Boundary-dominated Flow Research Articles

A new production analysis method for shale gas well based on the evaluation of decline parameters in advance

Production forecasting for multi-fractured horizontal well (MFHW) in shale gas reservoir is of vital importance to the evaluation of development potential.In this paper, we develop a new method to predict production of the MFHW under constant bottom-hole Pressure (BHP) condition. Based on the analytical model, well's life cycle is divided into two stages, in which the decline models are established, respectively. According to these models, the decline exponent is a function of fluid properties, the pressure drawdown strategy and heterogeneous completion. It can be directly calculated without production data matching. Influence of desorption on decline exponent, calculation of “initial pressure” during boundary dominated flow (BDF) period, are discussed. A workflow is established to perform production forecasting for a MFHW with complex fracture configuration and constant BHP in shale reservoir. A preliminary scheme is also developed to extend the workflow to variable BHP condition. Results indicate that a special hyperbolic model in which decline exponent changes as pressure drops, can be employed to forecast production during BDF. A constant decline exponent may result in an underestimation/overestimation well production, especially, in the BDF period. This new method can be used to explore how each factor impacts well productivity rigorously. Compared with conventional methods, it is of higher accuracy when making production forecast, especially for wells with short history.

Machine-learning predictions of the shale wells’ performance

The ultra-low permeability nature of shale reservoirs leads to an extended linear flow and necessitates horizontal wells with multi-stage engineered fractures to efficiently extract hydrocarbons resources. These artificially-generated and naturally-occurring fractures form complex networks that create complex flow regimes which control oil production. These fractures are neither identical nor equally-spaced, which leads to a production profile with a masked onset of the boundary-dominated flow. The combination of the extended linear flow with the indeterminate onset of the boundary-dominated flow challenges the current deterministic analytic approaches to forecast the estimated ultimate recovery (EUR). Herein, we propose a novel machine-learning approach which overcomes these challenges and provides reliable EUR estimates based on field-wide analyses. We implement a novel unsupervised machine learning (ML) methodology, which allows for automatic identification of the optimal number of features (signals) present in the data based on non-negative matrix/tensor factorization coupled with k-means clustering incorporating regularization and physics constraints. In the presented analyses, the input data to the ML algorithm is the available (public) production history from the field collected at existing unconventional reservoirs. We validate our approach through hindcasting of the production data, where we achieved an excellent agreement. In addition, our approach is able to identify the poorly-performing wells, which could benefit from early refracing. Our approach provides fast and accurate estimations of the well performance without presumptions about the state of the well or the flow regime.

Implications of Aggregating and Smoothing Daily Production Data on Estimates of the Transition Time Between Flow Regimes in Horizontal Hydraulically Fractured Bakken Oil Wells

The level to which data are aggregated or smoothed can impact analytical and predictive modeling results. This paper discusses findings regarding such impacts on estimating change points in production flow regimes of horizontal hydraulically fractured shale oil wells producing from the middle member of the Bakken Formation. Change points that signal transitions in flow regimes are important because they subsequently affect estimates of ultimate recovery from wells producing from shale plays. Extending our earlier work, we employ two different statistical approaches, Bacon–Watts Bayesian regression and nonlinear constrained least squares regression, and a designed computational experiment to estimate the time of transition from the transient to the boundary-dominated flow regime for 14 different wells using daily production data rather than aggregated monthly data, as previously considered. The daily data were also smoothed to reduce noise. Computational experiments suggest that both statistical approaches can lead to plausible estimates of the transition point under different data aggregation or smoothing regimes, but that daily data are likely too granular to produce credible estimates. Although the expected value of transition points using smoothed daily data and monthly disaggregated data are generally comparable, the confidence intervals bounding the estimates based on smoothed daily data are generally wider. Our results not only inform the operational practices of oil producers engaged in economic evaluation of their shale resources and additional play development activities, but also the activities of petroleum research groups, government agencies, and financial organizations seeking to improve the trustworthiness of resource projections.

