rogr..

To [m] Drill rilled e d [m] [m]

So lid Oi Oil/w ater Ratio.

[ %] %]

Flow Ra tte e Pres s ur e

Sa Sand pm pm/pom pf pf

[ %]

A nn. v el. Jet v el. HHP Bit

mf mf

N°

Manuf .

/ [c c /30"]

Da Daily Los s es Progr. Losses

Run N°

Ty pe pe Seri Serial al No.

Ge Gel 10"/10' Wa Water Los s

pH pH/ES MBT

N°

Data

Stock

Total Cost

HSI [m3] I [m3] B

O

D

L

I

O

D

L

Daily

G

O

R

B

G

O

R

Progr.

Quantit y

UM

Supervisor:

Supply vessel

115

SPEO

IDENTIFICATION CODE

PAG

106

OF



A.2.

0 1

WELL TEST REPORT REPORT “ General Data” (ARPO 10/A) 10/A)

WELL TEST TEST REPORT

WELL NAME

(General Data)

FIELD NAME

District/Affiliate Company: ARPO 10/A

DATE:

SINGLE COMPLETION

SELECTIVE

DUAL COMPLETION We Wel l Co de

Tes t N° End Dat e

WELL SK ETCH

Formation Name Pool Lithology Gener al d at a

RKB Elevation @ m.

Base Flange

Tbg Spool

W eight (lb/ft)

From m

To m

Li Liner Size OD

W eight (lb/ft)

From m

To m

Tu Tubing Size OD

W eight (lb/ft)

From m

To m

Tu Tubing Size OD

W eight (lb/ft)

From m

To m

Tu Tubing Shoe Ø

@ m.

Pa Packer Type

@ m.

Pa Packer Type

@ m. Com p l et i o n Fl u i d

Pac k er Fl u id

Ty Type Density [kg/l] Na N aCl (g/l)

Type Density [kg/l] pH

NaCl (g/l)

pH

Yes

Acid Job Perfor med

No

Op Open Hole

From (m)

To (m)

Slotted Casing

From (m)

To (m)

Gravel Paking

From (m)

To (m)

Perforation

W ire Line

T.C.P.

Underbalance

Gu Gun Size

Shoots / ft

Ch Charge Type

On date

From (m)

T o (m)

From (m)

Remarks

Su Supervisor

SHORT STRING LONG STRING

St St ar t Dat e

Casing Size OD

Cost center center

Superintendent

To (m)

115

SPEO

IDENTIFICATION CODE

107

PAG

OF

115



A.3.

0 1

WELL TEST REPORT REPORT “ DST Data” (ARPO 10/B) 10/B)

WELL TEST REPORT

WELL NAME

(DST Data)

FIELD NAME

District/Affi liate Company: Company: ARPO 10/B

DATE: We Wel l Cod e:

Tes t N°:

St ar t Dat e

Depth

Lenght

(m)

(m)

Su Su p er v i so r Co Co mp l et i o n

Wo r k ov er

Cost center center

Equipment Description

En d Dat e I.D.

O.D.

(mm)

(mm)

Sup er in t en dent

Capacity (l)

SPEO

IDENTIFICATION CODE

PAG

108

OF



A.4.

WELL TEST REPORT REPORT “ Record Recor d Data” (ARPO 10/C) 10/C)

0 1

115

SPEO

IDENTIFICATION CODE

109

PAG

OF



A.5.

0 1

Waste Report (ARPO 6)

WASTE DISPOSAL

WELL NAME

Management Management Report

FIELD NAME


ARPO-06 Cost center

DATE:

Re Report N°

Depth (l m) ill

Mud T i ype l 3

Drilled Volume [m ]

To [m]

Cl- concentration (g/l ) 3

Cumulative volume [m ]

Phase size [in]

3

Us U s age

3

Phase /Period [m ]

Water consumption

Fresh water

Recy cled

Cumulative [m ] Total

Fresh wat er

Rec ycled

Total

Mixing Mud Others Total

3

3

Fresh water [m ]

Readings / Truck

3

Mud Volume [m ]

Phase

Cumulative

Recycled [m ]

Service

Mi Mixed

M ud Company

Lo L ost

Waste Disposal

Dumped

Company

Contract N°

T ransportation

Transported IN Transported OUT

Waste Disposal

Period

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]

Cumulative

Remark s

Remarks

Supervisor

Superintendent

115

SPEO

IDENTIFICATION CODE

PAG

110

OF



A.6.

