Pressure Transient Analysis Research Articles

A three-dimensional numerical pressure transient analysis model for fractured horizontal wells in shale gas reservoirs

Shale gas development has greatly contributed to the world's energy supply. Pressure transient analysis (PTA) has extremely helped the development of shale gas. In this paper, a three-dimensional numerical model for transient pressure analysis of multi-stage fractured horizontal wells (MFHWs) in shale gas reservoirs was proposed, which was based on the embedded discrete fracture model (EDFM). The adsorption effect of shale gas, stress sensitivity of shale reservoir, and high-velocity non-Darcy flow in fractures were considered in this model, and the model was solved by Matlab Reservoir Simulation Tool (MRST). The discrete process of governing equations is described in detail, the typical MFHW pressure transient response curve of a shale gas reservoir was obtained, different flow regimes were divided, and three-dimensional pressure distribution profile of different flow stages were drawn to clearly understand the flow states of shale gas in the reservoir. The effects of different flow mechanisms and fracture properties on the log–log curves of the MFHW pressure transient response were analyzed in detail. The numerical PTA model proposed in this paper not only considers a variety of complex flow mechanisms of shale gas, but also accurately describes the characteristics of complex fracture network of shale reservoirs in three-dimensional conditions through EDFM. In addition, the problems of the incomplete description of shale gas flow stages by conventional analytical methods and semi-analytical methods were avoided through the numerical solution. The pressure response behavior of fluid in shale gas reservoir can be better explained by using this model, which helps to reduce the uncertainty of shale reservoir development.

PTA-metrics for time-lapse analysis of well performance

Monitoring of a well and the surrounding reservoir performances is a crucial component in evaluating on-going and planning future well and field operations. This is carried out at all stages of a well life-span: from exploration to production and, sometimes, after abandonment. Despite tremendous progress in reservoir simulations, simple and fast techniques for well-reservoir performance evaluation are still demanded in the industry, especially in the context of the vast amount of permanent well monitoring data continuously accumulated. Such techniques are of special interest for on-the-fly well monitoring to detect and alarm about deteriorating performance issues. Installation of permanent pressure gauges in many wells motivated development of time-lapse Pressure Transient Analysis (PTA), capable of revealing and monitoring of different factors governing well performance and reservoir production. The paper describes PTA-based metrics introduced in the context of automated interpretation of time-lapse pressure responses and their derivatives. The paper begins with a review of time-lapse PTA applications in the oil and gas industry and examples of patterns formed by the time-lapse pressure transients and their derivatives in the log–log scale. Then, integral-based PTA-metrics for well-reservoir performance analysis are introduced. The metrics enable to distinguish between reservoir and well-reservoir connection contributions to a well’s performance using the Bourdet derivative, while avoiding the need for selecting and matching of a well-reservoir model. The metrics were further tested with synthetic well models and field cases. The testing demonstrated high accuracy of the metrics for the cases of vertical wells with stable transient patterns. Testing for the horizontal well cases has confirmed reliability of the metrics for the stable patterns, while change of the patterns may reduce the metrics reliability. Model independence and using only pressure and rate measurements as input data are the main advantages of the metrics for integration into automated interpretation workflows and on-the-fly analysis intensively developed in the industry.

Pressure Transient Analysis using Generated Simulation Reservoir Data for Dual Porosity Model of Naturally Fractured Reservoir

A naturally fractured reservoir today plays a significant role in the improved worldwide oil and gas production. More than half of the resource is mostly found in this reservoir. In this reservoir, there are two porous media: the matrix, which serves as the fluid source, and the fractures, as the fluid network that flow to the wellbore. Many authors have done the researches of works in order to modelling this reservoir. There are two model are done in this study, such as Warren and Root model, where fluid flow mechanism matrix to fractures is known as pseudosteady-state flow and Kazemi-Gilman model is known as transient interporosity flow.
 Reservoir Engineers generally utilize pressure transient analysis to determine this reservoir's characteristics. The purpose of this study is to assess whether it is feasible to incorporate the parameters from the Pressure Transient analysis using a synthesis simulation model. It also aims to observe how reservoir parameters behave in relation to the characteristics of naturally fractured reservoirs by utilizing various values for porosity, permeability, and fracture spacing.

