WELL TESTING PROCEDURES
J. Keemink @2009
Page 1
TABLE OF CONMTENTS 1. 1.1. 1.2. 1.3. 1.4.
INTRODUCTION Purpose of the manual Objectives Drilling Installations UPDATING, AMENDMENT, CONTROL & DEROGATION
2. 2.1. 2.2. 2.3. 2.4. 2.5. 2.6. 2.7. 2.8. 2.9. 2.10.
TYPES OF PRODUCTION TEST Drawdown Multi-Rate Drawdown Build-up Deliverability Flow-on-Flow Isochronal Modified Isochronal Reservoir Limit Interference Injectivity
5 5 5 5 5 6 6 6 6 6 6
3. 3.1.
GENERAL ROLES AND RESPONSIBILITIES Responsibilities and Duties 3.1.1. Company Drilling and Completion Supervisor 3.1.2. Company Junior Drilling and Completion Supervisor 3.1.3. Company Drilling Engineer 3.1.4. Company Production Test Supervisor 3.1.5. Company Well Site Geologist 3.1.6. Contractor Toolpusher 3.1.7. Contract Production Test Chief Operator 3.1.8. Contractor Down-hole Tool Operator 3.1.9. Wire-line Supervisor 3.1.10. Company Stimulation Engineer 3.1.11. Company Reservoir Engineer Responsibilities And Duties On Short Duration Tests 3.2.1. Company Drilling and Completion Supervisor 3.2.2. Company Junior Drilling and Completion Supervisor 3.2.3. Company Well Site Geologist 3.2.4. Well Testing Personnel
13 13 14 14 14 14 15 15 15 15 15 15 15 16 16 16 16 16
4. 4.1.
WELL TESTING PROGRAM Contents
17 17
5. 5.1. 5.2.
SAFETY BARRIERS Well Test Fluid Mechanical Barriers - Annulus Side 5.2.1. SSTT Arrangement 5.2.2. Safety Valve Arrangement Mechanical Barriers - Production Side 5.3.1. Tester Valve 5.3.2. Tubing Retrievable Safety Valve (TRSV) or (SSSV) Casing Overpressure Valve
18 18 19 19 21 22 22 23 23
3.2.
5.3.
5.4.
J. Keemink @2009
2
7 2 3 4
Page 2
6. 6.1. 6.2.
6.3. 6.4.
6.5.
7. 7.1.
7.2. 7.3.
7.4. 7.5.
TEST STRING EQUIPMENT General Common Test Tools Description 6.2.1. Beveled Mule Shoe 6.2.2. Perforated Joint/Ported Sub 6.2.3. Gauge Case (Bundle Carrier) 6.2.4. Pipe Tester Valve 6.2.5. Retrievable Test Packer 6.2.6. Circulating Valve (Bypass Valve) 6.2.7. Pipe Tester Valve 6.2.8. Safety Joint 6.2.9. Hydraulic Jar 6.2.10. Down-hole Tester Valve 30 6.2.11. Single Operation Reversing Sub 6.2.12. Multiple Operation Circulating Valve 6.2.13. Drill Collar 6.2.14. Slip Joint 6.2.15. Crossovers High Pressure Wells Sub-Sea Test Tools Used On Semi-Submersibles 6.4.1. Fluted Hanger 6.4.2. Slick Joint (Polished Joint) 6.4.3. Sub-Sea Test Tree 6.4.4. Lubricator Valve Deep Sea Tools 6.5.1. Retainer Valve 6.5.2. Deep Water SSTT
30 30 31 31 31 31 31 31 31 31 32 32 32 32
SURFACE EQUIPMENT Test Package 7.1.1. Flow head Or Surface Test Tree 7.1.2. Coflexip Hoses And Pipe work 7.1.3. Data/Injection Header 7.1.4. Choke Manifold 7.1.5. Steam Heater and Generator 7.1.6. Separator 7.1.7. Data Acquisition System 7.1.8. Gauge/Surge Tanks And Transfer Pumps 7.1.9. Diverter Manifolds, Burners and Booms Emergency Shut Down System Accessory Equipment 7.3.1. Chemical Injection Pump 7.3.2. Sand Detectors 7.3.3. Crossovers Rig Equipment Data Gathering Instrumentation 7.5.1. Laboratory and Instrument Manifold Equipment 7.5.2. Separator 7.5.3. Surge Or Metering Tank 7.5.4. Steam Heater
33 33 33 33 34 34 35 35 36 36 37 38 39 39 39 40 40 40 40 41 41 41
J. Keemink @2009
24 24 29 29 29 29 29 29 29 30 30 30
Page 3
8. 8.1
8.2.
BHP DATA ACQUISITION Gauge Types 8.1.1. Quartz Crystal Gauge 8.1.2. Capacitance Gauge 8.1.3. Strain Gauge 8.1.4. Bourdon Tube Gauge Gauge Installation 8.2.1. Tubing Conveyed Gauges 8.2.2. Gauge Carriers 8.2.3. SRO Combination Gauges 8.2.4. Wire-line Conveyed Gauges 8.2.5. Memory Gauges Run on Slick line 8.2.6. Electronic Gauges Run on Electric Line
9. 9.1. 9.2. 9.3.
PERFORATING SYSTEMS Tubing Conveyed Perforating Wire-line Conveyed Perforating Procedures For Perforating
10. 10.1.
PREPARING THE WELL FOR TESTING Preparatory Operations For Testing 10.1.1. Guidelines For Testing 7ins Liner Lap 10.1.2. Guidelines For Testing 95/8ins Liner Lap 10.1.3. General Technical Preparations Brine Preparation 10.2.1. Onshore Preparation of Brine 10.2.2. Transportation and Transfer of Fluids 10.2.3. Recommendations 10.2.4. Rig Site Preparations 10.2.5. Well And Surface System Displacement To Brine 10.2.6. Displacement Procedure 10.2.7. On-Location Filtration And Maintenance Of Brine Down-hole Equipment Preparation 10.3.1. Test tools
10.2.
10.3.
42 42 42 42 42 43 43 43 43 44 44 44 45
10.4. TUBING PREPARATION 10.4.1. Tubing Connections 10.4.2. Tubing Grade 10.4.3. Material 10.4.4. Weight per Foot 10.4.5. Drift 10.4.6. Capacity 10.4.7. Displacement 10.4.8. Torque 10.4.9. AGIP (UK) Test String Specification 10.4.10. Inspection 10.4.11. After Testing/Prior To Re-Use 10.4.12. Tubing Movement 10.5. Landing String Space-Out 10.5.1. Landing String space-Out Procedure
J. Keemink @2009
Page 4
10.6. GENERAL WELL TEST PREPARATION 10.6.1. Crew Arrival on Location 10.6.2. Inventory of Equipment Onsite 10.6.3. Preliminary Inspections 10.7. Pre Test Equipment Checks 10.8. Pressure Testing Equipment 10.8.1. Surface Test Tree 11. 11.1. 11.2. 11.3. 11.4. 11.5. 11.6.
TEST STRING INSTALLATION General TUBING HANDLING RUNNING AND PULLING Packer And Test String Running Procedure Running the Test String with a Retrievable Packer Running a Test String with a Permanent Packer
12. 12.1. 12.2.
WELL TEST PROCEDURES Annulus Control And Pressure Monitoring Test Execution
13. 13.1. 13.2. 13.3. 13.4. 13.5. 13.6.
WELL TEST DATA REQUIREMENTS General Metering Requirements Data Reporting Pre-Test Preparation Data Reporting During the Test Communications
14. 14.1. 14.2. 14.3.
SAMPLING Conditioning The Well Down-hole Sampling Surface Sampling 14.3.1. General 14.3.2. Sample Quantities 14.3.3. Sampling Points 14.3.4. Surface Gas Sampling Surface Oil Sampling Sample Transfer And Handling Safety 14.6.1. Bottom-hole Sampling Preparations 14.6.2. Rigging Up Samplers to Wire-line 14.6.3. Rigging Down Samplers from Wire-line 14.6.4. Bottom hole Sample Transfer And Validations 14.6.5. Separator/Wellhead Sampling 14.6.6. Sample Storage
14.4. 14.5. 14.6.
15.
WIRE-LINE OPERATIONS
16.
HYDRATE PREVENTION
17.
NITROGEN OPERATIONS
J. Keemink @2009
Page 5
18.
OFFSHORE COILED TUBING OPERATIONS
19. 19.1.
19.3. 19.4. 19.5.
WELL KILLING ABANDONMENT Routine Circulation Well Kill 19.1.1. Circulation Well Kill Procedure Bullhead Well Kill 19.2.1. Bullhead Kill procedure Temporary Well Kill For Disconnection On Semi Submersibles Plug And Abandonment/Suspension Procedures Plug and Abandonment General Procedures
20.
HANDLING OF HEAVY WATER BRINE
19.2.
J. Keemink @2009
Page 6
1.
INTRODUCTION The main objective when drilling a well is to test and evaluate the target formation. The normal method of investigating the reservoir is to conduct a well test. There are two types of well test methods available: 1) Drill Stem Test (DST). The scope is to define the quality of the formation fluid. Where drill pipe/tubing in combination with down hole tools is used as a short term test to evaluate the reservoir. The formation fluid may not reach or only just reach the surface during the flowing time. 2) Production Test. The scope is to define the quality and quantity of the formation fluid. Many options of string design are available depending on the requirements of the test and the nature of the well. Many designs of well testing 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 but basically it consists of installing a packer tailpipe, packer, safety system , down hole test tools and a tubing or drill pipe string then introducing a low density fluid into the string in order to enable the well to flow through surface testing equipment which controls the flow rate, separates the fluids and measures the flow rates and pressures. A short description of the types of tests which can be conducted and generic test string configurations for the various drilling installations, as well as the various down hole tools available, surface equipment, pre-test procedures and test procedures are included in this section. Well test specific wire line and coiled tubing operations are also included.
1.1.
PURPOSE OF THE MANUAL The purpose of the manual is to guide technicians and engineers, involved in Company ’s worldwide activities, through the Procedures and the Technical Specifications which are part of the Corporate Standards. Such Corporate Standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local 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 Company operates.
1.2.
OBJECTIVES The test objectives must be agreed by those who will use the results and those who will conduct the test before the test program 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 formalized by holding a meeting (or meetings) at which 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.
J. Keemink @2009
Page 7
Investigate formation characteristics. Evaluate boundary effects. 1.3.
DRILLING INSTALLATIONS Well tests are conducted both onshore and offshore in either deep or shallow waters. The drilling units from which testing can be carried out include:
Workover Rigs
Jack-Up Rigs
Land Rigs
Semi-Submersible Rigs
Swamp Barges
Drill Ships
ONSHORE 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 flow head 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 OFFSHORE The preferred method for testing from a floating rig is by using a drill stem test retrievable packer. However where development wells are being tested, the test will be conducted utilizing a production packer and seal-bore 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.
J. Keemink @2009
Page 8
1.4.
UPDATING, AMENDMENT, CONTROL & DEROGATION This is a ‘live’ controlled document and, as such, it will only be amended and improved by the Corporate Company, in accordance with the development of Company’s Division and Affiliates 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. Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Company’s Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.
2.
TYPES OF PRODUCTION TEST
2.1.
DRAWDOWN A drawdown test entails flowing the well and analyzing the pressure response as the reservoir pressure is reduced below its original pressure. This is termed drawdown. It is not usual to conduct solely a drawdown test on an exploration well as it is impossible to maintain a constant production rate throughout the test period as the well must first clean-up. During a test where reservoir fluids do not flow to surface, analysis is still possible. This was the original definition of a drill stem test or DST.
2.2.
MULTI-RATE DRAWDOWN A multi-rate drawdown test may be run when flow rates are unstable or there are mechanical difficulties with the surface equipment. This is usually more applicable to gas wells but can be analyzed 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 analyzed using type curves, in conjunction with the buildup test.
2.3.
BUILD-UP A build-up test requires the reservoir to be flowed to cause a drawdown then the well 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 an oil well and can be analyzed using the classic Horner Plot or superposition. From these the permeability-height product, kh, and the near wellbore skin can be analyzed.
J. Keemink @2009
Page 9
2.4.
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. DELIVERABILITY A deliverability test is conducted to determ ine the well’s Inflow Performance Relation, IPR, and in the case of gas wells the Absolute Open Flow Potential, AOFP, and the rate dependant skin coefficient, D. The AOFP is the theoretical fluid rate at which the well would produce if the reservoir sand face was reduced to atmospheric pressure. This calculated rate is only of importance in certain countries where government bodies set the maximum rate at which the well may be produced as a proportion of this flow rate. There are three types of deliverability test: Flow on Flow Test. Isochronal Test. The Modified Isochronal Test.
2.5.
