Chapter 7. Well-Site Operations
Chapter Contents
- Well-site Planning Tools 213
- Crew Integration 216
- Problem Solving 216
- Pressure Testing 217
- Well Test Program 219
- Establishing an Underbalance 234
- Demobilization 243
- Service Tickets 243
- Well-Site Reports 243
At the well site, the role of the well test engineer takes on a prominent profile. The well test engineer coordinates the activities of well test service contractors and liaises with resource company and MODU management to put into effect the plans and processes prepared for the well test. The focus of this role changes as the operation progresses. Initially, that focus is on logistics, and in this role the well test engineer works with the logistics coordinator at the well site to plan contractor equipment and personnel movements to the MODU. This process continues until the equipment is located in its allocated area on deck. The focus then changes to that of inspection and quality control, as the well test engineer witnesses contractor preparations. These preparations include pressure tests, tool settings, equipment assembly, and subassembly measurements. The role then becomes one of supervisor: the well test engineer directs the critical path activities of the well test, delegates tasks to various contractor specialists, and oversees the installation of the test string and the commissioning steps in preparation for well testing. The well test engineer then supervises a pretest safety meeting and the subsequent production operations, monitoring production data gathering, sampling operations, and data reporting. Finally, the focus of the role switches back to logistics as equipment and personnel are demobilized to their contract agreed points of origin. In parallel with these areas of focus, the well test engineer has a continuous role working with rig management to ensure the implementation of safety management processes and to work with the drilling supervisor in a support function in the day-to-day management of the facility. The purpose of this chapter is to describe the processes associated with these roles; the order of presentation follows that which would occur at a well site.
Well-Site Planning Tools
The early stages of well-site operations focus largely on logistics — the movement of equipment, personnel, and materials to and from support facilities to the well site. The lookahead and the logistics plan are tools available to well-site personnel in support of this phase of the operation.
Lookahead
A lookahead is a schedule that estimates the timing for critical path operations. It is a useful reference tool, particularly for planning logistics since it helps to anticipate when certain equipment and services will be required.
A lookahead is usually prepared on a spreadsheet by the well test engineer. A brief description for each high-level operational step is listed in a column; for example, a typical well test operational step could include Make up Bottom Hole Assembly. This operation entails the installation of several pieces of equipment following program and contractor-specific procedures. A lookahead does not need to identify each tool or the procedures, only the overall operation or task. In a separate column, the anticipated duration of that step is usually inserted in units of hours. Next, in a separate column, a space is provided for actual time. For example in the step Make up Bottom Hole Assembly, the well test engineer might estimate this step to take four hours. If in reality it takes six hours, the well test engineer enters this time into the actual time column. Finally, the date and time are displayed, calculated from the duration of each step. The date and time calculates based on estimated time until a value has been entered into actual time, which it then uses to revise the entire schedule. For a sample lookahead, see Figure 7.1.
Figure 7.1. Sample lookahead
Logistics Planning
At an offshore facility, because materials and equipment arrive in large shipments on supply vessels, the order in which they are loaded and transferred to the facility is important so as to minimize double handling. This process of organization commences during planning with the development of a logistics plan. This plan is of significant value at the well site because the order in which different tasks occur on the critical path does not necessarily reflect the order in which equipment should arrive at the well site. Some equipment requires only a number of hours to prepare; whilst other equipment may require days, some equipment requires very little deck space and other equipment a great deal. A well test logistics plan details a loadout order from the supply base so that the logistics coordinator knows what equipment to load onto vessels and in what order. A detailed list of each item of equipment from every service is placed on a spreadsheet, and a loadout priority is assigned to each. This level of detail is necessary because many items of equipment within each service might only be required for contingency or backup purposes, while others will not be needed until late in the operation. Deck space is limited both on supply vessels and on the MODU. Mobilizing low priority equipment early may cause logistics headaches, use up valuable deck space, and require double handling at the well site. The consolidated loadout list (Figure 7.2) also provides other important information, including individual container identification numbers, a brief description of contents, weights and dimensions.
Figure 7.2. Sample loadout list
The logistics plan also provides a personnel schedule to identify what contractors are required at the well site and in what order. Personnel associated with each service must arrive at the well site just prior to their equipment because contractor personnel are responsible for supervising the unloading and positioning of their equipment on deck. However, since it can take some time to position all of the equipment, it is only necessary and cost effective to have one or two contractor representatives at this stage, the remainder of the crew arriving after the equipment has been located in position. This aspect of the mobilization must be flexible, particularly on offshore facilities that can only accommodate a limited number of personnel. The well test engineer must work with the drilling supervisor, the offshore installation manager OIM, and the well-site logistics coordinator to prioritize personnel movements, striking a balance between the need to have equipment prepared for the test and the need to ensure that ongoing operations are adequately supported. A convenient method for capturing this process in the plan is to list the personnel required according to some operational flag. For instance, let us assume that it would take four days to prepare a well test equipment package. The logistics plan will flag that personnel must arrive at the well site at least four days prior to the well test. The logistics coordinator can view the lookahead and identify when the well test operation is due to commence and work back four days to plan for personnel to arrive at the well site.
A deck plan showing the location of each item of equipment is included in the logistics plan for reference. This helps facility management to plan ahead to clear the required deck space in advance of the arrival of the supply vessel(s). Failure to do so might result in extended delays while equipment is double handled from one part of the facility to the next.
Other than equipment and personnel, the logistics plan also provides detail for transporting bulk materials, brine, and chemicals, along with special materials such as explosives and dangerous goods. Brine and other chemicals may need to travel in vessels with specially cleaned tanks to avoid contamination with other fluids. Scheduling tank cleaning operations requires coordination with the drilling supervisor because this operation takes time and requires the support vessel to be off site for tank cleaning, which can take more than a day.
The plan, distributed to contractors before the well test operation, provides information of value to contractors, including
- Contacts list identifying contractor focal points
- Important delivery addresses and freight labeling instructions
- Lifting certification requirements
- Equipment manifest requirements
- Personnel check in instructions including baggage labeling and weight restrictions
- Personnel safety training requirements, including helicopter safety training
Crew Integration
Contractor crew integration is an issue at the outset of most well test operations. Well test crews are often as unfamiliar with one another as they are with the facility, and it can take some time for personnel to fit in with the routine, particularly if contractor personnel have traveled a great distance and come from differing cultural backgrounds. It is not unusual for it to take several days before the well test crew starts to work well as an integrated team. This factor should be considered when allocating the time available to contractors to prepare their equipment. The well test engineer can play a role in helping crews to settle in, using inductions, holding informal briefings, and getting involved with the issues that the crews have to face in order to get set up. This role might also include holding briefings to the MODU crew as to the tasks the well test crews need to perform to prepare for the job at hand and acting as a liaison between parties to get specific tasks completed. This role is particularly valuable in areas where many different contractors have to work together, for example, organizing cranes, facility electricians, and the cementing service to help prepare the well test equipment.