Application of the Producer-Based Capacitance Resistance Model to Undersaturated Oil Reservoirs in Primary Recovery

Summary We investigated the application and usefulness of the producer-based representation of the capacitance resistance model (CRM) to characterize single and multiwell undersaturated oil reservoirs during primary recovery. The CRM is a physics-based, data-driven method that has been amply used to model reservoirs under different recovery stages, particularly during flooding processes. However, there have been very few applications to primary recovery. The previous work on primary recovery used the rate and bottomhole pressure (BHP) data to calculate the time constant or storage capacity, and the productivity index (PI) associated with each production well. Here, we incorporate popular productivity models in CRM, making the results comparable with those from pressure transient analysis (PTA) or rate transient analysis (RTA). We also investigate various topics that have not been discussed or that deserve a further explanation to include CRM in the reservoir engineering toolbox. These comprise constant and variable rate wells, transient flow, well location, well geometry, anisotropy, and different types of reservoir heterogeneity. CRM is systematically compared and validated against analytical and numerical models of single and multiwell reservoirs. We also use it to characterize flow in a real oil reservoir . Our results demonstrate that CRM can provide important parameters for reservoir characterization using BHP and rate data acquired from routine production operations, that is, without the need to shut in wells or perform dedicated tests. It yields reasonable estimates of flow resistance properties that depend on reservoir geology, petrophysics, and well condition. It can also be applied during successive time intervals to assess changes in well-reservoir properties, such as drainage radius or the PI, an indication of well damage. Most importantly, we show that for several well-reservoir cases with multiple complexities, CRM can accurately capture the reservoir size, or the drainage pore volume (PV) associated with each well in developed fields, which enables the calculation of average pressure and helps assess interwell communication and opportunities for infill drilling.

Automated Classification of Well Test Responses in Naturally Fractured Reservoirs Using Unsupervised Machine Learning

Understanding the impact of fractures on fluid flow is fundamental for developing geoenergy reservoirs. Pressure transient analysis could play a key role for fracture characterization purposes if better links can be established between the pressure derivative responses (p′) and the fracture properties. However, pressure transient analysis is particularly challenging in the presence of fractures because they can manifest themselves in many different p′ curves. In this work, we aim to provide a proof-of-concept machine learning approach that allows us to effectively handle the diversity in fracture-related p′ curves by automatically classifying them and identifying the characteristic fracture patterns. We created a synthetic dataset from numerical simulation that comprised 2560 p′ curves that represent a wide range of fracture network properties. We developed an unsupervised machine learning approach that can distinguish the temporal variations in the p′ curves by combining dynamic time warping with k-medoids clustering. Our results suggest that the approach is effective at recognizing similar shapes in the p′ curves if the second pressure derivatives are used as the classification variable. Our analysis indicated that 12 clusters were appropriate to describe the full collection of p′ curves in this particular dataset. The classification exercise also allowed us to identify the key geological features that influence the p′ curves in this particular dataset, namely (1) the distance from the wellbore to the closest fracture(s), (2) the local/global fracture connectivity, and (3) the local/global fracture intensity. With additional training data to account for a broader range of fracture network properties, the proposed classification method could be expanded to other naturally fractured reservoirs and eventually serve as an interpretation framework for understanding how complex fracture network properties impact pressure transient behaviour.

Application of Pressure Transient Analysis in Highly Deviated Reservoir

Conventional pressure transient analysis (PTA) alone may not be a reliable scientific tool for safe oilfield operations and reservoir development, according to earlier studies. The pressure responses were plotted using a skilled simulator in this study to examine the application of PTA and produce an exhaustive analysis. The Nelson oilfield, which is in the UK's North Sea, specifically addressed reservoir characterization and field development in a highly deviated well. The work also used sensitivity analysis and log-log diagnostic plotting to create a model that best matched a short pressure build-up (PBU) test. As a result, reservoir characteristics like permeability, porosity, and reservoir height were modeled, computed, and analyzed alongside wellbore characteristics. For various wells in the Nelson field, averages of core logs, seismic data, and wireline logs were taken to verify the accuracy of these models. Reservoir characterization was accomplished using PTA in conjunction with field data, which improved pre-existing macro and micro datasets. The use of a simulator and such additional data undoubtedly helped to improve field development strategies as well.

