CR FPP 510 REV01 Well Testing (DST Case)
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Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 2 of 33
Contents 1. RECAP OF RULES ............................................................................................... 5 2. FOREWORD ......................................................................................................... 8 2.1
CLARIFICATION .......................................................................................................... 8
2.2
INDICATOR.................................................................................................................. 9
2.3
GLOSSARY.................................................................................................................. 9
3. ORGANISATION AND RESPONSABILITIES .................................................... 10 3.1
STATE OF REQUIREMENT (SOR)-/ PROGRAM ELABORATION ........................... 10
3.2
TESTS DATA ACQUISITION ..................................................................................... 11
3.3
PROGRAM MODIFICATION ...................................................................................... 11
3.4
RESPONSIBILITIES DURING OPERATIONS ........................................................... 11
4. WELL DESIGN: SPECIFIC POINTS................................................................... 12 4.1
INTEGRITY OF THE STRUCTURAL ENVELOPE ..................................................... 12
4.2
WELL ARCHITECTURE – CEMENT QUALITY ....................................................... 13
4.3
TUBING ANNULUS FLUID ........................................................................................ 13
5. BASIC OPERATIONAL CONSIDERATIONS ..................................................... 14 5.1
DST WITH A DP VESSEL .......................................................................................... 14
5.2
RUNNING IN AND PULLING OUT THE TEST STRING............................................. 14
5.3
EQUIPMENT PRESSURE TEST ................................................................................ 15
5.4
NIGHT OPERATIONS ................................................................................................ 15
6. TESTING PROGRAM / REPORT CONTENTS ................................................... 16 6.1
TYPICAL PROGRAM ................................................................................................. 16
6.2
TYPICAL TESTING REPORT .................................................................................... 16
7. EQUIPMENT SELECTION .................................................................................. 17 7.1
PERFORATIONS EQUIPMENT ................................................................................. 17
7.2
TUBING STRING ....................................................................................................... 18
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 3 of 33
7.3
BOTTOM HOLE DST TOOLS .................................................................................... 18
7.4
SUBSURFACE DST SAFETY VALVES..................................................................... 19
7.5
RIG FLOOR DST EQUIPMENT.................................................................................. 21
7.6
TEMPORARY PROCESS FACILITIES ...................................................................... 23
8. SPECIFIC OPERATIONS.................................................................................... 29 8.1
WL & CT OPERATIONS THROUGH THE TEST STRING ......................................... 29
8.2
OPEN HOLE TESTING .............................................................................................. 31
8.3
DP VESSEL: STATION KEEPING AND DISCONNECTION...................................... 32
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 4 of 33
Reference documents Unless otherwise stipulated, the applicable version of the reference documents listed below, including relevant appendices and supplements, is the latest revision published. Standards Reference
Title
Not applicable
Professional Documents Reference
Title
Not applicable
Regulations Reference
Title
Not applicable
Codes Reference
Title
Not applicable
Other documents Reference
Title
Not applicable
Other Total documents Reference
Title
Not applicable
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 5 of 33
1. RECAP OF RULES Blue color for rules to apply for offshore operations only, green color for rules to apply for onshore operations only and black for rules for all situations. Rule 1:
If a drilling phase was performed through the Production/Test casing, this string and associated wellhead must be pressure tested again at MEWHP just before well testing operations start.
Rule 2:
BOP’s will be pressure tested at MEWHP just before DST, independently of the pressure test frequency applied during the drilling phase.
Rule 3:
If a brine is used to perform the test, density of this brine will be selected to keep at least an overpressure of 150 psi above the anticipated formation pressure at the most critical production depth.
Rule 4:
Tubing string from the flowhead down to the circulating valve, kill line and flowline up to the choke manifold shall be pressure tested to 110% of the MEWHP during formation testing. MEWHP is given by the maximum WH shut in pressure plus the overpressure for bullheading; if not known, this overpressure will be taken at 500 psi in case of dry gas, 1500 psi if oil is expected Production path from the choke manifold up to the burning system shall be water tested with regard to the different service pressures of components.
Rule 5:
“Sour service” material should systematically be selected for a test tubing except if H2S risks have been proven to be insignificant. 100% connections tensile efficiency shall be selected for well test tubing application.
Rule 6:
For the tubing string, the following design factors shall apply on the worst case:
Burst Collapse Tensile strength Triaxial strength
1.25 1.25 1.60 1.37
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rule 7:
Rev: 01
Date: 15/10/2003
Page: 6 of 33
For all applications, the DST tools minimum features are:
Sour service. Two Downhole closure devices: (one tester valve + one single shot safety valve). Two Circulating devices : (one reversible tool + one single shot tool). Elastomers qualified for expected fluids and temperature conditions.