FLOW-ON-FLOW Conducting a flow-on-flow test entails flowing the well until the flowing pressure stabilizes and then repeating this at several different rates. Usually the rate is increased at each step ensuring that stabilized 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.
2.6.
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 stabilized reservoir pressure. The final flow period is extended to achieve a stabilized flowing pressure for defining the IPR.
2.7.
MODIFIED ISOCHRONAL The modified isochronal test is used on tight reservoirs where it takes a long time for the shut-in pressure to stabilize. 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.
J. Keemink @2009
Page 10
2.8.
RESERVOIR LIMIT A reservoir limit test is an extended drawdown test which is conducted on closed reservoir systems to determine their volume. It is only applicable where there is no regional aquifer support. The well is produced at a constant rate until an observed pressure drop, linear with time, is achieved. Surface readout pressure gauges should be used in this test. It is common practice to follow the extended drawdown with a pressure build-up.
The difference between the initial reservoir pressure, and the pressure to which it returns, is the depletion. The reservoir volume may be estimated directly from the depletion, also the volume of produced fluid and the effective isothermal compressibility of the system. The volume produced must be sufficient, based on the maximum reservoir size, to provide a measurable pressure difference on the pressure gauges, these must therefore be of the high accuracy electronic type gauges with negligible drift. 2.9.
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 flow rate at one of the wells is varied in a series of steps, is sometimes used to overcome the background reservoir pressure behavior when it is a problem.
2.10.
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 sand face, a short term injection test will generally not provide a good measure of the long term injectivity performance. After the injectivity test, the pressure fall off is measured. The analysis of this test is similar to a pressure build-up, but is complicated by the cold water bank.
J. Keemink @2009
Page 11
3.
GENERAL ROLES AND RESPONSIBILITIES 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.
RESPONSIBILITIES AND DUTIES The following Company’s/Contractor’s personnel shall be present on the rig: Company Drilling and Completion Supervisor. o Company Junior Drilling and Completion Supervisor. o Company Drilling Engineer. o Company Production Test Supervisor. o Company Well Site Geologist. o Contractor Toolpusher. o Contract Production Test Chief Operator. o Contractor Down-hole Tool Operator. o Wire-line Supervisor (slick-line & electric line ). o Tubing Power Tong Operator. o Torque Monitoring System Engineer. o
Depending on the type of test, the following personnel may also be required on the rig during the Well test: Company Reservoir Engineer. o 3.1.1.
Company Drilling and Completion Supervisor The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations. He is assisted by the Company Production Test Supervisor, Drilling Engineer, Well Site Geologist and Company Junior Drilling and Completion supervisor. When one of the above listed technicians is not present, the Company Drilling and Completion Supervisor, in agreement with Drilling and Completion Manager and Drilling Superintendent, can perform the test, after re-allocation of the duties and responsibilities according to the Well Test specifications. If deemed necessary he shall request that the rig be inspected by a Company safety expert prior to starting the well test.
3.1.2.
Company Junior Drilling and Completion Supervisor The Company Junior Drilling and Completion Supervisor will assist the Company Drilling and Completion Supervisor in well preparation and in the test string tripping operation. He will cooperate with the Company Production Test Supervisor to verify the availability of down-hole drilling equipment, to carry out equipment inspections and tests and to supervise the Down-hole 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 down-hole tool Operator and the
J. Keemink @2009
Page 12
Contractor Production Chief Operator. He shall be responsible for supplying equipment he is concerned with (down-hole tools) and for preliminary inspections. He shall provide Contractor personnel with the necessary data, and prepare accurate daily reports on equipment used in cooperation 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, wire-line, 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 program alterations whenever test behavior is not as expected. The final decision to make any program 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 down hole testing tools, supervising preliminary inspections as per procedures. He will supervise contract wireline and production test equipment operators, as well as the down-hole 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 program. The Company Production Test Supervisor is responsible for the preparation of all reports, including the final field report previously mentioned. 3.1.5.
Company Well Site Geologist The Well Site Geologist is responsible for the supervision of perforating operations (for well testing) cased hole logging when the Company Production Test Supervisor is not present on the rig. If required he will co operate with the Company Production Test Supervisor for the test interpretation and preparation of field reports.
3.1.6.
Contractor Toolpusher The Toolpusher is responsible for the safety of the rig and all personnel. He shall ensure that safety regulations and procedures in place are followed rigorously. The Toolpusher shall consistently report to the Company Drilling and Completion supervisor on the status of drilling contractors material and equipment.
3.1.7.
Contractor Production Test Chief Operator The Production Test Chief Operator shall always be present to co-ordinate and assist the well testing operator and crew. He will be responsible for the test crew to the Company Production Test Supervisor and will draw up a chronological report of the test.
3.1.8.
Contractor Down-hole Tool Operator The down-hole 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 down-hole tool manipulation and annulus pressure control during tests.
J. Keemink @2009
Page 13
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.
Wire-line Supervisor The Wire-line Supervisor will ensure all equipment is present and in good working order. He will report directly with the Company Production Test Supervisor.
3.1.10. Company Stimulation Engineer If present on the rig, the Stimulation Engineer will assist the Company Production Test Supervisor during any stimulation operations. He will provide the Company Production Test Supervisor with a detailed program 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 program 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 program. 3.2.
RESPONSIBILITIES AND DUTIES ON SHORT DURATION TESTS As a general rule the only company personnel present on the rig shall be the Company Drilling and Completion Supervisor, the Company Junior Drilling and Completion Supervisor and the well site Geologist, the Company Drilling Manager/Superintendent shall evaluate, in each individual case, the opportunity of providing a company Drilling Engineer. The responsibilities and duties of the Company Drilling and Completion Supervisor and Well Site Geologist will be as follows: 3.2.1.
Company Drilling and Completion Supervisor The Company Drilling and Completion Supervisor retains overall responsibility on the rig during testing operations assisted by the Company Junior Drilling and Completion Supervisor and the well site Geologist. He is responsible for the co-ordination of testing operations, well preparation for tests, shut-in of the well, formation clean out, measuring, flaring and wire-line 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, Wire-line Operator and Production Test Crew, as well as the Down-hole Tool Operator and Surface Tool Operator.
3.2.2.
Company Junior Drilling and Completion Supervisor The Company Junior Drilling and Completion Supervisor shall assist the Company Drilling and Completion Supervisor to accomplish his duties. He shall also prepare accurate daily reports on equipment used.
J. Keemink @2009
Page 14
4.
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 program, whenever test behavior 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, Down-hole Tool Operator), refer to long test responsibilities.
WELL TESTING PROGRAM When the rig reaches Total Depth (TD) and all the available data is analyzed, the company Reservoir/Exploration Departments shall provide the Company Drilling/Production and Engineering 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 Drilling, Production and Engineering departments shall then prepare a detailed testing program verifying that the testing equipment conforms to these procedures. The duty of the Engineering Department is 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 program feasibility, verifying that the test program 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 program 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, Engineering departments 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 program shall be drawn up in order to acquire all necessary information taking into account two essential factors: The risk to which the rig and personnel are exposed during testing. The cost of the operation.
A detailed testing program shall include the following points: 1) 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. 2) Detailed and specific instructions covering well preparation, completion and casing perforating system, detailed testing program field analysis on test data and samples, mud program and closure of the tested interval.
J. Keemink @2009
Page 15
5.
SAFETY BARRIERS Barriers are the safety system incorporated into the structure of the well and the test string design to prevent uncontrolled flow of formation fluids and keep well pressures off the casing. It is common oilfield practice to ensure there are at least two tested barriers in place or available to be closed at all times. A failure in any barrier system which means the well situation does meet with this criteria, then the test will be terminated and the barrier replaced, even if it entails killing of the well to pull the test string. To ensure overall well safety, there must be sufficient barriers on both the annulus side 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 test ing. Well kill operations are conducted after the test.
During the testing operation when the packer is set and the well is flowing, the test fluid is only one of the barriers on the annulus side. The test fluid density will be determined form log information and calculated to provide a hydrostatic pressure, generally between 100-200psi, greater than the formation pressure. completion. As the test fluid is usually a clear brine for damage prevention reasons, high overbalance pressures may cause severe losses and alternatively, if the overbalance pressure is too low, any fluid loss out of the wellbore may quickly eliminated the margin of overbalance. When using low overbalance clear fluids, it is important to calculate the temperature increase in the well during flow periods as this decreases the density. An overbalance fluid is often described as the primary barrier during well operations. A modern test method used on wells which have high pressures demanding high density test fluids which are unstable an extremely costly, is to design the well test with an underbalanced fluid which is much more stable and cheaper. In this case there will be one barrier less than overbalance testing. This is not a problem providing the casing is designed for the static surface pressures of the formation fluids and that all other mechanical barriers are available and have been tested. 5.2.
MECHANICAL BARRIERS - ANNULUS SIDE On the annulus side, the mechanical barriers are: Packer/tubing envelope. Casing/BOP pipe ram/side outlet valves envelope.
J. Keemink @2009
Page 16
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 utilized to allow the rig to suspend operations and leave the well location for any reason. On a jack-up, a safety valve is installed below the mud line as additional safety in the event there is any damage caused to the installation (usually approx. 100m below the rig floor). Both systems use a slick joint spaced across the lower pipe rams to allow the rams to be closed on a smooth OD. 5.2.1. SSTT Arrangement A typical SSTT arrangement is shown in figure 5.a. The positioning of the SSTT in the stack is important to allow the blind rams to be closed above the top of the SSTT valve section providing additional safety and keeping the latch free from any accumulation of debris which can effect re-latching. Note: The shear rams are not capable of cutting the SSTT assembly unless a safety shear joint is installed in the SSTT across the shear ram position. Figure 5.A - SSTT Arrangement
5.2.2.
J. Keemink @2009
Safety Valve Arrangement On jack-ups where smaller production casing is installed, the safety valve may be too large in OD (7-8ins) to fit inside the casing. In this instance a spacer spool may be added between the stack and the wellhead to accommodate the safety valve. This is less safe than having the valve positioned at the mud line as desired
Page 17
5.3.
MECHANICAL BARRIERS - PRODUCTION SIDE On the production side there are a number of barriers or valves which may be closed to shutoff well flow. However some are solely operational devices. The barriers used in well control are:
Semi-submersible string - Latched 1) Tester valve 2) SSTT 3) Surface test tree. Semi-submersible string - Unlatched 1) Tester valve 2) SSTT. Jack-Up 1) Tester valve 2) Safety valve 3) Surface test tree. Land well 1) Tester valve 2) Safety valve 3) Surface test tree. 5.3.1.
Tester Valve The tester valve is an annulus pressure operated fail safe safety valve. It remains open by maintaining a minimum pressure on the annulus with the cement pump. Bleeding off the pressure or a leak on the annulus side closes the valve.
The tester may have an alternate lock open cycle device and it is extremely important that this type of valve is set in the position where the loss of pressure closes the valve. It is unsafe to leave the tester valve in the open cycle position as in an emergency situation there may not be sufficient time to cycle the valve closed. The tester valve may be considered as the primary barrier during the production phase.
J. Keemink @2009
Page 18
5.3.2.
Tubing Retrievable Safety Valve (TRSV) or (SSSV) This is a valve normally installed about 100m below the wellhead or below the mud line in permanent on-shore and off-shore completions respectively. This type of valve can also be installed inside the BOP for well testing as an additional down-hole barrier on land wells or on jack-up rigs, see figure 5.b 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 meters 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.
5.4.
CASING OVERPRESSURE VALVE A test string design which includes an overpressure rupture disk, or any other system sensible to casing overpressure, should have an additional single shot down-hole safety valve to shut off flow when annulus pressure increases in an uncontrolled manner. This additional safety feature is recommended only in particular situations where there are very high pressures and/or production casing is not suitable for sudden high overpressures due to the test string leaking. This valve is usually used with the single shot circulating valve which is casing pressure operated and positioned above the safety valve, hence will open at the same time the safety valve closes. This allows the flow line to bleed off the overpressure.
6.
TEST STRING EQUIPMENT
6.1.
GENERAL The well testing objectives, test location and relevant planning will dictate which is the most suitable test string configuration to be used. Some generic test strings used for testing from various installations are shown.
In general, well tests are performed inside a 7ins production liner, using 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 bare-foot-test, conventional test tools will usually be used with a packer set inside the 95/8ins casing.
J. Keemink @2009
Page 19
If conditions allow, the bottom of the test string should be 100ft above the top perforation to allow production logging, re-perforating and/or acid treatment of the interval. In the following description, tools which are required both in production tests and conventional tests are included. The list of tools is not exhaustive, and other tools may be included. However, the test string should be kept as simple as possible to reduce the risk 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 program, 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).
Fig. – TCP Guns 6.2.