Problem Solving
Every well test operation involves the expenditure of a considerable amount of money and resources whether land based or offshore. When the operation is offshore, the significant cost of the facility amplifies the overall cost of the test. When things don't go according to plan, personnel on site and the support team may place themselves and each other under pressure to act with a degree of urgency. In such circumstances, it is tempting to take short cuts to recover the situation. However, sometimes the most positive thing to do is to pause, at least until a situation has been properly assessed and the planning team has had time to develop a considered solution. Unmanaged, changes to programs and procedures constitute risk in their own right. The safety and technical hazards that may result from any significant change in procedure should be assessed utilizing the resources available, including management of change controls. On site, the well test engineer has access to experienced rig managers, contractor engineers, technicians, and the support teams in town. Regular communication, meetings, telephone conferences, and adherence to best practices generally yield the most successful outcomes. It is particularly important that senior management take a lead in maintaining the focus on safety at such times.
Pressure Testing
Uncontrolled release of pressure carries high-risk HSE consequences. Its prevention is one of the objectives of the well test design, and pressure testing is one of the most important controls applied to equipment to provide assurance that it will safely contain pressure. Most pressure tests are performed using an incompressible liquid such as water, although there are occasions when other fluids might be used. Contractors carry out pressure tests on their equipment prior to mobilization as part of their standard maintenance procedures. The assembled equipment at the well site also requires pressure testing. However, these pressure tests are more complex. A detailed procedure is required to ensure that the tests are performed in the right order and that valves are configured correctly for each test. Pressure testing itself is hazardous since it entails the application of pressure to equipment that is untested. Thus, additional controls are required to minimize the risks associated with this activity. Certain criteria are essential for every pressure test and must be defined in a pressure test standard or guideline:
- The magnitude of the test pressure
- The duration for which the test pressure must hold
- Acceptance criteria, or degree of variation of pressure acceptable
- The test fluid
- The method of application
Manufacturers provide recommended test procedures specific to their equipment, which generally do not address pressure testing of that equipment when connected in a system to other equipment. Contractors provide pressure test procedures for well-site operations, specific to the equipment provided by a particular service. Resource companies produce pressure test guidelines to ensure that appropriate controls are applied to every pressure test operation and that the pressure tests are performed to an adequate standard. Resource companies also write many of the pressure test procedures for the well test; these procedures are included in the Well Test Program.
Developing a Pressure Test Guideline
The objective of a pressure test is to verify that a piece of equipment or a number of connected pieces of equipment will safely contain expected operational pressures.
A number of factors can make it difficult to establish a good pressure test: the presence of trapped air within equipment components, the compressibility of the medium used to perform the test, heating or cooling of equipment during the test, the volume of fluid, and the accuracy and range of the pressure recording device.
A pressure test guideline will generally include
- Details of the controls required to minimize the risks associated with pressure testing
- Steps to eliminate, or at least minimize, factors that hinder a good test
- Procedural steps indicating the method for applying pressure and the maximum value
- Acceptance criteria
Well-Site Pressure Test Guideline
The following steps list a typical set of controls for addressing the hazards associated with pressure testing and controlling some of the factors that can complicate or impede a good test.
- Pressure test operations must be preceded with a safety meeting by those conducting the tests.
- The safety meeting must address communications, permits, barriers and details of the procedure
- Pressure test operations require a permit to work and must satisfy any of the controls identified in the permit.
- The procedure must include steps to remove all air and other contaminating fluids from the system prior to a test.
- With certain exceptions all pressure tests shall be performed using an incompressible nonflammable medium (i.e., water). There may be occasions when water might not be suited. For example, a water–glycol mix is permitted to pressure-test equipment where the test fluid might later come in contact with gas and trigger the onset of hydrates.
- The general test pressure, which applies to high-pressure equipment only, shall be 20 percent above the maximum expected shut in tubing head pressure SITHP.
- A calibrated pressure-recording device shall be used for all pressure tests, and a current calibration certificate must be submitted to the well test engineer along with the record of the pressure test.
- Pressure must be applied in at least two stages: low pressure initially followed by high pressure. Typically, a 5-minute duration low-pressure test at about 10 percent the value of the maximum test pressure will suffice.
- Maximum test pressure shall be applied to a predetermined value, which will not exceed the safe working pressure of any of the components to be tested.
- Where stated in the procedure, all pressure tests must be witnessed by the well test engineer.
Pressure Test Acceptance Criteria
Pressure test acceptance criteria generally have two components: hold duration and an acceptable pressure drop profile. The hold duration should be adequate to allow sufficient time to detect a leak or to provide evidence that there is none, but it should not be of excessive duration such that unnecessary time is consumed conducting multiple pressure tests. For small volumes, of the order of liters, a 5-minute test may be considered sufficient. A leak in such a volume should become apparent almost immediately, provided the fluid used is incompressible. Above this volume, 10 minutes is adequate for most pressure tests, although many operators specify 15 minutes. Anything above this is rarely practical.
With regard to pressure drop profiles, a straight-line graph with no pressure drop whatsoever is sometimes difficult to achieve, particularly in a large system. This does not mean that it is not possible to detect a leak. A straight line may be impractical due to trapped air that cannot be removed from some systems or due to thermal expansion and contraction. At high pressures, clouds passing in front of the sun can change the way a pressure test is recorded because it may only take a small change in temperature to produce a noticeable change in pressure. In practice, most standards accept some drop from the initial value but require that the pressure profile show a stabilizing trend. A leak from a system small or large would show a continuous dropping trend. In this manner, a reduction in pressure due to a leak can be distinguished from a reduction in pressure due to other causes based on the pressure test chart profile.
From this discussion, the acceptance criteria specified in a pressure test standard might take the following form.
Pressure tests shall be of 10 minutes duration and shall be considered acceptable provided that the overall pressure drop does not exceed 1 percent of the initial applied test pressure over the 10-minute duration and the drop profile recorded on the recording device shows a decreasing trend.
Exceptions to a company-generated standard will exist for contractor equipment that may require very specific pressure test procedures. The elements of a pressure test standard, listed above, might include a provision that contractor procedures will apply in these cases.
