Pressure Transient Tests Research Articles

Estimation of upcoming problems in Alaşehir geothermal field using a numerical reservoir model

Alasehir geothermal area located in Alasehir Graben, West Anatolia, is the latest target for geothermal field development in Turkey. Seven different operators are developing the power capacity in this geothermal field on a strictly competitive and largely confidential basis without the significant exchange of resource information among them. Currently, eleven binary and combined flash-binary geothermal power plants with widely changing power generation efficiency between plants produce from the same reservoir. In order to identify upcoming problems for the complex and aggressive geothermal exploitation in Alasehir Geothermal Field, a highly populated numerical reservoir model was developed in TOUGH2 using different data sources such as geology, geophysics, pressure transient tests, tracer test, and geochemistry. The real-time power data are retrieved from the transparency platform of the Turkish energy exchange. The geothermal fluid is withdrawn from the field at a total production rate of 12,600 tons per hour. There are more than 100 wells in the field. The flow rate and wellhead flowing pressure of wells in the field central are used for calibration. The flow rate of wells changes between 100 and 450 tons per hour. The numerical model results are compared with a Monte Carlo simulation results in the field. Numerical reservoir simulation showed that more than 270 MWe production is not supported by artesian flow which is in agreement with Monte Carlo simulation results. The pressure decline of the field was found 3 bar per year. Using this model, power supply capability of the field is discussed considering economic and physical reliability. The best solution for maximizing energy exploitation from the field was found to produce with unitized reservoir management.

Injectivity index: a powerful tool for characterizing CO2 storage reservoirs—a technical note

AbstractInjectivity index is a powerful tool that can be easily calculated from field injection and pressure data. Theoretically, injectivity index is linked to reservoir properties such as permeability, thickness of pay, and size of the reservoir. Consequently, injectivity index data can serve as a powerful tool to assess changes in reservoir quality and performance. In this article, we have looked at field data from notable global carbon sequestration projects in order to identify a correlation between injectivity index (J) and the product of reservoir permeability and thickness (kh). Results suggested that there is a linear relationship between J and kh with field data confirming to lower and upper bounds of J = 0.03×kh and J = 0.23×kh respectively. Average trend was calculated to be J = 0.08×kh. This correlative approach can be extremely beneficial when there is a need to estimate pressure buildup corresponding to a target injection or vice versa. The approach can also be used to understand reservoir flowability and performance at a broader scale prior to the need for expensive or time consuming flow and pressure transient testing. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Identification and characterization of a proper gel system for large-volume conformance control treatments in a fractured tight reservoir: From lab to field

The existence of fractures in petroleum reservoirs can greatly reduce the sweep efficiency and subsequently limit the oil recovery during water flooding. Gel treatment is widely known as a cost-effective method for conformance control and water shutoff during water flooding in fractured reservoirs. In this study, we discuss the feasibility of three types of gel systems for conformance control in fractured reservoirs, aiming to select a proper one for field pilot applications in Huabei oilfield (China). Based on the gelation time and the gel strength, the water-soluble phenolic resin (WSPR) gel was chosen for field applications. This silica nanoparticle strengthened WSPR gel demonstrated high gel strength and long-term thermal stability in the lab. Furthermore, its plugging capability was studied by determining the rupture pressure of the gel-filled tubes. The results indicate that the plugging ability of WSPR gel is enhanced with increasing the polymer concentrations and decreasing the size of apertures. Besides, the WSPR gel exhibits high rupture pressure under low brine injection rate. For field applications, the pressure transient tests, tracer tests and the injection-production data were used collaboratively to determine the volume of the fractures in the reservoir. A large volume of gelant was designed for well treatment, and multiple gel slugs with different polymer concentrations were tailored to meet the operational conditions. After the gel treatments, the bottom hole pressure for each injector was significantly increased, indicating that the fractures were effectively plugged. Moreover, the oil production rates were notably increased, accompanied by a prominent decrease in water cut after the gel treatment. To date, the oil production rates of two well-connected production wells, HH55P56 and HH55P58, have been increased from 0.36 t/d to 0.9 t/d and from 0.19 t/d to 0.48 t/d, respectively. The oil production rate of well HH55P24 has been increased by 0.5 t/d.