Fig. – Retrievable Packer
Fig. – Bridge Plug
COMMON TEST TOOLS DESCRIPTION 6.2.1.
Beveled Mule Shoe If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top. The beveled mule shoe also facilities pulling wire-line tools back into the test string. If testing with a permanent packer, the mule shoe allows entry into the packer bore.
6.2.2.
Perforated Joint/Ported Sub The perforated joint or ported sub allows wellbore fluids to enter the test string if the tubing conveyed perforating system is used. This item may also be used if wire-line retrievable gauges are run below the packer.
J. Keemink @2009
Page 20
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 and temperatures.
6.2.4.
Pipe Tester Valve A pipe tester valve is used in conjunction with a tester valve which can be run in the open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure which is during the first cycling of the tester valve.
6.2.5.
Retrievable Test Packer
The packer isolates the interval to be tested from the fluid in the annulus. It should be set by turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from being pumped up the hole under the influence of differential pressure from below the packer.
6.2.6.
Circulating Valve (Bypass Valve) This tool is run in conjunction with retrievable packers to allow fluid bypass while running in and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It can also be used to equalize differential pressures across packers at the end of the test. It is automatically closed when sufficient weight is set down on the packer This valve should ideally contain a time delay on closing, to prevent pressuring up of the closed sump below the packer during packer setting. This feature is important when running tubing conveyed perforating guns which are actuated by pressure. If the valve does not have a delay on closing, a large incremental pressure, rather than the static bottom-hole pressure, should be chosen for firing the guns
6.2.7.
Pipe Tester Valve A pipe tester valve is used in conjunction with a tester valve which can be run in the open position in order to allow the string to self fill as it is installed. The valve usually has a flapper type closure mechanism which opens to allow fluid bypass but closes when applying tubing pressure for testing purposes. The valve is locked open on the first application of annulus pressure which is during the first cycling of the tester valve.
J. Keemink @2009
Page 21
6.2.8.
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.
6.2.9.
Hydraulic Jar
The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an over-pull to be taken on the string which is then suddenly released, delivering an impact to the stuck tools.
6.2.10. Down-hole Tester Valve
The down-hole tester valve provides a seal from pressure from above and below. The valve is operated by pressuring up on the annulus. The down-hole test valve allows down-hole shut in of the well so that after-flow effects are minimized, providing better pressure data. It also has a secondary function as a safety valve.
J. Keemink @2009
Page 22
6.2.11. Single Operation Reversing Sub Produced fluids may be reversed out of the test string and the well killed using this tool. It 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. 6.2.12. Multiple Operation Circulating Valve This tool enables the circulation of fluids closer to the tester valve whenever necessary as it can be opened or closed on demand and is generally used to install an underbalance fluid for brining in the well. This tool is available in either annulus or tubing pressure operated versions. The tubing operated versions require several pressure cycles before the valve is shifted into the circulating position. This enables the tubing to be pressure tested several times while running in hole. Company’s preference is the annulus operated version. 6.2.13. Drill Collar Drill collars are required to provide a weight to set the packer. Normally two stands of 43/4ins drill collars (46.8lbs/ft) should be sufficient weight on the packer, but should be regarded as the minimum. 6.2.14. 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. 6.2.15. Crossovers Crossovers warrant special attention They are of the utmost importance as they connect every piece of equipment in the test string which have differing threads. If crossovers have to be manufactured, they need to be tested and fully certified. In addition, they must be checked with each mating item of equipment before use. 6.3.
HIGH PRESSURE WELLS If the SBHP >10,000psi a completion type test string and production Xmas tree is recommended to test the well.
6.4.
SUB-SEA TEST TOOLS USED ON SEMI-SUBMERSIBLES The sub-sea test tree (SSTT) assembly includes a fluted hanger, slick joint, and sub-sea test tree. 6.4.1. 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. 6.4.2.
J. Keemink @2009
Slick Joint (Polished Joint) The slick joint (usually 5ins OD) is installed above the fluted hanger and has a smooth (slick) outside diameter around which the BOP pipe rams can close and sustain annulus 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 Page 23
be closed on it and also allow the blind rams to close above the disconnect point of the SSTT.
6.5.
6.4.3.
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; 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; a 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.
6.4.4.
Lubricator Valve The lubricator valve is run one stand of tubing below the surface test tree. This valve eliminates the need to have a long lubricator to accommodate wire-line 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 hydraulic operated through a second umbilical line and should be either a fail closed or; fail-in-position valve. When it is closed it will contain pressure from both above and below.
DEEP SEA TOOLS 6.5.1.
Retainer Valve The retainer valve is installed immediately above the SSTT on tests in extremely deep waters to prevent large volumes of well fluids leaking into the sea in the event of a disconnect. It is hydraulic operated and must be a fail-open or fail-in-position valve. When it is closed it will contain pressure from both above and below. It is usually run in conjunction with a deep water SSTT described below.
6.5.2.
Deep Water SSTT 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. This is overcome by use of the deepwater SSTT which has an Electro-Hydraulic control system. The Hydraulic deep water actuator is a fast response controller for the deepwater SSTT and retainer valve. This system uses hydraulic power from accumulators on the tree controlled electrically from surface (MUX). The fluid is vented into the annulus or an atmospheric tank to reduce the lag time and reducing closure time to seconds. If a program required deepwater test tools, the tool operating procedures would be included in the test program.
7.
SURFACE EQUIPMENT This sub-section contains the list of surface equipment and the criteria for use.
7.1.
TEST PACKAGE
J. Keemink @2009
Page 24
7.1.1.
Flow head Or Surface Test Tree Modern flow heads are of solid block construction, i.e. as a single steel block, as opposed to the earlier modular unit which was assembled from various separate components. Irrespective of the type, both should contain: Upper Master Valve for emergency use only. Lower Master Valve situated below the swivel for emergency use only. Kill Wing Valve on the kill wing outlet connected to the cement pump or the rig manifold. Flow Wing Valve on the flow wing outlet, connected to the choke manifold, which is the ESD actuated valve. Swab Valve for isolation of the vertical wire-line or coil tubing access. Handling Sub which is the lubricator connection for wire-line or coiled tubing and is also for lifting the tree. Pressure Swivel which allows string rotation with the flow and kill line connected.
On floating rigs, with the rig at its operating draft, the flow head 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, i.e. 5ft and a further 5ft safety margin. Coflexip hoses are used to connect from the flow head kill wing and flow wing to the rig manifold and the test choke manifold. A permanently installed test line is sometimes available which leads from the drill floor to the choke manifold location. 7.1.2.
J. Keemink @2009
Coflexip Hoses And Pipework Coflexip hoses must be installed on the flow head correctly so as to avoid damage. They must be connected so that they hang vertically from the flow head wings. The hoses should never be hung across a wind wall 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 due to having fewer connections. On floaters, they connect the stationary flow head to the moving rig and its permanent pipe work. Page 25
Permanently installed surface lines should be used with the minimum of temporary connections supplied from the surface testing contractor. Ideally these temporary connections should be made-to-measure pipe sections with welded connections, however chiksans can be used but must be tied down to the deck. Additional protection can be given by installing relief valves in the lines. Is now comm on practice to have a relief valve on the line between the heater and the separator to cater for any blockage downstream which may cause over-pressure in the line. If there is further risk from plugging of the burner nozzles by sand carry-over, then consideration should be given to installing further relief valves downstream of the separator to protect this lower pressure rated pipe work. Note: Ensure that the Coflexip hoses are suitable for use with corrosive brines. 7.1.3.
Data/Injection Header This item is usually situated immediately upstream of the choke. The data/injection header is merely a section of pipe with several ports or pockets to mount the following items: Chemical injection Wellhead pressure recording Temperature recording Wellhead pressure recording with a dead weight tester Wellhead sampling Sand erosion monitoring Bubble hose.
Most of the pressure and temperatures take off points will be duplicated for the Data Acquisition System sensors.
7.1.4.
Choke Manifold The choke manifold is a system of valves and chokes for controlling well flow and usually has one adjustable and one fixed choke. Some choke manifolds may also incorporate a bypass line. The valves are used to direct the flow through either of the chokes or the bypass. They also provide isolation from pressure so that the choke changes can be made.
A well shall be brought in using the adjustable or variable choke. This choke should never be fully closed against well flow. The flow should then be redirected to the appropriately J. Keemink @2009
Page 26
sized fixed choke for stable flow conditions. The testing contractor should ensure that a full range of fixed chokes 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 these have been checked during the previous refurbishment to confirm they were still within specification. 7.1.5.
Steam Heater And Generator Heat is required from the steam heater, or heat exchanger, to: Prevent hydrate formation on gas wells Prevent wax deposition when testing high waxy, paraffin type crudes Break foams or emulsions Reduce viscosity of heavy oils.
For use on high flow rate wells, a 4ins bore steam heater should be used to reduce high back pressures. The heat required to raise a gas by 1oF can be estimated from the formula: 2,550 x Gas Flow (mm scf/day) x Gas Specific Gr avity (air = 1.000), BTU/hr/oF
The heat needed to raise an oil by 1oF can be estimated from: 8.7 x Oil Flow (bbls /day) x Oil Density (gms/cm 3), BTU/hr/oF
Always use the largest steam heater and associated generator that space or deck loading will allow as the extra output is contingency for any serious problem which may arise. The rig steam generator will not usually have the required output and therefore diesel-fired steam generator in conjunction with the steam heat exchanger should be supplied by the surface test contractor. 7.1.6.
J. Keemink @2009
Separator The test separator is required to: Separate the well flow into three phases; oil, gas and water Meter the flow rate of each phase, at known conditions Measure the shrinkage factor to correct to standard conditions Sample each phase at known temperature and pressure. The standard offshore separator is a horizontal three phase, 1,440psi working pressure unit. This can handle up to 60mmscf/day of dry gas or up to 10,000bopd and associated gas at it working pressure Other types of separator, such as the vertical or spherical models and two phase units may be used. Gas is metered using a Daniel’s or similar type orifice plate gas meter. The static pressure, pressure drop across the orifice plate and the temperature are all recorded. From this data the 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-pressurize and cool to ambient conditions. The shrinkage factor is the ambient volume, divided by the original volume. The small volume, however, 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 Page 27
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 discrepancy with 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. 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 computerized Data Acquisition Systems (DAS) on offshore well tests. However, it is essential that manual readings are still separately recorded for correlation of results and contingency in the event of problems occurring to the system. These systems can collect, store and provide plots of: Surface data Down-hole data from gauges Memory gauge data. The main advantage of DAS is that real time plots can be displayed at the well site for troubleshooting. Another advantage is that all of the surface (and possibly down-hole) data is collected into one system and can be supplied on a floppy disk for the operator to analyze and subsequently prepare well reports.
7.1.8.
Gauge/Surge Tanks And Transfer Pumps A gauge tank is an atmospheric vessel whereas a surge tank is usually rated to 50psi WP and is vented to the flare. A surge tank is essential for safe working if H2S production is anticipated. Therefore, 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 which are too low for accurate flow meter measurement. They usually have a capacity of one hundred barrels and some with twin compartments so that one compartment can be filled while the other is pumped to the burner via the transfer pump. Tanks can also be used for collecting large atmospheric samples of crude for analysis or used as a secondary separator for crudes which 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.
J. Keemink @2009
Diverter Manifolds, Burners and Booms
Page 28
Burner heads are mounted on the end of the booms which are usually installed on opposing sides of the rig to take maximum advantage of wind direction changes, i.e. to keep at least one burner heading downwind. The oil and gas flowlines, including the tank and relief vent lines, from the test area to the booms, must have diverter manifolds for directing flow to the leeward boom. Most recent designs of burners are promoted as ‘green’ or ‘clean’ type burners. This is indicative of them being less polluting to the environment by having superior burning technology. Although still not ‘ideal’ their ability is much improved over previous models. The burner has a ring of atomizers or nozzles which break up the flow for complete combustion. This is assisted by pumping air into the flow stream. 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, suitably fitted with check valves. It is recommended that the air compressors are manifolded together to provide a continuous supply of air in the event of a compressor failure. 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 which 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 combustion but, if there is only partial combustion, carry over can cause pollution. Oil slicks can also be ignited and be 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. Figure 7.A - Surface Equipment Layout
J. Keemink @2009
Page 29
7.2.
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 flow head 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 flow head 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
J. Keemink @2009
Page 30
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.
7.4.
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, flow head or at the SSTT/subsurface safety valve. 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 flow stream. 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 sample at the data/injection manifold to monitor for sand production. If the flow rates are low, samples taken from the high side of flow line 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 flow rate 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. Erosion can eventually cause: Reduced pipe wall thickness and cutting of holes in pipe work, 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 down-hole test tools.
