Interval Pressure Transient Testing Research Articles

Technology Focus: Well Testing (February 2024)

Standing alone as the shortest month of the year, February also features JPT’s Well Testing Technology Focus, reviewing the latest industry publications on the subject. Well testing has enjoyed a recent uptick in activity and interest as operators continually realize the value in understanding and monitoring the dynamic performance of their reservoirs. Whether it pertains to the deliverability of conventional oil and gas or the storage potential for carbon capture and storage, large-scale dynamic data remains one of the more coveted pieces to the subsurface puzzle. There is no silver bullet for reservoir characterization. Instead, proper characterization will always be the result of integrating static and dynamic data, collected at varying scales, with a macro geological understanding. Technology facilitates the collection of the aforementioned data. With the latest technologies pushing limits of what can be achieved, subsurface engineers must rigorously evaluate what reservoir characterization techniques and tools are suited for project objectives. Formation testing (FT) platforms provide many options for operators to get a first look at dynamic reservoir performance and nearly always precede a well test. After digesting the alphabet soup of acronyms, so many FT options exist that one may encounter what psychologists refer to as “choice overload.” FT objectives also may begin to overlap with objectives traditionally reserved for drillstem tests (DSTs), narrowing a long-standing technology gap. The current advances in FT tools are exciting, and using FT tools to perform a “mini-DST” makes for brilliant marketing. However, “mini” could mean up to 10,000 times less produced volume, which undoubtedly affects objectives thought to overlap. Subsurface complexity is mitigated by defining clear objectives and executing data-collection programs to reduce uncertainty. Caution should be taken in selecting how to dynamically test your reservoirs. Regardless of how advanced hardware becomes, achievable objectives always will be dependent on key factors such as rock and fluid properties, reservoir geometry, and local regulatory and environmental considerations. This month’s papers highlight ongoing developments from different segments of the well-testing discipline. Dive into valuable lessons learned from a frontier carbon capture, use, and storage project, backed by an impressively sized data set and an in‑depth review of multiphase effects. This case study covers differing saturations around the wellbore region and fluid types in operations and should have global applications. Learn about the limitations and potential pitfalls of nonisothermal effects in pressure transient analysis, which pose challenges in the reservoir characterization of geothermal wells. Sensitivities to thermal effects on reservoir rock properties provide intriguing insights. Completion efficiency also may be affected by thermal effects, resulting in additional pressure drop at sandface. Finally, catch up on one of the weapons most recently added to the well-testing arsenal with powerful new FT tools that feature industry improvements for greater flexibility and improved data reliability. Recommended additional reading at OnePetro: www.onepetro.org. OTC 32610 Multiphase Flowmeter Comparison in a Complex Field by Mohammed Alqahtani, Saudi Aramco, et al. IPTC 23050 Frequently Asked Questions in the Interval Pressure Transient Test and What Is Next With Deep Transient Test by Saifon Daungkaew, SLB, et al.

Dynamic Simulation Platform Aids Deep Transient Tests, Well-Control Safety

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, “Enhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,” by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed. _ The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented. DTT DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals. In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall. A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.

Technology Focus: Well Testing (February 2022)