0 1

Well Prob lem Report (ARPO (ARPO 13)

WELL PROBLEM REPORT


ARPO ARPO -13

DATE: Problem Code Well

Ø

Situation

WELL WELL NAME

Cost center

Top [m]

Star t date

Bottom [m]

End date

Meas ur ed Depth Top [m]

FIELD NAME

V er tical Depth

Bottom [m]

Top [m]

KOP

Bottom [m]

Op Open hole

[m]

Mud in hole

Max inc lination [°]

Ty pe

@m

La Las t c as ing

Dens .[kg/l]:

DROP OFF [m]

Well problem Description

So So l u t i o n s A p p l i e d :

Re s u l t s Ob t ai n e d :







Su Super vis or

Super v is or

Super v is or

Remarks at District level:

Superintendent L Lo os t Time Rem Rem arks at HQ HQ level

hh:mm Los s v alue [in c ur r ency ] Pag. Of

115

SPEO

IDENTIFICATION CODE

PAG

111

OF

115



A.7.

0 1

Malfunction & Failure Report (FB-1) MALFUNCTION & FAILURE REPORT (FEED BACK REPORT 01)

District/Subsidiary Report Date:____________________ Well Code: Genera Generall Information Contract Type: Contractor:

Well Name: Contract No: Service/Supply: Drillin g

Completi on

Workove r

Duration Dates of Failure:

Distributed By:

RIG SITE Description of Failure:

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

Contractor Contingency Measures:

Contractor Representative: DISTRICT OR SUBSIDIARY NOTES:

Failure Classification Technical Management/Organisation Safety/Quality

Status

Operations Manager: Normal Extreme Innovative Adverse

Time Lost: Estimated Cost of Failure:

MILAN HEAD OFFICE NOTES:

Analysis Code:

SPEO

IDENTIFICATION CODE

PAG

112

OF

115



A.8.

0 1

Contractor Evaluation (FB-2) CONTRACTOR EVALUATION (FEED BACK REPORT 02)

District/Subsidiary Report Date:__________________ Well Name: Name: Well Code: Genera Generall Information Contract No.: Contract Type: Contractor: Service/Supply: Distributed By: R1 Technical Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (€M): Category Evaluation Score (0-9) Suitability of Equipment and Materials Compliance of Equipment and Materials to the Adequacy of Personnel Meeting with Operational Programme Meeting with Contract Operation Timings Equipment Condition/Maintenance R2 Management and Organisational Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (€M): Category Evaluation Score (0-9) Availability of Equipment and Materials Technical and Operational Support to Capability and Promptness to Operational R3 Safety and Quality Assurance Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (€M): Category Evaluation Score (0-9) Meeting with the Contract Agreement DSS Availability and Validity of Requested Meeting with Contract Quality Assurance Event Event Support Documentation Type of Subject: Issued By: Document:

Notes: Failure Status

Normal

Extreme

Operations Manager Adverse

Drilling & Completions Manager

Innovative

Date:

SPEO

IDENTIFICATION CODE

PAG

113

OF

115



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Ap p end i x B – Ab b r evi ati at i o ns AC/DC API BG BHA BHP BHT BMT BOP BPD BPM BPV BS&W BUR C/L CBL CCL CDP CET CGR CR CRA C/T DC DE DHM DHSV D&CM DP DPHOT DST E/L ECD ECP EMS EMW DE DHM DHSV D&CM DP DPHOT DST