7.3.3.
Crossovers Crossovers warrant special attention They are of the utmost importance as they connect every piece of equipment in the test string which have differing 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.
RIG EQUIPMENT The main items of rig equipment used for testing, such as the permanent pipe work and water spray system have been addressed previously. However, it is essential that all the necessary rig
J. Keemink @2009
Page 31
equipment which is to be used, has been checked. This includes the rig water pumps, cement pumps, mud pumps and the BOPs. The BOP rams must be dressed in accordance with the test program. Also there are some smaller item s of equipment required which must be made available. These include; long bails for rigging up equipment above the flow head, 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.
Laboratory and Instrument Manifold Equipment Hydrometer for measuring gravity of produced liquids. Manometer for calibrating DP meters. Shrinkage tester to allow the calculation of production in stock tank barrels. Dead-weight tester for pressure gauge checking and calibration. Gas gravity meter 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. Down-hole sampling kit.
Hydrometer
Deadweight Tester
Gas Gravity Meter
Pressure Gauges
Draeger Pump & Tubes
Chemical Injection Pump
Recorder
Temperature Gauges
Some instrumentation is mounted on the test equipment such as:
J. Keemink @2009
Page 32
7.5.2.
Separator Oil flow meters on both separator oil lines. Gas flow meter. Thermometers. Pressure gauges.
7.5.3.
Surge Or Metering Tank Sight glasses and graduated scales. Thermometer. Pressure Gauge.
7.5.4.
Steam Heater Temperature controller.
Other special instrumentation must be listed in the specific test program. 8.
BHP DATA ACQUISITION The two of the most important parameters measured during well testing are down-hole pressures and temperatures. This data is obtained from BHP gauges installed as close to the perforations as is practicable. BHP gauges are either mechanical or electronic type gauges. The mechanical BHP gauge is rarely used today as it accuracy does not generally meet the demands of engineers for modern analysis. It does still have uses on high temperature wells where the temperature is above the limit of electronic gauges or when simple low cost surveys are required; for instance, to obtain bottom hole pressure before a workover. They are cheaper due to the 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 are more susceptible to damage like the crystal gauge and also more expensive. The criteria used should be to select the most robust and cost competitive gauge which meets the test requirements. Currently there are three basic types of pressure sensors used in electronic gauges available: Quartz Crystal, Capacitance, and Strain. The electronic gauge can operate through an electric cable for surface read out in real time but more generally is run with an 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 where gauges now have up to 500K. They can also be programmed to change the sampling speed at various times and/or on pressure change
points in the test. Both mechanical and electronic types of gauges are listed below in order of decreasing accuracy. 8.1.1.
J. Keemink @2009
Quartz Crystal Gauge The principle of the gauge is the change in 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. Poor temperature resolution used to be the Achilles’ heel of the crystal gauge but modern gauges have overcome this problems by having the temperature sensor built into the crystal assembly. The tool is comparatively delicate because of the fragility of the crystals. Page 33
8.2.
8.1.2.
Capacitance Gauge The 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 is much more robust than the crystal gauge. It did not suffer from poor temperature resolution like the earlier crystal gauges as the temperature sensor is an integral part of the pressure diaphragm.
8.1.3.
Strain Gauge The strain gauge principle works on the deflection of a diaphragm. Pressure acting one side of the diaphragm causes the deflection which is measured and translated into pressure. The accuracy of the gauge is lower than the quartz or the capacitance. This type of gauge is extremely robust and is not affected by temperature changes.
8.1.4.
Bourdon Tube Gauge This is a mechanical gauge and was the first type of pressure gauge and is very robust. 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 hand operated chart reader or electronically by a computerized chart reader. The gauge accuracy is much lower than any of the electronic gauges.
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 pressure and temperature data as near to formation conditions as possible. On a well test this can be done by one of two methods: tubing conveyed or on wire-line. 8.2.1.
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 down-hole gauges without having to pull the string. This is an advancement in technology which means 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.
8.2.2.
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 the string off at the safety joint. Also, the packer absorbs some shock from tubing conveyed guns providing protection for the upper gauges.
J. Keemink @2009
Page 34
9.
8.2.3.
SRO Combination Gauges Systems which allow the databanks of the gauges run in the upper gauge case to be read have been developed. The disadvantages of the SRO system are thus eliminated as the gauges may be read continually or periodically. However 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 tried and proven tester valves for the down-hole closure which are ported to above the valve to a bank of memory gauges or transducers. 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 is not stationed in the well, i.e. latched into the housing, during flow periods unless absolutely necessary. This reduces the risk from becoming stuck due to sand production or the wire getting cut through flow erosion.
8.2.4.
Wire-line 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 down-hole shut-in tool, similar to the SRO systems described earlier, except they use wire tension to open and close a separate shut-in mechanism, usually a sliding sleeve type device.
8.2.5.
Memory Gauges Run on Slick-line A number of memory gauges, usually three but can be as many a physically possible, may be run in on slick-line and set in a nipple positioned below the perforated joint. The advantages of this system are that the well may be shut-in down-hole, eliminating after flow effects. Also the gauges may be recovered, e.g. after the first build-up, and the data 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 wire-line BHP gauge hanger.
8.2.6.
Electronic Gauges Run on Electric Line Gauges may be run on electric line to give a ‘real-time’ readout of data at surface. This 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 which allow the well to be shut-in down-hole and still have 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.
PERFORATING SYSTEMS
J. Keemink @2009
Page 35
Two methods are currently used to perforate wells: wire-line conveyed guns or tubing conveyed guns. Tubing conveyed perforating is the Company’s 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 wire-line 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 bottom hole temperature and the length of time the guns are likely to be on bottom before firing (Refer to the ‘Completion Manual Perforating Section’)
9.1.
TUBING CONVEYED PERFORATING With this method the guns are run in the hole on the bottom of well testing string. Therefore, the guns and charge size can be maximized 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 utilized, depending on well conditions.
9.2.
WIRE-LINE CONVEYED PERFORATING There are two alternatives when perforating using wire-line 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 which cannot be run through normal tubing size. Therefore they must be used prior to run the test string and in overbalance conditions. Through-tubing guns are small diameter guns run through the test string. They can be used to perforate under-balance, 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”.
J. Keemink @2009
Page 36
Fig.
9.3.
– Tubing Conveyed Perforating
Fig. – Wireline Perforating
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 specialized 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 recognized explosive signs. d) Any remainder at the end of the test shall be returned to shore. 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.
J. Keemink @2009
Page 37
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. The Company Drilling and Completion Supervisor shall collect all portable radios inside company office in order to avoid any possibility of untimely use. Radio silence shall be observed while guns are being primed and while primed guns are above seabed. j) The following shall be advised prior to radio silence being in force: Stand by vessel. Helicopter operations. Company Shore Base. Other nearby installations. k) In the event of uncontrollable sources of potential such as thunderstorms, operations involving the use of explosive shall be suspended. The only 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. l) 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). m) When the casing is perforated before running the DST string, mud level in the well shall be visually monitored. n) 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. o) The same principle applies for the weight of the fluid in the tubing/casing annulus when perforating after the DST string has been run. p) The first casing perforation shall be performed in daylight. Subsequent series of shots can be carried out at any time.
10.
PREPARING THE WELL FOR TESTING This section describes the operations necessary to prepare the well for well testing.
10.1.
PREPARATORY OPERATIONS FOR TESTING 10.1.1. Guidelines For Testing 7ins Liner Lap 1) While waiting on cement, test the BOP stack according to the Company Well Control Policy Manual procedures. Pull out of the hole with the test tool. 2) Run a 6ins bit/mill and clean out the 7ins liner to the landing collar (PBTD). The drilling program must allow for sufficient rat hole to enable TCP guns to be dropped off, if required. 3) Run a cement bond/correlation log from PBTD to top of 7ins liner. 4) Run in hole with 95/8ins packer assembly and perform positive and negative tests on liner lap as per the Company Drilling and Completion Supervisor’s instructions. As 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 drill pipe 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
J. Keemink @2009
Page 38
pressure for influx for 1hr. If the liner lap or liner is found to be leaking then a remedial cementing program will be advised. 10.1.2. Guidelines For Testing 95/8ins Liner Lap 1) While waiting on cement, test the BOP stack according to the Company Well Control Policy Manual procedures. Pull out of the hole with the test tool. 2) Run a 81/2ins bit/mill and clean out the 95/8ins casing to the landing collar (PBTD). The drilling program must allow for sufficient rat hole to enable TCP guns to be dropped off, if required. 3) Run a cement bond/correlation log from PBTD to above the packer setting depth. 10.1.3. General Technical Preparations 1) Surface well testing equipment should be installed and pressure tested as per the procedures in Section 7. 2) DST tools should be laid out and tested on the pipe desk (Refer to Section 10.8). 3) Ensure that all down-hole 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 beveled inside and outside. 4) Make a visual inspection to verify the condition of packer rubbers and all DST equipment. 5) Drift all DST equipment to ensure full ID for wire-line, coiled tubing or Surface Read Out (SRO) tools to be run in the hole. 10.2.
BRINE PREPARATION In order to efficiently utilize 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 Preparation of Brine 1. Filter and recondition any (suitable) brine which is in stock. 2. Following the final filtration/reconditioning cycle of this stored fluid, re-weigh and adjust as necessary to suit the conditions of the well. 3. Prepare balance of fluid from sacked material or liquid, as appropriate. Filter and condition as necessary. 10.2.2. 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: 1) Onshore Brine Tanks Dip storage tanks before transferring fluids. Take samples of brine at beginning, middle and end of pumping. If required, submit to the district office. Check samples for SG at 60oF; centrifuge for solids content, check clarity. Dip storage tanks after brine is loaded onto transport vessel. Record and submit report the volume and density of brine provided by brine supplier. 2) Pumping into Vessel
J. Keemink @2009
Page 39
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. 3) Off-loading Brine at Rig-Site Inspect pontoons/tanks/pits for cleanliness, report any residual solids or fluids and ensure their removal prior to off-loading. Obtain calibration charts in order 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.
10.2.4. Rig Site Preparations The importance of initial cleanliness of mud/brine tanks, pumps, lines, etc. can not be over-emphasized. 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 and pumps can be 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. When all the mud has been emptied from the pit tanks to be used, 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 de-scaler/oil mud remover. Pump second pill into first pit and first pill into third pit. Continue the system 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. 2) Dump Valves Prior to receiving the brine, ensure all ‘O’ rings and seats are functioning correctly. Leaking valves can cause significant brine losses. 3) Ditch Gates - Slide Type
J. Keemink @2009
Page 40
4) 5) 6)
7)
8)
9)
All gates should be sealed prior to receiving brine. Two layers of ‘Densotape’ a pplied 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. Water Lines All water lines should be taped or chained off. Pump Packing Replace all work mixing pump packing. Tripping Significant losses of brine can be avoided during tripping by: Using wiper plugs Using collection box and drip pan Slugging of pipe with heavier weight brine. 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. 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, 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. 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 pre-determined that fluid can be completely removed when required.
10.2.5. 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. 10.2.6. Displacement Procedure Extensive displacement procedures will be issued by the Brine Contractor. The procedures will be contained as part of the detailed well specific test program. The technique utilized 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 utilized).
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. J. Keemink @2009
Page 41
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) Install filtration equipment in order to operate at its maximum efficiency. 2) Filtration service company should advise proper DE filter aids and cartridge size to ensure maximum filtration efficiency and economics based on type of fluid to be filtered, anticipated contaminants such as barite solids, mud solids, oil, etc. 3) Brine in suction tank should be maintained at proper density and filtered prior to being pumped into hole. 4) Returns of brine should be placed in adequate settling/separation tank tank to allow proper chemical treatments and filtration before being placed into the active brine system. 5) 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. 6) Avoid dilution of brines brines caused by water hoses, water lines, washing down or rig and/or filtration equipment, etc. 7) Pick up bit for casing and drill out cement to the top of the liner. If it is planned 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. 8) Run in the hole with bit for liner and drill out the liner to landing collar which is then the PBTD (Refer to section 10.1). 9) Run and record CBL/VDL or CET from the landing collar to the top of the liner. 10) If there are reasons to believe that the integrity of the seal on the liner lap is not effective, a pressure and/or inflow test should be performed (Refer to section 10.1). 11) If the liner lap is found to be leaking then a remedial cementing job is advised.
10.3.
DOWN-HOLE EQUIPMENT PREPARATION 10.3.1. Test tools Down-hole 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) Layout all of the tools on the pipe deck for inspection. 2) Measure the tools and provide a dimensional sketch for each, giving: Identification number Length Maximum outside diameter Minimum inside diameter Thread connection up Thread connection down Fishing neck dimensions.
