Rate-transient Analysis Methods Research Articles

Rate Transient Analysis for Multi-Fractured Wells in Tight Gas Reservoirs Considering Multiple Nonlinear Flow Mechanisms

Making rate transient analysis (RTA) and formation evaluation for multi-fractured tight gas wells has always been a difficult problem. This is because the fluid flow in the formation has multiple nonlinear flow mechanisms, including gas-water two-phase flow, gas slippage, low-velocity non-Darcy flow, and stress-dependent permeability. In this paper, a novel RTA method is proposed for multi-fractured wells in tight gas reservoirs incorporating nonlinear flow mechanisms. The RTA method is based on an analytical model, which is modified from the classical trilinear flow model by considering all the nonlinear flow mechanisms. The concept of material balance time and normalized rate is used to process the production data for both water and gas phases. The techniques of approximate solutions in linear/bilinear flow regimes and type curve fitting are combined in the proposed RTA method. After that, the rate transient behaviors and influencing factors of multi-fractured tight gas wells are analyzed. A field case from Northwestern China is used to test the efficiency and practicability of the proposed RTA method. The results show that six flow regimes for both gas and water production performances are exhibited on the log-log plots of normalized production rate against material balance time. The rate transient responses are sensitive to the nonlinear flow mechanisms, and formation and fracture properties. The medium flow regimes are significantly affected by fracture number, fracture conductivity, fracture half-length, stress-dependent permeability, gas-water two-phase flow, and formation permeability, which should be considered in making RTA of fractured tight gas wells. The field case shows that both gas and water production performances can be well-fitted using the proposed RTA method. The major innovation of this paper is that a novel RTA method is proposed for fractured tight gas wells considering multiple nonlinear flow mechanisms, and it can be used to make reasonable formation and fracturing evaluations in the field.

Estimation of fracture half-length with fast Gaussian pressure transient and RTA methods: Wolfcamp shale formation case study

Accurate estimation of fracture half-lengths in shale gas and oil reservoirs is critical for optimizing stimulation design, evaluating production potential, monitoring reservoir performance, and making informed economic decisions. Assessing the dimensions of hydraulic fractures and the quality of well completions in shale gas and oil reservoirs typically involves techniques such as chemical tracers, microseismic fiber optics, and production logs, which can be time-consuming and costly. This study demonstrates an alternative approach to estimate fracture half-lengths using the Gaussian pressure transient (GPT) Method, which has recently emerged as a novel technique for quantifying pressure depletion around single wells, multiple wells, and hydraulic fractures. The GPT method is compared to the well-established rate transient analysis (RTA) method to evaluate its effectiveness in estimating fracture parameters. The study used production data from 11 wells at the hydraulic fracture test site 1 in the Midland Basin of West Texas from Upper and Middle Wolfcamp (WC) formations. The data included flow rates and pressure readings, and the fracture half-lengths of the 11 wells were individually estimated by matching the production data to historical records. The GPT method can calculate the fracture half-length from daily production data, given a certain formation permeability. Independently, the traditional RTA method was applied to separately estimate the fracture half-length. The results of the two methods (GPT and RTA) are within an acceptable, small error margin for all 5 of the Middle WC wells studied, and for 5 of the 6 Upper WC wells. The slight deviation in the case of the Upper WC well is due to the different production control and a longer time for the well to reach constant bottomhole pressure. The estimated stimulated surface area for the Middle and Upper WC wells was correlated to the injected proppant volume and the total fluid production. Applying RTA and GPT methods to the historic production data improves the fracture diagnostics accuracy by reducing the uncertainty in the estimation of fracture dimensions, for given formation permeability values of the stimulated rock volume.

Rate transient analysis of wells exhibiting two-phase (gas+water) flowing by use of pseudopressure-based approach