Well Test Program
A Well Test Program is a document prepared by the well test engineer comprising a set of procedures and references that govern the conduct of a well test. The program is available at the well site to all contractors and resource company personnel involved with the well test. The procedures provided in the program cover critical path tasks such as installation of the test string, production of well fluids, and well kill. The program also provides procedures for the preparation of test equipment on deck offline. The program document is normally sectioned, each section addressing a specific task.
The program contains reference information in support of the procedures. Reference information can include equipment specifications, drawings, and well data, and can also include contractor procedures that form activities within a particular task. For example, the program will detail a procedure to install the test string, but within that procedure the program may refer to a particular contractor procedure to set the packer.
Elements typical in a well test program include
- Overview
- Well and reservoir data
- Well test objectives
- Well status assumptions
- Roles and responsibilities
- Preparations
- Preassemblies
- Test string installation
- Commissioning
- Establishing an underbalance
- Perforation
- Cleanup and flow periods
- Well kill and test string retrieval
- Contingency procedures
- References (drawings, tubing data, offline procedures)
The structure within each procedure is similar
- List of references, which include contractor procedures, diagrams, and running tallies. References may be located in the appendices to the program or in external documents. Generally, the most important or most frequently referenced are included in the appendices, unless they constitute substantial documents in their own right.
- Responsibilities, which identify the key personnel responsible for directing each procedure. For example, the TCP specialist is identified as the person responsible for directing the assembly of the guns and firing heads on the drill floor.
- Checklists, which provide a useful tool to ensure that the preparations required for any specific procedure have been completed. For example, when preparing to run the test string, a checklist might be included to remind personnel to have well control crossovers and special handling equipment to hand prior to commencing the operation.
- Toolbox meetings, which are held at every point in the operation when a new task commences, or when some activity within a task has new and specific hazards associated with it. The procedure must identify the need to stop and conduct a meeting as a procedural step.
- Procedure steps, which are set out in the order that they should occur. Reference information is often included along with each step — for example, the running order of the test tools, together with a reminder as to the tool settings and running speeds. A certain degree of judgment is required when supplying supporting information to a procedural step. On the one hand, it is not desirable to clutter the procedure with too much information, thereby making it difficult to follow. On the other hand, owing to its high visibility, some important reference information can usefully be given a high profile within the procedure in this manner.
A sample well test program is provided in the appendices.
Overview
The overview is a brief outline of the Well Test Program. It can be of value to those who have not previously been involved with planning but have become involved with the well test for the operational phase and wish to learn what they can of the operation before it commences. The overview is also of value for recordkeeping purposes for those who may wish to plan similar operations and need to reference previous programs to gain experience from previous operations.
Well and Reservoir Data
The drilling department and the subsurface team provides well and reservoir data. The data included is that most often referenced by contractors for planning, pressure, temperature, depth, fluid type, and weight and underbalance information.
This data is used to calculate many of the operating parameters, including the operating pressures for test tools and TCP firing heads, and to determine fluid displacement volumes for underbalance. Inaccurate information can have severe consequences. For example, the downhole temperature is an input to calculating the thermal expansion of the test string and some aspects of the TCP firing head calculation.
Well Test Objectives
The well test objectives are the principal reason for conducting the test. The objectives influence many aspects of the design and are therefore an important reference in the program. The well test objectives should be listed in the Well Test Program as stated by the subsurface team, using the same wording.
Achieving the test objectives is the principal measure of success of the test. Including this reference may be particularly useful if, during the course of executing the program, the procedure for a specific task needs to change as a result of unforeseen problems. Understanding the test objectives is important to developing an appropriate contingency procedure.
Well Status Assumptions
The well test operation follows directly from the drilling operation, which is governed by the drilling program, in order to ensure continuity of the operation as it changes from drilling to testing. The test program includes certain assumptions as to the well status at the point where the test program commences. They are not simply arbitrary assumptions; the test program is a controlled document approved by management in the drilling department. The assumptions communicate to those drilling the well the specific well conditions for which the well test is designed and which must be in place for the start of the well test program.
Well status assumptions typically include
- BOP ram configuration and pressure test
- Casing and liner data, including size, weight, setting depths, and final test pressure
- Wear bushing size and status
- Casing scraper across the packer setting depths
- Logging operations completed
- Well fluid type weight and condition
- Radioactive pip tags located as required in liner/casing
Roles and Responsibilities
Well test activity introduces many new contractors to the facility and also requires support from facility personnel. Because facility-based personnel roles and responsibilities during a well test often differ from the drilling phase, these changed roles and responsibilities must be defined for the well test. This promotes a fuller understanding for individuals as to their duties in relation to this nonroutine operation and can help prevent communication problems.
A flowchart may also be included to provide an overview of the reporting structure during this nonstandard phase of operations (refer to Figure 1.2 in Chapter 1). A reporting flowchart is a useful reference when test data starts to become available. Unless the reporting structure is clearly defined, the well test engineer may find him- or herself corresponding to a myriad of customers — subsurface engineers, drilling managers, asset managers—at a time when the well test engineer's attention should be firmly focused on the activity of the well test. Another danger associated with loose lines of communication is the distribution of field data, which may yet be subject to validation.
A typical set of well test specific roles and responsibilities is provided in the appendices.
Preparations
Incorrect or incomplete equipment preparation may result in costly operational failures and delays. For example, inserting an incorrect rupture disc into a downhole tool may result in the inability to operate that tool from surface or in the premature activation of the tool, necessitating a costly retrieval of the test string.
A checklist of preparations for each well test service is provided in the program to identify well-specific preparations not addressed in contractor standard operating procedures.
During the design phase, many of the equipment configuration and operating settings specific to each service are decided from planning meetings and calculations. The personnel who set up and operate that equipment on the facility are not always the same ones involved in the design work. It is therefore important to provide this information for reference in the program. Overall control of this process lies with the well test engineer, who will witness the key equipment preparations.
Following are some examples of the service-specific preparations typically included in the program; Generic preparations common to all services
- Inventory checks made for all equipment
- Equipment inspected for transportation damage
- Shortfalls and damages reported to the well test engineer
- Hazardous activities such as pressure testing, working at heights, electrical work, and dangerous goods performed in accordance with the facility safety management system
- Confirm with measurements of the loaded guns that the correct perforating interval has been selected (Note: it is not unusual for the perforation interval to be finalized at the well site, after the final logs have been run and long after the program has been issued. A well test is an exploration activity with many uncertainties. The program may simply state that the perforation intervals will be confirmed by the subsurface team after the final logs have been run.)