Gas rate decline analysis for boundary-dominated flow with fractal reservoir properties under constant / variable bottom-hole pressure conditions

Current gas rate decline analysis methods in boundary-dominated flow (BDF) are mainly based on Arps' empirical decline models, or the liquid-based analytical models associating with pseudo-variables. Recently, Stumpf and Ayala (2016), and Wang and Ayala (2020) demonstrated that the decline exponents (b) used in Arps’ hyperbolic model can be rigorously estimated in advance for both constant and variable conditions regardless of reservoir properties and before collecting any production data. In this paper, we further investigate the gas rate flow behavior for heterogeneous reservoir, which is characterized by fractal properties. The decline exponents (b) are thus re-derived based on the gas flow rate equation in BDF, and it is shown that the expression of decline exponents can be written in the same format with homogeneous reservoir by defining new productivity indexes. This allows for the application of the step-by-step explicit original-gas-in-place (OGIP) determination methods proposed by Stumpf and Ayala (2016), and Wang and Ayala (2020) in fractal radial flow. However, due to the heavily pressure depletion before BDF for linear flow, the average value of decline exponent (donated as bi) is not available any more. Therefore, our explicit OGIP determination method CANNOT be directly applied, which would lead to the underestimation of the true value if it is blindly used. Finally, several simulated cases are discussed to validate the capabilities of the methodology. The finding of this study can help for better understanding of the gas rate decline behavior in heterogeneous reservoirs.

Average Fracture Compressibility from Flowback Data

Summary We propose a novel method for estimating average fracture compressibility cf¯ during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate cf¯ by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The cf¯ estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our cf¯ estimates (4 to 22×10−5 psi−1) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.

A semianalytical well-testing model of fracture-network horizontal wells in unconventional reservoirs with multiple discretely natural fractures

Microseismic data shows that some unconventional reservoirs comprise well-developed natural fractures and complex hydraulic fracture networks. It is neither practical nor advantageous to simulate a huge number of natural and hydraulic fractures with numerical models. Given that the conventional dual-porosity models are not applicable to the highly discrete natural fractures, the paper develops a semianalytical well testing model for horizontal wells with hydraulic fracture networks and randomly-distributed discretely natural fractures.The proposed model has the capability to analyze the pressure behaviors by considering complex fracture networks and isolated natural fractures rapidly and efficiently. The model includes diffusivity equations in three domains: (1) matrix, (2) discretely natural fractures, and (3) hydraulic fracture networks. The pressure transient solution of these diffusivity equations is obtained by using Laplace transforms and superposition principle. We verify the presented model by performing a case study with a numerical simulator for complex natural fractures.It is found that there are some interesting flow behaviors for fracture-network horizontal well with discretely natural fractures like bilinear flow, “V-shape” caused by fluid supply, pseudo boundary-dominated flow, impact of natural fractures, etc. The pseudo boundary-dominated flow provides us the information about how large the area covered by hydraulic fracture networks. The impact of natural fracture shows the parameters of natural fractures. This work provides a good understanding of transient pressure behaviors in unconventional reservoirs and guidelines for the producer optimize field development and well economics.

Analysis of early-time production data from multi-fractured shale gas wells by considering multiple transport mechanisms through nanopores

Analysis of early-time production and flowback data from multi-fractured shale gas wells is of critical importance in the characterization of hydraulic fractures (HF). However, the accurate estimation of HF properties in the current models is challenged by the complexity in multiple transport mechanisms and two-phase flow of shale gas reservoir. This study presents a new semi-analytical method to estimate HF attributes for shale gas wells exhibiting two-phase flow based on straight line analysis. The proposed method considers two-phase infinite acting linear flow (IALF) and boundary dominated flow (BDF) for both HF and matrix domains. In addition, matrix flow considers desorption, diffusion, slip flow, continuum flow, stress dependence rock, and adsorbed water film in the nanopores. A modified material balance equation is proposed to calculate average pressure in the fracture and distance of investigation (DOI) in the matrix by considering gas desorption and diffusion in the matrix domain. The accuracy of the proposed method is tested against numerical results obtained from commercial software (IMEX-CMG). The validation results confirm that the developed method can closely estimate initial fracture volume, permeability, and permeability modulus from early-time production data exhibiting two-phase IALF and BDF regimes. Furthermore, the results indicate that the consideration of desorption, diffusion, and slip flow plays an important role in the modeling of gas transport in shale matrix. The impact of these transport mechanisms on production modeling as well as characterization of HF properties becomes significant when the matrix experiences substantial pressure drops. For the purpose of field application, the proposed method is used to analyze flowback data from a multi-fractured horizontal well. The field results reveal that the calculated fracture properties are consistent between the proposed method and the long-term production data analysis method.