Rule 8:
To perform DST from a floating rig, hydraulically or electro-hydraulically surface controlled dual fail-safe closing valves (two ball valves or one ball valve + one flapper valve) equipped with an hydraulic connector (Latch) must be installed in the BOP stack (SSTT).
Rule 9:
To perform DST from a floating rig, a fail safe type hydraulically or electrohydraulically surface controlled retainer valve must be incorporated above the SSTT when: The landing string internal volume is greater than 1m3 Significant effluent GOR is expected (above 200 m3/m3).
Rule 10: The lateral production valve (wing) on the flowhead of a DST string must be hydraulically operated, failsafe closed and connected to the Emergency Shut Down system (ESD). ESD control buttons must be installed one on the rig floor, one in the driller’s cabin and one on the DST layout. A hydraulic cutting valve must be installed in addition when WL is foreseen.
Rule 11:
Use of chiksans or fixed (or temporary secured) hard piping is prohibited on production line between the flowhead and the production manifold. A correctly rated HP hose shall be used. Downstream the production manifold: All temporary-piping sections must be secured to rig structures. Permanent rig production hard piping must be inspected, with valid certification and stamp tagged.
Rule 12:
On a land rig the use of atmospheric tanks is prohibited if H2S is expected.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 7 of 33
Rule 13: Indirect heater is not permitted on offshore rigs; only steam exchanger associated to a dedicated steam generator (water boiler) must be used. The drilling rig steam supply will not be used.
Rule 14:
Use of atmospheric tank is prohibited on offshore rig.
Rule 15: On a DP vessel WL/CT operations are not allowed below the tester valve; if appropriate acquisition technology cannot be made available, the WL/CT operations must be restricted to the section from surface to the bottom hole tester valve. Annulus pressure operated bottom hole samplers will be incorporated to the DST string BHA.
Rule 16:
Testing with packer in open hole can be contemplated on a fixed rig if all the following conditions are fulfilled:
No H2S Maximum mud hydrostatic : 5000 psi Deviation < 30° Maximum tested interval length : 30 m Maximum duration (packer set, packer unset) : 12 h Possibility to hold 500 psi in the annulus above packer for reversing purpose. No WL or swabbing operations envisaged No acid job Burner pit (Containment)
Rule 17: On a floating drilling rig, testing with packer in open hole is not allowed.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 8 of 33
2. FOREWORD 2.1 CLARIFICATION Formation testing from a drilling unit is conducted with a temporary production string associated to a temporary surface processing installation. Two testing configurations can be looked at: Case 1 (DST case) Drilling BOP’s are in place on the drilling wellhead. Test string with bottom hole tools remotely controlled from the surface, and attached to drill pipes or tubings. Test flowhead at the rig floor. Surface processing facilities (typical well test set up). This configuration, usually named ‘’DST’’ operation, covers most of the tests performed today : •cased
hole DST with formation covered by a casing/liner. •open hole DST with packer set in last casing/liner (‘’barefoot’’ test). •open hole DST with packer set in open hole. The present document focalizes on DST configuration. Case 2 (Completion testing case) BOP’s nippled down and tubing spool on the drilling wellhead. Tubing bonnet and Xmastree on the tubing spool. Test string is hanged on a tubing hanger. Test string composed of tubings with premium connections associated to bottom hole DST tools remotely operated from surface and to completion assemblies. Surface processing facilities (typical well test set up). This configuration, often named ‘’completion testing’’, covers specific cases like HP/HT testing, sour effluent testing and/or tests in urban areas and is not considered in the following. This last case will refer to the specific rules that apply to well design and especially to tubing design (CR FPP 310).
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 9 of 33
2.2 INDICATOR Rule which needs exemption, the blue ones are for offshore operations only, the green for onshore operations only and the black for all situations. Main recommendation or useful information.