- Witness firing head settings and calculations and confirm that the inputs (e.g., fluid weights, pressures, and temperatures)
- Prepare subassembly drawings showing dimensions and TCP firing head settings.
- Review all tool settings and operating calculations; confirm the correct inputs have been used.
- Pressure-test tools and assemblies on deck as per contractor test procedures to the general test pressure; record all tests on a chart.
- Have well test engineer witness the installation of rupture discs and shear pins.
- Review string movement calculations to ensure correct packer weight or packer seal bore spaceout.
- Prepare subassembly drawings with dimensions and tool settings.
- Lay out, clean, and inspect tubing and pup joint end connections, drift all tubulars.
- Strap (measure) each joint, use overall length dimensions only (made-up lengths will be subtracted in the tally), paint length and joint number on each.
- Prepare a tubing tally with all tubing lengths and identification numbers
- Prepare an assembly drawing showing the spaceout of the subsea test tree inside the BOP. Include all relevant dimensions.
- Function and pressure-test the subsea test tree and lubricator valves on deck.
Surface Equipment Preparations
- Lay out and assemble surface equipment in accordance with the layout and P & ID drawings.
- Confirm that relief valves and automatic shutdown switches are located according to the P & ID and that the settings and calibrations are correct.
- Pressure-test the surface equipment in accordance with the pressure test procedure. (This procedure is sometimes prepared by the well test engineer and included in the program. But it is not unusual for the well test service contractor supervisor to prepare this procedure for review and approval by the well test engineer at the well site.)
- Function-test the boiler, compressors, and burner head ignition system.
- Complete surface equipment checklist. (Because of the extent of the preparations required, the preparations for this service are often included in a separate checklist in the appendices.)
- Confirm type and number of gauges supplied is as per program.
- Confirm gauge calibrations are current.
- Confirm gauges are function- and pressure-tested on deck.
- Confirm gauges are programmed and set up as per the reservoir engineer's requirements, either specified in the program or via direct instructions.
- Confirm a new battery is installed in each gauge and that each battery has been checked.
Preassemblies
A subassembly is a number of individual tools connected together to form a single lift that can be handled and installed as a unit. This saves much time by reducing the number of lifts to the drill floor.
On deck these items are connected using hand tools. During installation, they require additional torque, which is applied using drill floor tong equipment. This is a time-consuming exercise inasmuch as any individual tool might require the servicing of several connections. With the increasing cost of offshore facilities, it is becoming common to make up some of the subassemblies prior to mobilization so that less critical path time is spent servicing tools as they are installed in the test string. This is not a universal practice yet, and there may be certain subassemblies that cannot be serviced onshore owing to their size or lack of facilities. A typical list of subassemblies required for a test string might includes the following.
- TCP guns
- TCP firing head
- Packer
- Gauge carrier, tester valve
- Circulating valve
- Subsea test tree
- Lubricator valve
- Flowhead
Every subassembly must be measured, or strapped, prior to installation. Since the length of each must be entered into the running tally, these measurements must be witnessed by the well test engineer, who is responsible for accuracy of the tally.
The subassembly preparation must include reference to any contractor-specific procedures for tool preparation. Every tool must be pressure-tested and any tool settings witnessed by the well test engineer, along with calculations in support of rupture disc, shear pin, or nitrogen charge settings. Contractors must also provide subassembly drawings showing all the critical dimensions. Such drawings are useful when describing the subassembly installation procedure and in the event a tool parts downhole and fishing equipment is required.
Figure 7.3. Test string diagram
Making up Preassemblies
On a floating facility the subsea test tree and flowhead subassemblies cannot generally be made up at the time of their installation in the test string. This is because of the size and shape of these assemblies. In the case of the subsea test tree, the large diameter of the components renders them difficult to access using tong equipment, combined with the weight of the test string tailpipe. At this point it is required that this assembly be serviced without any tailpipe in the rotary.
The flowhead is installed high in the derrick on a floating facility. This height can be anywhere from 5 to 10 m when fully landed and 12 to 17 m during installation — hardly accessible to the makeup tools.
A Well Test Program written for a floating facility generally includes a procedure to pick up and service these two subassemblies prior to installation of the test string and on critical path.
Test String Installation
Installation of the test string requires a good deal of coordination between the rig crew and various well test contractors because it entails the installation of perforating guns, the packer, test tools, tubulars, subsea equipment, upper tubing string, the flowhead, and possibly pressure control equipment. The process of installing the test string in reality involves several tasks, some of which entail complex procedures individually. For this reason, the test string installation is often divided into subsections according to service (i.e., TCP, DST, tubing, subsea, and flowhead), or grouped together into operations that are carried out collectively. For example:
- Bottomhole Assembly; comprising the TCP guns, DST tools, and packer, which are normally made up and pressure-tested together.
- Tubing Running and Spaceout Procedure, a procedure taking 12 to 18 hours, depending on the well depth. The spaceout of the test string may be included with the tubing procedure if the spaceout is achieved using the tubing to tag a packer or fixed point in the well. If not, a wireline correlation procedure may be required as a separate section.
- Subsea Test Tree, Landing String, and Flowhead Installation.
- Pressure Control Equipment (if required).
- Given the above, tasks may involve crews working together for the first time. The activity toolbox meetings for each section are particularly important in order to establish awareness of the hazards, responsibilities, lines of communication, and agreement on the detailed procedure for carrying out each task. Many of the deck crews and floor hands will not have read the procedure, instead relying entirely on toolbox meetings and directions from supervisors to carry out the various activities in the procedure.
In support of the individual tasks within this operation the program includes various references.
Bottomhole Assembly — References
- Running Tally.
- Test String Diagram.
- Compensator Use Managed by Driller, relevant only to floating facilities. The compensators help to reduce the effects of rig motion on the test string when landed in the well or when there is potential for the test string to hang up at a restriction. The procedure should highlight the requirement to use the compensators whenever there is a potential for the test string to hang up inside the well — for example, when the packer is passing through the BOP and the wellhead.
- Contractor Assembly Drawings.
- Contractor Standard Operating Procedures, provided in the appendix to the program or in separate contractor manuals. Examples include explosives handling, test tools, and packer handling procedures.
Tubing Installation and Spaceout References
- Running Tally.
- Test String Diagram.
- Tubing Handling Procedures.
- Packer Running Procedures - The packer is the largest diameter tool in the lower test string and most likely to hang up or contact an obstruction. The small clearance between the packer and the casing results in a high fluid velocity over the surface of the packer seals. The contractor supplying the packer will provide procedures that include maximum running speeds to avoid washout of the seals.