Gas and Water Rate Forecasting of Coalbed Methane Reservoirs Based on the Rescaled Exponential Method

Abstract The traditional production data analysis (PDA) techniques for gas wells largely relied on the implement of pseudo-functions and related type curve methods. Recently, Ye and Ayala (2012 “A Density Diffusivity Approach for the Unsteady State Analysis of Natural Gas Reservoirs,” J. Nat Gas Sci. Eng., 7, pp. 22–34.) proposed a new rescaled exponential method which can successfully capture the behavior of gas well under boundary-dominated flow (BDF) conditions with the density-based parameters. In this paper, this rescaled exponential method is extended in coalbed methane (CBM) reservoirs by accounting for the two-phase flow behavior, and the variable permeability characteristics in the coal seams that caused by mechanical compression, desorption shrinkage, and the desorption effect. The two-phase rescaled exponential solution for CBM reservoir is derived by modifying the definition of two-phase pseudo-pressure and total compressibility. The proposed rescaled method can evaluate reserve in a convenient and accurate way. Results show that the proposed modification of the original rescaled exponential approach can successfully predict the production of CBM reservoirs compared with the results of commercial numerical simulator (GEM-CMG) and production data of the field cases on the condition of constant bottom hole pressure.

Monte Carlo simulation and production analysis for ultimate recovery estimation of shale wells

The current scheme for developing shale reservoirs necessitates special considerations while estimating the reserve. While reservoir characteristics lead to an extended infinite acting flow regime, completion schemes could result in a series of linear flows. Therefore, the initial linear flow does not have to be followed by a boundary-dominated flow. Overlooking this observation leads to unphysical Arps' exponents and overestimations of the Estimated Ultimate Recovery (EUR). We are proposing a workflow to overcome these challenges and honor the inherited uncertainty while using the classic Arps (1956) hyperbolic forecast. Our workflow starts with identifying the current flow regime of the well where two intermediate flow regimes are considered, namely Linear-post-Linear (LPL) and Linear Post Linear Post Linear (LPLPL) flow regimes. We deterministically forecasted the boundary-dominated wells and probabilistically forecasted the rest. We used the distribution of the current flow regime in the field to forecast the transient wells. The well features of the infinite/semi-infinite wells are stochastically sampled from the field database combining well features of the boundary-dominated wells. After that, Monte Carlo simulation is employed to probabilistically estimate the EUR. We constrained the well life by an economical limit or a maximum of 40 years. We selected Bone Springs formation as a field study of this workflow. We found that the LPL is the common current flow regime. A reduction in Arps’ exponent is observed when well experience an intermediate linear flow before boundary-dominated flow. Significant number of interference wells are identified through their Water/Oil Ratio (WOR) signature. We also studied the evolution of EUR which suggests that more than 75% of the production history is needed for the deterministic methods to provide reliable estimates of the EUR. We generated heat maps of the area of interest to summarize the EUR and remaining reserve results.

Integrated approach for non-Darcy flow in hydraulic fractures considering different fracture geometries and reservoir characteristics