2.3 GLOSSARY BOP
Blowout Preventer
CT
Coil Tubing
DP
Dynamic positioning
DST
Drill Stem Test
ESD
Emergency Shut Down
GOR
Gas/Oil Ratio
HP/HT
High Pressure/High Temperature
ID
Internal Diameter
LMRP
Lower Marine Riser Package
MEWHP Maximum Expected Wellhead Pressure OD
Outside Diameter
PLT
Production logging
PVT
Pressure/Volume/Temperature
RSES
Site Safety and Environment manager
SOR
State Of Requirements
SRO
Surface Read Out
SSTT
Sub Sea Test Tree
WH
Wellhead
WL
Wire Line
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 10 of 33
3. ORGANISATION AND RESPONSABILITIES
3.1 STATE OF REQUIREMENT (SOR)-/ PROGRAM ELABORATION As mentioned in the bridging document CR FPO 510, Geosciences and Drilling & Completion subsidiary entities should jointly establish as soon as feasible a state of requirements or SOR to define the tests objectives and the general operational program. The following typical list may be used to complete the SOR:
Number of tests Zones depths Tests objectives Formations pressures Formations temperatures Expected effluents Main testing sequences Tests duration Stimulation Sand risks when relevant N2 lifting Surface Read Out Bottom hole sampling Production logging Additional perforations through the test string Type and number of P,T gauges Surface sampling during main flow Well head HP sampling Safety sampling during clean up Samples destination Surface chemical analysis Commercial rate Well status after testing phase
Once the SOR is approved and issued, the testing program will be elaborated by Reservoir engineer and Drilling/Testing engineer and approved by Geosciences and Drilling & Completion managers.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 11 of 33
3.2 TESTS DATA ACQUISITION All the data collected during the tests should be validated by the Reservoir engineer on site or at the base and approved by the Drilling & Completion manager.
In some cases, a PVT specialist is highly recommended to recover and validate sampling.
3.3 PROGRAM MODIFICATION During the testing sequence, any modification to the technical program is decided jointly by Geosciences and Drilling & Completion representatives at the rig site and with the approval of the base Drilling & Completion manager or the Operations manager if necessary.
3.4 RESPONSIBILITIES DURING OPERATIONS 3.4.1 Drilling & Completion entity Drilling & Completion entity is in charge of the execution of the testing operations in accordance with the technical program and applicable safety rules. A DST specialist should normally be requested, acting only as technical advisor. Main actions dedicated to this entity are: •
• • •
Assess the suitability of the drilling unit to conduct the expected test operations: q Permanent piping status and specifications q Burner booms status (if present) q Water spray system q Arrangement of all testing /stimulating equipment, Select equipment and services companies Issue the detailed technical program and contingency plan Issue the operational testing final report
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 12 of 33
3.4.2 Drilling & Completion Supervisor Responsible of safety (RSES functions) and of the coordination of contractors; he shall: • •
Supervise the execution of the technical testing program in respect of the safe limits. Coordinate the various contractors (drilling and specific testing services companies).
3.4.3 Reservoir Engineer Reservoir engineer shall validate data and do recommendations to improve test results.
4. WELL DESIGN: SPECIFIC POINTS 4.1 INTEGRITY OF THE STRUCTURAL ENVELOPE This envelope includes production casing, with liner if any, wellhead and BOP. 4.1.1 Production/Test casing and Wellhead : In case of testing operations and as mentioned in CR FPP 225 “Casing design”, this envelope has to cope with the 2 specific load cases:
Leak at upper part of DST string including overpressure for bullheading Use of bottom hole DST tools requiring high annulus overpressure to be actuated (up to 4500 psi).
Drilling & Completion entity should check the initial casing design and verify that casing “as set” suits the above load cases. Wellhead and casing suspension cannot be dissociated from the global string and shall be of course tested simultaneously.
Rule 1:
If a drilling phase was performed through the Production/Test casing, this string and associated wellhead must be pressure tested again at MEWHP just before well testing operations start.
A caliper log may be useful to evaluate the residual resistance of the casing prior to casing pressure test if risk of wear is suspected. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 13 of 33
If casing string is not suitable, following alternatives have to be studied: • • • •
Run adequate tie-back string (up to surface or up to the critical depth). Change the test string tools (lower annulus actuating pressures or non-annulus operated tools). Reduce the annulus fluid gravity (underbalance testing) Not to proceed to the test.
4.1.2 BOP : The following points are in accordance with the CR FPP 165 ”BOP pressure tests”. BOP rams configuration will allow to seal around main sizes of the test string tubular when running in or pulling out of hole and testing. To actuate the DST tools, the annulus is sealed off with the pipe rams. Redundancy of pipe rams closure is recommended; otherwise a specific procedure has to be issued in the technical program. Rule 2:
BOP’s will be pressure tested at MEWHP just before DST, independently of the pressure test frequency applied during the drilling phase.
When possible, BOP pressure test should be performed with clear fluid. 4.2 WELL ARCHITECTURE – CEMENT QUALITY Quality of cement should be assessed in terms of sealing capabilities especially:
In the gap between casing and liner. Between zones in case of multi zones testing to validate each individual test results.
