Operational aspects of oil and gas well testing pdf


    download Operational Aspects of Oil and Gas Well Testing, Volume 1 - 1st Edition . Print Book & E-Book. DRM-free (EPub, PDF, Mobi). × DRM-Free. This book covers all the major operational aspects of oil and gas well testing. It uses a structured approach to guide the reader through the various steps that are . { OPERATIONAL ASPECTS OF OIL AND GAS WELL. TESTING (HANDBOOK OF PETROLEUM EXPLORATION. AND PRODUCTION #1) } ] PDF.

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    Operational Aspects Of Oil And Gas Well Testing Pdf

    well testing concepts are to be found within the internal libraries of some oil- and gas-producing The roots of gas well testing are to be found in reservoir engineering taken in its broadest . all aspects of the material and its presentation. There is no future production under various modes of operation. The production. Occupational Safety and Health Standards for the Oil and Gas Industry Participant Manual Texas roughnosecontdar.gq Application of Remote Real-Time Monitoring to. McAleese S. Operational Aspects of Oil and Gas Well Testing. Handbook of Petroleum Exploration and Production. Volume 1. Файл формата pdf; размером

    Sara Burgerhartstraat 25 P. All rights reserved. This work is protected under copyright by Elsevier B. Photocopying Single photocopies of single chapters may be made for personal use as allowed by national copyright laws. Permission of the Publisher and payment of a fee is required for all other photocopying, including multiple or systematic copying, copying for advertising or promotional purposes, resale, and all forms of document delivery. Special rates are available for educational institutions that wish to make photocopies for non-profit educational classroom use. Other countries may have a local reprographicrightsagency for payments. Derivative Works Tables of contents may be reproduced for internal circulation, but permission of the Publisher is required for external resale or distribution of such material. Permission of the Publisher is required for all other derivative works, including compilations and translations. Electronic Storage or Usage Permission of the Publisher is required to store or use electronically any material contained in this work, including any chapter or part of a chapter. Except as outlined above, no part of this work may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without prior written permission of the Publisher. Address permissions requests to: Elsevier's Rights Department, at the fax and e-mail addresses noted above.

    Carry out an H2S drill, if H2S is expected. All fire fighting appliances to be inspected. Fire pumps to be functioned and the system pressurised. Fire drill to be carried out in test area. Fire appliances to be positioned next to the test spread. Gas detectors to be function tested.

    Explosion meter to be function tested. Lifeboat engines to be function tested. Lifeboat launching equipment to be function tested. Radio and telephones to be function tested. Life-jackets and survival suits checked. Drill floor sprinkler system to be function tested. List of safety muster points to be posted on the notice boards and reviewed at the pre-test safety meeting.

    Firedrill and abandon rig drill to be held prior to testing. Schematic showing hazardous areas to be posted.

    Operational Aspects of Oil and Gas Well Testing, Volume 1 - 1st Edition

    ESD system to be installed and tested. Personnel to know location and function. Kill lines and pump to be tested and manifold correctly lined up to kill wing. Personnel Briefing: Overleaf on a single page is a personnel briefing that may be copied and distributed to personnel at the well site prior to holding the pre-test safety meeting.

    Well test (oil and gas)

    The briefing will include the location of and use of the ESD system. No heavy lifts should take place in the well test area. Any requirements, announcements or emergencies to be co-ordinated by driller. All personnel must respond to any alarms immediately. To include: Safety Procedures 4. For onshore operations this may be before land acquisition. Consideration should be given to a safe area for loading guns and a safe area for storing explosives.

    Consideration should also be given to a suitable location for a flare pit at a land well taking prevailing wind direction into account. The design should consider the layout required for well testing operations to be carried out in a safe manner see also Section Consideration should also be given to the area weather forecast for the duration of the test.

    In the event that weather conditions deteriorate during an offshore test, the Drilling Supervisor and Test Engineer in consultation with the OlM will decide whether testing operations are to be suspended or terminated.

    The start of the flow test, i. The initial flow and shut-in may occupy the hours of darkness provided adverse weather is not expected and no hydrocarbons are produced to surface. Flow into or throughout the night should only be permitted if the well has stabilised and the surface equipment has been commissioned in daylight. Finally the flow of formation fluids to surface should normally only be performed with a complete set of surface equipment including choke manifold, separator and either a tank or burner arrangement.

    Very low budget land operations, on low GOR oil wells do occasionally omit the separator, however in general such operations should not be planned. Reverse Circulation Reverse circulating during the hours of darkness is only generally permitted if the test has previously produced hydrocarbons to surface.

    If no hydrocarbons have been produced to surface then this operation must be done during the hours of daylight.

    The responsibilities should be documented and agreed with all parties involved. Discussed below are generalised responsibilities, which should be considered when, defining responsibilities for a particular test. These should be reviewed with regard to the particular rig being used and prior to writing the detailed testing programme.

    The test programme may also include an organigram showing responsibilities and reporting lines. For all testing operations, only personnel from the company providing specific items of equipment shall operate that equipment. This is particularly important for the choke manifold, separator and flare systems. All relevant operations will be routed through the barge control room before implementation e.

    Work boat and standby boat movement will be controlled by barge control room prior to and during test. The base office must also maintain communication with the helicopter base or air strip if applicable. The captain will post a 24 hour visual watch from the bridge to observe the rig and a 24 hour radio watch on International Maritime Distress Channel 16 and any other working channels used by the rig and local vessels.