Abstract The motivation is eliminating the uncertainties in predicting reservoir performance, and reducing the errors in the reservoir characterization resulted by neglecting the impact of non-Darcy flow. In this study, an analytical multi-linear flow regimes model has been developed for pressure distribution in hydraulically fractured reservoirs and modified for the existence of non-Darcy flow by introducing the rate-dependent skin factor to the flow equations. This model is solved for different impacts of non-Darcy flow by assuming a constant flow rate and different non-Darcy flow coefficients. The effects of different cross-section areas of flow inside hydraulic fractures on the non-Darcy flow coefficient are considered in this study as well as different fracture conductivities. Reservoir configurations and petrophysical properties are also considered in calculating pressure distributions. Analytical models for hydraulic fracture linear flow regime, bi-linear flow regime, and boundary-dominated flow regime are developed based on pressure responses for different non-Darcy flow impact. Analytical models for transient and pseudo-steady state productivity indices are presented in this paper to demonstrate the impact of non-Darcy flow on these indices. The results of this study showed there are considerable effects of non-Darcy flow on reservoir performance and developed analytical mathematical models for recognized flow regimes which observed during reservoir production period. Additionally, results illustrated the reservoir configurations and petrophysical properties may not have significant contribution in developing non-Darcy flow. Finally, the productivity index has been sharply declined for later production time. Meanwhile, it is constant for high rate-dependent skin factors at the early time of production.

A Semianalytical Method for Two-Phase Flowback Rate-Transient Analysis in Shale Gas Reservoirs

Summary We propose a new semianalytical method for analyzing flowback water and gas production data to estimate hydraulic fracture (HF) properties and to quantify HF dynamics. The method includes a semianalytical flowback model, a set of two-phase diagnostic plots, and a workflow to evaluate initial fracture volume and permeability, as well as fracture compressibility and permeability modulus. The flowback model incorporates two-phase water and gas flow in both HF and matrix domains and considers variations of fluid and rock properties with pressure. The HF domain is modeled by boundary-dominated flow, whereas an infinite-acting linear flow is assumed for the matrix domain. The flowback model is developed by assigning the variable average pressure in the fracture as the inner boundary condition for matrix according to Duhamel's principle. The average pressure in the fracture and distance of investigation (DOI) in the matrix are calculated from a modified material-balance equation by updating the matrix DOI as well as phase saturation and relative permeability in both the fracture and matrix domains. A modified DOI equation is used for two-phase flow in the matrix, which considers the pressure-dependent fluid and rock properties in pseudotime. The diagnostic plots shed light on the identification of flow regimes during the coupled two-phase flow in both fracture and matrix. The proposed workflow quantifies the HF dynamics through the loss of both fracture volume and fracture permeability by reconciling flowback and long-term production data. The accuracy of the new method is tested against numerical simulations conducted by a commercial numerical simulator. The validation results confirm that the proposed method accurately predicts initial fracture volume, permeability, and permeability modulus. Further, we use production data from a multifractured horizontal well (MFHW) drilled in Marcellus Shale to test the practicality of the proposed method. The results show a significant reduction in fracture volume and permeability during production attributable to the HF closure.

A novel workflow for water flowback RTA analysis to rank the shale quality and estimate fracture geometry

Recently, flowback data analysis enabled us to evaluate important fracture parameters including fracture conductivity and volume in unconventional reservoirs. To perform the analysis, diagnostic plots, straight-line techniques, and history-matching techniques have been used. Immediate water and gas production usually occurs on flowback in shale gas wells. In this paper, a novel workflow is developed for the analysis of water flowback data and the early-time production of shale gas wells. This analysis then helps to define the movable water and the applicability of the soaking process on these wells.Rate transient analysis (RTA) combined with decline curve analysis (DCA) were used to analyze different shale gas wells. Effective fracture volume and geometry were calculated from the RTA analysis. The estimated ultimate water recovery (EURw) was calculated from DCA. The calculated original water-in-place (OWIP) and the EURw were compared to the injected fracturing fluid. The impact of the soaking process on the well performance was studied.Results showed that in high-quality shale wells, with no movable formation water, gas kicked off early. OWIP was equal to the total injected water volume, and boundary dominated flow (BDF) regime was observed with no transient period. The performance of these wells improved with soaking.On the other hand, in low-quality shale wells, initial formation water saturation was higher than the connate water, and water production was from both the frac fluid and formation water. Consequently, gas kicked off later and transient flow regimes were observed. Transient flow regimes were used to estimate the fracture stimulated area. In this case, however, soaking had a negative impact on the performance as the movable water saturation was high.Honoring the flowback data can be used to estimate the fracture geometry and judge the quality of the shale formation and its validity for the soaking process.