J. Keemink @2009
Page 42
3) 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. 4) 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. 5) Pressure test, from above, all test string valves, valves, if appropriate, to a minimum of 1,000psi above either the maximum differential pressure, or wellhead pressure, whichever is the greatest. 6) Where appropriate, the down-hole test equipment should be be function tested. 7) The test string components must be drifted to the 2.25ins maximum drift size to cater for all contingencies. 8) These tests should be carried out on the pipe deck and the tools dressed with the correct value shear pins or rupture discs, as per program. 9) Check that the appropriate crossovers are available and make up to the down-hole test equipment. This equipment includes, but is not limited to: Lubricator Valve Retainer Valve Sub-sea Test Tree Circulating Valve(s) Tester Valve (with Hydraulic Reference Section, if appropriate) Gauge Carriers Permanent Packer Seal Assembly or Retrievable Packer and associated Jars, Safety Joint and Slip Joints. 10.4.
TUBING PREPARATION Careful consideration of the tubing to be selected and how it is handled, checked and tallied is essential in well testing operations. The following sub-sections provide a short description of the important tubing aspects which need to be considered for a well test. 10.4.1. Tubing Connections One of the important aspects to be considered in a well test is the type of thread connection to be used for the tubing string. 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 metalto-metal seals 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 which is best fit for purpose. It is normally agreed that premium threads with a torque shoulder such as Hydril is ideal for testing as it has low refurbishment costs and is quick to make up and reasonably robust against handling J. Keemink @2009
Page 43
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, L 80, N 80, C 95. The letter signifies the properties of the steel and the number signifies its minimum tensile strength in 1,000lbs per sq inch, i.e. N 80 signifies a normalized and tempered carbon steel with 80,000lbs/ins2 minimum yield. The cross-sectional area of the tubing multiplied by the minimum yield stress provides the joint yield strength, e.g. Company’s 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. Company’s test string is grade D 95 SG (Dalmine designation, equivalent to C 95) and is suitable for tests where H2S is present. 10.4.4. Weight per Foot Is a the term used in conjunction with the tubing OD in order to signify the thickness, e.g. 41/2 ins 15.5lbs/ft has a wall thickness of 0.337ins hence an ID of 4.5 - (2 x 0.337) 3.826ins. 10.4.5. Drift Is slightly less than ID and represents maximum effective available bore diameter for 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. the Company’s tubing has 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 rotational force applied to connect the pin and the box connections to optimize the mechanical and sealing performance of the connections, e.g. the values for Company’s string are as follows: Minimum - 6,800ft/lbs Optimum - 7,650ft/lbs J. Keemink @2009
Page 44
Maximum - 8,500ft/lbs. 10.4.9. Company Test String Specification When possible, Company shall use its own standard test string which is 41/2ins OD with Dalmine SPJD 6 connections (compatible with Hydril PH6 of the same size). The grade of this tubing is D 95-SG (equivalent to C 95) which denotes Dalmine, 95,000psi minimum yield strength, Sour Gas service. table 10.a provides dimensional strength and performance data for the Company’s string. TYPE: 41/2 OD - 15.5lbs/ft Grade D 95 Dalmine SPJ D - 6 (Hydril PH 6 Compatible) Pipe Connection ID 3.826ins 3.765ins Drift 3.701ins Torque Values Min 6,800ft/lbs Opt 7,650ft/lbs Max 8,500ft/lbs Capacity 0.01422bbls/ft or 14.22bbls/1,000 ft Displacement 0.00564bbls/ft or 5.64bbls/1,000 ft Burst 12,450psi Collapse 12,760psi Yield 419,000lbs Table 10.A - AGIP (UK) Tubing Data 10.4.10. Inspection Prior To Running (On Board Visual Inspection And Field Repair) Ensure all connections are dried after cleaning and before inspection. Check the starting threads to ensure they have no small slivers or edges of steel which 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. 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: Out-of -roundness Corrosion pits, rust and scale J. Keemink @2009
Page 45
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. 10.4.11. After Testing/Prior To Re-Use After a series of tests and before re-utilization in another well, that part of the tubing used shall be inspected onshore.
Callipering Thread visual inspection Full length body log for cracking (e.g. Tuboscope) Hardness check. 10.4.12. Tubing Movement As part of the design process for the testing string, calculations should be performed by the DST contractor and confirmed by Company 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 seal-bore packer. 10.5.
LANDING STRING SPACE-OUT This procedure is applicable to testing from Semi-submersibles. The purpose of this procedure is to check the space-out of the fluted hanger, slick joint and SSTT inside the Subsea BOPs and determine the length of landing string required to provide the required height of the flow head 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 drill pipe. 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. Figure 10.A - SSTT Arrangement Figure 10.B - Typical Safety Valve Arrangement for a Jack-up 10.5.1. Landing String space-Out Procedure The procedure is: 1) Check that the rig is at operating draft.
J. Keemink @2009
Page 46
2) Make up the fluted hanger to the slick joint, with the appropriate adjustment, to give the correct length according to the stack drawing dimensions. 3) Pick up the fluted hanger and slick joint assembly and paint the slick joint with white paint. 4) Run in to immediately above the BOPs and engage the compensator. 5) Land the hanger in the wellhead. Pick up slightly and turn to the right to ensure the hanger has fully landed out. 6) Carefully close the rams on the slick joint, checking the volume of fluid taken to confirm that they are fully closed. 7) Mark the string at the drill floor at mid-heave. 8) Record the tide level. 9) Open the rams and strap out to the first connection to obtain the depth to the hangoff point at this tide level. 10) Pull the pipe and lay out the hanger and slick joint being careful not to smudge the paint marks. 11) Check where the ram marks are positioned on the slick joint. If the measure from the centre of the rams to the wellhead housing does not correlate, then re-check the stack dimensions. 12) 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 monitoring during DST operations. 10.6.
GENERAL WELL TEST PREPARATION 10.6.1. Crew Arrival on Location Contractor Service Specialist is to meet with the Company Representative and discuss the test program and any updates to the original program. 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 Maximum deviation Mud viscosity
Cushion type Bottom-hole temperature Maximum casing/liner test pressure Anticipated production rates. 2) 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. J. Keemink @2009
Page 47
3) Confer with the Tool Pusher concerning testing requirements during the test, such as: Procedures for pressure testing and functioning equipment and the necessity of doing this in a restricted area within easy access to air and water points. Pressure control and monitoring of the annulus. In particular, the presence of non return valves in the rig manifolding needs to be discussed and how they can 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. 10.6.3. Preliminary Inspections The following preliminary inspections, shall be carried out before starting testing operation, under the direct responsibility of the Company Drilling and Completion Supervisor who can avail himself of Company Drilling Engineer (if Present) and drilling contractor personnel (Toolpusher): 1) All tubular goods not required for the execution of the test and for the preparatory operations (scraping, setting of bridge plugs, etc.), shall be laid down from the derrick floor prior to start the test. 2) Fishing tools for all equipment to be used during testing shall be on rig. 3) Working area on the rig floor and around the separator, heater, tank and flare shall be clear of obstructions and flammable substance. 4) An adequate platform shall be available to operate the valves on the flow head. 5) Inspections shall be performed on masks, self breathing apparatus, resuscitators and extinguishers in order to check their efficiency and location on the rig.
1) Electric installations placed within area classified as ‘hazardous’ shall be ‘explos ion proof’. 2) It shall be checked that all access doors and escape ways, fire doors and vent line valves of pressurized tanks are in the position prescribed by the rig procedures during ‘production tests’. 3) Fuel tanks, oxygen bottles and other pressurized bottles shall be placed far from the area classified as ‘hazardous’ and cooled with water, if necessary. 4) It shall be checked that the amount of water available to the burners water spray and to the sprinkler system is sufficient to protect the burners and the rig from heat radiation generated by the combustion. 5) Inspection shall be performed on anti-pollution equipment and chemical (dispersant) stored on rig in order to cope with any oil spill which may occur, particularly during formation clean out. 6) The accuracy of the data supplied by the anemometer (wind speed and direction) shall be checked before opening the well. 7) Prior to start well testing operations, drills shall be performed for fire-fighting and pollution prevention. 8) Inspection shall be made on operating conditions of the communication system among rig floor, flares area and production equipment area. 9) Complete BOP test shall be carried out before starting well testing operations. The following additional inspections shall be performed prior to start testing operations, under the direct responsibility of Company Drilling and Completion Supervisor, who can avail himself of production test equipment operators: 1) 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
J. Keemink @2009
Page 48
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. 2) 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 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) 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. 10.7.
PRE TEST EQUIPMENT CHECKS 1) Lay out the appropriate down-hole tools, observing correct handling and slinging procedures. Tools must be positioned in a manner so that they are secure and cause minimal obstruction. 2) Visually inspect all tools to ensure no damage was sustained in transit particularly to threads and sealing surfaces. 3) Function and pressure test tools according to procedures laid out in the service companies operations manual which will be made available on the rig. 4) Ensure that all tool dimensions are accurately measured and lengths of extending mandrels recorded etc. 5) Ensure all required 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. 6) Ensure all tubulars are drifted, cleaned internally and the connections have been inspected prior to running. 7) Lengths, ODs, IDs and thread connections of all down-hole 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 beveled inside and out. 8) All down-hole tools should be drifted to 2.125ins to allow running of surface read out or any other wire-line or coil tubing tool. 9) The pipe tester valve (PTV) should be made up to the packer on the deck and tested from below to it’s working pressure prior to running in the hole. 10) A visual inspection should be made of the packer elements prior to running. The packer should be set appropriately above the perforated interval to allow safe wire-line operations such as production logging, if required (i.e. ensure the bottom of the tailpipe is positioned approximately 100ft above the top perforation). 11) The packer should never be set across a casing collar. 12) All down-hole test tools should be pressure tested at surface to a minimum of 1,000psi above maximum anticipated pressure.
J. Keemink @2009
Page 49
13) A list of all pressure gauges and serial numbers should be compiled and submitted To the Company Production Test Supervisor. 14) Only API 5A Modified thread lubricant should be used on tools, tubing and drill collar connections. 15) The lubricant should be applied to the pin end only with a paint brush. Apply sparingly. 16) Check the brine weight as accurately as possible and ensure that it is correct, based on the RFT results. 10.8.
PRESSURE TESTING EQUIPMENT All surface and down-hole testing equipment shall be full y pressure 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) For all pressure test, the area outside accommodation must be clear of non-essential personnel. 2) 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. 3) 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. 4) BOPs, choke manifold, choke and kill lines shall be pressure tested as per Agip Well Control Policy. 5) The following equipment of the surface package shall be pressure tested: To end of burner(s). 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.
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 t to manufacturer's specification. It is common practice to make up one full single joint of tubing from the landing string to the flow head 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 flow head should be prepared on the catwalk in accordance to the contractors procedures which should be as follows: 1) With master and swab valves open, drift the flow head to it’s maximum diameter to accommodate any wire-line or coiled tubing tools to be run. 2) Function test the ESD actuator on the flow wing valve. The ESD is a fail-safe valve. 3) Make up one joint of the landing string to the flow head with chain tongs. 4) After the SSTT and landing string dummy run has been made and has been racked back in the derrick, pick up the flow head with the single joint of tubing and torque it up in the rotary table to the correct torque. 5) Check the torque on the swivel and any other flow head service connection and then paint a white band across them. J. Keemink @2009
Page 50
6) 7)
8) 9) 10) 11) 12) 13) 14) 15)
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 flow head valves and pressure test the flow head body from the bottom to test pressure Close the swab, kill wing and flow wing valves. Open the respective needle 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 and pressure test against the lower master valve from below to test pressure. Bleed off pressure below the lower master valve and leave the needle valve open. Open the swab valve and pressure test against the lower master valve from above. Close the upper master and pressure test from above. Remove the test caps. Clean and grease the connections. Fit protectors and store the flow head in a convenient place until ready to use.
The flow head shall be pressure tested before installed it on the well with a tubing pup joint assembled on bottom in the followed way: 1) Plug the kill side, the flow side and close the swab valve; pressure test the internal of flow head pumping through the pup joint. 2) Bleed off pressure and remove plugs from kill and flow side, close kill valve ,flow side fail-safe valve and pressure test the gates from inside. 3) 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 flow head configuration. Figure 10.C – Flow head Schematic 11.
TEST STRING INSTALLATION Detailed individual well programs will be issued for all wells to be tested, which includes development, appraisal and exploration wells. Each program 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 program. a) Test Objectives. b) General well data and perforating details. c) Summary of test program. d) Guidelines for liner lap test and space-out calculations. e) Sequence of operations for running down-hole tools and surface equipment rig up. f) Flowing procedures for each test conducted.