The primary focus of rate transient analysis (RTA) is put on the estimation of the reserves of gas/water reservoirs. RTA based on the single-phase assumption is limited to gas/water two-phase flow in the development of the material-balance time function. This work aims to propose a practical approach for analyzing production data from wells exhibiting gas/water two-phase flow during both infinite-acting flow (IAF) and boundary-dominated flow (BDF) periods. In this work, we present a comprehensive pseudopressure-based solution associated with the constitutive saturation/pressure (Sw/p) relationship. The pseudovariables, namely pseudopressure and β-factor, have the ability of handling the two-phase nonlinearities in the governing flow equations of gas and water phases and generating the required benchmark analytical solutions for liquid flow equation. By integrating the liquid-type solutions with the principle of Duhamel convolution, a set of gas/water-phase productivity equations are recast for wells producing at different operating conditions, including constant bottomhole-pressure, constant rate and steplike change in bottomhole-pressure/rate. The presented solutions provide a theoretical framework for developing two-phase RTA based on two-phase material-balance pseudotime (MBPT). The RTA method is validated against synthetic cases generated from numerical simulation, and the dependability of two-phase MBPT is also corroborated in detail. A field case example is analyzed to demonstrate the practical applicability of this method. The RTA method provided herein accounts for all flowing phases in the reservoir, and serve as an alternative to numerical model history matching for estimating original gas in place (OGIP) and original water in place (OWIP).

Rate-transient analysis for estimating the linear flow parameters of communicating wells using the dynamic drainage area (DDA) concept

Development of unconventional reservoirs using multi-fractured horizontal wells (MFHWs) has led to closer well and hydraulic fracture spacing. Tighter placement of MFHWs has consequently led to increased instances of well interference, particularly through hydraulic fractures. In addition to possible problems posed for development, fracture communication that persists during production complicates rate-transient analysis (RTA) because models/methods for RTA have mostly been developed for single-well analysis. Availability of RTA methods specifically developed for communicating wells can reduce errors associated with hydraulic fracture and reservoir characterization and can lead to improved decision making.A semi-analytical method for history matching MFHWs communicating through hydraulic fractures has recently been developed using the dynamic drainage area (DDA) concept. In the current work, the DDA concept is employed to develop a new straight-line analysis (SLA) method for the transient linear flow regime that can be applied to two communicating MFHWs. The change in the drainage area of a single well due to communication challenges the use of the DDA concept. However, when the second well comes on production, reinitialization of the calculations for the first well helps to facilitate the implementation of the DDA concept.The new DDA-corrected RTA (SLA) method for communicating wells is verified against the results of numerical simulation. Several synthetic cases are generated using numerical simulation to verify the accuracy of the developed method using various reservoir/fracture properties. The new method applied to the simulated cases allows the fracture half-length (xf) to be estimated within 10% of simulation model input. The DDA-corrected RTA method has also been applied to a field dataset, previously analyzed by the authors using the DDA approach to history match well production data. This dataset consists of six wells, drilled into two separate reservoir layers (three wells per layer) and from two adjacent pads, which exhibit strong well-pair communication. For this dataset, the calculated linear flow parameters for these wells are compared. The results demonstrate that there is a difference between the linear flow parameters of wells completed in the upper layer and lower layers, which could be attributed to either differences in effective fracture area or permeability.This new approach can help practitioners quickly and accurately estimate reservoir and fracture properties in these scenarios. The method can therefore be used to improve hydraulic fracture design, well forecasting and development planning where persistent well communication through hydraulic fractures is occurring.

Using Agarwal analytical approach with superposition rate and time solutions to analyze multi and single well systems

There are many RTA (Rate Transient Analysis) methods available to analyze wells producing from unconventional formations. The approach of Agarwal (2010) is one of the RTA techniques which have gained an increasing interest due to its simplicity, flexibility, and wide range of applications. In this study, the approach of Agarwal (2010) was adopted to analyze not only single well systems but also multi-well systems by using three different equations. These equations were then integrated with the principle of superposition rate rather than conventional superposition time. By using two field cases, the accuracy of the proposed approaches was validated with current analytical methods and reservoir simulation. The first case represents a multi-well system in which the wells producing with a fixed flowing pressure were put on production at the same time. The operating conditions were then relaxed in the second case by allowing the wells to have different production starting times and varying production profiles.Additionally, this work examined in details the ability of the superposition rate function in converting various production behaviors to their equivalent constant rate solutions. This research clearly shows the advantage of the superposition rate solution over the traditional superposition time function (material balance time) in maintaining the data order in time. Such an advantage makes it easier for the analyst to observe the production changes in well performance in real normal time.Several case studies were used to show how Agarwal (2010) can be utilized to extract different information from boundary-dominated flow period which are useful in the evaluation of reservoir compartmentalization and the effectiveness of infill drilling campaigns. In addition to that, the application of Agarwal (2010) in terms of frac hits evaluation and refracturing operations encountered during the transient flow period was also examined.