    The captain must be familiar with the contents of the well specific oil spill contingency plan. Having ensured that chemical dispersants for oil are onboard the standby vessel and that the spraying equipment has been function tested. A service company representative must be on the drill floor at all times during the test. In the event that the test crew comprises of only one downhole tools specialist, it is important that this specialist be on the drill floor while running in or pulling out of the hole with the test string.

    The driller must ensure that the entire drill crew is familiar with the location and function of the ESD system. The Driller should ensure that the hole remains full at all times. The Driller should be given instructions at the programme meeting on the course of action to be followed if events do not go according to plan.

    The Driller will also be advised in which circumstances he needs to inform the Toolpusher and the oil and gas company onsite representatives about events. The Drilling Engineer will provide engineering and logistical support for the ongoing operations and liaise with the head office on engineering aspects of the test. Job Responsibilities during Well Testing 5.

    He is responsible for issuing all instructions to the drilling contractor and service company personnel. These instructions may have to be written formally.

    The Drilling Supervisor is responsible for: In addition, must ensure that all wireline pressure control equipment has been tested and is ready for use. The gauge engineer should be on the rig floor for the running and recovery of the gauges and is responsible for data verification. Also will have established areas for stock-piling breathing apparatus and emergency escape packs.

    The H2S representative will be ready during testing to provide assistance on the drill floor when requested by the Drilling Supervisor. Will run samples of produced gas through the chromatograph as required. In addition they Job Responsibilities during Well Testing 49 will ensure that the test package is complete and that compatibility exists with the rig equipment, e.

    Will ensure that the surface equipment is functional and that all equipment is installed and tested correctly. Test crew will monitor and operate the choke manifold, separator, burner heads and other test equipment during the operation. They will be responsible for ensuring that the data acquisition system is ftinctioning correctly in addition to manually recording all pertinent parameters throughout the test.

    Ensure radio silence is maintained while any explosive charges are being armed and until they are at a safe depth in hole. Then agam when being pulled out of hole and near to the surface, until such time as they have been safely disarmed. Must also ensure that all the fishing tools relevant to all the operations are available on-site.

    Will provide assistance in sub sea space out of slick joint, fluted hanger and accessories. The TCP Engineer will be on the drill floor for the make up, firing and recovery of the guns.

    He is responsible for the following: The Test Engineer should also make a final check on the test equipment by walking the route of the flow lines together with the Drilling Supervisor and OIM to ensure that all the valves are correctly positioned and all function tests have been carried out, prior to opening the well. He will ensure that all equipment is functioning and that safety rules are being observed.

    The Tool pusher and his delegated crew will: The specific well test objectives for a particular test with be set by consideration of the requirements of the different departments in the same way as the overall well test objectives refer to Section 3. It is important that the specific well test objectives are documented and distributed to interested parties.

    This document will be a significant part of the final audit trail and in the final analysis will help in determining whether the objectives of the test have been achieved. The specific test objectives are normally set once the well has been drilled and logged. The decision making at this point often has to be rapid and in some circumstances may be taken at the well site.

    The specific objectives must be set within the context of the overall well test objectives and should be set by the responsible parties as defined within the decision to test refer to Section 3. Some common specific well test objectives are discussed below: In order to evaluate these boundaries, flow and build-up periods must be sufficiently long so that late transient flow, or in the case of a small closed reservoir, pseudo steady state flow is developed.

    To help with the design of the test, the equation used to estimate the time taken to detect a boundary is shown in Appendix A, Increasingly now Reservoir Engineers will make use of the test design option that exists on most commercially available well test analysis programmes, to look at the likely pressure response that will occur during the test.

    These programmes can also model boundary effects and may be a useful guide to the length of flow and buildup required during a well test to obtain certain boundary information. If verification of reservoir boundaries is a critical objective of the test, wireline retrievable, or surface readout gauges should be considered when designing the test string. Incorporating one of these systems will allow approximate calculation of reservoir parameters prior to pulling the test string.

    It will also allow decisions to be made on the rig as to when build-ups should be extended, or curtailed. If the overall size of the reservoir is required to be determined then a longer term reservoir limits test would have be carried out.

    Flowrates are normally measured at surface using separation equipment. Flowrates are sometimes measured downhole using production logging equipment. Section These high drawdown flow periods are used to evaluate the following well parameters; wells open flow potential, production behaviour with wellbore pressure below bubble point oil wells , rate dependent skin effects gas wells , water coning or gas coning effects oil wells , and solids production tendencies.

    The high rate flow period is also useful as an indication of the wells flowrate potential as a future producer. Maximum rate tests if required should be carried out after the main reservoir data has been collected. When considering any high rate testing it is of utmost importance that the well is produced in a safe and controlled manner and that none of the downhole, or surface equipment working pressures, flow or temperature limits are exceeded.

    This includes the temperature of the rig and its equipment due to radiant energy from the flare. For this reason, flare simulations for the maximum anticipated flow rate should be carried out.

    In addition, if the well is to be suspended or completed as a potential development well it is important that no lasting damage is done to the reservoir. The most accurate and commonly used method for calculating permeability is from a a pressure build-up with downhole shut-in carried out after a period of stable flow.

    Horizontal permeability is used for calculating well productivity, comparison with core data, and as an input for reservoir simulation. Specific Well Test Objectives Vertical Vertical permeability is usually different from horizontal permeability in most cases vertical permeability is much less , even in a homogeneous formation.