Integrated reservoir study using well-test deconvolution analysis and well-logging data in a gas condensate carbonate reservoir

This paper presents an integrated approach to characterize a gas-condensate carbonate reservoir using the combination of well-test deconvolution analysis, and well logging interpretation. Each set of data from the subject well, namely, petrophysical logs, production logs, surface well tests and drill-stem tests was analysed. Well test analyses was implemented using both pressure-derivative and variable-rate deconvolution techniques. An integrated analysis and interpretation of the results from different sources was performed. This approach was especially beneficial in reducing some uncertainties such as the layered nature of the reservoir, the heterogeneous behaviour, and boundary-dominated flow regimes. The application of deconvolved derivative increased the radius of investigation and duration of original constant-rate pressure from 24 hours to 140 hours, enabling us to detect the possible fault effect at late-times. This method was also used for performance evaluation of an acid treatment job in the wellbore. It was found that after acidizing, the total skin factor was severely reduced from 33 to 1.2, indicating a successful performance of the acidizing job.

Assessing the hyperbolic trend in well response involving pressure, fluid and heat-flow rates

This paper explores the application of the Arps’ hyperbolic relation beyond the rate-decline analysis for reserves assessment in conventional reservoirs. Although intended for the late-time boundary-dominated flow, the hyperbolic approach appears to work well for both the transient temperature and -pressure responses to attain the equilibrium condition. Given the simplicity and ease of use, this approach should gain traction among practitioners.The temperature responses remain in a transient state in a typical shut-in period, given the slow nature of heat diffusion compared to its fluid counterpart. Also, in a complex reservoir geometry, pressure transients may take a substantial period to reach all the boundaries to convey the desired average-reservoir pressure. More importantly, the admixture of no-flow and constant-pressure boundaries in a reservoir flood environment virtually negates the application of the conventional analytical tools, unless rate-transient analysis or related methods can be applied in the reservoir-depletion stage.This paper attempts to provide credence to the proposed solution approach by way of using the simulated pressure-transient responses in various reservoir geometries, and temperature buildup and falloff responses obtained from field data. In both cases, we show that the Arps’ method, initially intended for analyzing rate decline in a boundary-dominated system, can be used for analyzing transient pressure and temperature responses for estimating their respective current conditions. Overall, we used several synthetic cases involving both oil and gas reservoirs. Field examples included gas leakage for annular pressure buildup, gas decline rate in a coalbed-methane reservoir, and studying temperature transients in a gas well.

Post-flowback production data suggest oil drainage from a limited stimulated reservoir volume: An Eagle Ford shale-oil case

We analyze flowback and post-flowback production data from six multi-fractured horizontal wells completed in Eagle Ford shale formation. Petrophysical analysis of samples from an offset well shows that the target shale is in oil window with type II kerogen. We analyze two groups of wells with different well-completion and operational parameters. Wells fractured with slickwater, with higher total injected volume (TIV) and larger choke size show higher initial oil rate, but faster pressure depletion compared with the wells fractured with cross-linked gel, with lower TIV and smaller choke size. Both groups show supercharged fractures when flowback starts and reservoir pressure remains above bubble point during post-flowback period. Interestingly, rate-normalized pressure plots of oil and water from both groups during post-flowback period show pronounced unit slope indicating boundary dominated flow (BDF), while this trend is not observed during flowback period. Analysis of rate-normalized pressure and rate-decline data suggests that both oil and water are produced from a closed tank under BDF conditions. We propose a multiphase flowing material balance (FMB) model to describe water and oil production from an effective stimulated reservoir volume (ESRV) during post-flowback period. The proposed FMB model assumes negligible oil and water influx into ESRV. The driving forces considered are closure of fractures and expansion of oil and water in ESRV. Applying the proposed model on post-flowback data confirms that after fracture depletion, oil is produced from highly stimulated matrix around hydraulic fractures while water is mainly produced from fractures.