Impact of Complex Fracture Networks on Rate Transient Behavior of Wells in Unconventional Reservoirs Based on Embedded Discrete Fracture Model

Abstract It has recently been demonstrated that complex fracture networks (CFNs) especially activated natural fractures (ANF) play an important role in unconventional reservoir development. However, traditional rate transient analysis (RTA) methods barely investigate the impact of CFN or ANF. Furthermore, the influence of CFN on flow regime is still ambiguous. Failure to consider these effects could lead to misdiagnosis of flow regimes and underestimation of original oil in place (OOIP). A novel numerical RTA method is therefore presented herein to improve the quality of reserves assessment. A new methodology is introduced. Propagating hydraulic fractures (HFs) can generate different stress perturbations to allow natural fractures (NFs) to fail, forming various ANF patterns. An embedded discrete fracture model (EDFM) of ANF is stochastically generated instead of local grid refinement (LGR) method to overcome the time-intensive computation time. These models are coupled with reservoir models using non-neighboring connections (NNCs). Results show that except for simplified models used in previous studies subjected to the traditional concept of stimulated reservoir volume (SRV); in our study, the ANF region has been discussed to emphasis the impact of NF on simulation results. Henceforth, ANF could be only concentrated around the near-wellbore region, and it may also cover the whole simulation area. Obvious distinctions could be viewed for different kinds of ANF on diagnostic plots. Instead of SRV-dominated flow mentioned in previous studies, ANF-dominated flow developed in this work is shown to be more reasonable. Also, new flow regimes such as interference flow inside and outside activated natural fracture flow region (ANFR) are found. In summary, better evaluation of reservoir properties and reserves assessment such as OOIP are achieved based on our proposed model compared with conventional models. The novel RTA method considering CFN presented herein is an easy-to-apply numerical RTA technique that can be applied for reservoir and fracture characterization as well as OOIP assessment.

Permeability measurements using rate-transient analysis (RTA): Comparison with different experimental approaches

Reservoir engineers commonly apply rate-transient analysis (RTA) and pressure-transient analysis (PTA) methods to analyze multi-fracture horizontal wells (MFHWs) completed in unconventional reservoirs quantitatively for reservoir and hydraulic fracture properties. Data from core analysis techniques are commonly used to provide important input for RTA-PTA models. However, conventional laboratory techniques (i.e., steady-state and non-steady-state fluid flow) do not reproduce the operating conditions that MFHWs are subjected to in the field. In the current work, laboratory techniques that better reproduce these boundary conditions are explored and compared to more traditional core analysis methods.For this study, RTA methods are applied to gas produced from core plugs and PTA methods are applied to gas injection-fall-off data at the start of the core test before gas production. While the RTA method has been previously described by the authors, the application of the PTA method to provide an early, and fast, estimate of permeability is unique to this study. Further, our previous experimental setup for performing RTA was modified to accommodate not only the use of both RTA/PTA methods, but also the use of conventional core analysis methods (steady-state and non-steady-state methods) to allow for direct comparison of all methods.For both RTA and PTA core tests, the observed flow-regime sequence is transient linear flow followed by boundary-dominated flow, which is the same sequence that is commonly observed in the field for MFHWs producing from low-permeability and shale reservoirs. Two independent permeability values were estimated using the slope of the square root time plot and the time at the end of linear flow for each test. The pore volume of the samples were also estimated using the RTA method. Permeability and pore volume values obtained from the RTA method, referred to as ‘RTAPK’ previously, were in good agreement with those obtained from more conventional core testing methods (average coefficient of variation = 8%). The derived permeabilities from the time at the end of linear flow during the fall-off test were close to other permeabilities. In contrast, the square root time plot (fall-off) resulted in significantly higher permeabilities attributed to the experimental artifact caused by substantial dead volume in the injection port. The primary advantage of the RTA core analysis method is the accelerated test-time. For samples with permeability values ranging between 0.1 and 3 mD, the apparent gas permeabilities can be estimated in less than 3 to 10 minutes using both fall-off and production data.