    Vertical permeability can be calculated from analysis of a vertical interference or pulse test. These permeability measurements are used to estimate the coning potential within the reservoir - often with the use of simulation models. It is further discussed in 5 Earlougher, R. Reservoir pressure is also calculated from build-ups following later flow periods.

    Comparison of reservoir pressure measurements between build-ups can be used to identify reservoir depletion. However, caution should be exercised in the interpretation of tight formations where supercharging may be present and this may lead to an erroneous interpretation of depletion. Operationally - extended MDT flow periods in high pressure wells could be considered a well control issue, as the reservoir sample is discharged into the well bore, with the potential for gas migration to surface without a string in the hole.

    Results from the analysis of these samples are used in many areas including: Typically representative samples can be collected as follows: The quality of samples collected is crucial to the accurate evaluation of the fluid property data. To this end specific sampling procedures are detailed in Chapter 15 of the book. Special precautions are required when shipping and handling pressurised samples, for details see Chapter Solids Collection of samples of produced solids during stabilised flow periods is often important when field development is being considered.

    Evaluation of produced solid samples is used for the following; completion design, including the requirement for gravel packing, calculation of maximum production rates, artificial lift strategy, surface facility design, estimating fi-equency of wellbore cleanout work. Samples should be collected upstream of the choke manifold if possible, and solids concentrations in produced fluids calculated. This procedure should be carried out at each flowrate over which the well is produced.

    Any wax found in any part of the test equipment should be noted on the test report. If wax is found, bottom hole samples should be taken to allow quantitative analysis.

    Operational Aspects of Oil and Gas Well Testing

    This is a specialist subject and advice should be sought fi-om a specialist company. Water Collection of representative formation water samples if produced during the course of the test is important for the following reasons: Formation water samples may be collected by the following methods: The quality of samples collected may be crucial to the calculation of reservoir fluids in place and field development plans.

    To this end specific sampling procedures are discussed in Chapter 15 of the book. Onsite Chemistry Where the hydrocarbons are known or suspected to be sour, onsite chemistry must be considered.

    Substances such as H2S, for example, are absorbed into the surface of sample bottles, thus evading subsequent quantitative analysis. However, special treated bottom hole samplers are available which absorb little or no H2S.

    These samplers may not be available in all locations at short notice and some advance planning may be required in order to have them available for a test.

    Within this interval large variations in porosity and water saturations may have been noticed during logging runs. This information will typically be gained by running a suite of production logging tools PLT's. In some cases where more qualitative results will suffice it may be quicker and more cost effective to run a memory recording spinner with temperature and pressure probes on slickline.

    For deviated or horizontal wells the FLT tools that are used have to be carefully selected. Often this may mean replacing the gradiomanometer with a radioactive type fluid density tool, which is not sensitive to deviation. In horizontal wells it may mean selecting tools that can provide a more comprehensive coverage of the entire pipe cross section, to account for the effects of phase segregation and stratified flow.

    Failure to select the correct tools will result in data being recorded, which is erroneous and unrepresentative of the fluid flow. In such circumstances advice should be sought from the local service provider. Information gained from evaluating zonal contributions can be used for the following; identifying reservoir recovery factors, identifying economic production intervals, sizing stimulation and diverter treatments, identifying prospective injection intervals, identification of zones requiring isolation during permanent completion, and verification of cement bond integrity.

    Preparation is the key to safe and successful well testing; because the design process is an iterative one involving the consideration of many small details it will always take longer than anticipated. This is to allow for the long lead times on equipment and to ensure that any necessary rig modifications can be scheduled. However, even for routine well tests the planning should begin three months before the issue of the test programme, which will usually be sent out to partners one month before drilling through the reservoir section.

    The overall conceptual test design must be carried out within the context of the well test objectives. However, the design process will also involve the selection of the most appropriate testing equipment and services and it will ensure that these services can be mobilised at the correct time for the well testing operations.

    Once the well is drilled and logged the final test design can be fine tuned for the particular test requirements. Open hole tesdng should not be undertaken on floating rigs or on wildcat wells see Section 7. Barefoot tesdng may be carried out on all wells provided that the interval can confidently be killed at the end of the test. Premium tubing e.

    Conventional drillpipe should only be used as the test string under certain circumstances see Section 7. However, it provides an overview of some of the more commonly conducted tests and the reason for carrying them out. Initial flow period minutes Initial shut in period 60 minutes Main flow period - Clean up well, then flow for 6 hours stabilised flow Main Shut in Pressure Build Up - PBU Sample flow period The initial flow period is designed to provide the best estimate of initial reservoir pressure.

    The initial flow period can also yield erroneous initial reservoir pressure measurements, in tight formations, due to supercharging. In addition on problematic wells: It can be substituted by a separate clean up flow period or this may be incorporated into the main flow period. The duration of the main flow period will be determined by the well test objectives. That is, if a specific radius of investigation is required from the test then the main flow period may have to be extended. One of a number of equations used for estimating the radius of investigation during testing, is shown in appendix A.

    It is commonly misunderstood that the radius of investigation is dependent on the well production rate, this is not the case. The rate at which the well is flowed will again depend on the objectives of the test e. The main shut in period is important for the analysis of reservoir transient pressure response; it should be of sufficient duration to allow analysis of all the pressure responses that results from flowing the well.