- Well Control Procedures
- Monitoring the trip tank so as to determine whether the well is taking fluid or whether returns from the well exceed those expected by normal metal displacement of the test string.
- Well Control Crossovers, required as a contingency in the event the well takes a kick when running the tubing. A well control crossover is attached to the top of the tubing to allow a standard well control valve to be fitted to help control the kick.
- General Housekeeping
- Maintaining covers over open pipe and keeping loose tools and fittings away from the rotary table.
Subsea Test Tree, Landing String, and Flowhead References
- Running Tally.
- Test String Diagram.
- Subsea Subassembly Drawings.
- Subsea Contractor Standard Operating Procedures: includes detail on tool preparations, umbilical handling, and clamp installation.
- Tubing Handling Procedures.
- Flowhead Handling and Installation Procedure.
Commissioning
Commissioning a test string is the process whereby a fit for purpose installation is established following specific tool setting procedures and pressure tests to confirm seal integrity. This process varies according to the type of packer and test tools and typically includes the following
- Test String Pressure Test
- Spaceout
- Land off
- Packer Set
- Tool Activation
Test String Pressure Test
In order to establish the integrity of the test string, every connection that has the potential to experience pressure during production must be pressure-tested to the general test pressure. Pressure tests performed on the test string during installation are as follows
- BHA
- Periodically during the tubing installation
- Prior to installation of the subsea test tree assembly
- Prior to installation of the flowhead
- After installation of the flowhead
Tests 1 and 5 are the minimum. The pressure test on the BHA tests not only the interconnections between the tools, but also the various service connections, ports, rupture discs, and sleeves. The test on the test string after the flowhead installation establishes the integrity of the entire test string. With regard to intermediate pressure tests, resource companies often consider premium connections sufficiently reliable that intermediate pressure tests are unnecessary. The decision to perform tests 2, 3, and 4 depends largely on the condition of the equipment and the resource company's practices and experience.
Spaceout and Land Off
The spaceout of the test string is the process of placing critical test string components at their correct depth. The critical components are the TCP guns, packer, subsea test tree, and flowhead.
In essence, to achieve a spaceout, the length of every item in the test string is tallied and entered onto a spreadsheet. Tubing is inserted between the different components to position each one at the required depth. The tally can be prepared in a number of ways, a common method being to use the wellhead wear bushing as a datum. The wear bushing acts as a no-go to a hanger fitted to the subsea tree: when this hanger lands in the wear bushing, the test string can go no further.
The subsea test tree itself includes two critical measurements: the distance to the hanger, which lands in the well head wear bushing; and the distance to the slick joint, where the BOP pipe rams will close to form an annulus seal at the wellhead.
Every item in the test string below the hang-off point in the wear bushing is measured beforehand and tallied or added up to equal the measured depth of the well so as to place the TCP guns and the packer where required. Every item above this point is also measured to place the flowhead an adequate distance above the drill floor. That is, in the case of a floating facility, the stick up must accommodate relative movement between the rig and the test string, which is fixed at the seabed.
Errors frequently occur in the tally, and so an additional spaceout check and final adjustment are highly recommended. This check can be achieved in a number of ways, often depending on the type of packer used.
Spaceout and Land Off with a Permanent Seal Bore Packer
Prior to running the test string, the outer packer body and seal bore are set on wireline. The wireline incorporates a gamma ray sensor and casing collar locator; these devices provide a precise means of determining the packer depth in relation to the casing and the formation.
After setting the packer body, a set of seals, together with a locator designed to land inside the packer body, is fitted to the lower part of the test string. TCP guns are suspended below the locator.
The remainder of the test string tools and tubing are installed, gradually progressing toward the bottom.
As the locator nears the packer body, the rig compensators are engaged to ensure that no damage occurs as a result of the relative movement of a floating facility and the test string as it lands off inside the packer body. At this point, both the driller and the well test engineer carefully observe the movement of the string and the weight indicator. An approximate land-off point should be available based on the tally. Once this is confirmed by a loss of weight on the indicator, the well test engineer has an increased level of confidence that the locator has landed in the correct position. Additional weight is applied to confirm that the string has been fully located.
If the BOP rams are closed at this point, they will mark the pipe at the subsea level. This length of pipe is normally painted white before installation to provide a better indication of the ram marks. The rams are opened again, and the painted joint is retrieved to surface. A measurement of the ram marks to a tubing joint connection below that mark provides a spaceout reference at the seabed. With the painted joint removed, the subsea test tree is installed, and its position is adjusted with short pup joints in order to place the slick joint at the same depth determined for the ram marks. The test string is then run with the subsea test tree, the flowhead is installed, and after pressure testing, the test string is landed out so that the packer locator is inside the packer body and the subsea test tree is landed in the wellhead and the slick joint, opposite the BOP rams.
Figure 7.4. Spaceout dimensions
Land Off with a Retrievable Packer
A retrievable packer requires both string movement up and down and rotation to set. Because retrievable packers are used, the land off and spaceout are complicated by the presence of telescopic slip joints in the well. Upward movement and rotation of the test string are necessary to activate the packer slips. Subsequent downward movement places the packer in compression and completes the setting process. The downward movement must be calculated to close the telescopic slips the required amount and to land the test string at the wellhead. Weight loss will be observed as soon as the packer slips engage and take the string weight below the slip joints. Additional weight loss will be observed when the test string lands in the wellhead.
Figure 7.5. Spaceout with seal bore packer
These operations are typical of their type; however, procedures do vary according to the make and type of packer. In every case, the well test engineer reviews these operations in consultation with the contractor supplying the packer.
Flowhead Installation
The flowhead merits particular discussion in relation to floating offshore operations. As previously discussed, the flowhead must be elevated above the level of the drill floor, in order to accommodate movement of the facility due to the metocean conditions of tide and heave. At the time of its installation, the test string has not yet been tested, nor has it been landed. Consider that when the flowhead is attached to the test string, the test string is set in the rotary slips and moves up and down with the motion of the facility, At this point, the compensators are not yet engaged. Care must therefore be taken that no point in the test string will contact and hang up on a restriction or shoulder, in particular the packer or the wellhead. In order to ensure this does not happen, the flowhead is installed as an assembly with a tubing joint already attached to it. This ensures that the packer and the subsea tree are still a full tubing joint above their respective landout points. The flowhead is an awkward lift and requires careful handling during installation; this operation must be preceded by a detailed toolbox talk.