4.3 TUBING ANNULUS FLUID If the test packer is required to be set significantly high above the top of formation or perforations, it should be verified that:
At least the test string volume can be bullheaded at the end of the test (Previously checked with an injectivity test). Once the packer is unset or locator stung out, the hydrocarbons volume trapped below the test packer can be safely evacuated.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 14 of 33
4.3.1 Use of drilling mud If drilling mud is used for testing, this mud should not show instability in static conditions that may induce severe sagging around the bottom part of the test string, and jeopardize the overall test operations sequence. 4.3.2 Use of brine Brine minimizing the formation damage is to be used if special operations such as acidizing or gravel packing are requested. The advantage of a brine lies in the perfect pressure transmission, while the drawback is to allow a quick migration of hydrocarbons to the surface and a less hydraulic stability in front of a reservoir. Rule 3:
If a brine is used to perform the test, density of this brine will be selected to keep at least an overpressure of 150 psi above the anticipated formation pressure at the most critical production depth.
5. BASIC OPERATIONAL CONSIDERATIONS 5.1 DST WITH A DP VESSEL With a DP vessel: A sufficient weather window is required to perform any formation testing operation. Third pod or acoustic system redundancy is recommended. 5.2 RUNNING IN AND PULLING OUT THE TEST STRING The string will be preferably run/pulled out with a tester valve fully open (« lock open position »). A safety closure device for the different test string tubular should be available at any time at the rig floor.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 15 of 33
5.3 EQUIPMENT PRESSURE TEST Rule 4:
Tubing string from the flowhead down to the circulating valve, kill line and flowline up to the choke manifold shall be pressure tested to 110% of the MEWHP during formation testing. MEWHP is given by the maximum WH shut in pressure plus the overpressure for bullheading; if not known, this overpressure will be taken at 500 psi in case of dry gas, 1500 psi if oil is expected Production path from the choke manifold up to the burning system shall be water tested with regard to the different service pressures of components.
5.4 NIGHT OPERATIONS Safety aspect of some critical operations can be affected by night or more specifically by bad lighting:
Perforations when hydraulic balance is questionable and particularly when several independent zones are perforated for commingle testing First effluent at surface after the initial opening of the tester valve Well killing and packer un-setting including required reverse circulation Acid job Intrusive operations inside the test string (WL or CT) for N2 lifting, acid spot or measurements.
A full risks assessment should be done case by case by the Drilling & Completion entity (lighting conditions, evacuation conditions, type of effluent, H2S, etc) before to decide to perform such operation by night. On a new and unknown reservoir, operations should be scheduled in order to perform the first perforation, test opening in order to have the first effluent at surface at day light. An acid job can be done during the night if the injectivity test has been positively done.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 16 of 33
6. TESTING PROGRAM / REPORT CONTENTS 6.1 TYPICAL PROGRAM A typical program includes: • General Data: Includes the well status, basic reservoir data, test objectives (SOR), list of contractors involved and some appendices. • Outline program: Quick view of the main operations sequence, from well preparation to well killing. • Preliminary operations: Includes the mud treatment / brine displacement, BOP tests, electrical logging, DST tools preparation and general safety preparation. • Detailed operations: The outline program is followed step by step. A glossary of tools and equipment could be valuable. Technical appendices to be preferably inserted in each step for easy reading. • Organization and Safety: 3 sections can be developed: General: H2S, test interruption, general rig procedures. Personal/Duties: simplified organization chart showing the links/responsibilities between the rig site and the base; short description of duties for the personal involved in the overall testing operation (from OIM to rig mechanic). Contingency procedures: q Sand production, hydrates or paraffin when applicable. q Leaks, tools failure, surface ESD, weather constraints. q Station keeping, disconnection for DP vessels. 6.2 TYPICAL TESTING REPORT The Geosciences representative (reservoir engineer) will issue the official report based on validated test data collected on the rig site and including the sequence of events. The Drilling & Completion entity (test engineer involved) will issue a technical report with the following frame:
Main test results table (provisional reservoir engineer synthesis). DST string actual architecture and comments if different from the program. Test operations sequence and deviations from initial program. Time analysis and lost time clarifications. Incidents, failures reports, feed back for future operations. Costs estimate summary. Contractors performance evaluation. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 17 of 33
7. EQUIPMENT SELECTION 7.1 PERFORATIONS EQUIPMENT 7.1.1 WL guns 7.1.1.1 Operations with surface wellhead When using WL guns, lengths of casing guns are determined by the mechanical cable resistance (10 m is a usual mean value). If well instability develops after firing, the cable will be cut at surface to allow high pressure pumping below the shear/blind rams. A shearing tool should be available at any time on the rig floor to cut the considered electrical cable.
7.1.1.2 Operations with subsea wellhead On a floating rig, to cut the braided cable and close the shear/blind rams will remain the unique method to kill the well if any instability is developing after firing. As results of cutting braided cable with shear rams could remain doubtful, use of WL guns from an anchored or a dynamic positioning floating vessel should be avoided when possible especially if perforations are performed in brine.