    In the absence of a surface pressure read out capability it should be about 1.

    A simple test such as this will provide information on well bore storage, skin, permeability kh and flow rates. More complex tests with multiple rates or extended well tests Reservoir Limit tests would be carried out only if specified by the Asset or Reservoir Engineering group.

    Test Design 7. This is because on low production rate gas wells there may be a flow rate dependent skin, which can be identified by carrying out a second flow and build up period. This is in fact the simplest form of a deliverability test.

    In practice most deliverability tests would have four flow periods as shown in figures 7. A deliverability test is run in gas wells to determine: Absolute open flow potential is the theoretical flow rate at which the well would produce if the reservoir sand face were at atmospheric pressure.

    This calculated rate is only of practical importance because the governments of certain countries set the maximum rate at which the well can be produced as a fraction of this flow rate. Rate dependent skin is an additional pressure drop in the near well bore which varies with the flow rate; this will be reflected on the wells inflow performance. There are three types of deliverability tests: Flow after Flow Tests involve flowing the well on successively larger choke sizes one after another without shutting the well in.

    The well is flowed on each choke size until stabilised. Chokes sizes are normally selected such that stabilisation can be obtained relatively quickly and the duration of each flow period is normally the same. This test is terminated with a long final build up. Figure 7. Each flow period is separated by a build up of sufficient duration to reach stabilisation.

    The final flow period is extended to achieve a stabilised flowing pressure for defining the IPR. The test is then terminated with a long build up.

    The isochronal test is an excellent test for high permeability and thick reservoirs, but it is time consuming and costly for low flow capacity reservoirs.

    The modified isochronal test consists of flow periods on successively larger chokes and build-ups of equal duration, except the final flow period which is extended until the well is stabilised. The final build up is often continued until the initial pressure at the start of the extended flow period is reached.

    It will however not allow the mechanical and non-Darcy skin factors to be separately determined, and thus does not allow deliverabililty calculations. Often gas well tests are made unnecessarily long and complicated e. Use of a more complex testing procedure considerably lengthens the testing time and cost.

    Therefore, the additional information obtained must be valued against the additional costs of the operation. DeliverabiHty tests as described above are usually carried out over four distinct flowrates. However, if testing time is limited or there are surface equipment limitations, a three rate rather than a four rate test can be carried out. It should be noted however that reducing the number of flow periods will affect the accuracy of the deliverability relationship determined.

    Careful consideration of the anticipated production rates should be made at the design stage of the test to allow a spread of data. During gas deliverability testing as with other tests it is important that surface data is collected on a regular basis. Increases in LGR or CGR are particularly important as 62 Operational Aspects of Oil and Gas Well Testing these may mean that the well is not staying clean of liquids during lower flowrates, or that the well is flowing below dew point.

    For lower permeability tests, extended flow periods may be required to obtain representative samples at stable conditions. Where it is known or suspected that the hydrocarbon will ultimately be gas condensate and that the bottom hole flowing pressure will fall below the dewpoint. A dedicated low rate sampling flow period should be considered before the main flow.

    However, it is worth noting that bottom hole shut in during a DST is often sought as it allows better determination of well bore storage effects. Moreover, downhole shut in helps prevents well bore storage effect from continuing into the middle and late time regions of the transient pressure response and possibly dominating that pressure response, with the effect that permeability and boundary information may be misinterpreted.

    Frequently, discovery and appraisal wells are drilled into productive reservoirs than cannot flow to surface or cannot flow at a stable rate to surface. This is usually due to one of or a combination of the following reasons: Test Design 63 The forms of artificial lifting that can be employed in DST's are nitrogen lift, electric submersible pumps, jet pumps and rotary pumps.

    The choice between these techniques will be based on the expected productivity of the well, production conditions such as GOR, equipment availability and whether the rig is fixed or floating. Environmental considerations may also dictate the choice of artificial lift method.

    In order that this can be examined a separate DST will be performed over an interval within the aquifer. This DST will normally be conducted in the same way as for a hydrocarbon producing interval. This means that a series of flow and build-up periods are conducted over the zone of interest.

    It should be noted that this type of test can only be reliably performed in an over-pressured reservoir. Reliable samples are generally only obtained when a well can flow to surface long enough to fiiUy clean the well of the completion fluid mud or brine. It can be useful for the completion brine to be "spiked" with a tracer chemical so that the samples taken can be checked for contamination by the brine.

    If the well is to be permanently abandoned or if a water zone can be plugged back later, it may be possible to add on a water zone to a hydrocarbon bearing zone where normal pressures are found , in order to obtain water samples to surface.

    Special consideration must be given to the active sump volume below the packer to ensure that the well can be successfully killed at the end of the test. Consideration must also be given to the pressure regime, formation homogeneity and integrity, and hole condition.

    In all instances, the largest possible gas volume below the packer at the highest anticipated formation pressure must be able to be safely circulated out.

    The slug test or closed chamber tests allows results to be obtained without consuming much rig time. The well is perforated usually with a nitrogen cushion, which is then bled off at surface. Bottom hole gauges measure the pressure build-up as the well dies and this data can be analysed for permeability and skin provided that the properties of the inflowing fluids are known.

    A closed chamber test is similar to above, but as its name implies it is shut-in, usually at surface. This test is generally used for oil and water wells which will flow to surface. As long as the density and compressibility of the wellbore fluid are known only wellhead pressure gauges need be used.