A new method for evaluating the unstable deliverability of gas wells in gas formation testing phase

Predicting the deliverability change laws of a gas well in the early stage is one of the technical difficulties in natural gas development. The commonly used steady seepage analysis methods have relatively large errors. And this problem cannot be solved effectively by the classical methods of production decline analysis and pressure transient well test analysis. To solve this problem, this paper did calculation based on the well test model of constant-pressure production, changed the previous approximate method of simplifying the calculation of the exponential integral function, and accurately calculated the analytical solution of absolute open flow potential of a gas well. In addition, the deliverability instability characteristics of different types of gas wells were quantitatively described by taking vertical wells in homogeneous reservoirs as the reference benchmark. Then, combined with the deliverability evaluation needs of a new well, a new practical method focusing on solving the problems of gas formation testing analysis was researched and developed, and also applied on site at some key wells in the hot spots of natural gas development in the Sichuan Basin. And the following research results were obtained. First, the accurate formula for the analytical solution of well test model significantly enhances the adaptability to short-term test conditions. Second, the newly established chart briefly reveals the quantitative relationship between the unstable deliverability characteristics of a gas well and the main influencing factors. Third, if the characteristic parameter of turbulence effect is unknown, it is necessary to perform iterative calculation of the variable skin factor when the well test model of constant-pressure production is used to analyze the change trend of the absolute open flow potential of a gas well. Fourth, by conducting comparative analysis on the calculation results of typical cases, the decline laws of the absolute open flow potential of different types of gas wells can be understood further. It is concluded that this new method is capable of improving the prediction accuracy of the unstable deliverability of gas wells. Therefore, it can be widely applied to the deliverability evaluation of gas wells in the exploration stage, the evaluation stage of early development and the commissioning stage of new development and production wells, which is conducive to the formulation of natural gas exploration and development decision.

Fast permeability measurements of tight and sorptive gas reservoirs using a radial-flow transient technique

The pressure transient technique has been widely used for laboratory tests on unconventional gas reservoirs; however, it is still a time-consuming process when applying this technique to rocks of ultra-low permeability in the nano-Darcy scale. The applicability of a novel radial-flow transient technique to achieve fast and accurate permeability measurements is verified by an experimental investigation in this study. Pressure transient tests were performed on two hollow cylindrical shale specimens with different inner radii under radially convergent flow conditions; and for comparison, a solid shale core was also tested via an axial-flow transient technique. The results showed that the time required for a complete pressure pulse decay by the radial-flow test is within several hours compared to a few days by the axial-flow test. It was also found that non-uniform stress distribution along the radius of the sample is the principle factor resulting in errors in the measured permeability; and thus, samples with a small inner radius should be used to reduce the error in the measured permeability. In addition, analytical solutions are derived to interpret the lab data for permeability determination. The accuracy of the proposed technique is elucidated by the small permeability difference of less than 15% compared to the axial flow tests. The permeability error analysis indicated that the effect of compressive storage and gas sorption can be eliminated, and the error is less than 6.7% even though two large pressure pulses of 0.5 MPa were generated. The study experimentally validates that fast and accurate permeability measurements can be achieved by adopting the proposed radial-flow transient technique.

Semi-analytical modeling of transient rate behaviour of a horizontal well with multistage fractures in tight formations considering stress-sensitive effect