Comparison of the Methods for Analyzing Rate- and Pressure-Transient Data from Multistage Hydraulically Fractured Unconventional Gas Reservoirs

Summary In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate- and pressure-transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed in this study do not address complex transport mechanisms and complex fracture networks, but do address transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary-dominated flow (BDF). The methods for BDF are the contacted-volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the flowing material-balance (FMB) methods. The Agarwal-Gardner FMB method (Agarwal et al. 1999) and the conventional FMB method involve plotting rate-normalized pseudopressure vs. material-balance pseudotime. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes—constant rate (CR), constant bottomhole pressure (BHP) (CBHP), and variable-rate BHP—are considered. For comparison, various synthetic test data sets generated from a high-resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate-transient data, is used. Both synthetic noise-free and noisy-rate pressure-data sets considering wide ranges of initial reservoir pressure and BHP, as well as real-field data sets, are used to compare the methods. For linear flow, the Nobakht-Clarkson method (Nobakht and Clarkson 2012a, 2012b) yields the best results, although its use is tedious because it requires an iterative procedure. The Chen and Raghavan (2013) method for linear flow seems to provide results that are comparable with the Nobakht-Clarkson method (Nobakht and Clarkson 2012b) but does not require an iterative procedure. The Ibrahim-Wattenbarger method (Ibrahim and Wattenbarger 2006) for linear-flow analysis always overestimates flow capacity compared with the other methods. Among the methods that discuss the ending time of linear flow, it was found that the unit-impulse method from Behmanesh et al. (2015) provides the best results for predicting gas in place. For BDF, the results show that the Agarwal-Gardner FMB method (Agarwal et al. 1999) is quite vulnerable to the error in rate/pressure data, whereas the conventional FMB method is more robust to noise and provides more accurate estimates of gas in place.

A New Straight-Line Analysis Method for Estimating Fracture/Reservoir Properties Using Dynamic Fluid-in-Place Calculations

SummaryStraight-line analysis (SLA) methods, which are a subgroup of model-based techniques used for rate-transient analysis (RTA), have proved to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulic-fracture information, whereas boundary-dominated-flow (BDF) data can be interpreted for fluid-in-place estimates. Because transient-flow periods might be extensive, it is also advantageous to evaluate the volume of hydrocarbons in place contacted over time to assist with reserves assessment. The new SLA method introduced herein enables reservoir/fracture properties and contacted fluid in place (CFIP) to be estimated from the same plot, which is an advantage over traditional SLA techniques.The new SLA method uses the Agarwal (2010) approach for CFIP estimation, extended to variable-rate/pressure data for low-permeability (unconventional) reservoirs. A log-log plot of CFIP vs. material-balance time (for liquids) or material-balance pseudotime (for gas) is created, which typically exhibits power-law behavior during transient flow, and reaches a constant value [original fluid in place (OFIP)] during BDF. Although CFIP calculations do not assume a flow geometry, the SLA method requires this to extract reservoir/fracture information. Herein, transient linear flow (TLF) is assumed and used for the SLA-method derivation, which allows the linear-flow parameter (LFP) to be extracted from the y-intercept (at material-balance time or material-balance pseudotime = 1 day) of a straight-line fit through transient data. OFIP can also be obtained from the stabilization level of the CFIP plot.Validation of the new SLA method for an undersaturated oil case is performed through application to synthetic data generated with an analytical model. The new SLA results in estimates of LFP and OFIP that are in excellent agreement with model input (within 2%). Further, the results are consistent with the traditional SLA methods used to estimate the LFP (e.g., the square-root-of-time plot) and the OFIP (e.g., the flowing material-balance plot).Practical application of the new SLA method is demonstrated using field cases and experimental data. Field cases studied include online oil production from a multifractured horizontal well (MFHW) completed in a tight oil reservoir, and flowback water production from a second MFHW, also completed in a tight oil reservoir. Experimental (gas) data generated using a recently introduced RTA core-analysis technique were also analyzed using the new SLA method. In all cases, the new SLA-method results are in excellent agreement with traditional SLA methods.The new SLA method introduced herein is an easy to apply, fully analytical RTA technique that can be used for both reservoir/fracture characterization and hydrocarbon-in-place assessment. This method should provide important, complementary information to traditionally used methods, such as square-root-of-time and flowing material-balance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs.The method is currently limited to cases exhibiting single-phase flow, the flow-regime sequence of TLF to BDF, and reservoir homogeneity. In future work, these limitations will be resolved.