7.1.2 TCP run on Drill Pipe TCP should be selected each time the well balance is questionable (High risks of losses). Two firing devices should be available. Slick WL equipment should nevertheless be available at the rig site to fish the drop bar in case of complete misfire.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 18 of 33
7.2 TUBING STRING Rule 5:
“Sour service” material should systematically be selected for a test tubing except if H2S risks have been proven to be insignificant. 100% connections tensile efficiency shall be selected for well test tubing application.
The string should be of a proper metallurgy and can sustain the produced effluents under the maximum expected pressure, considering the range of temperatures. The following design factors shall apply on the worst case: Rule 6:
For the tubing string, the following design factors shall apply on the worst case:
Burst Collapse Tensile strength Triaxial strength
1.25 1.25 1.60 1.37
NB : These factors are the design factors used in standard tubing design (CR FPP 310) increased by 10% to account for multiple trips (test string reused as a work string). 7.3 BOTTOM HOLE DST TOOLS 7.3.1 For all Operations Each time it is possible, bottom hole DST tools shall be annulus operated tools, full bore (2.25‘’ ID standard, 1’’ID slim hole, 3’’ ID big bore). Rule 7:
For all applications, the DST tools minimum features are: Sour service. Two Downhole closure devices: (one tester valve + one single shot safety valve). Two Circulating devices : (one reversible tool + one single shot tool). Elastomers qualified for expected fluids and temperature conditions.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 19 of 33
Guide lines to select the packer type: Maximum expected differential pressure from above or from below : 75 % of nominal rating. Permanent or retrievable Undisturbed bottom hole temperature H2S and CO2 contents Potential losses when unsetting the packer Future well status (definitely abandoned, temporary suspended) Multi-zones testing and zones spacing Possible injection at low temperatures.
7.3.2 Additional point for operations with subsea wellhead The presence of several hydraulic umbilicals should be kept in mind for the packer type selection (no need of string rotation). 7.4 SUBSURFACE DST SAFETY VALVES 7.4.1 Operations with surface Wellhead A safety valve associated to a ported slick joint may be inserted in the DST string; this tool, located in BOP’s, can allow a quick closure in case of leak on string just below the flowhead and can protect the rig floor from any large hydrocarbon release. The need of this kind of safety valve shall be assess but seems justified in case of H2S, HP wells or critical environment (Urban zone for example) Arrangement : Configuration with enough space between the rig floor and lower pipe rams of BOP’s. Pump through type. Hydraulically operated at the rig floor. In any case minimizing risks of breakage on top part of the string remains the first objective; crossovers below the flowhead should be connected to a heavy wall stiff joint (3-4 m long) set in the slips.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 20 of 33
7.4.2 Operations with subsea wellhead 7.4.2.1 Sub Sea Test Tree (SSTT) : Rule 8:
To perform DST from a floating rig, hydraulically or electro-hydraulically surface controlled dual fail-safe closing valves (two ball valves or one ball valve + one flapper valve) equipped with an hydraulic connector (Latch) must be installed in the BOP stack (SSTT).
Features: Two ways of disconnection (primary hydraulic or electro-hydraulic, secondary mechanical rotation). Total length such as the shear sub above the latch section is in front of the BOP shear rams. Pump through capability. Hydraulic or electro-hydraulic umbilical comprising a ½”chemical injection line to inject above, inside or below SSTT. Cutting capability: 7/32’’ cable and 1’’½ coil tubing N2 or diesel injection subs If a DP vessel is considered, the disconnection time of the SSTT latch section will be consistent with the emergency sequence of the LMRP disconnection. The disconnected latch should be above the BOP shear rams when LMRP sequence is initiated.
7.4.2.2 Slick joint /Fluted hanger: Length of the slick joint should be suitable with BOP space out to close both lower and middle pipe rams. Remark : Usual slick joint OD is 5’’. In some cases, smaller slick joint (3 ½’’ OD) may be used and impact on the WL/Coil tubing operations will be thoroughly investigated.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 21 of 33
7.4.2.3 Retainer valve: Rule 9:
To perform DST from a floating rig, a fail safe type hydraulically or electrohydraulically surface controlled retainer valve must be incorporated above the SSTT when: The landing string internal volume is greater than 1m3 Significant effluent GOR is expected (above 200 m3/m3).
7.4.2.4 Lubricator valve : For any WL operation (data acquisition or remedial), the lubricator valve installation is recommended (safer and convenient WL rig up). This ball valve is incorporated to the landing string at about 30m below the rig floor approximately, and is actuated by an independent hydraulic system at the rig floor.
7.5 RIG FLOOR DST EQUIPMENT This includes the flowhead and associated kill and flow lines. 7.5.1 Basic arrangement The following is independent of type of rig and wellhead configuration. 7.5.1.1 The flowhead will be equipped with 4 gate valves:
One kill valve (systematically associated with a check valve). One swab valve. One lateral production valve. One manual master valve.