    If the formation is of very high permeability, then analysis may not be possible because the build-up will be too quick. The advantages of running these type of test are that they are both cheap and quick. The disadvantages are that only a small radius is investigated and no samples are usually obtained.

    One such piece of information may be the determination of the ability of an underlying aquifer, or base layer of the oil reservoir to accept injected water. An injectivity test will either be carried out following a conventional flow and buildup test on a producing zone, or as a separate zonal test. In either case it is important to try and encourage the well to flow prior to injecting water. This will allow the production of any dirty and solids laden fluids to surface prior to injection testing.

    It may also allow information on the zones pressure, permeability and skin factor to be gained. This information can then be used to estimate the maximum expected injection rates allowable in the well without exceeding fracture initiation pressure.

    It is critical during injectivity testing that fracture initiation pressure is not exceeded. If the well does not flow to surface after perforating a new zone there are two courses of action. Firstly injection fluid can be bullheaded to the formation. This procedure will mean that any dirty fluids and suspended fluids will be pumped into the formation leading to a high skin factor. Secondly clean injection fluids can be circulated down the test string using a multi-reversing valve.

    This procedure will allow most of the dirty fluids within the test string to be displaced. The downhole tester valve is maintained closed during this operation.

    The injectivity test itself should be carried out over a minimum of two stabilised flow rates, each below fracture pressure, followed by a pressure fall off with the well shutin downhole.

    Test Design 65 During injectivity testing it is necessary to monitor the 'sand face' pressure continuously. In deep wells this should be done using downhole gauges, as correlations for friction pressure drops in the tubing will not be sufficiently accurate for quantitative analysis. For wells of less than 3, ft, corrected wellhead pressures can be used if downhole gauge rental is considered too expensive. Samples of injection fluids should be collected during each injection period.

    These will be used to evaluate fluid specific gravity and sand face viscosity at downhole injection conditions. In general most prudent operating oil companies now have a policy that open hole testing may only be carried out on land and jack-up rigs, but not from floating rigs.

    Many operators also prohibit open hole testing on wildcat wells where reservoir parameters are not well known. Openhole tests should generally not be considered for any of the following well types: Conventional DST's can be used to gain parameters from which a long term test can be designed and implemented.

    The main objectives of long term tests are usually as follows: In most cases long term tests are carried out onshore in oil reservoirs where it is possible to obtain revenue from the sale of the produced oil. Offshore long term testing - extended well testing EWT is usually confined to situations where confirmations of certain reservoir parameters is vital to evaluate possible development options and these parameters cannot be ascertained from a conventional DST.

    Long term tests are usually carried out with a completion in the well rather than using DST tools. For an onshore test the rig will often not be required on location. The tubing and downhole equipment can be run by a workover unit, which typically moves off location prior to commencing the test. The time scale and data requirements of these tests will be set by the objectives of the test.

    Designing a test for these conditions requires rigorous procedures, uprated equipment and a great deal of time. It is a specialist subject normally undertaken by experienced consultants and space constraints prevent detailed coverage here. In discovery wells, stimulation treatments may be used when a prospective interval will not flow hydrocarbons after perforating.

    This will usually be as the result of low permeability and or severe near wellbore damage. In appraisal wells, the effectiveness of the stimulation treatment will need to be evaluated.

    These well tests will normally be used to establish economic production rates from a well and evaluate the stimulation treatments. Stimulation techniques can only be evaluated in the light of unstimulated performance. It is therefore of utmost importance that flow and build-up tests are conducted over the interval prior to carrying out a stimulation treatment. Stimulation treatments should normally only be considered for cased hole tests, as stimulating open hole sections may result in possible well collapse and packer leaks.

    Typical stimulations that are used to increase a welFs productivity are: Where possible stimulation treatments should be planned prior to the start of a well test as they may require special service DST tools and surface equipment. All stimulation techniques involve additional risk. Therefore, a detailed stimulation programme should be formulated once any pertinent well information is obtained from the initial unstimulated well test. For tests of normally pressured oil reservoirs drill pipe or tubing can be used.

    These special drill pipe products are available from Mannesmann and from Grant Prideco. Guidelines for use of these products for DST's would be similar to premium tubing, provided proper qualification and inspection is performed. Factors that should be considered in choosing tubulars for a test, include: Circumstances when it is acceptable to use drill pipe are: This applies to all offshore wells and onshore wells in unknown hydrocarbon areas.

    This applies to offshore and onshore wells. This is applicable only to onshore wells in known hydrocarbon areas.

    Conventional drill pipe does not have a gas tight seal except for the 'special gas tight drill pipe' mentioned above and the interference fit of a standard drill pipe connection relies on pipe dope to affect a seal, the dope is quickly removed during gas flow and consequently should not be used for gas tests or high GOR oils where there is likely to be a free gas fraction. Also high GOR oils often have solvent properties, which can attack and dissolve the pipe-dope that seals the drill pipe threads.

    One of these valves may be a downhole tester valve provided it is permanently in place. Thus tools that can be removed from the string during testing are not considered as isolation tools in this context. The other valve will normally be some form of safety valve. On land wells both valves can be in the test tool section of the string.