Impact of pressure-dependent diffusivity on transient pressure analysis of a dry Coalbed Methane (CBM) wells: A new approach

Impact of pressure-dependent diffusivity on transient pressure analysis of a dry Coalbed Methane (CBM) wells: A new approach

Pressure-Transient Analysis for Waterflooding with the Influence of Dynamic Induced Fracture in Tight Reservoir: Model and Case Studies

Summary It is well known that waterflooding will create fractures. The created fractures are divided into hydraulic fractures (artificial fractures with proppant) and induced fractures (formed during waterflooding without proppant). There is no proppant in the induced fracture, so it will close as the pressure decreases and extend as the pressure increases. We call it a dynamic induced fracture (DIF). Because of reduced pressure, the DIF will be closed during the shut-in pressure test (well testing). The current conventional well-testing model cannot describe the dynamic behavior of the DIF, resulting in obtaining unreasonable parameters. Thus, this work proposes a DIF model to characterize the DIF behavior during well testing (the injection well will shut in, resulting in a reduction in bottomhole pressure and induced-fracture closure). It is worth noting that a high-permeability zone (HPZ) will be formed by long-time waterflooding and particle transport. The HPZ radius will be greater than or equal to the DIF half-length because the waterflooding pressure can move particles but not necessarily expand the fracture. The point source function method and Duhamel principle are used to obtain the bottomhole pressure response. Numerical simulation methods are used to verify the accuracy of the model. Field cases are matched to demonstrate the practicability of the DIF model. Results show a straight line with a slope greater than the unit, a peak, a straight line with a slope less than one-half, and an upturned straight line on the pressure derivative curve. This peak can move up, down, left, and right to characterize the induced fracture’s dynamic conductivity (DC). The straight line with a slope greater than the unit can illustrate a fracture storage effect. The straight line with a slope less than one-half can describe the closed induced-fracture (CIF) half-length. The upturned straight line can describe the HPZ and reservoir permeability. The obtained parameters will be inaccurate if they are incorrectly identified as other flow regimes. Field cases are matched well to illustrate that identifying the three innovative flow regimes can improve the parameters’ accuracy. In conclusion, the proposed model can characterize the dynamic behavior of induced fracture, better match the field data, and obtain more reasonable reservoir parameters. Finally, two field cases in tight reservoir are discussed to prove its practicality.

Well interference evaluation considering complex fracture networks through pressure and rate transient analysis in unconventional reservoirs

Severe well interference through complex fracture networks (CFNs) can be observed among multi-well pads in low permeability reservoirs. The well interference analysis between multi-fractured horizontal wells (MFHWs) is vitally important for reservoir effective development. Well interference has been historically investigated by pressure transient analysis, while it has shown that rate transient analysis has great potential in well interference diagnosis. However, the impact of complex fracture networks (CFNs) on rate transient behavior of parent well and child well in unconventional reservoirs is still not clear. To further investigate, this paper develops an integrated approach combining pressure and rate transient analysis for well interference diagnosis considering CFNs. To perform multi-well simulation considering CFNs, non-intrusive embedded discrete fracture model approach was applied for coupling fracture with reservoir models. The impact of CFN including natural fractures and frac-hits on pressure and rate transient behavior in multi-well system was investigated. On a log–log plot, interference flow and compound linear flow are two new flow regimes caused by nearby producers. When both NFs and frac-hits are present in the reservoir, frac-hits have a greater impact on well #1 which contains frac-hits, and NFs have greater impact on well #3 which does not have frac-hits. For all well producing circumstances, it might be challenging to see divergence during pseudosteady state flow brought on by frac-hits on the log–log plot. Besides, when NFs occur, reservoir depletion becomes noticeable in comparison to frac-hits in pressure distribution. Application of this integrated approach demonstrates that it works well to characterize the well interference among different multi-fractured horizontal wells in a well pad. Better reservoir evaluation can be acquired based on the new features observed in the novel model, demonstrating the practicability of the proposed approach. The findings of this study can help for better evaluating well interference degree in multi-well systems combing PTA and RTA, which can reduce the uncertainty and improve the accuracy of the well interference analysis based on both field pressure and rate data.