Alternate Current, Direct Current American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom Hole temperature Blue Methylene Test Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment and Water Build Up Rate Control Line Cement Bond Log Casing Collar Locator Common Depth Point Cement Evaluation Tool Condensate Gas Ratio Cement Retainer Corrosion Resistant Alloy Coiled Tubing Drill Collar Diatomaceous Earth Down Hole Motor Down Hole Safety Valve Drilling & Completion Manager Drill Pipe Drill Pipe Hang off Tool Drill Stem Test Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight Diatomaceous Earth Down Hole Motor Down Hole Safety Valve Drilling & Completion Manager Drill Pipe Drill Pipe Hang off Tool Drill Stem Test

E/L ECD ECP EMS EMW EP ESD ESP ETA FBHP FBHT Temperature FPI/BO FTHP FTHT Temperature GLR GOC GOR GP GPM GPS GR HAZOP HHP HO HP/HT Temperature HW/HWDP IADC IBOP ID IPR JMA JM A L/D LA T LC 50 LCM LEL LN LOT

Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight External Pressure Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Flowing Bottom Hole Pressure Flowing Bottom Hole Free Point Indicator / Back Off Flowing Tubing Head Pressure Flowing Tubing Head Gas Liquid Ratio Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Hazard and Operability Hydraulic Horsepower Hole Opener High Pressure - High Heavy Weight Drill Pipe International Association of Drilling Contractors Inside Blow Out Preventer Inside Diameter Inflow Performance Relationship Joint Make-up Torque Analyser Lay Down Lowest Astronomical Tide Lethal Concentration 50% Lost Circulation Materials Lower Explosive Limit Landing Nipple Leak Off Test

SPEO

IDENTIFICATION CODE

PAG

114

OF

115



LCDT LQC LTA M/D M/U MAASP MD MLH MLS MMS MODU MPI MSCL MSL MUT MW MWD NACE NDT NSG NTU OBM OD OH OIM OMW OWC P&A P/U PBR PDM PI PLT POB POOH PPB PPG Ppm PVT Q Q/A Q/C Control

Last Crystal to Dissolve oC Log Quality Control Lost Time Accident Martin Decker Make Up Max Allowable Annular Surface Pressure Measured Depth Mudline Hanger Mudline Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Magnetic Particle Inspection Modular Single Completion Land Mean Sea Level Make up Torque Mud Weight Measurement While Drilling National Association of Corrosion Engineers Non Destructive Test North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Open Hole Offshore Installation Manager Original Mud weight Oil Water Contact Plugged & Abandoned Pick up Polished Bore Receptacle Positive Displacement Motor Productivity Index Production Logging Tool Personnel On Board Pull Out Of Hole Pounds per Barrel Pounds per Gallon Part Per Million Pressure Volume Temperature Flow Rate Quality Assurance, Quality

R/D R/U RBP RCP RFT RIH RKB ROV RPM RT S/N SBHP SBHT SCC SDE SF SG SICP SPM SR SRG SSC TCP TD TG TGB TOC TOL TVD UR VBR VDL VSP W/L WBM WC WL WOC WOW WP YP

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Rig down Rig up Retrievable Bridge Plug Reverse Circulating Position Repeat Formation Test Run In Hole Rotary Kelly Bushing Remote Operated Vehicle Revolutions Per Minute Rotary Table Serial Number Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Senior Drilling Engineer Safety Factor Specific Gravity Shut-in Casing Pressure Stroke per Minute Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Tubing Conveyed Perforations Total Depth Trip Gas Temporary Guide Base Top of Cement Top of Liner True Vertical Depth Under Reamer Variable Bore Rams (BOP) Variable Density Log Velocity Seismic Profile Wire Line Water Base Mud Water Cut Water Loss Wait On Cement Wait On Weather Working Pressure Yield Point

SPEO

IDENTIFICATION CODE

PAG

115

OF



0 1

Ap p end i x C – Bi B i bl i og r aph y Eni E&P Document

Document code

Drilling Procedures Manual

STAP-P-1-M-6140

Completion Design Manual

STAP-P-1-M-6110

Well Control Policy Manual

STAP-P-1-M-6150

115

ENI Well Test Procedures Manual

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