    On jack-up rigs the second valve should be in the tubing string, the best position being approximately 15 metres below the sea bed. With floating rigs the SSTT sub-surface test tree will normally be the second isolation valve. Tubing retrievable ball valves may be employed as one of the isolation valves on jack-ups and land rigs. However, when mechanically actuated test tools are being used, a TRBV hung in the BOP's is not recommended as it can become caught in the ram pockets while functioning the test tools.

    Note - The two valve isolation requirement is sometimes relaxed, at local operating company discretion, on land operations in areas that are known to be unable to support hydrocarbon flow to surface and for slug or closed chamber testing. Provided the bond logs are satisfactory and sufficient time has elapsed since cementation, the casing and or liner should be pressure tested to a predetermined test pressure.

    If annulus pressure operated testing tools are to be used, the test should establish that the maximum pressure required to actuate the tools usually the SHORT or RD can be contained in the casing - so called 'positive' leak off or casing pressure test. Pressure is applied to the casing or liner either directly from surface or in the case where a liner has been run by setting a retrievable packer on drill pipe above the overlap and applying pressure to the liner via the drill pipe.

    A simple test string consisting of pressure gauges a retrievable packer with a tester valve, reversing valve and collars is run into the well on the drill pipe. The packer is set in the casing above but close to the liner overlap.

    The string is either run in with sufficient cushion so that when the tester valve is opened a predetermined pressure draw-down is applied to the overlap, or an underbalanced fluid is circulated into the string after the packer is set. Normally an inflow test is only required when it is envisaged that a drawdown will be applied to a liner overlap during the test programme. For example, if a well has been completed with 2 liner strings, 5" and 7" and the test programme has been designed such that a 7" packer will be run and set in the 7" liner above the 5" by T overlap.

    Quite obviously then the 5" by 7" overlap will "see" a pressure drawdown during testing, whereas the T by casing overlap will not. In this case it would normally be considered acceptable to only inflow test the 5" by 7" overlap during the preparatory phase.

    Should the bond logs and pressure tests indicate that remedial cementation is required, a separate programme will have to prepared and approved before the work is undertaken. Pressure testing of the casing will have to be repeated and satisfactory results obtained before continuing with the well testing programme.

    It is not always possible to use the above method if the interval between zones is small.

    In this case it is recommended that two bridge plugs be used, rather than relying upon one only. The choices for completion fluid are normally drilling mud or brine. There are a number of factors that must be considered in selecting a completion fluid and these are discussed below. Brines should be used for formations that are sensitive to formation damage by fine solids. Above about All calcium based brines should however be checked for compatibility with the fomiation waters.

    Zinc Bromide. An alternative to Zinc Bromide which does not require HSE dispensation is Cesium Formate, however this is probably the most expensive of all the brine systems currently available. Figure 8. It becomes markedly cheaper to use mud with barite beyond 11 ppg. Table 8. However, many problems have been encountered with water based mud at high temperatures. As the temperature increases the ability of the polymer gels to hold the barite reduces and other gelling agents have to be used, such as bentonite.

    Moreover too much bentonite leads to solidification and if this is not engineered properly it can result in the drop out of the solids and cause a stuck test string. It is recommended that oil based mud be considered at higher temperature conditions in place of water based mud. Recently, however, mud companies have undertaken significant research into high temperature water based systems for environmental reasons and these should be reviewed. Completion Packer Fluids 8.

    If too much barite settles there is a high probability of the packer and lower test string becoming stuck. In these circumstances it is better to use a suitable brine formulation, and to consider the use of a permanent packer and stinger. In some cases sea water has been used, however, this results in very large differential pressures across the well bore packer and possibly the liner lap. If diesel is used it may react with the mud causing barite drop out; in this case the base oil for the mud should be used.

    With brine in the hole, diesel or base oil can be used and there will be no mixing problems. In these circumstances it is normally advisable to use clean filtered brine. For brine it is important that the completion fluid is cleaned or filtered prior to use. There is no point in using expensive brine unless the fluid is filtered to remove debris, which could damage the formation.

    Additionally the pits and rig lines through which the brine will flow must be cleaned and or flushed. Skin will also be reduced by perforating underbalanced by using TCP's or through tubing guns.

    It is therefore important to plan early so that the most suitable equipment will be available when required. This chapter describes the major features of the various perforating techniques that may be considered. However when selecting a large perforating interval for a DST, it may be prudent to leave a space in the middle of the interval, for future workovers or PLT's to determine zonal contribution if the well is to be kept.

    Use 76 9. Metal Strip and Scalloped Tube. However, because of their open design the strip guns can result in perforating debris being produced into the tubing string, which can also occasionally plug up the surface choke. Perforating 11 Scalloped Tube Scalloped guns that may be used during a DST tend to have smaller charges than the comparable strip guns and therefore poorer performance. However, one advantage is that the bulk of the perforating debris is contained within the gun.

    These guns have a 0 degree and degree phasing and performance comparable with most casing guns. Can perforate large intervals underbalanced in one run. Large perforating charges and high shot densities can be used, increasing exposed sand face open to flow. Useful when sand production may cause a problem. Guns can be dropped off after perforating if sufficient rat hole exists and subsequent wireline runs across the perforations may be made e.

    PLT or to add on perforated intervals. TCP charges are often exposed to high bottomhole temperatures for a number of days. Some charges are more resistant to long term high temperature exposure than others. There is a further high temperature explosive type known as PYX, which is not shown in figure 9. In all cases check with the supplier or manufacturer before selecting explosives, particularly in the case of high temperature wells.