Bias is always a factor in decision making. To put it a catchier way, “if you have a brain, you are biased.” This was the opening to a recent soft-skills training course I took on the science of better decision making. I left pondering the implications of bias on pressure transient analysis. Well tests are conducted throughout the resource life cycle to establish well and reservoir properties and to optimize depletion planning. But this requires well-test interpretation, which, in turn, requires choosing among nonunique solutions. One key to reducing nonuniqueness is to integrate pressure data with information from other disciplines, including - Routine core analysis, core description, and well logs - Formation-tester mobilities and interval pressure transient tests - Production logging and distributed temperature surveys - Fieldwide production and injection history - Seismic data and geologic understanding This is where technology comes in. New tools have made the unmeasureable measurable and have provided data in larger quantities with improved precision and for longer periods of time. While it may be an engineer’s dream, more and better data do not necessarily lead to better decisions. As with any sound scientific or engineering study, one must think about bias. Is the data being unconsciously cherry-picked to mold the desired outcome? After all, the subsurface is complex enough that multiple assumptions and hypotheses remain plausible; not all information may fit the storyline, and some might be dismissed or underweighted before the full range of possibilities is considered. A critical component of interpretation includes acknowledging one’s own bias and carefully listening to and seriously considering alternative and opposing views. Cold-eyes reviews and devil’s advocates are part of a centuries-old toolkit proven to root out bias, ambiguity, and unnecessary complexity, leading to better-defined problems and, ultimately, better decision making. Interpreting data from new and well-established technologies under the framework of the Socratic method paves the way to a clearer view of the subsurface. This month’s papers demonstrate the continued relevance and diversity of our discipline. The ambitious permeability log, referred to as “elusive” in my column 2 years ago, now boasts a tangible pilot in a Middle Eastern carbonate field. Well tests and cleanup operations do not always require flaring. Alternative fluid-disposal solutions, tailored to project specifics, show potential to meet the timely topic of emissions. Machine learning offers a key to deciphering well connectivity in field data, overcoming noise and other suboptimal conditions. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 21780 - Design and Implementation of a Water-Based Micronized Weighting Agent Fluid System for Deepwater Drillstem Testing Operation in Environmentally Restricted Location by Marcelo Dourado Motta, MI-SWACO, a Schlumberger Company, et al. SPE 205145 - Systematic Application of Pressure and Temperature Transient Analysis in an Oil Field: A Case Study by Khafiz Muradov, Heriot-Watt University, et al.

Insights From Interval Pressure Transient Tests Derive Key Fracture Parameters

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195435, “Macro Insights From Interval Pressure Transient Tests: Deriving Key Near-Wellbore Fracture Parameters in a Light-Oil Reservoir Offshore Norway,” by Alfredo Freites, SPE, Patrick Corbett, SPE, and Sebastian Geiger, SPE, Heriot-Watt University, et al., prepared for presentation at SPE Europec featured at the 81st EAGE Conference and Exhibition held in London, 3–6 June 2019. The complete paper describes the shortcomings of traditional well testing methods and the methodology and results of applying wireline-conveyed IPTT in a light-oil reservoir offshore Norway. The study focuses on cases in which fractures are present in the near-wellbore region but do not intersect the wellbore. The study included parameters such as fracture densities and conductivities, distance between fractures and wellbore, and the vertical extension of the fractures across geological beds. Introduction Fractures can be first-order controls on fluid flow in hydrocarbon reservoirs. Understanding fracture characteristics such as aperture, density, distribution, conductivity, and connectivity is key for reservoir engineering and production analysis. Well testing plays a key role in fracture characterization, particularly in fractured reservoirs. New advances in pressure transient analysis (PTA) have enabled the interpretation of production data such that the resulting geological scenarios are in better agreement with fracture patterns observed in out-crop analogs. Traditionally, drillstem-test (DST) data have been the primary source of information for well testing. However, the authors hypothesized that wireline-conveyed tools designed for interval pressure transient testing (IPTT) could yield a more-thorough description of near-wellbore heterogeneities, including fractures. To prove their hypothesis, they used a next-generation wireline testing tool to investigate the applicability of IPTT for characterizing fractured reservoirs, using detailed numerical simulations models with ac-curate wellbore representation to generate synthetic IPTT responses. The effect of the different fracture scenarios on the pressure transient tests was recorded as characteristic signatures on diagnostic plots, which the authors call IPTT-geotypes because they can be used to assist the interpretation of IPTT responses. The paper includes a field example of an IPTT case that was analyzed using the concept of geological well testing. Information from petrophysical logs and the IPTT-geotypes was integrated to assist the calibration of a reservoir model developed to represent the geological setting of the tested reservoir interval. The results provided a sound interpretation of the reservoir geology and quantitative estimation of the matrix and fracture parameters. IPTT Methodology Static characterization of fracture systems, which can be key controls on reservoir performance, rely on analog outcrop observations, seismic, image logs, and core analysis. Direct observations in cores; image logs; a sudden increase in mud filtration during drilling; and, at later stages, substantial differences between the wells’ expected and real productivity indices are all indicators of the presence of fractures in a reservoir. Well testing provides the means for dynamic characterization and is an area that has shown significant progress in recent years. The industry standard model for well test interpretation in naturally fractured reservoirs (NFRs) was developed in 1963. This model assumes a geometrically idealized system where flow occurs only in the fractures, which have uniform properties, while the matrix is stagnant and only recharges the fractures. Such a system normally does not represent real fracture networks. Features such as fracture geometry, density, and connectivity cannot be derived from the purely mathematical description.