Stress-sensitive permeability imposes a significant impact on production performance in a tight formation; however, the widely used models assume the constant permeability or same stress-sensitive level for different systems, resulting in incorrect prediction of production rate and reservoir properties. In this work, theoretical models have been formulated, validated, and used to characterize the transient rate behaviour of a horizontal well with multistage fractures at constant wellbore pressure in tight formations by taking the different stress-sensitive effects in matrix and fracture subsystems into account. More specifically, a matrix-fracture fluid flow model with considering stress-sensitive effect was developed, during which the resulting nonlinear governing equation caused by stress-sensitive matrix permeability was weakened and linearized by using the Pedrosa's transform formulation and perturbation technique, respectively. Then, a slab source function was developed to obtain the solution for such a linearized problem in the Laplace domain. Meanwhile, a semi-analytical method is applied to solve the matrix-fracture flow models by discretizing each hydraulic fracture into small segments. Furthermore, the Blasingame type curves are generated to examine the stress-sensitive effects. In particular, stress-sensitivity in matrix and hydraulic fracture subsystems can be respectively analyzed. It is found that stress-sensitive permeability in either the matrix subsystem or the fracture subsystem has its negative influence on production rate. Such an influence is increased as the permeability modulus in matrix and fractures is increased. The matrix permeability modulus mainly decreases the production rate in the intermediate and late flow period, while its effect on the early time production rate is relatively small compared with other flow periods. Stress-sensitivity in fractures mainly affects the early time production rate and imposes a negligible impact on production rate during the intermediate and late period. The production rate is increased with an increase in the initial fracture conductivity. The dominant flow which contributes to the majority of the total production gradually shifts from the near-wellbore fracture segments to the near-tip fracture segments for the intermediate and high conductive fracture cases, while, for the low conductive fractures, the near-wellbore fluid flow is dominant for the entire period. Due to the inherent constraints in a tight formation, rate transient analysis is found to be more physically representative for accurately describing performance of a horizontal well with multistage fractures compared to the traditional pressure transient testing.

Determination of in-situ elastic properties and reservoir boundary conditions

The elastic properties of reservoir formation are usually measured through laboratory triaxial tests or are estimated from empirical correlations obtained from well logs. Both approaches have similar limitation of the estimated value being representative of near-wellbore region. The former, however, has the further limitations of being costly and the unavailability of core samples for having a reliable estimate. In this paper, a new methodology is presented to determine the in-situ elastic properties (Poisson's ratio-PR- and Young's modulus) using pressure transient testing. Adopting the poroelasticity theory, a generalized diffusivity equation is formulated incorporating reservoir deformations into the fluid flow. By applying different boundary conditions, namely generalized plane stress, plane strain, and uniaxial strain, several analytical solutions were developed to obtain the PR from well testing. It shall be noted that the Young's modulus can be estimated given PR and bulk modulus. Two field data sets were used to implement and validate the proposed methodology for estimation of the PR (a build-up test data-set from a limestone oil reservoir and an interference drawdown well testing data-set from a sandstone aquifer). Results indicate that indeed the PR is a strong function of the reservoir deformational behavior. Moreover, estimation of PR under different boundary conditions provide a tool to identify the dominant reservoir deformational conditions. This was identified for the first data set by having the sonic well log data available and for the second data set by comparing the pressure-time measurements with their counterparts obtained from fully coupled fluid flow/geomechanics simulations. Moreover, once the validity of the output is confirmed by comparison with the available PR from well logging and/or coupled flow/geomechanics simulations, the proposed protocol can be re-used multiple times during reservoir life to estimate the elastic properties under the appraised BCs, without the necessity to run new well logs or lab tests.

Correction to: Radius of Investigation in Pressure Transient Testing

The arguments in Eqs. (16) and (18) have typographical errors in the original publication of the article.

A Discrete fracture–matrix model for pressure transient analysis in multistage fractured horizontal wells with discretely distributed natural fractures