    For extreme high temperature wells the gun system may have to be qualified by laboratory tests for the bottom hole temperature and duration of a planned well test. The basic types of firing head commonly available are listed below: This system incorporates a variable time delay mechanism to allow bleeding down of tubing pressure prior to the guns firing. Detonation results from mechanical impact of the bar on the firing head.

    Perforating 79 Electric line firing head - this requires a signal from a wet connect electric line tool to detonate. A robust pressure gauge can be run in association with the wet connect to confirm detonation. Slickline activated firing head - this requires a fishing neck on the firing head to be latched with a slickline tool and jarred up or down to detonate. Slickline conveyed retrievable firing heads - where one of the above firing head types is run in the hole on slickline and latched into a receptor after the guns are on depth and the packer is set.

    In some operations this may provide enhanced safety. It is common to run a hydraulic firing head usually absolute pressure type as the primary mechanism, with a mechanical firing head typically a drop bar as the backup. So called 'dual firing or multiaction systems' allow combinations of firing mechanisms to be run together to provide redundancy, an example of such a system is shown in figure 9. Detonation Interruption Devices: A detonation interruption device DID provides an additional safety measure when using tubing conveyed perforating guns.

    These devices consists of a eutectic metal which is a solid at surface and near surface temperatures preventing pressure from being transmitted to pressure activated firing heads. As the TCP gun is lowered into the well bore and the temperature increases the eutectic metal changes from a solid to a liquid.

    When the guns are on depth pressure may then be transmitted to the firing head. The detonation interruption devices are available in a range of temperature to suit various well bore environments. Live TCP guns should not be brought back through the rotary table if a drop bar becomes stuck in the tubing and cannot be fished.

    In such a case, the guns should be dropped, using tubing severance if required. The delay fuse allows 5 to 7 minutes for adjusting the actuating pressure in the tubing to achieve the desired pressure before firing the guns. The tubing is pressured to the maximum actuating pressure slowly. The maximum pressure shears the pins in the shear set and forces the firing piston into the primer.

    The primer ignites the pyrotechnic delay fuse. For more information, consult your local Halliburton representative. TDF firing head. It is a pressure-actuated firing head with a built-in p rrotechnic fime-delay assembly. This assembly allows the operator to run guns in the hole on the end of tubing without a firing head.

    This assembly can be run in on slickline and attached to the firing head after the tubing is in the hole. It can also be retrieved on slickline. The other side o the firing head may be a bar drop-type head or another pressure-actuated firing head. Either side of the firing head may be used as the primary or backup firing system. For more information, consuk your local Halliburton representative. The text of this chapter has been prepared using the generic names of the various types of downhole test tool.

    This approach has been adopted because of the great diversity of DST tools currently on the market and because the nomenclature used to describe these tools varies from company to company. Furthermore, the specification and usage of such tools is continually changing, so a review of the principals of such tools is considered more appropriate that a detailed review of the specifics. The most recent product specifications should be obtained from the service companies at the start of the well test planning process to augment the principals described here.

    However, the general principals of operation of the various Drill Stem Test DST tools are similar and they function in one of two ways, namely: In each of the following sections an explanation of the usage of the different types of DST tools is given.

    In addition, possible applications for these tools are discussed and some example DST strings have been included. Prior to the first test all drill collars to be used should be drifted, rattled and measured with a steel tape, then put aside. All tubing or drill pipe to be used for the test, including pup joints and crossovers, should be drifted and measured with a steel tape.

    The dimensions of all downhole equipment to be used during the test should be measured and recorded prior to the test. A radioactive pip tag for TCP depth control should be run in the liner or casing and correctly located, above the uppermost test interval taking the position of closed valves, etc.

    The string serves the purpose of providing isolation of three different pressures: See Figure Pressure Recorders Records Pressure vs. Time During DST However, the basic premise of DST string design is; "keep it simple". Start the design with nothing more than a packer and add in those components necessary to meet the test objectives, provide flexibility of operations and meet the safety requirements of the test. DST string design is however a specialist task, as there are many items to be considered such as well control, functionality and flexibility of operations.

    The service companies can usually provide assistance with the design of DST strings. However, some in-house expertise or engineering consultancy services will be required to ensure that the string meets all the possible requirements of the test and complies with the operating oil and gas companies well control procedures.

    At the end of this chapter, the DST tool nomenclature for many of the Schlumberger and Halliburton tools is given. Although other manufacturers and services providers exist, the author considers that providing this information gives a fairly wide coverage of the DST tool market.

    Most standard DST tools are 5" O. Slim hole versions of many of the tools exist, e. Drill Collar 4. Drill Collars S. Drill Collars Riser Tubes D. LINC D. Length TF. T with How-Open 5. Pipe Tester Valve 5. Firing Head 3. Eaprtt Petroleum T echnology Wen: The packer helps to absorb the shock from the perforating guns, which can damage the gauges. Consideration should however be given to the placement of the carriers if run above the packer to ensure they are below any slip joints as movement of the carrier during flow and buildup may invalidate the data.

    However, when testing with a permanent packer with a floating seal assembly there is no option other than to have the gauges floating if they are to be positioned above the packer. Although consideration could be given to a ratch latch system if carrier movement is deemed to be critical to the acquisition of quality data.