Technology Focus: Well Testing (February 2023)

The energy transition is in a continuous pursuit of innovative technology applications from all corners of the oil and gas industry. With the exponential growth of carbon capture and sequestration (CCS) projects, similar subsurface appraisal objectives remain. Derisking dynamic reservoir performance and characterizing storage pore space are key enablers for prospective CCS projects. The mention of well testing often takes readers to a visualization of hydrocarbon disposition by a flare. Once a bright and vibrant spectacle of our industry’s exploration updates, the days of flaunting a chairman’s flow or banker’s burn are past. Waning application of well testing during our energy transition is a specious assumption, and it’s the optics that are transforming as the well testing discipline proves its value to long-term carbon storage projects. Injecting CO2 into the subsurface is hardly a new concept; operators have been doing this for decades as part of enhanced oil recovery. However, the application of injecting CO2 is changing in response to operators’ environmental, social, and governance ambitions. While carbon storage concepts exist in many forms, anchoring a storage project requires pore space of adequate quantity and quality in proximity to a fixed source of emissions. Carbon storage projects also must manage additional risks such as sustained injectivity performance, geologic seal integrity, and plume migration, to name a few. Enter well testing. Quantifying injection performance of supercritical fluids is crucial for optimizing wells to meet project needs while minimizing the number of required penetrations through a structural seal. Whether for a saline aquifer or a previously depleted field, pressure transient analysis enhances understanding of the pore space intended for storage and the potential heterogeneities within. Furthermore, integrating well testing with other reservoir-description tools may be used to monitor migration of stored fluids within the reservoir. With corporate and regulatory targets driving the unprecedented pace and scale of CCS opportunities, well testing is quickly reaffirming itself as a powerful tool in characterizing pore space essential to our lower-carbon goals. This month’s papers highlight ongoing developments within the well testing discipline and important reminders about how to properly use dynamic data. The application of these well testing fundamentals to a nascent carbon storage market is still evolving. Recommended additional reading at OnePetro: www.onepetro.org. SPE 208967 Rate-Pseudopressure Deconvolution Enhances Rate-Time Models Production History-Matches and Forecasts of Shale Gas Wells by L.M. Ruiz Maraggi, The University of Texas at Austin, et al. URTeC 3705570 Analysis of Multiple Flow/Buildup Tests Including a 5-year Buildup: Case Study of an Australian Shale Gas Well by Christopher R. Clarkson, University of Calgary, et al. OTC 31691 Challenges and Mitigation Strategies for High-Rate Gas Well Testing in High-Pressure/High-Temperature DST Operation by Jakpakorn Hemaprasertsuk, PTTEP, et al.

Transient pressure analysis of polymer flooding fractured wells with oil-water two-phase flow

The oil-water two-phase flow pressure-transient analysis model for polymer flooding fractured well is established by considering the comprehensive effects of polymer shear thinning, shear thickening, convection, diffusion, adsorption retention, inaccessible pore volume and effective permeability reduction. The finite volume difference and Newton iteration methods are applied to solve the model, and the effects of fracture conductivity coefficient, injected polymer mass concentration, initial polymer mass concentration and water saturation on the well-test type curves of polymer flooding fractured wells are discussed. The results show that with the increase of fracture conductivity coefficient, the pressure conduction becomes faster and the pressure drop becomes smaller, so the pressure curve of transitional flow goes downward, the duration of bilinear flow becomes shorter, and the linear flow appears earlier and lasts longer. As the injected polymer mass concentration increases, the effective water phase viscosity increases, and the pressure loss increases, so the pressure and pressure derivative curves go upward, and the bilinear flow segment becomes shorter. As the initial polymer mass concentration increases, the effective water phase viscosity increases, so the pressure curve after the wellbore storage segment moves upward as a whole. As the water saturation increases, the relative permeability of water increases, the relative permeability of oil decreases, the total oil-water two-phase mobility becomes larger, and the pressure loss is reduced, so the pressure curve after the wellbore storage segment moves downward as a whole. The reliability and practicability of this new model are verified by the comparison of the results from simplified model and commercial well test software, and the actual well test data.