Also included will be the following, possibly as appendices: Hole cleaning and displacement to brine procedure. Stimulation program (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
J. Keemink @2009
Page 51
a) The testing string shall normally be made up of tubing. The use of drill pipe 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 well site Company Drilling and Completion Supervisor and Drilling Contractor Toolpusher to make all personnel involved are acquainted with detailed operating program (procedures and rules). 11.2.
TUBING HANDLING a) Tubing must always have the pin and box protectors in place while being handled. b) Tubing should always be handled with either certified nylon or cable slings or with single joint elevators when picking up or running out the tubing from the Vee door. Never Use Hook Ends
c) d) e) f)
Avoid rough handling of the tubing which may damage the joint. Never allow the tubing to be dropped when loading and or moving. Never bundle tubing in greater quantities than ten. 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 Company approved methods of cleaning should be used: -metallic brush and a recommended 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 a 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. 11.3.
RUNNING AND PULLING a) Any protective coating which 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.
J. Keemink @2009
Page 52
c)
d)
e) f) g)
h) i) j) k) l) m) n) o) p)
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 Test Supervisor thinks enough weight is available to properly set slips. 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. Check the alignment of the rotary table and the elevators. 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. Use power tongs and integral hydraulic back-up for all make-up and break-outs at recommended optimum torque valves. The use of a torque/turn analysis system, such as Weatherford’s ‘Jam’ system, is recomm ended. 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 90o. When pulling the tubing, always use a wiper rubber. Always install the pin protector fully before standing the tubing in the derrick. Never use a sledge hammer on connections to assist the break-out. Ensure tubing set back in the derrick is properly supported with a belly band to prevent undue bending. Always use the manufacturers recommendations for running, pulling or make-up. Check that the calibration of the torque machine is valid. 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. 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.
11.4.
PACKER 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 from a floater or a Jack-up rig. Example test string running procedures are given below for running strings with both types of packers from a semi-submersible drilling unit. For a Jack-up, the SSTT would be replaced by the sub-surface safety valve. The specific running procedures will always be detailed in the well specific test program.
11.5.
RUNNING THE TEST STRING WITH A RETRIEVABLE PACKER 1) Run a junk basket on wire-line to below the packer setting depth. 2) Before running the test string, hold a brief safety meeting on the drill floor and re-emphasize the precautions that should be taken during operations. 3) Ensure a Kelly Cock is situated on the drill floor for emergency use. 4) The down-hole gauges should be programmed and installed into the gauge carrier(s) in advance. 5) Make up and run the TCP gun assembly. 6) Install the packer assembly as per the string diagram. 7) Continue making up the string using a back-up tong to ensure that the packer is not turned to the right. 8) Pick up the test tools in reverse running order and make them up to the correct torque. Care should be taken that no connections are backed out and that the packer is not turned to the right.
J. Keemink @2009
Page 53
9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) 22) 23) 24) 25) 26) 27)
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 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 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 assembly and make up to 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 string and the space-out pup joints, strapping all hoses to the pipe. Install the surface test tree and 50ft bails or CTU lifting frame. Run a GR/CCL log to verify the packer 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. Set the packer and set down weight until the fluted hanger lands out in the wellhead. Run a GR/CCL log to verify the packer 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.
11.6. RUNNING A TEST STRING WITH A PERMANENT PACKER 1) Run a junk basket to below the packer setting depth 2) A safety meeting should first be held on the drill floor. 3) If the TCP guns are being run below the packer, make up the TCP gun assembly. 4) Install the packer and packer tailpipe assembly as per the program. The packer should be spaced out so that it is at least 5ft away from a casing collar. 5) Run the packer/TCP assembly on drill pipe with a radioactive marker sub, one stand above the setting tool. 6) Open the blind rams before the test tools reach them. 7) Rig up and run a GR/CCL and correlation gun setting depth. 8) Rig down the wire-line. Adjust the setting depth as required. 9) Set and pressure test the packer. Pull the work string. 10) Ensure a Kelly Cock is situated on the drill floor for emergency use. 11) The down-hole gauges should be programmed and installed into the gauge carrier(s) in advance. 12) If the TCP guns are to be run on the string, make up the gun assembly. 13) Install the space out tubing and then the seal assembly. 14) Continue and pick up the DST tools in reverse running order and make them up to the correct torque. Care should be taken that no connections are backed out. 15) Continue running the minor string as per the string diagram, until all the collars and slip joints have been made up. Record the string weight. 16) When the first tubing joint of the major string has been run pressure test the minor string. 17) Run the tubing.
J. Keemink @2009
Page 54
18) When the test string has been run half way into the well, the tubing should again be pressure tested (optional). 19) If there is a liner hanger above the packer setting depth, run the end of the string slowly through the liner hanger. 20) When approaching the permanent packer, pick up by one tubing joint to check the up weight and slack back down to check the down weight. 21) Run in slowly and tag the packer. Mark the pipe and calculate the spacing out. 22) It is recommended that the string be pressure tested. 23) Pull slowly out of the packer and pull back the pipe to install the SSTT. 24) Space out and pick up the SSTT assembly, install onto the tubing and function test. 25) Continue running the landing string, strapping the SSTT hoses to the tubing. 26) Install the lubricator valve. 27) Continue running the landing string, strapping all hoses to the pipe. 28) With the seal assembly still out of the packer, install the surface test tree attached to the final joint. Rig up the 50ft bails or CTU lifting frame. 29) Carry out the hook-up pressure test. 30) Slowly lower the seal assembly into the packer and land the SSTT hanger. 31) Conduct the final string pressure tests. 32) The well is now ready to be perforated and tested. 12.
WELL TEST PROCEDURES
12.1.
ANNULUS CONTROL AND PRESSURE MONITORING An important aspect of any well test is the continuous monitoring of the annulus pressure. This responsibility shall be delegated to the Driller who will maintain a log of pressures 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: Annulus pressure should always be controlled by the rig choke manifold. and any hydrocarbons vented to the poor-boy de-gasser.
The following aspects for annulus monitoring must be planned beforehand: At least two independent measurement points should be made available so that 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. top up times and volumes. 12.2.
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.
J. Keemink @2009
Page 55
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 down-hole and surface equipment (from bottom to surface): Tailpipe Packer Safety joint Jar Tester Two reverse circulation valves Slip joints head. a) 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 favorable weather conditions. b) Wind speed and direction shall constantly be monitored before formation clean out and during the flow to avoid smoke vapor, gas and heat invading the rig. To this purpose, Company and Contractor personnel shall continuously and directly monitor the flame behavior 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 jeopardized (heating of the structures, presence of smokes, gas on the rig). i) Wire-line operations inside a test string shall be limited as much as possible. j) Down-hole 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 Drilling Procedures Manual). 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 notif ied to Contractor's Toolpusher and Company's Drilling and Completion Supervisor. m) It is forbidden to release to the atmosphere non-combusted hydrocarbons. Only the use of production stock tanks shall be allowed. n) All stimulation jobs and subsequent formation clean out operations, shall be performed in daylight. o) During acid jobs, at least two water hoses shall be available to dilute any possible acid spills. p) 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. q) During acid job must be definite and marked all the pressure areas. 13.
WELL TEST DATA REQUIREMENTS
13.1. GENERAL The following is the procedure for gathering well test data: 1) Monitor all data points with the electronic surface data acquisition system as shown in table 13.a. J. Keemink @2009
Page 56
2) 3) 4) 5) 6) 7) 8)
9) 10)
11)
12) 13) 14)
15) 16) 17)
13.2.
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 samples every 30min and the mud logger is to perform laboratory analysis of water for chlorides and any other ions such as Ca, Mg, sulphates, TDS, pH and density. Record the specific gravity of the gas, oil and condensate every 30min. Take pressurized 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 Program. 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 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 in plastic or pressurized 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 the choke, initially every five minutes, during the clean-up. Monitor bottom-hole flowing and shut-in pressures and temperatures with surface readout system as appropriate.
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 utilized permitting more f requent data collection. However, if for any reason this system is not utilized, the recording intervals of table 13.a shall apply. Note: These intervals may be altered at the discretion of the well site Company Production Test Supervisor. Readings Timing 1 Well Pressure 1st Flow Every 1 min for 10 mins Every 2 mins for 20 mins
J. Keemink @2009
Page 57
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 st 2 Wellhead Temperature 1 Flow 1st Flow as above Further Flow Periods as above 3 SRO Pressure and Temperature (Print-outs) Further Flow Periods Every 15 secs for 10 mins 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 Separator Flow Rates Every 30 mins 5 Shrinkage Every 2 hours 6 Oil and Gas Gravities Every 1 hour 7 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 Further Flow Periods Every 2 hours by chemical analysis of separator gas 9 CO2 Determination As for H2S 10 Down-hole Memory Gauges Minimum 4 gauges, preferably 6-8 gauges, to berun. Minimum 2 different types of gauge to be run. Seek advice from Reservoir Engineers during test planning for special requirements. Table 13.A - Data Gathering Timings 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, but it is the responsibility of the Company Production Test Supervisor to ensure it is collected correctly, accurately and then distributed.
13.4.
PRE-TEST PREPARATION After the test program has been finalized, the following points should be discussed with the participating service companies: a) The type of down-hole 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 flow rates 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 computerized data acquisition unit is to be used.
J. Keemink @2009
Page 58
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. 13.5.
DATA REPORTING DURING THE TEST Data collected during the well test will be reported in the following formats, in addition to the daily drilling reports: a) Company Production Test Supervisor’s reports:
Test Supervisor on the rig and eventually returned to shore for placing in the well file. b) Composite data acquisition system report (if used) c) BHP gauge contractor’s reports (both hard copy and on compatible 5.25ins disk) d) Surface test facilities contractor’s report e) Sampling contractor’s report ( down-hole sampler) f) Stimulation contractor’s report (if used) 13.6.
COMMUNICATIONS ( Also refer to the Com pany ‘Drilling Procedures Manual’.) During the course of the test, it is important that information flows freely from the rig to the onshore base. The following telexes should be sent to the base to reduce the risk of misunderstanding and ensure a smooth operation. A daily telex should be prepared on the rig for transmission in the m orning covering the last 24hr period ending at 24.00hrs. This should be on the desk of base personnel when they arrive in the morning and will be used to keep partners informed. An afternoon telex should also be prepared covering the period to 15.00hrs. These telexes should include operations on an hour-by-hour basis with details of tools run in hole, flow rates, pressures etc. A telex should be sent at the end of each test briefly summarizing the daily operations and main results of the test. This is a ready source of data on the test which may be used for parent Company reports and reports to partners. Samples taken during the test should be sent to shore as soon as the test has been completed. A telex should be sent listing all the samples, the boat used for transportation when the boat leaves the rig and the ETA. If offshore, do not send all the samples taken during a single test on the same boat; split samples into complete sets and dispatch on different vessels. If any changes are to be made to the program during testing operations, a telex or fax will be sent from the rig to the base summarizing the procedure that is proposed to be followed for the next sequence of operations. This should be accordingly approved by shore base Production Superintendent who will ensure that all relevant personnel are informed of the change in the program.
14.
SAMPLING
14.1.
CONDITIONING THE WELL 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
J. Keemink @2009
Page 59
GOR Wellhead pressure Down-hole 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 down-hole sampling is not recommended. 14.2.
DOWN-HOLE SAMPLING After the well has been conditioned, it should be either shut-in or left to produce at a ver y low flow rate. At least two bottom-hole samplers in conjunction with a pressure and temperature gauge are installed in the well on wire-line. 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 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 are made with two samplers each run and that at least one sample is transferred at 100oF 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. Depending on conditions, sampling should continue until consistent quality checks are obtained on two separate samples. Note: All sampling should utilize mercury-free systems and piston type sample bottles for safety of personnel.
For long term storage of Company’s 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) 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. 2) Oil sample bottles need to be checked to ensure they are evacuated above the piston, and that the piston is at the top of the bottle. The fluid below the piston
J. Keemink @2009
Page 60
3)
4)
5)
6)
7)
8)
9)
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 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. All samples must be labeled immediately after being taken using Agip sample labels, if available. The following information must be recorded: Well number. DST number. Choke size. Perforation interval. Time of sampling and duration. Oil/condensate and gas rate at time of sampling. Stock tank oil/condensate, temperature, gravity and shrinkage, pressure. Gas temp, gravity, static and differential pressures, orifice size and meter run size. BS&W. All samples should be loaded 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: More specific sampling requirements may be detailed on individual well testing programs. 14.3.2. 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 greater than 1,500scf/stb, but less than 3,000scf/stb = 3:2 GOR greater than 3,000scf/stb = 2:1 J. Keemink @2009
Page 61
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 flow line. Not immediately after a bend in the flow line. Ideally the sampling point should protrude into the centre of the gas flow line and face upstream. However, a pipe into the stream is acceptable. Note: The sampling point should not be on the lower half of the flowline cross 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 flow line then it is preferable that it is on the top of the line and not on the side.