Technology Focus: Well Testing (February 2020)

Technology Focus In my inaugural column as editor of the Well Testing Technology Focus feature, I want to shine a light on the notable trend among operators of seizing on the tremendous untapped potential that exploration and appraisal wells represent for far-field reservoir characterization and connectivity. The concept is straightforward. Upon reaching total depth and running a suite of logs and tools (which may or may not include a well test), gauges are installed as part of the plug-and-abandonment phase, thus turning an otherwise throw-away reservoir penetration into a long-term observation well. Brilliant! The gauges communicate wirelessly by electromagnetic telemetry, cleverly capitalizing on the well’s casing. Well tests conducted elsewhere in the field then can be monitored from these gauges, thereby providing valuable insight into reservoir connectivity, interwell average properties to further calibrate geologic/reservoir models, and in-place resources (or at least a minimum connected volume). This is not new; however, the technology has become more powerful and reliable, now lasting longer and withstanding more-challenging environments. Fast forward to 2020. These systems are remarkably seamless add-ons to an exploration well design. The advances epitomize the virtuous circle of service company research and development tailored to meet the needs of operators, who, in turn, test these systems and help build a track record. Issues and failures are part of the game of innovative technologies, improving robustness and adding features, job after job. The value proposition is undoubtedly appealing. The marketing around it is compelling but rarely dwells on the implications of installing such systems. What will it take to yield a conclusive test? Two common pitfalls are the false negative and false positive. The former misleadingly suggests no connectivity when the signal is merely not strong enough or is not given enough time. With the latter, an unrelated response is misconstrued for evidence of connectivity. Successfully designing and interpreting an interference test amid subsurface unknowns, tidal effects, and gauge drift, to name but a few, remains an engineering feat. While compartmentalization is often flagged as an uncertainty in field-depletion plans (and as a fatal flaw in some instances), only after start-up is its severity revealed—for example, production falling off plateau early or producer/ injector pair not in communication. Early dynamic data collection from well tests paired with such long-term systems may help minimize or circumvent this altogether. This enabling technology truly gives a whole new meaning to “data wells.” This month’s feature illustrates the vitality of our discipline. Deconvolution is being extended to multiwell applications, opening the door to its use in production. Temperature is measured continuously from top to bottom of a test interval to determine zonal contribution over time, sans production logging intervention. Interval pressure transient tests are used for the consistent characterization of fractured carbonates. The diversity of original concepts and technologies is a reminder that well testing is far more than just pressure transient analysis. Check out as well the additional-reading suggestions. Take a look back with a service company’s review of 40 years of operational best practices. Peruse an operator’s case study taking a formation tester to new limits. Look ahead to the elusive permeability log from an audacious joint industry project. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 19369 Innovative Mini-DST and Production-Evaluation Approach at Challenging HP/HT Conditions for the KeShen Tight Gas Reservoir: A Case Study at Tarim Basin by Shichen Shuai, PetroChina, et al. SPE 193195 Successful Well-Test Operations in Complex Reservoir Fluids: Lessons Learned and Best Practices Over 40 Years of Worldwide Operations by Yakov Shumakov, Schlumberger, et al. SPE 196116 Permeability Logging Through Constant Pressure Injection Test: In-Situ Methodology and Laboratory Tests by Sivaprasath Manivannan, Ecole Polytechnique, et al.

Fertility Preference Inversely Related to ‘Legacy Drive’ in Women, But Not in Men: Interpreting the Evolutionary

This paper used finite element method to simulate the pressure response of wireline formation tester applied in fractured reservoir. At first, the interval pressure transient tests (IPTT) are used to test the pressure response for both crossing well bore and non-crossing fractures in low permeability formation. The simulation results indicate that the fractures crossing the well bore can have dramatic effect on pressure response depending on fractures conductivity, but non-crossing fractures in the vicinity of the well bore have negligible effect. Then the paper used numerical simulation to analyze the feasibility that evaluates the fractures non-crossed well bore with the method of harmonic pulse testing, the results indicate both harmonic amplitude and phase shift are sensitive to the conductivity of fractures in the vicinity of well bore and certify the method can be used to evaluate the fractures efficiently.