With additional fittings: A swivel above the master valve. Methanol or glycol injection sub in gas wells A WL / coil tubing top sub.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 22 of 33
Rule 10: The lateral production valve (wing) on the flowhead of a DST string must be hydraulically operated, failsafe closed and connected to the Emergency Shut Down system (ESD). ESD control buttons must be installed one on the rig floor, one in the driller’s cabin and one on the DST layout. A hydraulic cutting valve must be installed in addition when WL is foreseen. One additional ESD control button could be installed in living quarters. 7.5.1.2 The kill line or pumping line: That line is normally used to inject mud, brine, water, nitrogen or inhibited acid (« cold service »). Use of a piece of HP hose (2’’ ID) between the drilling manifold and the flowhead kill inlet is recommended but chiksans (with swivels) can also be acceptable for static configuration (bottom supported rig). Its length should be enough to allow pick up of the DST string without breaking the kill line (complete packer unsetting, long locator seal assemblies sting out). 7.5.1.3 The flowline or production line, up to the production choke manifold: Rule 11: Use of chiksans or fixed (or temporary secured) hard piping is prohibited on production line between the flowhead and the production manifold. A correctly rated HP hose shall be used. Downstream the production manifold: All temporary-piping sections must be secured to rig structures. Permanent rig production hard piping must be inspected, with valid certification and stamp tagged.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 23 of 33
7.5.2 Additional points for operations with subsea Wellhead The following additional points should be considered for operations with subsea wellhead: • Flowhead : If high stick up is anticipated, a hydraulically operated kill valve is recommended. • Kill line or pumping line : Due to heave, chicksans shall not be used on a floating rig; HP hoses are required. • Other specific arrangements Certified long bails 9 m long will be installed below the travelling block for WL spacing out. If coil tubing is anticipated, the coil tubing frame will be used for safety reasons (hydrates plug).
7.6 TEMPORARY PROCESS FACILITIES The basic functions of the temporary process installation are:
Control of the well performance upstream the process. Separation of effluent components for metering, sampling, calibrating. Burning or storage of all the hydrocarbons produced. Environment protection
Safety, effluent type, environment, pressure/temperature envelopes, rates and local regulations govern the surface processing set up selection. The typical components are listed here below:
One or two production choke manifolds (in line or in parallel). One optional multiphase tester with bypass. One optional heating system (hydrates, wax, emulsions, efficient separation). One separator (2 or 3 phases, low or high operating pressure) One or several surge/gauge tanks (calibration and accurate metering). One transfer pump to re-inject the effluent in the main line to the burning or storage system. One or two burning systems (burner booms + green burner heads, flares + pits). This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 24 of 33
Between the different sections of the production path, various connections can be used (unions, flanges, hubs, Graylock) : The connections and their sealing elements should be suitable (rating, compatibility with effluents and temperatures) for the expected well test.
7.6.1 Basic configuration for operations on a land rig 7.6.1.1 Equipement spread out Generally onshore, the surface well test components can be widely spread to follow the safety areas and properly located regarding wind. Low pressure Weco connections should be welded on gas lines. 7.6.1.2 Data header : Recommended for multifunction purpose without interfering with the production manifold (sampling, monitoring P, T, chemical injection). 7.6.1.3 Choke manifold : Five valves, two branches and one by pass, with the same working pressure. All the production path components from the flowhead to the choke manifold downstream valves and installed kill line should have a working pressure at least equal to 110% of the maximum expected well head pressure (MEWHP). 7.6.1.4 Heat exchanger : Accepted system : indirect type with water bath heated with diesel (two coil sections at different working pressures). All the items from downstream choke manifold to heater choke and by pass valves should have the same working pressure than upstream elements. If it is not possible, a high pressure pilot set at 80% of the limiting working pressure, should be installed in that section and tied in the ESD system to actuate the automatic wing valve on the flowhead. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 25 of 33
7.6.1.5 Separator : Whenever possible, a three phases separator 1440 or 720 psi is to be used. All the items from heater choke to separator inlet valve should be protected against high pressure: With an independent high-pressure pilot set at 80% of this section working pressure. If not, the previous section high pressure pilot setting will be lowered at 80% of this section working pressure. Separator safety devices: The separator should be protected by two independent relief systems (relief valves or rupture discs) set at 90% of the separator working pressure. Two independent vent lines should be installed for relief valve and rupture discs. The relief valve may be piped back into the gas outlet line.
7.6.1.6 Surge tanks, atmospheric tanks : Rule 12: On a land rig the use of atmospheric tanks is prohibited if H2S is expected. If surge tank is used , safety features are: A safety relief valve at top of tank A specific vent line going to the burning pit When using pressurized surge tanks (50 or 150 psi), two safety systems should be present.