Figure 7.6. (a) Flowhead handling (b) Flowhead handling
Tool Activation
The various tools placed in the test string are generally installed in a run mode. In other words, the tools are in a configuration best suited to permit the installation of the test string. The tester valve, for example, is a ball valve designed to operate as a normally closed valve. This is inconvenient during installation since the test string must fill with well fluid. The tester valve normally has an installation setting that locks it into the open position and is placed in the operating position following an activation procedure.
A typical sequence for setting the various tools from run to test mode is as follows;
- Conduct low-pressure test on the annulus to verify that the packer is set and the BOP rams are sealing on the subsea slick joint.
- Increase the annulus pressure to lock open the tubing fill test valve and to activate the hydrostatic reference tool. This pressure will also be observed inside the tubing through communication ports on the tubing fill test valve. These ports close during this operation.
- Further increase annulus pressure to activate the downhole tester valve, No further increase in tubing pressure should be observed, thus confirming the tubing fill test valve has activated.
- Bleed off the annulus pressure and the well test valve will close.
- Bleed off any remaining tubing pressure at this point.
Establishing an Underbalance
A final task prior to firing the TCP guns is the introduction of the underbalance so that the reservoir fluids can flow to surface. Diesel is a common underbalance fluid and is readily available on most facilities in the quantities desired. Resources needed for this operation include the rig cementing services unit and a supply of diesel from the motor room. Because this operation involves interfaces between several of the services on the facility and the well test crew, the procedure should address the interface issues, which include;
- The rig safety management system or permit to work system
- Communication and overall responsibility for the transfer operation
- Other controls and measures to manage the operation including
- Pressure testing of lines and valves critical to the operation
- Methods for monitoring volumes pumped and volumes returned
- Storage of fluid returns, including the use of the trip tank and pits
- Pressures indicating underbalance and U-tube pressure
- Contingency procedures in the event of valve closure, leak, or seal failure
Before the operation commences, the well test engineer will perform a calculation to determine the volume of diesel required to achieve the desired underbalance pressure, leaving an adequate safety margin to ensure diesel is not accidentally displaced through the circulating valve and into the annulus.
To displace the fluid in the test string with underbalance fluid, a valve providing tubing to annulus communication near the bottom of the test string is opened. Depending on the valve design, this is usually achieved with tubing pressure cycles. As a preliminary step, a volume of water is pumped to the test string prior to the diesel to ensure the correct valve lineup; returns taken from the annulus to the trip tank provide the necessary indication. Once the correct valve configuration has been confirmed with fluid returns to the trip tank, the diesel supply is direct to the pump and displaced to the test string, pushing the heavier kill weight fluid into the annulus. The returned fluid is recovered back to the facility trip tank, and the volumes are monitored to ensure the desired displacement is achieved. During the displacement, the well test engineer will direct the cement unit operator not to exceed preset limits for pump rate and pressure. This ensures no other valves downhole are operated accidentally. The downhole circulating valve is then closed in preparation for the test. The procedure will include all the steps necessary to operate the valve as per the contractor's procedures.
The above procedure assumed diesel as the underbalance fluid, but other fluids including water, base oil, and nitrogen gas essentially involve the same downhole valve manipulations.
Pretest Safety Meeting
Just prior to perforating TCP guns and opening the well to production, a thorough pretest safety meeting must be held to ensure that all safety controls are in place and personnel are aware of operations and their responsibilities.
This safety meeting is attended by all parties connected with the well test, including facility management, resource company representatives, the driller and floor hands, service contractors, and deck crew. Typically, the meeting takes place on the drill floor and takes 20 to 30 minutes to ensure thoroughness. The meeting is normally facilitated by the well test engineer using a checklist of well test safety-related items to ensure all points are covered. The checklist includes a sign-off upon completion.
The topics covered by the checklist include
- Permit to work for well test operations
- Responsible personnel and communication focal points
- Review of sequence of operations, expected flowing conditions, and durations
- Review of operation of emergency shutdown system, who is authorized to operate it, and under what circumstances
- Emergency response during a well test
- Review of metocean conditions, wind direction, and sea state
- Final check and confirmation of equipment readiness and valve alignment
An example pretest safety checklist, provided in the appendices.
Perforating
This section of the program details the short but important task of detonating the perforating guns. References for this task include the perforating contractor procedures and the TCP firing head calculations performed by the TCP specialist and reviewed by the well test engineer during deck preparations. The accuracy of firing head calculations is dependent on the accuracy of the data supplied — for example, the fluid weight above the firing head and the accuracy of the depth to the firing head. Often this data is available only after the program is written and only just prior to running the test string.
This procedure varies considerably according to the firing head system. There are generally two types of systems: pressure activated or drop bar. The firing head also normally incorporates a time-delay mechanism. Regardless of the type of system, some preliminary steps must be taken to ensure a successful operation.
- Verify that all valves are open to the firing head, including the tester valve, subsea valves, and the required valves on the flowhead.
- Ensure that the pressures in the tubing are closely monitored to identify any indication that the guns have fired.
- Confirm computer pressure and temperature acquisition systems are acquiring prior to the commencement of this task with data sampling rates set to a high frequency, (e.g., every second).
For a pressure-activated firing head, the pressure must be applied above the underbalance fluid. Note that the underbalance fluid is a lighter fluid; therefore, the reduced hydrostatic pressure of the underbalance fluid should be taken into account when calculating the activation pressure. This pressure is applied using the cement unit, which can generally provide a more accurate measurement of volumes and pressures than the rig mud pumps. In the case of a nitrogen underbalance fluid, the pressure may be applied using the nitrogen unit. The activation pressure is generally held for only a short period of 1 to 2 minutes, depending on the firing head design. After the activation pressure has been held for the required period, it is common practice not to completely bleed this pressure to zero but to maintain a slight positive pressure on the test string. This is in order to provide a more positive indication that the guns have fired. When guns detonate, the indication received at surface is often slight — sometimes only a dull thud and a rattling of the tubing string, followed by a sudden increase in pressure as the reservoir fluid produces into the test string. However, this positive indication does not always occur. Without seeing an increase of pressure, there can be significant uncertainty. It may be that the guns have fired and the well is not producing, or it may be that the guns have not fired at all.
TCP Contingencies
TCP systems are generally very reliable, provided all of the pre-job checks have been completed as per the contractor's procedures and data regarding fluid weight pressures and temperatures are accurate. However, reasons other than an inherent failure in the gun system might give rise to problems. Examples include a closed valve in the system or debris settling near the bottom of the test string, creating a communication barrier between the firing head and surface. More commonly, a TCP system might work, but little or no indication is observed at surface, giving rise to doubts that the guns have fired.