Pressure transient analysis of multistage fractured horizontal wells based on detailed characterization of stimulated area

In ultralow permeability tight oil reservoirs, the fracturing scale of multistage fractured horizontal wells (MFHWs) is relatively large, and the artificial fracture system is generally more complex. Analytical and semi-analytical methods are difficult to characterize the stimulated area in detail, which includes main fractures, branch fractures, and microfractures. Numerical methods have unique advantages in studying such problems. The mathematical model of oil–water two-phase seepage is established by the finite element method, the permeability and pseudo threshold pressure gradient that vary with spatial position are proposed to characterize the stimulated area except the main fracture. A single well numerical model was established to study the influence of the width and permeability of the stimulated area on the pressure response. The analysis shows that the transient pressure response of MFHW is controlled by main fracture conductivity. Main fractures have high conductivity can better communicate the stimulated area, and MFHW can be better developed.

Pressure transient analysis for stress-sensitive fractured wells with fracture face damage

Fracture networks improve wells’ deliverability of fluids from underground reservoirs. However, conductive fractures may lose efficiency because of fracture closure or formation damage that needs to be monitored and detected for proper reservoir management and intervention. Fracture hydraulic conductivity is a function of fracture geometry and its hydraulic aperture, which tends to degrade during operations because of fracture compaction and closure. Furthermore, pore-clogging of fracture walls (faces) results in a damaging skin zone that may reduce fracture-matrix transmissibility. Current Pressure Transient Analysis (PTA) models in the literature do not consider the interconnected combined effect of stress-dependent conductivity of fractures and fracture face skin. Modeling fracture closure without accounting for the skin effect may mislead the PTA interpretations of well performance. This work proposes a rigorous PTA model to account for fracture closure combined with fracture face skin for single and multistage hydraulic fractures with uniform and complex geometries. The solution approach is based on subdividing the domain into three flow regions, matrix, damage zone, and hydraulic fracture (HF). The proposed model is verified extensively using a commercial simulator and other less comprehensive models from the literature. The pressure response in fractured wells with stress-sensitive fractures is analyzed at early, middle, and late times. In each flow regime, we identify pressure signals to detect fracture closure by incorporating fracture closure and skin effects. Results show that the fracture face skin has a significant effect on fracture performance as it introduces an additional pressure drop that triggers an earlier and more pronounced occurrence of fracture closure. We proposed a semi-log approach to identify fracture closure for low compressible fractures and a pseudo-radial simplification to generate late-time response curves. The proposed method serves as a PTA diagnostic tool to detect fracture conductivity degradation due to fracture closure and formation damage.

A Novel Workflow for Early Time Transient Pressure Data Interpretation in Tight Oil Reservoirs with Physical Constraints

In this work, a novel workflow has been proposed, validated and applied to interpret the early time transient pressure data in tight oil reservoirs with physical constraints. More specifically, the theoretical model was developed to obtain the transient pressure response for a vertical well in tight oil reservoirs with consideration of pseudo threshold pressure gradient (TPG). Then, a physical constraint between the skin factor and formation permeability has been proposed based on the physical meaning of percolation theory. This physical constraint can be applied to determine the lower limit of the skin factor which can reduce the uncertainty during the interpretation process. It is found that the influence range of the skin factor and permeability may partially overlap during the interpretation process without consideration of physical constraints. Additionally, it is found that the equivalent wellbore radius is more reasonable by considering the skin factor constraints. Furthermore, the short-time asymptotic method was applied to separate the small pressure signal at the early time period and a novel type curve was proposed to better analyze the early time pressure response. Subsequently, sensitivity analyses were conducted to investigate the influence of different parameters on the new type curves. It is found that the new type curves are more dispersed and sensitive to the parameters at the early time period which can be beneficial for the early time transient pressure analysis in a tight formation. The proposed method has been validated and then extended to a field application, demonstrating that the transient pressure for a vertical well in a tight formation can be analyzed in a reasonable and accurate manner with only early time transient pressure data.