A Novel Infinite-Acting-Radial-Flow Analysis Procedure for Estimating Permeability Anisotropy From an Observation-Probe Pressure Response at a Vertical, Horizontal, or Inclined Wellbore

Summary This paper presents a new infinite-acting-radial-flow (IARF) analysis procedure for estimating horizontal and vertical permeability solely from pressure-transient data acquired at an observation probe during an interval pressure-transient test (IPTT) conducted with a single-probe, dual-probe, or dual-packer module. The procedure is based on new infinite-acting-radial-flow equations that apply for all inclination angles of the wellbore in a single-layer, 3D anisotropic, homogeneous porous medium. The equations for 2D anisotropic cases are also presented and are derived from the general equations given for the 3D anisotropic case. It is shown that the radial-flow equation presented reduces to Prats' (1970) equation assuming infinite-acting radial flow at an observation point along a vertical wellbore in isotropic or 2D anisotropic formations of finite bed thickness. The applicability of the analysis procedure is demonstrated by considering synthetic and field packer/probe IPTT data. The synthetic IPTT examples include horizontal- and slanted-well cases, but the field IPTT is for a vertical well. The results indicate that the procedure provides reliable estimates of horizontal and vertical permeability solely from observation-probe pressure data during radial flow for vertical, horizontal, and inclined wellbores. Most importantly, the analysis does not require that both spherical and radial flow prevail at the observation probe during the test.

Pressure-Pressure Deconvolution Analysis of Multiwell-Interference and Interval-Pressure-Transient Tests

Summary This paper investigates the use of pressure-pressure (p-p) deconvolution for interpretation of conventional multiwall-interference and wireline-formation-tester (WFT) interval pressure-transient tests (IPTTs). The investigation is limited to interference tests for which only a single source/sink well exists in a single-layer system. It is shown that the recent deconvolution algorithms developed for pressure-rate (p-r) deconvolution based on the same assumptions (i.e., a single source/ sink well) can also be used for performing p-p deconvolution by simply replacing the rate data in p-r deconvolution algorithms by the pressure data recorded at a source/sink location or at one of the observation locations. We apply p-p deconvolution to both synthetic and field-transient test data sets from IPTTs and multiwall-interference tests. Specifically, we investigate the applicability of p-p deconvolution for inconsistent data sets, where wellbore storage and skin may change from one flow period to another one. The results show that the impulse functions deconvolved from p-p deconvolution have signatures for various flow regimes (e.g., radial, spherical, linear) that are similar to from p-r deconvolution except from the pseudosteady-state (pss)-flow regime. Therefore, p-p deconvolution can also be used for model identification in the similar way based on p-r deconvolution algorithms, without requiring the flow-rate information.

Estimating Thickness-Independent Horizontal and Vertical Permeabilities With Packer/Probe Wireline Formation Testers