Analysis of transient pressure test has become a reliable and powerful tool for petroleum engineers to study the impacts of complex fracture networks on multistage fractured horizontal wells (MFHWs) in unconventional reservoirs. Although lots of models have been established in the past decades, such as well-known dual-porosity model (DPM), dual-permeability model (DKM) and stripe fracture model (SFM), they have been proven unsuitable for modeling discretely distributed natural fractures (NFs).In this study, to overcome the disadvantages of existing models, a Discrete fracture–matrix method based on numerical well testing model (DFM-WTM) is proposed to study the pressure transient responses of MFHW with discretely distributed NFs. In DFM-WTM, local grid refinement method, well model and transmissibility corrections, natural fracture generation and time-step size are improved based on the framework of Matlab Reservoir Simulation Toolbox (MRST) (Lie, 2019), ensuring that pressure transient responses of MFHW with complex fracture networks can be obtained accurately and efficiently. Then, sensitivity analysis is conducted to study the impacts of different fracture properties. Finally, a case study is performed to further demonstrate the reliability and practicality of DFM-WTM.The results show that MFHW with discretely distributed NFs can be divided into 8 flow regimes, including (1) wellbore storage and skin effect, (2) fracture linear flow, (3) bilinear flow, (4) NF–HF fluid supply, (5) second bilinear flow, (6) formation linear flow, (7) pseudo boundary flow and (8) pseudo radial flow. Besides, a “dip” is found in the pressure derivative curve which is caused by the NF–HF fluid supply. Through the sensitivity analysis, it is found that this “dip” is an important signal to identify the impacts of NFs. It can also help us fathom the properties of HFs and NFs because this “dip” can be mainly affected by the number and conductivity of both HFs and NFs.

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.

Thermal impacts on pressure transient tests using a coupled wellbore/reservoir analytical model

This work investigates the impact of temperature effect on pressure-transient measurements made at any gauge location along a slanted wellbore completed with a production tubing. The analysis is based on a coupled transient-wellbore/reservoir thermal analytical model, which considers flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system. The analytical model provides temperature- and pressure-transient data for drawdown and buildup tests, accounting for Joule-Thomson, adiabatic fluid-expansion, conduction and convection effects. Regarding pressure transient analysis (PTA), thermal distorted pressure data might lead to the interpretation of false geological heterogeneities, because the transient heat loss during the buildup period provides an increase in the pressure exerted by the wellbore-fluid column and a change in the gauge location due to pipe contraction. Though some of the derived expressions are lengthy, they encompass an intrinsic simplicity in that one can compute pressure- and temperature-transient data on a spreadsheet. Analytical results are compared with those of a commercial thermal wellbore/reservoir simulator showing a good agreement. Thermal impacts on PTA interpretations are demonstrated by showing that a homogenous reservoir can be wrongly interpreted as a double-porosity system. A field case is presented, consisting of a drill stem test conducted in a multi-layered heterogeneous reservoir.

Numerical simulation and three-phase pressure transient analysis considering capillary number effect - case study of a gas condensate reservoir

When the wellbore pressure drops below the dew point pressure of gas in a gas condensate reservoir, there is the possibility of condensate bank build-up and wellbore blockage. These adverse processes result in development of different mobility zones around the wellbore which complicates the pressure transient test analysis. The focus of this study is on the analytical and numerical analysis of pressure testing data obtained from a well in a target gas condensate reservoir. First, the well test data were analytically interpreted through which several well and reservoir parameters were identified such as condensate bank radius, gas effective permeability, mechanical skin and skin due to non-Darcy flow. A three-phase compositional reservoir model was then built using the analytical solution, for numerical analysis of the pressure transient data as well as validation of the analytical results. This numerical model was then used to estimate well deliverability and predict future reservoir performance. [Received: August 17, 2018; Accepted: March 15, 2019]

Analysis of determining deliverability test and transient pressure in the PW-02 Well of Alpha Fields by using Ecrin software

Quantitative analysis of reservoir properties in a well is determined by transient pressure analysis. Transient pressure according to its type consists of Pressure Build up and Pressure Draw Down. this analysis provides an overview of the characteristics of a reservoir. This analysis includes the process of determining drainage area, shape, heterogeneity, porosity, average pressure, skin, permeability, and distance from a reservoir to boundary or flow discontinuities. This test is to determine the ability of gas production in the PW-02 Well, carried out by using the Modified Isochronal test method. This test aims to determine the productivity of a potential (Absolute Open flow). Transient pressure test on PW-02 Well using the Pressure Build up Test (Type Curve Pressure Derivative) method, it is found that the well model is Vertical well and the reservoir model is Two porosity PSS. While the boundary model obtained is Rectangle. Then, the data obtained in the form of positive skin is 1.46, the permeability is 62.5 mD and the reservoir pressure is 2529.32 psia. Based on the analysis obtained Absolute Open Flow Potential (AOFP) is 117406 mscf/D. While the deliverability test value obtained is 117413 mscf/D with n value of 0.825.