7.6.1.7 Flares and burning system : Flares and vent lines should be properly secured to the ground. Flare arrestor has to be evaluated (Included in initial risks assessment) Sealed burner pit
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 26 of 33
7.6.1.8 ESD system : hydro-pneumatic The ESD panel linked to the flowhead wing valve may be located in the testing area down the rig. A minimum of two command buttons should be installed at the following locations: One at drill floor/driller’s cabin. One near the separator. 7.6.2 Specific configuration for offshore operations 7.6.2.1 Equipement spread out On an offshore drilling unit, the spread out of the well test equipment should follow the classified zones. Recommended minimum distances between items: Flowhead to separator : 15 m Flowhead to heater : 25 m Flowhead to surge tank : 10 m Low pressure Weco connections should be welded on gas lines. 7.6.2.2 Data header : Recommended for multifunction purpose without interfering with the production manifold (sampling, monitoring P, T, chemical injection). 7.6.2.3 Optional Surface hydraulically operated safety valve: Can be located upstream the data header to shut in the flow. The rig permanent piping and production line are then isolated from the well. If used, this valve should be operated with a dedicated manual ESD.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 27 of 33
7.6.2.4 Choke manifold : Five valves, two branches and one by pass, with the same working pressure. All the production path components from the flowhead to the choke manifold downstream valves and installed kill line should have a working pressure at least equal to 110% of the maximum expected well head pressure (MEWHP).
7.6.2.5 Heat exchanger : Indirect heater is not permitted on an offshore rig, as this equipment shall generally be close to the separator due to the limited space available. All the items from downstream choke manifold to heater choke and by pass valves should have the same working pressure than upstream elements. If it is not possible, a high pressure pilot set at 80% of the limiting working pressure, should be installed in that section and tied in the ESD system to actuate the automatic wing valve on the flowhead. Rule 13: Indirect heater is not permitted on offshore rigs; only steam exchanger associated to a dedicated steam generator (water boiler) must be used. The drilling rig steam supply shall not be used.
7.6.2.6 Separator : Whenever possible, a three phases separator 1440 or 720 psi is to be used. All the items from heater choke to separator inlet valve should be protected against high pressure: With an independent high-pressure pilot set at 80% of this section working pressure. If not, the previous section high pressure pilot setting will be lowered at 80% of this section working pressure. Separator safety devices: The separator should be protected by two independent relief systems (relief valves or rupture discs) set at 90% of the separator working pressure. Two independent vent lines should be installed for relief valve and rupture discs: The relief valve may be piped back into the gas outlet line. The rupture discs vent line should be extended down the hull close to sea level. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 28 of 33
7.6.2.7 Surge tanks : Rule 14: Use of atmospheric tank is prohibited on offshore rig. If surge tanks are used, safety features are: A safety relief valve at top of tank. A specific vent line going down the rig hull close to sea level. When using pressurized surge tanks (50 or 150 psi), two safety systems should be present. 7.6.2.8 Flares and burning system : Air supply for burner heads should be delivered by an independent air compressor (a second compressor should be available as a back up one). A check valve should be present on each burner and at compressor outlet. Flares and vent lines should be properly secured to the guide posts and deck. A quick calculation of the maximum expected heat radiation should be performed to check if burner booms length and rig water spray system are satisfactory.
7.6.2.9 ESD system : hydro-pneumatic Offshore, the ESD panel linked to the flowhead wing valve may be located on the main deck, near the production choke manifold. Offshore, three ESD command buttons should be installed at the following locations: At drill floor/driller’s cabin. Near the choke manifold / separator In leaving quarters.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 29 of 33
8. SPECIFIC OPERATIONS 8.1 WL & CT OPERATIONS THROUGH THE TEST STRING WL and coil tubing operations decrease the overall safety level of the test. These operations should be limited and clearly justified.
8.1.1 With Surface Wellhead 8.1.1.1 Surface read out (SRO) The SRO will be run only during build up periods. The rig floor WL pressure control equipment will be rated at 100% of MEWHP (should the tester valve leak). The pressure control equipment should be pressure tested with a mixture of glycol/water. When WL is anticipated, a hydraulic cutting valve should be installed below the flow head. Remark : risk of hydrates or wax may require to reverse circulate the tubing contents and spot a neutral fluid during the build up period.