Use of a New Thermodynamics-Based Saturation/Pressure Relationship in Two-Phase Rate-Transient Analysis of Boundary-Dominated Gas/Condensate Reservoirs

Summary Considerable research has been focused on the development of rate-transient-analysis (RTA) models to estimate the reserves of gas/condensate reservoirs. Currently, broadly deployed RTA tools rely on multiphase pseudopressure concepts to enable multiphase production-data analysis. In any multiphase pseudopressure calculation, the determination of the saturation/pressure (So/p) relationship plays a vital role because it directly influences the ability of multiphase RTA methods to reliably forecast original gas in place (OGIP). In this work, we present a thermodynamics-based So/p model that provides a better understanding of the phase behavior for the boundary-dominated gas/condensate reservoirs. The proposed So/p model is derived from the thermodynamic nature of extended black-oil formulations. A noniterative flash-calculation protocol is used to establish the So/p path in the condensate-buildup region. The developed method can be coupled with RTA tools and services for the calculation of multiphase pseudopressure. In this work, we present case studies of three gas/condensate reservoirs with different types of fluids. Two RTA multiphase analysis models are used to scrutinize the production data using the newly proposed So/p relationship, and results are compared with the use of a traditional steady-state method coupled with constant-volume-depletion (CVD) data. Results of the case studies show that RTA models that use the proposed So/p consistently yield more accurate OGIP estimation. Thus, this work presents a practical approach to remove commonly used yet potentially faulty assumptions in multiphase RTA applications for liquid-rich gas/condensate reservoirs.

The workflow to analyze hydraulic fracture effect on hydraulic fractured horizontal well production in composite formation system

Hydraulic fracturing generally leads to highly complex hydraulic networks for tight oil reservoirs. It is significant to understand the hydraulic fracture effect on well performance. As an effective tool, semi-analytical solution for well pressure transient analysis (PTA) and rate transient analysis (RTA) is used in large amount because of higher calculation efficiency than numerical solution. In this paper, the PTA and RTA methods and result of composite formation system (CFS) are shown comprehensively. Firstly, a mathematical model of multistage fractured horizontal well (MsFHW) in CFS was proposed for tight oil reservoir with different regions and formation properties. In the model, two regions with different formation parameters were distinguished. This assumption of two regions, i.e. CFS is a composite tight reservoir formed after hydraulic fracturing. Difference of finite hydraulic fracture conductivity, inclined angle of hydraulic fracture, different shapes of multi-wing fractures in perforating point are considered to make this model powerful to analyze production performance of different MsFHW types. The inner and outer regions were assumed as dual porosity medium but single porosity medium model can also be solved by simplification. Then, the solution of MsFHW performance analysis model is obtained by source function method and the source function superposition principle which are common used in PTA and RTA. PTA for well producing at a constant production rate and RTA for well producing at a constant wellbore pressure were obtained and discussed. Different flow regimes were divided for different fracture geometry situations. The effects of different MsFHW types on PTA and RTA were analyzed. The inflow performance for different hydraulic fractures were presented. Cited as : Yuan, J., Jiang, R., Zhang, W. The workflow to analyze hydraulic fracture effect on hydraulic fractured horizontal well production in composite formation system. Advances in Geo-Energy Research, 2018, 2(3): 319-342, doi: 10.26804/ager.2018.03.09

A review of stimulated reservoir volume characterization for multiple fractured horizontal well in unconventional reservoirs

Unconventional resource exploration has boosted U.S. oil and gas production, which is successfully by horizontal well drilling and hydraulic fracturing. The horizontal well with multiple transverse fractures has proven to be effective stimulation approach could increase reservoir contact significantly. Unlike the single fracture planes in typical low permeability sands, fractures in shales tends to generate more complex, branching networks. The concept of stimulated reservoir volume (SRV) was developed to quantitative measure of multistage fracture interact with natural fractures in unconventional reservoir. However, the simple fracture modeling of the past do not suitable for the complex scenarios simulation. This paper reviews the mainstream characterization method of stimulated reservoir volume in shale reservoirs, including microseismic interpretation, rate transient analysis method, analytical and semi-analytical method and numerical method. Finally, the systematic evaluation of application conditions with respect to each method and further research directions for characterization method are proposed.