Contingency procedures describe a troubleshooting process to verify the firing head calculations and the valve lineup. The delay period is normally extended before the firing procedure is repeated, often at elevated pressures in the case of a hydraulic firing head. Should the volumes pumped to achieve the firing pressure suggest that a downhole valve is closed, contingency procedures will direct the use of slickline equipment to drift to the firing head to verify that there is a free communication path.
Cleanup and Flow Periods
A flow or production period is any period during which reservoir fluids produce into the wellbore. This process is also known as a drawdown for the reason that the pressure at the reservoir face and in the immediate wellbore area drops from its initial shut-in value to some lower value during a flow period, the magnitude of the drop depending on production rate and certain formation and fluid characteristics.
During the various flow periods, the well test engineer is very much an observer of the activity of the well test crew. His or her role is largely one of quality control, checking to see that the conduct of the well test is in line with the procedures detailed in the program and to ensure adherence to safety controls.
Initial Flow
Programs generally include a short initial flow period of about 10 minutes followed by a shut-in period of about 30 to 60 minutes to precede the cleanup flow. The purpose of this short initial flow is to clean the perforation tunnels of debris and obtain initial reservoir pressure.
Cleanup
Conditions are most unpredictable during the cleanup and initial part of the main production period until conditions stabilize. During the cleanup, changes to the adjustable choke must be made in response to buildup of pressure and the fluids returned at surface. Initially, returns are taken to the storage tank. As pressure continues to increase, the production is switched directly to the flare. In cases where the wellhead pressure is naturally low, the entire fluid production for the period might be taken to the tank and later pumped to the flare for disposal.
In addition to process equipment adjustments, well-site personnel require guidance as to what defines a cleanup. This can be difficult to determine, and the decision can have significant consequences in relation to cost and data quality. On one hand, extending the production period to achieve a thorough cleanup will significantly add to the cost of the test and might only add a negligible incremental improvement to the quality of the cleanup. On the other hand, terminating the cleanup too early might result in contamination of the separator and fluid samples later during the main flow.
Toward the end of the cleanup, some programs call for a short period of production with the separator in order to take a set of contingency samples and to provide an early indication of the production rate. This data is useful later for deciding what choke sizes to select for the main flow period.
Options available to the resource company to manage these uncertainties include providing guidance in the program and sending a subsurface representative to the well site to assess the well conditions and recommend appropriate responses.
A typical cleanup procedure might read as follows
- Wait for pressure response to indicate TCP guns have fired.
- Open well at choke manifold on small adjustable choke to storage tank.
- Record volumes of underbalance fluid recovered in storage tank.
- Increase choke gradually under the direction of the well test engineer.
- Direct flow to the flare when adequate wellhead pressure is available to sustain a good burn
- Continue monitoring fluids at surface and record the change from underbalance to drilling fluid and reservoir fluid.
- Continue increasing adjustable choke under the direction of the well test engineer to achieve the maximum flow rate allowed
for the system
- Make adjustments to the choke to optimize burn efficiency or if heat radiation is excessive.
- Monitor fluid returns at all times taking fluid samples for BSW and gravity measurements.
- Cleanup will continue until the following criteria have been met.
- BSW <1 percent over three successive 15-minute readings.
- Water production, if any, must be monitored; chloride levels in samples will indicate if water is drilling fluid residue or formation.
- Wellhead pressure stable less than 10 psi variation over a 10-minute period.
- Wellhead temperature stable less than 2 Celsius variation over a 10-minute period.
- Confirm with the drilling supervisor and with head office that the criteria have been satisfied to obtain approval to shut-in.
- Shut-in downhole; once a pressure drop of ∼5 percent has been observed at surface, shut-in at the choke manifold.
Shut-In Period
A shut-in period following the cleanup is required to allow time for the reservoir pressure to build to its maximum value. The wellbore from the reservoir to the surface equipment is filled entirely with reservoir fluid, all drilling and underbalance fluid having been removed during the cleanup. Downhole gauges sensing pressure below the tester valve record this buildup data, which can be utilized later by the subsurface team to assist with modeling. The duration of this period will vary according to the expected nature of the reservoir formation. Typically, this period will last 1.5 times the cleanup flow.
A typical buildup procedure will include the following guidance.
- The duration of the shut-in period will be 1.5 times the cleanup flow period, or as directed by the on-site subsurface engineer.
- During the shut-in, no activity shall take place that might disturb gauge data, such as valve manipulation on the flowhead or choke manifold.
- Note that the pressure trapped between the downhole tester valve and surface will drop as a result of thermal contraction to the fluid in the test string. No action is required.
Main Flow Period
Depending on the well test objectives, this period might involve production at a single rate or multiple rates. This aspect of the test design is the responsibility of the subsurface team because the data derived from this activity is an important element in reservoir modeling. The program details the order and duration of each flow period and the data requirements, including samples for each.
A typical main flow period procedure might read as follows.
- Open the downhole tester valve with annulus applied pressure.
- When a pressure response is observed at surface, open the well on a small adjustable choke to commence production.
- Continue to increase the adjustable choke until the production rate is estimated to be equal to the first desired flow rate.
- Change to a fixed choke.
- Pass production to the separator and commence readings.
- Acquire PVT samples, samples for fluid properties, and assay and trace element measurements.
- At the end of the first rate period, switch to an adjustable choke.
- Increase the adjustable choke to achieve the next desired flow rate.
- Repeat the steps above for each successive flow period.
Final Shut-In
The final shut-in period serves a similar purpose to the shut-in following the cleanup, but the final shut-in might be considered more representative since the flow periods immediately preceding it involve a longer drawdown on the reservoir. The resultant buildup data therefore provides a greater radius of investigation into the reservoir since fluids travel from further into the reservoir to replace those lost during the test.
Well Kill and Test String Retrieval
After the final buildup, the well must be secured in such a manner as to permit the safe retrieval of the test string. This is achieved by displacing the reservoir fluids in the test string with a heavy kill weight fluid to provide a barrier; the BOPs provide a second barrier. The procedure for this retrieval varies, primarily according to the test fluid, oil or gas, and also according to the type of packer and other test tools in the string.
A typical sequence showing the main procedural steps for a gas and oil well test is outlined in the following section.
Well Kill — Gas
- With the tester valve in the closed position, open the surface choke manifold and bleed the entire tubing contents above the tester valve to zero.
- Lubricate the kill weight fluid to fill the test tubing above the tester valve to surface.
- Open the tester valve.
- Bullhead kill fluid into the test string; this will push reservoir fluids below the tester valve back into the formation
- Calculations for the volume between the tester valve and the formation will indicate pump volumes required.