Radius of Investigation in Pressure Transient Testing

The spatial domain of interpretation in pressure transient and formation testing is constrained by its radius of investigation. A classical descriptor for this radius relies on the time derivative of pressure within a bounded domain becoming time independent. Another approach quantifies the radius of investigation based on the distance at which the pressure change is greater than the characteristic noise or resolution in the measurement system. In this paper, we postulate that the correct measure of radius of investigation is the distance at which the inversion of noisy test data is able to discern an anomaly within a given tolerance. This paper details the design requirements for a testing and measurement system suitable for a given investigation distance, measurement noise, and the confidence requirements for the inferred distance. The approach is demonstrated with two specific models. The first is a formation with a sealing fault in an infinite medium, and the second is a formation with a single-layer boundary vertically displaced from a production probe. With normally distributed random and correlated noise, computed results show that the measure of distance investigated is highly dependent upon the background over which the anomaly is imposed. Although the methodology is illustrated with particular models, the principles are applicable in general.

Effect of natural fractures on determining closure pressure

In Utah FORGE reservoir, eight pressure transient tests (microhydraulic fracturing and DFIT™) show natural fracture/pressure-dependent leakoff. This behavior may lead to misinterpretation of the closure pressure (proxy for minimum principal stress). The closure pressures obtained from DFIT™ (or microhydraulic fracturing) testing may reflect shear failure along natural fractures or discontinuities rather than tensile failure and lead to inaccurate estimates of the minimum principal stress. In pressure tests conducted at the Utah FORGE site showed that reactivation or opening of natural fractures intersecting the wellbore and were suggested by multiple closure events in DFIT™ tests. In addition, comparisons between the pre- and post-well-tests FMI logs show that there are populations of induced fracture and reactivated natural fractures which are mostly vertical and sub-vertical. In this study, DFIT™ (or microhydraulic fracturing) test analysis and numerical simulations were used to suggest that hydraulic shearing of critically stressed natural fractures can contribute to multiple closure signatures and possibly lead to incorrect determination of the minimum principal stress. As other authors have previously advocated, the DFIT™ test analyses and numerical simulations suggest that better estimations of minimum principal stress may be derived by injecting at relatively high rate and pressure and insuring that tensile breakdown is reached. In addition, extended shut-in period is required to determine accurate reservoir characteristics and fluid flow regime.

Application of diffuse source functions for improved flow upscaling

A novel upscaling approach was previously introduced using pressure transient concepts which allowed us to distinguish between well-connected, weakly connected, and disconnected pay in the local upscaling region. The current work applies these same concepts to benchmark the upscaling formulation against existing upscaling techniques to test the impact of localization. The local flow field generated for transmissibility calculation is based on transients approaching pseudo steady state in a sub volume as opposed to steady state or pseudo steady state in the entire volume. Identification of well-connected sub volume allows us to assess the impact of localization and degree of local connectivity on overall coarse simulation performance. The upscaling step draws upon its similarity to pressure transient well testing concepts to set up local flow problems and obtain coarse transmissibilities. The concept of diffusive time of flight together with diffuse source functions allows us to assess the error in localization for a particular local flow problem. A large error in localization may require adaptive grid resolution as a possible solution by separating the well-connected and weakly connected pay. The transient methodology has also allowed us to generalize the flow diagnostics designed for incompressible flow to compressible flow. The diagnostics are used to evaluate the quality of coarsening and upscaling.