Rate-transient analysis of an undersaturated CBM reservoir in Australia: Accounting for effective permeability changes above and below desorption pressure

Rate-transient analysis (RTA) of coalbed methane (CBM) wells is an on-going reservoir engineering challenge because of the dynamic nature of coal reservoirs. During their lifetime, producing CBM wells completed in initially undersaturated reservoirs (flowing above desorption pressure) experience a change from single-phase water to two-phase (gas + water) production as desorption pressure is reached, and the production characteristics of these wells are affected by a multitude of dynamic CBM reservoir properties. Amongst the most important dynamic properties influencing production is absolute permeability of the natural fracture (cleat) network.Prolific coalbed methane wells in the Fairview Field, central Queensland, eastern Australia, exhibit stress-dependent permeability changes during early dewatering, followed by strong desorption-dependent permeability effects below desorption pressure. These effects, combined with the switch from single-phase to two-phase flow at desorption pressure, make quantitative production data analysis for reservoir properties (e.g. permeability and original gas-in-place) particularly challenging.In this study, a combination of flowing material balance (FMB) equations for gas and water, modified for dynamic changes in effective permeability, and analytical simulation is used to analyze a Fairview Field CBM well completed in coals of the Bandanna Formation using the cavitation technique. The subject well exhibits strong permeability changes for the first several years after desorption pressure is reached, after which permeability changes appear to occur more gradually. Single-phase water production data above desorption pressure is analyzed using an FMB method modified for stress-dependent permeability; gas production data below desorption pressure is analyzed using an FMB method modified to account for relative permeability and desorption-dependent permeability. Because of uncertainty in below-desorption pressure FMB model inputs, the FMB equations and analytical simulation are linked. This approach allows for a consistent, if not unique, analysis.The RTA approach outlined herein provides a reasonable starting point for more rigorous numerical simulation, which in turn can be used for reserves forecasting and development planning. Because of the multitude of reservoir properties (several of the key properties being dynamic) affecting the production characteristics of CBM wells such as those in the Fairview Field, it is important to advance RTA methods to constrain numerical model inputs.

Quantitative determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs by free-simulator approach

Abandonment pressure of shale gas reservoirs has been in the center of attention to evaluate the CO2 storage in such reservoirs. However, the evaluation of abandonment pressure in shale gas reservoirs is not clearly defined. To quantitatively determine the abandonment pressure for CO2 storage in depleted shale gas reservoirs, we introduced two effective and reasonable semi-analytical models, named pressure transient analysis (PTA) and rate transient analysis (RTA), based on a free-simulator approach. Firstly, by line source function, CO2 seepage models for an injection well with constant injection rate or constant injection pressure were simultaneously proposed in consideration of gas adsorption, diffusion flow, stress sensitivity and non-Darcy flow effects. Then, we solved seepage models using Laplace transformation, perturbation method, superposition principle and numerical discretization method, thus obtained transient-pressure and transient-rate solutions of the injection well. Further, we compared the proposed mathematical models with existing models. Furthermore, we systematically examined the sensitivity of the parameters, thereby constraining the intrinsic uncertainty to evaluate the abandonment pressure. Finally, we applied the proposed method to study a real case from Sichuan Basin in China, thus demonstrating the promising prosperity of this new quantitative determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs.Our results showed that the maximum difference between our proposed method and numerical method was lower than 5%, suggesting a good agreement between the two methods. Moreover, our results also showed that free-simulator approach gave much faster calculation speed compared to numerical method. As a result, we provided a framework for the quantitative determination of abandonment pressure, by coupling pressure transient analysis (PTA) and rate transient analysis (RTA) during CO2 injection at constant injection pressure and injection rate. Moreover, our results also showed that the abandonment pressure has power law relationship with the injection pressure using PTA method, and the abandonment pressure has logarithm relationship with CO2 injection volume using RTA method.