- A sharp rise in pressure will occur when the kill weight fluid contacts the formation.
- Do not exceed formation rock fracture pressure during the bullhead process.
- Observe the well for 10 minutes to indicate the well is dead.
- Open pipe rams and unset the packer.
- Circulate 1.25 times the entire well volume, taking returns to the rig pit system.
- Monitor continuously for gas in the returns; some gas may have been trapped below the packer.
- At the end of the circulation, observe the well for a further 10 minutes to confirm dead.
- Flush surface equipment with seawater.
- Proceed to pull out of hole with the test string.
Well Kill — Oil
- With the tester valve in the closed position, bleed the tubing head pressure to zero to the well test equipment.
- Cycle the reclosable reversing valve to the reverse position.
- Pump kill weight fluid into the annulus to displace the tubing contents to the well test equipment.
- When annulus fluid returns are observed at surface and no oil contamination is evident, stop pumping.
- Close the reversing valve and open the tester valve.
- Bullhead kill fluid into the test string; this will push reservoir fluids below the tester valve back into the formation.
- Calculations for the volume between the tester valve and the formation will indicate pump volumes required.
- A sharp rise in pressure will occur when the kill weight fluid contacts the formation.
- Do not exceed formation rock fracture pressure during the bullhead process.
- Observe the well for 10 minutes to indicate the well is dead.
- Open pipe rams and unset the packer.
- Circulate 1.25 times the entire well volume, taking returns to the rig pit system.
- Monitor continuously for gas/oil in the returns; some gas may have been trapped below the packer.
- At the end of the circulation, observe the well for a further 10 minutes to confirm dead.
- Flush surface equipment with seawater.
- Proceed to pull out of hole with the test string.
Both of the above procedures for well kill entail pumping cold fluid into the well. This may cause contraction of the test string and may also affect the operating pressure of the tester valve by cooling the nitrogen reference chamber. Close monitoring of the tester valve and surface pump pressures must be maintained during this operation in the event the valve closes unexpectedly.
Unseating a retrievable packer typically involves picking up on the test string to open the telescopic slips and lifting the compression weight on the packer. As the packer unseats, the driller should be made aware of the potential for some gas to escape from below the packer seals. Once unset, the test string can again be lowered to a position where the BOP rams can close on the SSTT slick joint in preparation for circulation.
A permanent seal bore packer also requires upward movement to remove the seals on the packer locator from the packer seal bore. However, the test string cannot be lowered prior to the circulation because this would re engage the locater seals inside the packer, closing the circulation path. The driller should also be made aware of the correct height to pick up to allow BOP pipe rams to close on the pipe below the SSTT, if required for any well control issues that may arise during the circulation.
Retrieving the Test String
Before disconnecting the flowhead, the surface well test equipment should be flushed in preparation for dismantling. Flushing the surface equipment can be achieved easily by closing the master valve on the flowhead and pumping seawater, followed by inhibited drill water through the equipment on deck. This operation normally takes about 15 to 30 minutes to ensure that all equipment, pipework, and the like have been thoroughly flushed. Once completed, the lines may be disconnected from the flowhead, and the task of retrieving the test string can begin.
Precautions during the test string retrieval operation should be taken against swabbing the well. This can happen particularly on gas wells, for the packer can act like a piston. The fluid bypass area around the outside of the packer is not great, so as the test string travels upward a suction force is generated below the packer, which can induce an underbalance and cause the well to flow. The driller must be alert to this hazard and monitor well fluid volumes at the trip tank to ensure there are no gains at surface. The upward speed of the packer will be limited to minimize the effect, particularly while the packer is inside a liner.
As the test string is being retrieved, other rental equipment on deck may be decommissioned, again observing good housekeeping precautions.
The well test engineer will busy him- or herself assisting in the management of logistics. Rental equipment should be packaged safely for transportation and shipping manifests, packing lists, and associated documentation prepared as required.
After the downhole gauges have been retrieved at surface, the gauge data is analyzed and validated for quality control purposes. This task is ideally performed by the subsurface representative.
Contractors submit reports to the well test engineer as required by their service contract. In particular, well test production, gauge, and sample data must be carefully backed up and a complete copy provided to the well test engineer.
End of Program
Retrieval of the test string marks the end of the Well Test Program. The next critical path operation, that of abandoning or isolating the well, is managed under the drilling program. However, it is sometimes necessary to pick up the well test preassemblies, such as the subsea test tree and the flowhead in order to break service connections.
Demobilization
The well test engineer's focus after completion of the well test program is the logistics associated with the demobilization of equipment and personnel. Contractually, the resource company pays charges until both equipment and personnel return to an agreed point of origin. Before this can happen, all contractors must pack away their equipment and issue manifests, field reports, and service tickets to the well test engineer.
Service Tickets
A service ticket is a well-site record summarizing the most relevant details for each service provided. This record is prepared by each senior contractor supervisor and reviewed and signed by the well test engineer at the well site. On the basis of the information provided in the service ticket, the contractor subsequently submits an invoice for the service to the resource company.
Well-Site Reports
An end of well report is a detailed record of the service provided by a contractor. This record provides a useful reference to assess the quality of the data recorded during a well test. In particular, it addresses anomalies or incomplete data. Referencing the report identifies events that may have influenced the quality of the data — for example, adjustments to a separator or choke manifold. It is also referenced for incident investigation purposes, particularly in relation to equipment damage and production interruptions that might also have influenced data quality. The report also provides support for contracts and invoicing purposes.
Every well test service contractor must submit a report to the well test engineer. The content varies significantly according to the nature of the service. For instance, a contractor providing a rig cooling service might only submit events, heat monitoring data, and well-site personnel records, whereas the surface well test contractor will have a more comprehensive report to submit. Typically, a comprehensive end of well report includes the following:
- Sequence of events
- Pressure test records
- Calibration records
- As-installed assembly drawings
- As-installed equipment layout drawings
- Tallies
- Well test data (downhole gauge pressure and temperature data and surface production data).
- Sample records
- Well-site crew list
- Incident reports
- Service tickets
It is common practice to issue a field version of the report to the well test engineer at the well site and a finalized version after demobilization, the final report being subject to review by the well test engineer. Together all of the contractor reports provide a detailed record for every aspect of the well test. Acceptance of the final report is often a contract condition for payment of invoices. In addition to the uses identified above, these reports also provide input to the continuous improvement process, whereby the participants learn from their successes and mistakes and develop practices and procedures to improve the quality of subsequent operations.