8.1.1.2 WL bottom hole sampling and production logging (PLT) Bottom hole samplers or PLT are usually run close to the perforations, by mean of slick or electrical WL. The tester valve should be set in locked open position when running through and in fail safe position as soon as the WL string is pulled back above it.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 30 of 33
8.1.1.3 Coil tubing operations This includes chemical spotting, N2 lift and coil tubing PLT. The test string is left with only one safety barrier (BOP valve) during these operations as soon as CT is run in front of tester valve. The tester valve should be set in locked open position when running through and in fail safe position as soon as the CT string is pulled back above. Cutting capability of the BOP valve should be assessed (ball valve and closure assistance). A preliminary cutting test is recommended before mobilization of the tool. An additional CT cutting device should be available below the flowhead.
8.1.2 With Subsea Wellhead For any WL or CT operations through the test string, cutting capability of the SSTT ball valve should be assessed (ball valve type and closure assistance); a preliminary cutting test is recommended prior tool acceptance. But obviously, risks linked to these operations are greater on a DP vessel. After an uncontrolled drift off or a sudden drive off, the impact of the riser disconnection may lead to an extreme situation (DST aborted, piece of WL cable or coil tubing preventing to maintain lower tubing barrier, damage to the upper tubing barrier and well sealed off only with BOP shear/blind rams, hazardous well re-entry). Present well testing acquisition technology (ex. METROL pulse devices) allows «wireless» systems to be deployed both for direct pressure read out or for bottom hole sampling.
Rule 15: On a DP vessel WL/CT operations are not allowed below the tester valve; if appropriate acquisition technology cannot be made available, the WL/CT operations must be restricted to the section from surface to the bottom hole tester valve. Annulus pressure operated bottom hole samplers will be incorporated to the DST string BHA.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 31 of 33
8.2 OPEN HOLE TESTING Barefoot testing is not considered as open hole testing and therefore is not covered by this chapter 8.2. 8.2.1 With Surface wellhead The main limitations for the open hole tests are dictated by the formations strength, the tested height or below packer volume, the deviation, the expected effluent and the « exotic » DST tools incorporated in the test string. Rule 16: Testing with packer in open hole can be contemplated on a fixed rig if all the following conditions are fulfilled:
No H2S Maximum mud hydrostatic : 5000 psi Deviation < 30° Maximum tested interval length : 30 m Maximum duration (packer set, packer unset) : 12 h Possibility to hold 500 psi in the annulus above packer for reversing purpose. No WL or swabbing operations envisaged No acid job Burner pit (Containment) Short flow to surface may be considered for rate estimation if, all above conditions being fulfilled, the effluent is mainly liquid. 8.2.2 With Subsea Wellhead Rule 17: On a floating drilling rig, testing with packer in open hole is not allowed.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 32 of 33
8.3 DP VESSEL: STATION KEEPING AND DISCONNECTION 8.3.1 Station Keeping Alarms Four alarm levels are well recognized today : • Green (Normal operational status) :
DP operating normally with back-up system available. All thruster power available. Vessel’s indicated position and heading within predetermined limits. Weather conditions within the limits.
• Dark Green or Advisory status :
Decreasing thruster power. Decreasing total power. Loss of one DP systems but with available back-up. Degraded weather conditions. Heave above 2m Pitch and roll 2°
• Yellow (Degraded operational status) :
Failure in DP system with no available back-up. Unstable station keeping. Vessel beyond determined limits. Risk of collision.
• Red (Emergency status) :
Positioning and or power system major failure; unable to maintain heading and position. Imminent collision. No time available for position recovery. Sudden bad weather.
The above Station Keeping Alarms have to be updated according to weather and sea conditions evolutions using the Drilling Contractor « Emergency Disconnect and Red Watch Circles Limits » calculation sheet. A bridging document for disconnection procedures should be established jointly by Operator, Drilling Contractor and Testing Company. A disconnection instructions sheet, specific to testing phase, will be posted in the driller’s cabin. This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
Company Rule
CR FPP 510 Well testing (DST case)
Exploration & Production
Rev: 01
Date: 15/10/2003
Page: 33 of 33
8.3.2 Drift off situation while testing • Dark Green or Advisory status : DST operations to be stopped by closing the tester valve and the SSTT ;then, preparation for SSTT disconnection or for operations resuming. • Yellow status : DST operations stopped and SSTT disconnected; then, preparation for LMRP disconnection or for SSTT reconnection and operations resuming.
8.3.3 Drive off situation while testing The Red Alarm is actuated and LMRP disconnection sequence initiated: The SSTT will be closed in (hydraulically or electro-hydraulically). No attempt to unlatch the SSTT will be made, leaving the BOP shear rams cut the SSTT shear sub. Remark: the tester valve will not be closed in due to lack of time for annulus pressure bleed off.
This document is the property of Total. It must not be stored, reproduced or disclosed to others without written authorisation from the Company.
CR_FPP_510_REV01_well_testing_(DST_case).doc
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