The oil sampling point should be: As close as possible to the exit of the oil flow line from the m ain vessel and upstream of meters. Not immediately downstream of thermal well or bends in the flow line. Ideally the sampling point should protrude into the centre of the flow line with the mouth facing upstream. However a pipe into the centre of the flow line is acceptable. It should be upstream of any increase in flow line diameter. It is preferable that samples are not taken from the bottom of the oil sight glass, as the level in the sight glass does sometimes falls, especially if there is much rig movement which can allow free gas to enter the sampling line. Note: The sampling point should not be on the upper half of the flow line cross section, due to any possibility of there being free gas. If the sampling point is on the wall of the flow line then it is preferable that it is on the side, rather than on the top or the bottom, due to possibility of free gas or water being in the flow line. 14.3.4. Surface Gas Sampling The following is the procedure for taking a gas sample: 1) Any flushing should be done through a hose directly downwind, or to sea level, to prevent any risk of poisoning due to gasses such as H2S. 2) Record the bottle number. 3) It is preferable, for the sake of safety, to take gas samples with the bottles lying horizontally unless it can be securely fastened upright or held in a stand. 4) The manifold should be flushed before use, then attached either to the top valve (V1), or to one of the end valves (V1, V2) if the bottle is lying on its side (Refer to figure 14.a). The manifold valve (V3) should then be opened slowly to test for any leaks. If there is a leak, then close the manifold valve, and remake the connections to the bottle. Note: No manifold or gauge should be attached to the second valve (V2) under any circumstances. This is to prevent the loss of any of the heavier components of the gas which might have condensed in the bottle when exposed to a vacuum. J. Keemink @2009
Page 62
5)
The bottle valve (V1) may now be slowly cracked open. 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 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 to oil samples is greater that 1:1, then the fill time should be worked out to still allow the oil samples to take about 30 minutes. 6) When the sample bottles are full and the sampling time has elapsed, shut the bottle valve (V1) and the valve on the separator sampling point (V3). 7) Record the pressure on the gauge, and bleed off about 30psi (using V4) then open 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. 8) Record the final sampling pressure and temperature, as they will be needed for the sampling sheets. The bottle and manifold valves (V1, V3) may now be closed, and the connecting line broken. 9) Plug the valves, and both valves checked in a bucket of water for any leaks. Now place the bottle safely aside. 10) Prepare for the next bottle for sampling. 14.4.
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) First record the bottle number. 2) The piston sample bottle should be stood in its custom built stand provided for the purpose. 3) The top manifold should be flushed to ensure that the line to the manifold and the manifold filled with fresh fluid from the flow line. 4) The manifold may now be connected to the top valve (V1) on the sample bottle. 5) Connect the lower manifold to the bottom of the sample bottle, open the bottom bottle valve (V2) and use the pump to pressurize the bottle below the piston to a pressure slightly in excess of the sampling pressure. This stops the piston 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. 6) The next step may be performed in one of two ways: Open the top manifold valve (V3), then connect a flushing line to the evacuation port (V6) on the sample bottle. Open the top bottle valve (V1 to allow oil into 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
J. Keemink @2009
Page 63
7) 8)
9) 10)
11)
12) 13)
14) 15) 14.5.
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 the safe shipping and storage of the bottle. This is done by removing a portion of the buffer fluid 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 (V2) should now be closed and the pressure in the bottom manifold valve bled off before removal. Fit a plug to the bottom valve (V2). Check the 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 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 Program, or issued with separate instructions. Figure 14.A - Surface Sampling Typical Installation
14.6.
SAFETY All equipment must be pressure tested and appropriately certified prior to dispatch. Obtain and comply with any permit to work system before commencing any work. 14.6.1. Bottom-hole Sampling Preparations Workscope Pressure testing and priming the tools with synthetic oil. Work Area Rope off the work area and post pressure testing signs. Inform all relevant personnel before commencing, and after completing, pressure testing. All non-essential personnel are to be kept clear. Safety Gear Safety glasses and gloves must be worn. Comments Tools will now contain high pressure dead synthetic oil and should be stored and moved in a safe manner. 14.6.2. Rigging Up Samplers to Wire-line Work scope: Attaching the samplers to the running tool string. Work Area: Rig floor and wellhead area. Safety Gear: Additional gear may be required depending on mud type. Comments Normal slick line/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. 14.6.3. Rigging Down Samplers from Wire-line Work Scope Removing the samplers from the running toolstring.
J. Keemink @2009
Page 64
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 slick line/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. No source of ignition is to be in vicinity. The sampling engineer will supervise the tool handling. 14.6.4. Bottom-hole Sample Transfer And Validations 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 commencing, and after completing, transfers or validations. All non-essential personnel are to be kept clear. Safety Gear Safety glasses and gloves must be worn.
Comments When high pressure oil/gas samples are transferred from tools 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 in present, normal H2S operating procedures are to be followed, i.e. breathing apparatus, buddy system etc. Personnel work duration will not generally exceed 18hrs. 14.6.5. Separator/Wellhead 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 commencing, and after completing, sampling. All non essential personnel are to be kept clear. 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. Personnel work duration will not generally exceed 18hrs. 14.6.6. Sample Storage Work Scope Storage and shipping of high pressure oil or gas samples. Storage Area Must always be away from heat sources and sources of ignition. Must be well ventilated.
Comments Samples must be in two phases for storage and shipment, i.e. samples will have a gas cap. Samples must be labeled as being flammable high pressure oil or gas samples. 15.
WIRE-LINE OPERATIONS Although sometimes operationally necessary, wire-line operations, both slick line or electric wireline, carry an inherent risk which is even greater on an offshore exploration well test due to the
J. Keemink @2009
Page 65
configuration of the test string and the well conditions. If possible, running wire-line 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. Slick line tools are run for: -hole sampling which can be taken above or below the test tools. Down-hole pressure gauges, set in nipples or hung off. down-hole shut off tools which are set in nipples. circulating valve etc. line or electric wire-line tool strings. Electric wire-line tools are run for: tools. Down-hole pressure gauges which may be run with PLT tools. -perforating with Through-Tubing guns. ee a test string from a stuck packer, etc. Both types of wire-line require the use of long bails, or a C/T (coiled tubing) lifting frame, to cater for the rigging up of the wire-line BOPs and the lubricator on top of the flow head. Pressure testing is to be carried out against the lubricator valve. The main difference between a slick line and electric line rig up is that double BOPs and a grease flow tube must be used to achieve a seal on a braided cable. 16.
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 down-hole tubing and/or surface lines. Hydrates can form under both 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 key to prevention is understanding the conditions under which they will form. 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 favorable regime for their formation. Under conditions of no flow they can form as a kind of snow on the walls of tubing. A down-hole hydrate plug is potentially dangerous and should be avoided at all costs. The area of most risks is in the string from the seabed upwards where the lowest temperature usually occur. 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:
head
J. Keemink @2009
Page 66
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. 17.
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 pressureoperated 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 under-balance or bringing on a well which 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 tubing annulus differential by holding the annulus pressure and bleeding away the nitrogen cushion pressure. Alternatively, with the well open, the nitrogen could be bled off very slowly to minimize the drawdown, for instance, on a poorly consolidated sand. The disadvantage with this is that it is uncertain what is occurring down-hole as 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 the 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.
18.
OFFSHORE COILED TUBING OPERATIONS Equipment for a coil tubing operation offshore for use on a well test is the same as on a platform except that a lifting frame is installed to simplify the rig up. This must be rigged up on the flow head from the beginning as part of the landing string as this cannot be accomplished afterwards. The built-in lifting hoist must be a chain pulley type, which stops immediately the drive control is released. It can also be used for the wire-line rig-up making it easier and safer. Coiled tubing on a well test is normally used for:
Wire-line) 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. When coiled tubing is to be run on a well test, it is essential that the sub-sea test tree is dressed to be capable of cutting, whatever the size of the tubing.
19.
WELL KILLING ABANDONMENT There are a number of methods for conducting a well kill operation in a well test situation, dependent upon the well hardware and configuration, taking into account of any well problems which have arisen. However, the two main methods under normal circumstances are; ‘Reverse Circulation’ and ‘Bull-heading’. Note: Bull-heading from surface should never be carried out as a routine kill method without prior permission from Company management. Procedures for any such method of well kill would be issued in the test program.
J. Keemink @2009
Page 67
Killing by reverse circulation is the preferred method of killing a well as it reduces the quantity of foreign materials coming into contact with and prevents over pressuring the formation. Bull-heading is sometimes preferred in cases where the circulation method may not be efficient due to gas entrainment etc. Other methods of well kill are used in circumstances where there has been a circulating valve failure or a blockage in the tubing. These are; ‘Bleed off and Bullhead’, ‘Reverse Circulate and Bullhead’ and ‘Lubricate’. These are so specialized in nature that it is not practical for them to be used without first thoroughly examining the well situation and then producing a detailed well specific program and are, therefore, not addressed in this manual. On tests with Semi-Submersibles there is a well kill procedure for making the well safe for a disconnection due to bad weather etc. 19.1.
ROUTINE CIRCULATION WELL KILL The normal procedure for killing a well is the forward circulation method which displaces the formation fluids from the test string with kill weight fluid. This method can also be used in the event of premature termination of an offshore test due to weather or any other reason when there is sufficient warning and time allows. This procedure requires DST tool operation to open the circulating device and control of the circulating pressure using the well test choke manifold. 19.1.1. Circulation Well Kill Procedure The following procedure is the normal method of well kill following the termination of a test program (Refer to figure 19.a). 1) After the final build up, or flow period, close the tester valve and pull any surface read out tools out of the hole if being used. 2) Open the multi-function circulating valve and reverse out string contents, collecting samples if required. Circulate to condition and balance tubing and annulus. Close the circulating valve. 3) Pressure up on the annulus to open the tester valve. Pressure up on kill wing valve with brine to slightly less than shut in well head pressure then open the kill wing valve. The production wing valve should be closed. 4) Pressure up on the test string with brine, checking the pump volume. 5) Calculate the maximum the bottom-hole pressure to be applied, which must be kept below the formation frac pressure. 6) If the formation takes the pumped fluid, continue bull-heading down the test string and liner below the packer to the bottom perforations. Check the volume of pumped brine. 7) A variation in the pumping pressure should be detected when brine reaches the formation. Record the leak-off rate. 8) Carry out a 30min flow check. If static, proceed to step 14. 9) If the well takes brine at more than 5bbl/hr, the displacement of a temporary plugging pill to bottom may have to be considered. 10) If the formation doesn’t take the pumped fl uid or the injection rate is less than 0.1bpm over a 3hrs period, close the kill side wing valve and tester valve. 11) With the multi-function circulating valve in the test position, open the single shot reversing valve and reverse circulate until the tubing and annulus are in balance. 12) For tests using permanent packers, pull out seal assembly and reverse circulate at least twice bottoms up, or until minimum gas returns. For conventional DST, unseat the packer and bullhead the hole contents below the packer into the formation. Reverse circulate again, if necessary, until tubing and annulus are in balance.
J. Keemink @2009
Page 68
13) Flow check the well. 14) Once the well is stable, pull string out of hole while carefully monitoring the hole volume, especially while DST tools are in 7ins liner as the swabbing effect is to be avoided. 15) If the brine lost into formation is more than 5bbl/hr, the displacement of a temporary plugging pill to bottom must be considered. This may be composed of CaCO3, HEC or MICA etc. and the material must be available on the rig to make up the appropriate weighted pill. 19.2.
BULLHEAD WELL KILL Bull-heading is only allowed by permission of Company management. If a well has good permeability, the simplest method of well kill is to bullhead from surface. Bull-heading is most effective when:
Mixing between the hydrocarbons and the kill fluid will be limited, e.g. with a small diameter tubing and in a vertical well. The drawback of bull-heading is when the formation may be fractured, as with low permeability reservoirs. This can lead to a protracted well kill with hydrocarbons leaking back from the fracture into the well bore and migrating upwards in the well. As a very rough way of estimating if bull-heading will fracture the formation is as follows: a) Estimate the productivity index (PI) of the well form surface pressure and flow rate data. b) Use the estimated of PI to calculate the injection pressure at a rate of 1bbl/min (1,440bbl/d). c) Compare the estimated injection pressure with the prognosed formation fracture pressure. 19.2.1. Bullhead Kill procedure The Bullhead kill procedure is: 1) Calculated the volume to the perforations. 2) Line up the cement pump with sufficient quantity of kill fluid. 3) Pressure up with the pump to equalize across the wing valve and open the valve. 4) At as fast a rate as possible, keeping below frac pressure, pump kill fluid. 5) Monitor when the fluid first reaches the formation by observing a pump pressure rise. Once kill fluid reaches over the whole perforated interval it will be more difficult to squeeze away fluids and the pressure will increase. 6) Continue to pump until the hole volume calculated is pumped plus a few barrels excess to push away the kill fluid/well fluid interface. 7) Establish the circulation path, then unseat the packer (when a lock open tester valve is run, unseating the packer will establish the circulation path). 8) Circulate bottoms up. If the well is taking losses, an LCM pill should be circulated in and bullheaded against the formation. 9) Only when the well is safe may the string be pulled. 19.3.