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13912, ’A Novel Analysis Procedure for Estimating Thickness- Independent Horizontal and Vertical Permeabilities From Pressure Data at an Observation Probe Acquired by Packer/ Probe Wireline Forma tion Testers,’ by M. Onur, SPE, Istanbul Technical University, and P.S. Hegeman, SPE, I.M. Gok, SPE, and F.J. Kuchuk, SPE, Schlumberger, pre pared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. The paper has not been peer reviewed. A spherical-flow cubic-analysis procedure has been developed for estimating horizontal and vertical permeabilities, kvh and kv, respectively, solely from pressure-transient data acquired at an observation probe of a dual-packer/probe wireline formation tester (WFT) for any wellbore-inclination angle. The procedure is based on an analytical spherical-flow equation and a conventional spherical-flow-analysis graph of the observed drawdown or build-up pressures. The procedure does not require knowledge of the formation thickness, h, or observing the radial-flow regime at the probe. Introduction Over the last 4 decades, wireline formation testing has become widely accepted for reservoir-pressure pro-filing, fluid sampling and identification, interval-pressure-transient tests (IPTTs), and in-situ stress testing. IPTTs conducted with packer/probe formation testers provide dynamic permeability and anisotropy information with high vertical resolution along the wellbore. Permeability is one of the most important parameters in reservoir management and well performance. Permeability and permeability anisotropy (kv /kh ratio) strongly affect all reservoir-displacement processes. Thus, it is increasingly important to determine these values as operators shift their focus from primary recovery to secondary and tertiary recovery. Fig. 1 shows a schematic of a packer/probe interference test (usually referred to as an IPTT) in a deviated well in an anisotropic formation that is bounded vertically and is laterally infinite. The schematic represents a general configuration that is valid for all inclination angles, θw, of the well-bore. For instance, if θw=0°, the IPTT is considered conducted in a vertical well, whereas if θw=90°, the IPTT is considered conducted in a horizontal well. In these tests, a dual packer is set against the formation to serve as a flow source. The pressure transients are measured at both the packer interval and the observation probe. Any pressure change at the observation probe caused by flow from the packer interval clearly indicates communication within the formation between the two locations. Interpretation of packer and probe data provides permeability values in both the vertical and horizontal direction. Furthermore, the near-wellbore heterogeneity can be characterized from IPTTs. Interpretation of packer/probe IPTT data begins with an independent analysis of each pressure data set. The first step is to identify the flow regimes on the basis of conventional pressure-derivative analysis. Then, initial estimates of parameters such as spherical and horizontal permeabilities are obtained from special straight-line (semilog and spherical) analyses based on flow regimes identified from the log-log diagnostic graphs of the draw-down/buildup and/or deconvolved responses. Construction of a formation model from existing openhole-log data is essential for the interpretation. Log data provide porosity and rock compressibility, while fluid analysis provides fluid compressibility and viscosity. All available data (including log, core, and pretests) are used for parameter initialization of the formation model before nonlinear-regression analysis. Then nonlinear-regression analysis is performed to optimize the key parameters such as horizontal and vertical permeabilities, skin, and wellbore- or tool-storage coefficient. The final step of the analysis involves verification and sensitivity analyses of the history matches of the pressure data.

A New Pressure/Rate-Deconvolution Algorithm To Analyze Wireline-Formation-Tester and Well-Test Data

Summary Reconstructing constant-rate drawdown-pressure response and its logarithmic time (or Bourdet) derivative by deconvolution from multirate pressure-transient data is very important for wellbore-/ reservoir-system identification and interpretation. In recent years, the use of pressure/rate deconvolution has increased considerably because of significant improvement of the algorithms. In this paper, we present a new deconvolution algorithm based on a weighted Euclidean norm in the Tikhonov (1963) regularized objective function so that one can assign weights to individual pressure- and rate-measurement points, and, thus, define different error estimates for different sections of the data. Incorporating such features into the deconvolution algorithm is very useful to mitigate the effects of unreliable pressure and rate measurements and the sections of the data not obviously consistent with the wellbore/reservoir model. We present two applications of the new algorithm using real field pressure/rate transient data sets. In addition to conventional drillstem-test (DST) well-test data, we apply the algorithm to wireline formation-tester (WFT) pressure transients, which are usually also referred to as interval pressure-transient tests (IPTTs). The results show that the new deconvolution algorithm presented in this paper is useful in interpreting pressure/rate transient data from both formation and well tests.