    Below packer gauges carriers are acceptable when there are no TCP guns and their position is fixed because of the packer, even if slip joints are used. However, it would be prudent to include a carrier above the packer in case the packer becomes stuck. Below packer carriers can normally only be run with retrievable packers. The gauge caiTier pressure rating should be checked prior to use because there are many types available on the market with different ratings.

    They should also be drifted prior to use as they often have the smallest internal diameter in the test string and sometimes the bore is eccentric. Additionally the effective outside diameter of the carrier on rotation will have to be considered for offset carriers, if there is a requirement to rotate the string e. Gauge carriers are sometimes prone to pressure leaks at the seal between the gauge and the gauge carrier. For this reason they should be pressure tested with the gauges installed on surface before running them in the hole.

    The shorter length newer gauge carriers should be run in preference to the longer ones, as the shorter ones are easier to handle on the rig. The sub prevents solids gathering around the firing heads when running in the hole and carrying out pressure tests. The brittle barrier in the debris sub is broken by a drop bar or on contact with wireline tools.

    This may increase the area available to flow and will allow access to the perforated interval with wireline tools. There are a number of gun release types available, such as outo release or mechanical release.

    The requirements for gun release will be dictated by the anticipated forward programme for the well test. However, a gun release sub should only be run if sufficient rat hole is available below the perforated interval to accommodate the full length of the dropped items. The lateral and vertical shock absorbers will reduce the transmission of mechanical shock energy to the downhole gauges at the time of perforating.

    The use of a shock absorber is particularly important if high accuracy quartz gauges are being used as these are more prone to shock failure that strain gauges or sapphire gauges. When perforating long intervals damage to the packer may also occur if shock absorbers are not run. In addition, there have been a few isolated cases where the shock from TCP guns have caused single shot rupture disc tools to fail also.

    The perforated joint allows the entry of hydrocarbons into the tubing string but will also filter out any large debris. Certain debris subs also have long slot ports which have an effective flow area greater than that of the tubing string and these can be used instead of a perforated joint. Where there are open perforations and pressure activated TCP guns are being used the perforated joint may be substituted by a production valve. Downhole Test Equipment In this case the packer rubber is extruded to seal against the formation by slacking off the required amount of drillstring weight onto the packer.

    Open Hole Inflatable For zones where permeable formations are indicated above and below the zone of interest packers must be set to isolate both of these zones from the zone to be tested.

    This is typically achieved by using inflatable type packers in the test string. These packers are typically inflated by wellbore fluids using a pump located on top of the packer assemblies.

    This pump is run by rotating the drillstring at surface at a critical speed for a certain period of time. Cased Hole Retrievable These differ from open hole packers in that sets of slips are located above and below the sealing elements.

    The slips allow all the string weight to be slackened off on to the packer and the load is transmitted to the casing, drill collars are used for additional weight. Depending on the make of packer it may be possible to set, pull and reset the packer several times before retrieving the packer and redressing it at surface. Cased hole retrievable packers are usually available with full bore thus allowing access for wireline and electric line tools.

    Newer packers include a hydraulic hold down device designed to automatically activate whenever tubing pressure exceeds annulus pressure. When this occurs the hold down buttons are pushed out against the casing wall by the differential pressure created.

    Permanent During DST's permanent packers with seal bore extensions are normally used in higher pressure or sour well environments. This book covers all the major operational aspects of oil and gas well testing. It uses a structured approach to guide the reader through the various steps that are required to effectively plan and implement a well test operation under just about any circumstances worldwide onshore or offshore.

    Journal of Canadian Petroleum Technology. He gained his initial oil industry experience while employed with major oil industry service companies. He also worked as a staff Petroleum and Reservoir Engineer with operating oil companies and has extensive experience in the planning and supervision of wellsite operations including testing, well services and completions; he held the post of Senior and Chief Petroleum Engineer for various oil companies in the UK and overseas.

    In addition to his engineering skills, Stuart McAleese has significant management experience in operations and in the board room.

    His commercial skills have been brought to bear in licence negotiations with Oil and Gas Ministers and he has undertaken due diligence work for the stock market. He graduated in with an honours degree in Applied Physics from the University of Strathclyde, Scotland.

    Currently he is an independent consultant for Esprit Petroleum Technology Ltd. We are always looking for ways to improve customer experience on Elsevier.

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    Thanks in advance for your time. Skip to content. Search for books, journals or webpages All Webpages Books Journals. View on ScienceDirect. Hardcover ISBN: Elsevier Science. Published Date: Page Count: View all volumes in this series: Handbook of Petroleum Exploration and Production. Sorry, this product is currently out of stock. Flexible - Read on multiple operating systems and devices. Easily read eBooks on smart phones, computers, or any eBook readers, including Kindle.

    When you read an eBook on VitalSource Bookshelf, enjoy such features as: Access online or offline, on mobile or desktop devices Bookmarks, highlights and notes sync across all your devices Smart study tools such as note sharing and subscription, review mode, and Microsoft OneNote integration Search and navigate content across your entire Bookshelf library Interactive notebook and read-aloud functionality Look up additional information online by highlighting a word or phrase.

    Institutional Subscription. Free Shipping Free global shipping No minimum order. Perforating equipment, drill stem test equipment and bottom hole pressure gauges are discussed in detail in the book. There is also a very valuable section on sub sea equipment, an area often not well understood even by experienced engineers who may have been primarily involved with land or jackup rigs.

    It also covers operational and testing related problems such as, hydrates, wax and sand, and offers the reader some possible solutions. English Copyright:


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