Rate-transient analysis of liquid-rich tight/shale reservoirs using the dynamic drainage area concept: Examples from North American reservoirs

The early-time performance of multi-fractured horizontal wells is mainly controlled by fracture geometry, total effective area of the fractures, and conductivity of the primary fracture system. Inverse modeling using rate-transient analysis (RTA) methods has historically been used to characterize MFHWs at different stages of well life, including the early-time performance. In particular, linear flow analysis is used to estimate the total effective fracture area from online production data, provided that reservoir and fluid properties are known. However, a primary complication in analytical linear flow analysis is the incorporation of nonlinearities such as multi-phase flow and pressure-dependent rock/fluid properties into the calculations.A new linear flow analysis technique is presented in the current study, which can be applied to tight/shale systems with multi-phase flow and pressure-dependent rock/fluid properties. The method combines three important reservoir engineering concepts for linear flow analysis: dynamic drainage area (DDA), material balance, and decoupling of saturation and pressure (which is analogous to the decoupling of geomechanics and fluid flow). The DDA approach has been used previously by the authors for history-matching and forecasting using a semi-analytical model, but not for inverse modeling (RTA). The DDA concept, which uses a time-dependent well productivity index equation for the transient flow period, facilitates the incorporation of any sort of nonlinearity (including decoupled saturation functions) and operational constraints in modeling and RTA of linear flow in MFHWs.The method is validated against numerical simulation and applied to various sets of field production data from tight/shale gas and oil wells with different levels of condensate- (oil-) gas ratio. For all the field cases, total effective fracture area obtained from the new analytical RTA method is in reasonable agreement with numerical modeling results.Regarding accuracy and practicality, the new method represents an improvement in RTA of liquid-rich tight/shale reservoirs, particularly for cases with multi-phase flow and pressure-dependent rock/fluid properties. Further, the concepts used in the new model development are easy to understand and implement.

Comprehensive application of semi-analytical PTA and RTA to quantitatively determine abandonment pressure for CO2 storage in depleted shale gas reservoirs

Recent studies suggest the possibility of CO2 sequestration in depleted shale gas reservoirs, motivated by large storage capacity estimates in these formations. Although various approaches have been proposed to evaluate and estimate CO2 storage capacity and even almost all of researches mainly focus on the calculation of storage capacity at the present time, questions remain regarding the quantitative determination of abandonment pressure for a depleted shale gas reservoir, which is a key joint between shale gas recovery and CO2 storage operation. Also the determination of abandonment pressure is the inversion problems of estimation of CO2 capacity. Therefore, in this paper, to quantitatively determine the abandonment pressure and mathematically analyze related impacts of dynamic parameters on it, two semi-analytical models of pressure and rate transient analysis are simultaneously proposed for the closed outer boundary condition, without the assumption of sequential flow between the three contiguous media. Adsorption, desorption, diffusion flow, stress sensitivity and non-Darcy flow effects are simultaneously considered. Besides, a new modified Langmuir isotherm equation of CO2 is initially established to consider the impacts of residual adsorption shale gas. Laplace transformation, source function, perturbation transformation method, superposition principle and numerical discretion method are employed to effectively solve these new models. Laplace solutions are inverted into real time space with stehfest numerical inversion algorithm. Numerical simulation and existing models are also simultaneously conducted to validate this proposed mathematical models. Based on this new solution, some crucial dynamic engineering parameters, including abandonment pressure and non-Darcy flow, are creatively analyzed combining pressure transient analysis (PTA) and rate transient analysis (RTA) For two kinds of CO2 injection control: constant injection pressure and constant injection rate, it is the essence of this paper that typical chart referring quantitative determination of abandonment pressure is originally established via pressure transient analysis (PTA) and rate transient analysis (RTA). Via regression method using synthetic and real data, results mathematically show that for PTA method, the abandonment pressure has exponent relationship with the injection pressure, however, for RTA method, the abandonment pressure has logarithm relationship with CO2 injection volume. Finally, well testing of gas production data, micro seismic date and core analysis allow for formation parameter estimation, two real shale gas wells from Sichuan Basin in China are selected to show the promising application prosperity of the new performance analysis and quantitatively determination of abandonment pressure for CO2 storage in depleted shale gas reservoirs.

Transient flow analysis and partial water relative permeability curve derivation for low permeability undersaturated coalbed methane wells