The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testing—Case Studies

Summary Modern wireline formation testers (WFTs) are able to collect a massive amount of data at multiple depths, thus helping to quantify changes in rock and fluid properties along the wellbore, to define hydraulic flow units, and to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility profiling vs. depth, fluid sampling, downhole fluid analysis (DFA), interval pressure-transient testing (IPTT), and microfracturing. Because of the complex tool strings and the elaborate operational aspects involved in wireline formation testing, success requires detailed upfront planning and procedural design as well as real-time operational and interpretational support. It is becoming increasingly critical for operating and service company experts to remotely monitor and interpret WFT surveys in real time through Web-based systems. The importance of meeting all rock and fluid data-acquisition objectives cannot be overstated, given the high cost of offshore operations and the implications of obtaining false or misleading information. The main objective of real-time monitoring remains to assure that the planned data are acquired according to pre-established procedures and contingency plans. However, even in developed reservoirs, unexpected circumstances arise, requiring immediate response and modifications to the preplanned job procedures. Unexpectedly low or high mobilities, probe plugging, unanticipated fluid types, the presence of multiple phases, and excessive fluid contamination are but a few examples of such circumstances that would require real-time decision making and procedural modifications. Real-time decisions may include acquiring more pressure data points, extending sampling depths to several zones, extending or shortening sampling times, and repeating microhydraulic fracture reopening/closure cycles, as well as real-time permeability, composition, or anisotropy interpretation to determine optimum transient durations. This paper describes several examples of formation tester surveys that have been remotely monitored in real time to ensure that all WFT evaluation objectives are met. The power of real-time monitoring and interpretation will be illustrated through these case studies.

Estimating permeability distribution from 3D interval pressure transient tests

In this paper, the basic features of 3D (spatially r and z and time) interval pressure transient testing (IPTT) are described for the estimation of horizontal and vertical permeabilities and delineation of fracture and fault conductivities using the packer module and observation probe tool combination of the multiprobe wireline formation tester. Mathematical models for the pressure behavior of IPTT tests for using the packer module and the observation probes in multilayer (stratified) formations are presented. The maximum likelihood (ML) method is presented for nonlinear parameter estimation to handle uncertainty in error variances (weights) in observed data. The main advantage of the ML method over the traditional weighted least squares (WLS) is that it eliminates the trial-and-error procedure required to determine appropriate weights to be used in the WLS estimation. As shown by the examples presented in the paper, the ML method provides significant improvement in parameter estimation when working with pressure data sets of disparate orders of magnitude and noise, e.g., pressure measurements for the packer–probe and multiprobe interval tests. A field example where eight IPTT tests were conducted in a major carbonate formation is presented for characterization of vertical and horizontal layer permeabilities and vertical communication through the main producing reservoir section. These IPTT tests were conducted with a Formation Tester Dual Straddle Packer and two Probe Modules in a newly drilled well. An IPTT test at each location was interpreted using an appropriate geological model with the packer and probe pressure and flow rate measurements. The interpretation procedure consisted of identification of the different flow regimes followed by history (type curve) matching for the estimation of vertical and horizontal permeabilities for each layer. A detailed interpretation of two of the interval pressure transient tests is presented.

Detailed analysis of probe permeameter and interval pressure transient test permeability measurements in a heterogeneous reservoir

The goal of reservoir characterization is to generate models that allow the accurate prediction of future well performance and the estimation of reserves. Of particular importance to the characterization of permeability heterogeneity is an accurate understanding of vertical flow behaviour in a reservoir. Upscaling techniques applied to conventional core plug and probe permeameter permeability anisotropy are compared with Interval Pressure Transient Tests (IPTT) conducted with multiprobe formation testers. The aim is to investigate the scale of the dynamic permeability measurement and review the representivity of the IPTT estimate in a field example. We illustrate improvement in permeability anisotropy estimation by a combination of dynamic measurements with static measurements. Further to this, we consider the permeability prediction from continuous downhole measurement. High-resolution measurements such as probe permeametry data and borehole imaging can produce the most complete data coverage at the well and have similar measurement scales. Predicted permeabilities are compared with IPTT results by upscaling to a length scale appropriate to the IPTT and the geometry of the formation.

Interval Pressure Transient Testing With MDT Packer-Probe Module in Horizontal Wells

Summary In this paper, the use of various pressure measurements is investigated for determining formation pressure and permeability distributions by use of the multiprobe formation testing packer and probe modules (PPM's) in horizontal wells. It is shown that reservoir pressure measurements along the wellbore give local and reservoir-scale information about how the reservoir is being depleted and how cleanup takes place. The estimation of horizontal and vertical permeabilities, skin, and reservoir pressure along the wellbore is also presented by use of interval (local) pressure transient tests. For PPM in horizontal wells, an interpretation method is presented for determining the reservoir parameters. A few interval pressure transient test (IPTT) examples are presented for formation pressure and permeability distributions, and fluid sampling.