TEMPORARY WELL KILL FOR DISCONNECTION ON SEMI SUBMERSIBLES This operation does not involve pulling the string out of hole and killing the well is limited only to filling up the string down to the tester valve, time allowing: Close the tester and kill the well by reverse circulation through the multi-function circulating valve and continue with operations to disconnect. If in an emergency situation, when there is insufficient time to kill the well, disconnection will be implemented without the well kill. In this eventuality, there will still be the requisite number of barriers on the well for safety, although reconnection to a live well has it’s own particular risks. This operation would be detailed in a separate program.
J. Keemink @2009
Page 69
Figure 19.A - Reverse Circulate Decision Tree 19.4.
PLUG AND ABANDONMENT/SUSPENSION PROCEDURES Whenever feasible, a decision should be made on the disposition of the well as early as possible, before any plugging operations are begun, whether or not the well is to be suspended for future production purposes. Well plugging procedures and equipment will differ depending upon the need for future well intervention. In particular, the choice of bridge plugs used for abandonment of test intervals will be affected, especially if perforating guns have been dropped into the sump below the plugs.
If the well is to be suspended, the course of action should be to install plugs which meet regulations but can protect the formation from any further damage during re-entry. For instance retrievable bridge plugs or packers can be used with a course of sand or saturated salt between the plug and the cement plug. This allows the cement to be drilled up with both the cuttings and sand being circulated out and the well displaced to clean brine before the plug is pulled. Often the ideal method of suspension is to use a permanent packer for the test which is also used as the completion packer. This allows the packer to be plugged by wire-line, with oil or gas below, at the end of the test preventing any contamination of the formation. Detailed plug and abandonment procedures will be issued by the Drilling and Completion Department who are responsible for this part of the operation. Note: If it is necessary, submit details of the methods and arrangements to be used to the proper authorities to obtain their written approval prior to commencement of work. 19.5.
PLUG AND ABANDONMENT GENERAL PROCEDURES 1) Rig up wire-line and run in the hole with gauge ring and junk basket to 10ft above the top perforation/permanent packer. Pull out of the hole. 2) Run in the hole and set a bridge plug 10ft above top perforation/ permanent packer. Test the bridge plug to 500psi above leak off pressure. 3) Run in the hole and set a second bridge plug immediately above the first. Test this bridge plug to 500psi above the leak off pressure. Note: Use of two bridge plugs instead of bridge plug and cement is to avoid contamination of the completion brine.
Separate detailed procedures will be issued as part of the well specific drilling program. Pre-drilled development wells will also be covered by well specific drilling programs. 20.
HANDLING OF HEAVYWATER BRINE Both CaBr2/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 shriveled by the brine)
J. Keemink @2009
Page 70
d) Full face masks for use when mixing powdered CaBr2/CaCl2. e) Barrier cream (e.g. ‘Vaseline’) for use on exposed skin, particularly face, neck and wrists, to prevent direct skin contact with the brine. Additionally, whenever powder/brine is inadvertently splashed onto clothing, then the aff ected 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. Appendix A - Report Forms A.1. Daily Report (ARPO 02) WELL NAME FIELD NAME District/Affiliate Company DATE: ARPO 02 Cost center Rig Name RT Elevation [m] Well Code Type of Rig Ground Lelel / Water Depth [m] Report N° of Contractor RT - 1st flange / Top Housing [m] Permit / Concession N° Well Last casing Next Casing BOP Type Ø w.p. [psi] M.D. (24:00) [m] Ø nom.[in] Stack T.V.D. (24:00) [m] Top [m] Diverter Total Drilled [m] Bottom [m] Annular Rotating Hrs [hh:mm] Top of Cmt [m] Annular R.O.P. [m / h] Last Survey [°] at m Upper Rams Progressive Rot. hrs [hh:mm] LOT - IFT [kg/l] at m Middle Rams Back reaming Hrs [hh:mm] Reduce Pump Strockes Pressure Middle Rams Personnel Injured Pump N° 1 2 3 Middle Rams Liner [in] Lower Rams Rig Rig Strokes Last Test Others Other Press. [psi] Total Total Lithology Shows From (hr) To (hr) Op. Code OPERATION DESCRIPTION Operation at 07:00 Mud type Bit N° Run N° N° Run N° Bottom Hole Assembly N° __________ Rot. hours Density [kg/l] Data Description Ø Part. L Progr.L Partial Progr. Viscosity [s/l] Manuf. P.V. [cP] Type Y.P. [g/100cm2] Serial No. Gel 10"/10' / IADC Water Loss [cc/30"] Diam. HP/HT [cc/30"] Nozzle/TFA Press. [kg/cm2] From [m] Temp. [°C] To [m] Cl- [g/l] Drilled [m] Salt [g/l] Rot. Hrs. pH/ES R.P.M. MBT [kg/m3] W.O.B.[t] Solid [%] Flow Rate Stock Quantity UM Supply vessel Oil/water Ratio. Pressure Sand [%] Ann. vel. pm/pom Jet vel. J. Keemink @2009
Page 71
pf HHP Bit mf HSI Total Cost Supervisor: Daily Losses [m3] I O D L I O D L Daily Progr. Losses [m3] B G O R B G O R Progr. DAILY REPORT Drilling A.2. Waste Report (ARPO 6) WELL NAME FIELD NAME District/Affiliate Company DATE: ARPO-06 Cost center FRreopmor [tm N]° IDneteprtvha (lm D)rilled (m) DMeunds Tityyp (ekg/l) To [m] Drilled Volume [m3] Cl- concentration (g/l ) Phase size [in] Cumulative volume [m3] Water consumption Phase /Period [m3] Cumulative [m3] Usage Fresh water Recycled Total Fresh water Recycled Total Mixing Mud Others Total Readings / Truck Fresh water [m3] Recycled [m3] Mud Volume [m3] Phase Cumulative Service Company Contract N° Mixed Mud Company Lost Waste Disposal Dumped Transportation Transported IN Transported OUT Waste Disposal Period Cumulative Remarks Water base cuttings [t] Oil base cuttings [t] Dried Water base cuttings [t] Dried oil base cuttings [t] Water base mud [t] Oil base mud transported IN [t] Oil base mud transported OUT [t] Drill potable water [t] Dehidrated water base mud [t] Dehidrated oil base mud [t] Sewage water [t] Transported Brine [t] Remarks Supervisor Superintendent WASTE DISPOSAL Management Report A.3. Well Problem Report (ARPO 13) FIELD NAME WELL NAME District/Affiliate Company J. Keemink @2009
Page 72
DATE: ARPO -13 Cost center Problem Top [m] Start date Code Bottom [m] End date Well Ø Measured Depth Vertical Depth KOP [m] Mud in hole Situation Top [m] Bottom [m] Top [m] Bottom [m] Max inclination [°] Type Open hole @ m Dens.[kg/l]: Last casing DROP OFF [m] Well problem Description Solutions Applied: Results Obtained: Solutions Applied: Results Obtained: Solutions Applied: Results Obtained: Solutions Applied: Results Obtained: Supervisor Supervisor Supervisor Remarks at District level: Superintendent Lost Time hh:mm Loss value [in currency] Remarks at HQ level Pag. Of WELL PROBLEM REPORT A.4. Malfunction & Failure Report(FB-1) MALFUNCTION & FAILURE REPORT (FEED BACK REPORT 01) Report Date: Well Name: Well Code: General Information Contract No: Contract Type: Contractor: Service/Supply: Drilling Completion Workover Duration Dates of Failure: Distributed By: RIG SITE Description of Failure: Drilling & Completions Company Man: Adopted or Suggested Solution(s): Contractor Contingency Measures: Contractor Representative: DISTRICT OR SUBSIDIARY NOTES: Failure Classification Status Operations Manager: Technical Normal Management/Organisation Extreme Time Lost: Safety/Quality Innovative Adverse Estimated Cost of Failure: MILAN HEAD OFFICE NOTES: Analysis Code: District/Subsidiary A.5. Contractor Evaluation (FB-2) CONTRACTOR EVALUATION (FEED BACK REPORT 02) Report Date: Well Name: Well Code: J. Keemink @2009
Page 73
General 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 Program Requirements 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 Operations Capability and Promptness to Operational Requests 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 Certificates Meeting with Contract Quality Assurance Terms Event Support Documentation Type of Document: Subject: Issued By: Date: Notes: Failure Status Operations Manager Drilling & Completions Manager Normal Extreme Adverse Innovative District/Subsidiary Appendix B - ABBREVIATIONS AC/DC Alternate Current, Direct Current American Petroleum Institute API Background gas BG Bottom Hole Assembly BHA Bottom Hole Pressure BHP Bottom Hole temperature BHT Blue Methylene Test BMT Blow Out Preventer BOP Barrel Per Day BPD Barrels Per Minute BPM Back Pressure Valve BPV Base Sediment and Water BSW Build Up Rate BUR Control Line C/L J. Keemink @2009
Page 74
Cement Bond Log CBL Casing Collar Locator CCL Common Depth Point CDP Cement Evaluation Tool CET Condensate Gas Ratio CGR Cement Retainer CR Corrosion Resistant Alloy CRA Coiled Tubing C/T Drill Collar DC Diatomaceous Earth DE Down Hole Motor DHM Down Hole Safety Valve DHSV D&CM Drilling & Completion Manager Drill Pipe DP Drill Pipe Hang off Tool DPHOT Drill Stem Test DST Electric Line E/L Equivalent Circulation Density ECD External Casing Packer ECP Electronic Multi Shot EMS Equivalent Mud Weight EMW External Pressure EP Electric Shut-Down System ESD Electrical Submersible Pump ESP Expected Arrival Time ETA Flowing Bottom Hole Pressure FBHP Flowing Bottom Hole Temperature FBHT Free Point Indicator / Back Off FPI/BO Flowing Tubing Head Pressure FTHP Flowing Tubing Head Temperature FTHT Gas Liquid Ratio GLR Gas Oil Contact GOC Gas Oil Ratio GOR Gravel Pack GP Gallon (US) per Minute GPM Global Positioning System GPS Gamma Ray GR Hazard and Operability HAZOP Hydraulic Horsepower HHP Hole Opener HO HP/HT High Pressure - High Temperature Heavy Weight Drill Pipe HW/HWDP International Association of Drilling Contractors IADC Inside Blow Out Preventer IBOP Inside Diameter ID Inflow Performance Relationship IPR Joint Make-up Torque Analyser JAM Lay Down L/D Lowest Astronomical Tide LAT Lethal Concentration 50% LC 50 Last Crystal to Dissolve oC LCDT Lost Circulation Materials LCM J. Keemink @2009
Page 75
Lower Explosive Limit LEL Landing Nipple LN Leak Off Test LOT Log Quality Control LQC Lost Time Accident LTA Martin Decker M/D Make Up M/U Max Allowable Annular Surface Pressure MAASP Measured Depth MD Mudline Hanger MLH Mudline Suspension MLS Magnetic Multi Shot MMS MODU Mobile Offshore Drilling Unit Magnetic Particle Inspection MPI Modular Single Completion Land MSCL Mean Sea Level MSL Make up Torque MUT Mud Weight MW Measurement While Drilling MWD National Association of Corrosion Engineers NACE Non Destructive Test NDT North Seeking Gyro NSG Nephelometric Turbidity Unit NTU Oil Base Mud OBM Outside Diameter OD Open Hole OH Offshore Installation Manager OIM Original Mud weight OMW Oil Water Contact OWC Plugged & Abandoned P&A Pick up P/U Polished Bore Receptacle PBR Positive Displacement Motor PDM Productivity Index PI Production Logging Tool PLT Personnel On Board POB POOH Pull Out Of Hole Pounds per Barrel PPB Pounds per Gallon PPG Part Per Million ppm Pressure Volume Temperature PVT Flow Rate Q Quality Assurance, Quality Control Q/A Q/C Rig down R/D Rig up R/U Retrievable Bridge Plug RBP Reverse Circulating Position RCP Repeat Formation Test RFT Run In Hole RIH Rotary Kelly Bushing RKB Remote Operated Vehicle ROV Revolutions Per Minute RPM J. Keemink @2009
Page 76