Semi-analytical solution for bottomhole pressure transient analysis of a hydraulically fractured horizontal well in a fracture-cavity reservoir

This paper study the role of hydraulic fracture properties on the transient bottomhole pressure (BHP) behavior of a horizontal well producing from a tight fracture-cavity reservoir. A combination of point source function, Laplace transformation and Perturbation transformation are used to obtain BHP step by step. Through literature comparison and numerical simulation, the results of BHP have a good consistency, which indicates the proposed method is scientific and reasonable. We divide the fluid flow into five stages, namely the wellbore storage stage, the karst cave fluid flows to the fracture stage, the radial flow stage of karst cave and fracture system, the matrix fluid flows to the fracture stage and the quasi-steady state stage. We come to the conclusion that the number of fractures and fracture direction mainly affect radial flow stage. In contrast, the length of horizontal subsection and skin factor mainly affect the karst cave fluid flows to the fracture stage. The matrix fluid flows to the fracture stage is more obvious when the fracture half-length and the horizontal segment spacing of the horizontal well are small. The study believes special attention should be paid to reforming the formations at both ends of the horizontal well. The advantage of this method is to incorporate well geometry (skin factor) and hydraulic fracturing design (fracture parameters), which is useful for well test interpretation through generating a new set of type curves. What’s more, this new method has the characteristics of easy calculation. The findings of this study can help for better understanding of well test analysis in fracture-cavity reservoir. However, the limitation of this study is that it is only suitable for this situation the horizontal well does not encounter karst caves and the karst caves in the reservoir are connected to the wellbore through fractures.

Pressure Transient Analysis for the Fractured Gas Condensate Reservoir

Gas condensate reservoirs exhibit complex thermodynamic behaviors when the reservoir pressure is below the dew point pressure, leading to a condensate bank being created inside the reservoir, including gas and oil condensation. Due to natural fractures and multi-phase flows in fractured gas condensate reservoirs, there can be an erroneous interpretation of pressure-transient data using traditional multi-phase models or a fractured model alone. This paper establishes an analytical model for a well test analysis in a gas condensate reservoir with natural fractures. A three-region composite model was employed to characterize the multi-phase flow of retrograde condensation, and the fractured formation was described by a dual-porosity medium. In the first region, both the gas and condensate phases were mobile. In the second region, the gas was mobile whereas the condensates were immobile. In the third region, the only moving phase was the gas phase. The analytical solution was solved by a Laplace transformation to change the partial differential equations to ordinary differential equations. The Stehfest numerical inversion technique was then used to convert the solution of the proposed model into real space. Subsequently, the type curve was obtained and six flow regimes were determined. The influence of several factors on the pressure performance were studied by a sensitivity analysis. Finally, the accuracy of the model was verified by a case study. The model analysis results were in good agreement with the actual formation data. The proposed model provides a few insights toward the production behavior of fractured gas condensate reservoirs, and can be used to evaluate the productivity of such reservoirs.

Analysis of Multiple Flow/Buildup Tests Including a 5-Year Buildup: Case Study of an Australian Shale Gas Well

Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.

Pressure transient analysis of a horizontal well intercepted by multiple hydraulic fractures in heterogeneous reservoir with multiple connected regions using boundary element method

The focus of this paper is to establish a new general model framework considering both hydraulic fractures with finite conductivity and heterogeneous characteristics of multiple connected regions by using boundary element method. With this framework, we can calculate the pressure performance of any heterogeneous reservoir. The innovation is that the complex fracture flow, boundary shape and heterogeneous characteristics can be flexibly considered in the model. Transient pressure of fractured horizontal wells in heterogeneous reservoir is obtained by using Stehfest numerical inversion method. Subsequently, this proposed regional heterogeneity model was validated by using numerical simulation methods. The results show that the proposed heterogeneous model can be divided into five flow segments, which are bilinear flow, linear flow, radial flow, first boundary dominated flow and second boundary dominated flow. However, the research results show that the presence or absence of some flow sections is closely related to the regional permeability ratio and the regional storage capacity ratio. As the two most important parameters of heterogeneous reservoir, the permeability ratio and regional storage capacity of heterogeneous reservoir will have a huge impact on the pressure response and pressure field. The sensitivity analysis shows that these two factors will lead to the deformation of the pressure field distribution and affect the flow characteristics, and cause some flow segments to fail to appear. The smaller the regional storage capacity ratio, the deeper the V-shape, and the more fluid supplied from the outer zone to the inner zone. This study also suggests that the fracture conductivity mainly affects the early flow characteristics, and the smaller the conductivity, the greater the pressure loss. In addition, irregular boundary will also cause important deformation of pressure field, and the area size will affect the late flow characteristics, and the smaller the area, the greater the pressure loss. The new semi-analytical solutions can form a series of typical curves and be applied to the well test analysis of multi-stage fracturing horizontal wells in heterogeneous and unconventional oil and gas reservoirs. The findings of this study can help for better understanding of the influence of reservoir heterogeneity on pressure response and find some applications in well testing for inverse problems in heterogeneous reservoirs.