An equivalent single phase approach to production data analysis in gas condensate reservoirs

In gas condensate reservoirs (GCR) operating below dewpoint pressure, two-phase conditions introduce non-linearities into the diffusivity equation, rendering conventional single-phase production data analysis unreliable. Recent studies, presented in a companion paper published in 2018, demonstrated the application of an equivalent single phase approach to improve the quality of GCR production data analysis using “Blasingame” type curves. That study analysed production data from radial GCR simulation models with fluid maximum liquid dropout ranging from 1% to 42%. The pressure-saturation/kr data for the computation of equivalent-phase pseudovariables was determined using an approach based on two-phase steady-state (SS) theory. For saturated reservoirs, less consistent improvements in permeability, skin and drainage area estimates were obtained – an observation attributed to unrepresentative pressure-saturation/kr data.This current study builds on the earlier work, by examining alternative sources of pressure-saturation data for use in the analysis of saturated GCR cases. PVT liquid-saturation curves and sufficiently representative pressure-saturation responses from the near-wellbore region of numerical simulations are considered. The results suggest that pressure-saturation data representative of the response in the near-wellbore region during transient flow is adequate for the two-phase analysis of long term production data using type curves. The results further highlight reservoir and well operating conditions under which each source of pressure-saturation data is most suitable for use with the equivalent-phase approach. A new time-based adjustment is also introduced to improve the quality of the equivalent-phase type curve analysis for cases in which the entire reservoir becomes saturated prior to stable boundary dominated flow (BDF) conditions.Finally, results are presented which show that our equivalent-phase approach can be successfully combined with other conventional production data analysis tools, e.g. type curves for hydraulically fractured wells, and straight-line techniques used in the analysis of BDF data, all of which were originally developed for analysing single phase systems.

Rapid and accurate evaluation of reserves in different types of shale-gas wells: Production-decline analysis

The prediction of production levels and estimated ultimate recovery (EUR) with high accuracy is necessary for shale-gas development. Empirical decline methods are widely applied in the oil and gas industry owing to their simplicity and effectiveness; however, none of them can accurately predict the results for typical wells with fluctuating production or in transient flow (TF). To address the urgent issue, four empirical methods, namely the Arps' decline method, stretch exponential production-decline (SEPD) method, and two different patterns of rate decline for fracture-dominated reservoirs (the traditional Duong's method and Wk's method), are compared in terms of their principles and characteristics. The results show that the traditional Duong's method is the most reliable; therefore, improvements are proposed (the improved Duong's method) to overcome the influence of production fluctuations and multiple solutions when considering wells that have achieved boundary-dominated flow (BDF). For reasonable production and EUR forecasting in wells with a rapid and unstable decline in TF production, a hybrid method is proposed using a combination of Yu's modified method based on SEPD (YM-SEPD) and the improved Duong's method. The accuracy and universality of the improved Duong's method and the rationality and effectiveness of the hybrid method are evaluated through field examples in the Weiyuan Block of the Sichuan Basin.

To Interpret Rate Transient Analysis for the Determination of Reservoir Properties

Rate-time decline curve analysis is a major technique which is mostly used in petroleum engineering. Many methods are used for the determination of the decrease in the production rate within a given period of time. The main disadvantage of Arp’s decline type curve analysis is that it is only used for boundary dominated flow period; it is not used for transient flow period. The analysis of the Fetkovich is to determine the log-log type curve for both the transient flow period (early time period or infinite) and boundary-dominated flow period (late time period). Arps developed the type curve which shows the production rate decline with time for the finite reservoir or late time period. The exponential or constant flow decline, hyperbolic decline, and harmonic decline according to the value of decline curve exponent (b) is given by Arps. After that Fetkovich improved on earlier work done by Arps in predicting decline production rate of wells over a given period of time. The main objective of this study was to plotting the rate transient analysis curve. I will plot the Fetkovich type curve (combined early and late times region). The graph will be plotted between the dimensionless decline flow rate (qDd) and the dimensionless decline time” (tDd). This will be the objective of the study.