Rate transient analysis (RTA) is an important reservoir engineering tool used to extract reservoir and stimulation information from flow rates and pressures obtained from producing wells. Adaptation of analytical RTA methods for this purpose has been slow for coalbed methane (CBM) reservoirs because of the complexities of multi-phase flow, non-static absolute permeability, desorption, among others. Some progress has been made historically for high permeability CBM reservoirs, where depletion (boundary-dominated flow) occurs quickly, however low permeability CBM reservoirs are currently being evaluated internationally (e.g. China), which brings forward additional challenges. For example, in some instances, low permeability, undersaturated CBM wells exhibit long periods of transient flow, during which the transition from single-phase flow of water to two-phase flow of gas and water occurs. This behavior has not been dealt with rigorously in the development of analytical RTA methods. It is the purpose of the current work to extend RTA to apply to low-permeability, undersaturated CBM wells exhibiting this behavior.The horizontal CBM well studied in this work exhibits two periods of apparent transient linear flow separated by a transition, as determined from diagnostic analysis of water production data using a log–log plot of rate-normalized pressure (RNP) versus time. It is hypothesized that the well actually exhibits transient linear flow throughout the entire studied production period (supported by reservoir simulation) and that productivity changes leading to the apparent transition in flow regime are caused by the combined effects of relative permeability changes after desorption pressure is reached, and (possibly) fines migration and stress-dependent permeability. In order to extend the early single-phase linear flow analysis of this well (occurring above desorption pressure) to the multi-phase period (below desorption pressure), the RNP half-slope trend (linear flow) established during the single-phase flow period is extrapolated through the rest of the production period. An RNP ratio (RNPR) is then created by calculating the ratio of the extrapolated (corrected) RNP and the RNP of the uncorrected field data. The RNPR can then serve to correct the production data affected by multi-phase flow (and possibly fines migration and stress dependent permeability) and hence extend the amount of data that can be used for production analysis. Further, the RNPR squared, combined with water saturation calculations, may be used to derive water relative permeability curves from the transient data. These concepts are tested using both numerical simulation and field data. The resulting field-derived water relative permeability curve can be used as a solid starting point for simulation history-matching, although it covers a limited range of water saturations.This work should be of interest to professional engineers and geoscientists involved in CBM reservoir characterization efforts. Future work will determine if these concepts are applicable to other low-permeability reservoirs exhibiting the transition from single- to multi-phase flow during the transient linear flow period, such as tight oil and gas condensate reservoirs.

Practical Aspects of Reserves Determinations for Shale-Gas Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144357, ’Practical Aspects of Reserves Determinations for Shale Gas,’ by R. Strickland, SPE, D. Purvis, SPE, The Strickland Group, and T. Blasingame, SPE, Texas A&M University, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 12-16 June. The paper has not been peer reviewed. Uncertainty in shale-gas reserves has significant implications at both the micro and the macro level. Conventional reservoir-engineering tools must be viewed as potentially inadequate (or even inappropriate) for evaluating shale-gas performance, primarily because of the extremely low aggregate permeability of these systems. Methods for shale-gas evaluation are discussed (including methods and limitations) that represent the physics of shale-gas production more closely; however, their implementation often is prohibitive. Introduction Although some 20,000 horizontal shale wells have been drilled, the longest production history available is approximately 6 years. To complicate matters further, the nature of shale development creates an urgent need for accurate predictions of recovery very early in the life of a play. The industry’s ability to interpret well logs, analyze core, and understand (at least qualitatively) the geological controls on production has increased vastly and has proved to be more important than acknowledged previously. Those geological factors are more numerous and more complexly interrelated than for conventional reservoirs. Engineering Methods Depending upon how the methods are grouped, there are six basic engineering techniques for determining reserves in general: volumetrics, analogy, production performance, material balance, simulation, and, most recently, rate-transient analysis (RTA). Each method has its own predicates and limitations. In the case of shale gas, they also have their own idiosyncrasies for accurate application. Material balance is not suitable because the ultralow matrix permeability makes obtaining average reservoir pressure impractical. With volumetrics, improvements in core and petrophysical analyses have led to reasonable estimates of gas in place; however, the recovery factor to be applied to an in-place figure is imprecise at best. The many difficulties caused engineers to rely heavily on the simplest, most accessible tool: production-decline analysis. Often, very large asset purchases or even entire plays have been reduced to a single type curve on the basis of production performance. This fact concentrates and, thus, amplifies potential error. Without the benefit of good analogs or sufficient guidance from first principles, it is possible, even likely, that production analysis results in a carelessly optimistic view of ultimate recovery. Fortunately, concentrated effort by many engineers and academics has significantly advanced the understanding of, and analysis tools for, shale gas. Simulation, RTA, and decline-analysis methods have demonstrated usefulness in shale-gas reservoirs, but they must be applied in a manner consistent with the uniquenesses of shale reservoirs.