Analytical model for transient pressure analysis in a horizontal well intercepting with multiple faults in karst carbonate reservoirs

In recent years, the Shunbei karst-carbonate reservoirs becomes a huge productivity oilfield, which produced over one million tonnes crude oil annually. However, there are difficulties in understanding production contribution of each fault-karst branch in reservoirs, which significantly impacts the efficient development. Multibranched fault-karst reservoirs in the Shunbei have an obvious tree-shaped geostructure, in which the natural fractures and eroded cave develop along multiple large-scale faults. The existing models for pressure transient analysis (PTA) were mainly established for fracture-cave reservoirs only with single fault, which cannot be applicable to characterize the multibranched fault-karst reservoir. To fill this gap, a novel analytical PTA model for horizontal commingled production well in the multibranched fault-karst reservoir was established to describe pressure response and identify flow regimes. First, our model includes the Darcy flow with the fluid compressibility effect in fracture region, and the large-scale vertical storage flow in cave region as well as the horizontal laminar flow in the horizontal wellbore. Then, the accuracy of this PTA model is verified by comparing it with the existing single branch fault-karst pressure model. Further, we applied the model to analyze the Shunbei oilfield case data. Last, the effect of boundary type, fluid compressibility effect, fracture physical properties, and cave spatial distribution on the pressure response are discussed in detail. The sensitivity analysis results show (a) the cave storage flow regime exhibits an obvious unit-slope-line on pressure derivative curve, at the time the skin transient flow constitutes a V-shape characteristic. (b) The number of fracture-cave branches can be directly obtained by counting the number of V-shaped appearances on the pressure derivative curve. (c) The fluid compressibility effect leads to an upward trend on the pressure and its derivative, reservoir engineers should be cautious to explain that characteristic as a closed boundary effect. (d) The cave volume and cave position control the timing of the V-shape occurring. As the cave volume increases, the linear flow regime lasts longer and the V-shaped feature becomes apparent. With the cave distance and cave depth increasing, the V-shape characteristic comes later. This work can provide technical support for accurate characterization of multibranched fault-karst reservoirs, and give a type curve analysis method for rapidly diagnosing the spatial location of each karst cavity by analyzing bottom-hole pressure.

Carbonate excess permeability in pressure transient analysis: A catalog of diagnostic signatures from the Brazil Pre-Salt

Dynamic appraisal in carbonates with excess permeability is critical to successful reservoir modeling and depletion planning. Accurate recognition and characterization of a dual-porosity system may translate to improved project performance. We present a catalog of diagnostic signatures that elevate pressure transient analysis beyond the traditional V shape, to aid in identifying non-matrix features’ presence, extent, and contribution to reservoir performance. We reviewed 152 well tests from the Brazil Pre-Salt, integrated with multi-scale static and dynamic data (conventional core, borehole image logs, seismic, and drilling losses). A recurring set of eight signatures with characteristic slopes and shapes stood out, which we reconciled with geologic concepts and tested with numerical modeling. These signatures reveal key insights into excess-permeability architecture and non-matrix types, from touching vugs to caves, from natural fractures to fault damage zones. They will assist subsurface teams to optimally frame well test objectives and maximize value of information during early appraisal and field development. They will help enhance reservoir performance prediction, by enabling a comprehensive use of well test data in geologic and reservoir simulation models.