Development of inflow performance model in high temperature gas-condensate reservoirs

Inflow Performance Relationships (IPRs) are important element for reservoir engineers in the design of new wells and also for monitoring and optimizing existing wells. IPRs are used to determine optimum production of gas rate and condensate rate in a well for any specified value of average reservoir pressure and predict the performance.Jokhio and Tiab proposed a simple method of establishing IPR for gas condensate wells. The method uses transient pressure test data to estimate effective permeability as a function of pressure. Effective permeability data used to convert production bottomhole flow pressure into pseudopressure to establish well performance. Despite the effectiveness of the method, single phase correlations were used in PVT calculations of each phase, which over simplified the fluid flow in gas condensate wells. Single phase dry gas equations do not reflect the multiphase flow behaviour of gas condensate wells below the dew point. Due to this limitation Jokhio and Tiab method modified by this study and new analytical IPRs for gas condensate well proposed.The major improvement of the above method is incorporating new viscosity correlation developed by this study and using two-phase compressibility factor as key parameters for predicting gas condensate inflow performance. Therefore, the main contribution of this study is development of viscosity correlation which is a critical issue in predicting gas condensate inflow performance both above and below the dew point. Optimization techniques and nonlinear regression used to develop a new viscosity correlation for high temperature heavy gas condensate reservoirs under depletion.The application of the new model is illustrated with field example for current IPR curves. Compositional simulation study of the well performed in PIPSIM simulator. The proposal approach provides reasonable estimates of simulator input reservoir properties (e.g. IPRs). Accuracy of the new method compared with compositional simulation study. The proposed method presents average absolute relative deviation (AARD) of 5.8% for gas IPR and 7.5% for condensate IPR compare to compositional simulation results. New method provides a tool for quick estimation of gas condensate wells without need of relative permeability curves and expensive and time consuming compositional simulation.

Partially Penetrated Well Solution of Fractal Single-Porosity Naturally Fractured Reservoirs

In the oil industry, many reservoirs produce from partially penetrated wells, either to postpone the arrival of undesirable fluids or to avoid problems during drilling operations. The majority of these reservoirs are heterogeneous and anisotropic, such as naturally fractured reservoirs. The analysis of pressure-transient tests is a very useful method to dynamically characterize both the heterogeneity and anisotropy existing in the reservoir. In this paper, a new analytical solution for a partially penetrated well based on a fractal approach to capture the distribution and connectivity of the fracture network is presented. This solution represents the complexity of the flow lines better than the traditional Euclidean flow models for single-porosity fractured reservoirs, i.e., for a tight matrix. The proposed solution takes into consideration the variations in fracture density throughout the reservoir, which have a direct influence on the porosity, permeability, and the size distribution of the matrix blocks as a result of the fracturing process. This solution generalizes previous solutions to model the pressure-transient behavior of partially penetrated wells as proposed in the technical literature for the classical Euclidean formulation, which considers a uniform distribution of fractures that are fully connected. Several synthetic cases obtained with the proposed solution are shown to illustrate the influence of different variables, including fractal parameters.

Estimating the initial-formation temperature and flowing-temperature gradient with transient-temperature analysis: Applications in gas reservoirs

The formation temperature constitutes one of the essential factors that affect the wellbore fluid temperature behavior in production mode. The amount and direction of the radial heat transfer between the surrounding formation and the wellbore depend on the temperature differential and thermal properties of the media.Traditional studies probing geothermal gradients depended principally on extrapolating the transient bottomhole temperature to infinite shut-in time for obtaining the undisturbed formation temperature. After that, a straight line from the surface to the bottomhole condition constituted the geothermal gradient. Of course, the implicit assumption in this approach is that a linear geothermal gradient exists in light of unavailability of depth-wise temperature measurements.This study presents a new transient-temperature analysis approach to determine the undisturbed formation temperature. Specifically, we show the application of the line-source solution that has roots in the temperature-diffusivity equation. Secondly, using the distributed temperature measurements associated with transient-pressure testing, we proved that the bottomhole or static temperature is time-dependent, leading to alteration of the geothermal gradient in a well's proximity. Finally, the lowering of the temperature-derivative plateau with increasing depth during well shut-in periods indicated an increase in thermal conductivity, resulting in a nonlinear geothermal gradient.