The Experts below are selected from a list of 312 Experts worldwide ranked by ideXlab platform

Luis F. Ayala - One of the best experts on this subject based on the ideXlab platform.

  • Application of Superposition Principle to Variable Rate/Pressure Production Analysis of Multi-Fractured Horizontal Wells in Unconventional Gas Reservoirs
    Journal of Natural Gas Science and Engineering, 2019
    Co-Authors: Miao Zhang, Luis F. Ayala
    Abstract:

    Abstract Application of superposition principle to non-linear gas governing equations has been an elusive goal in early-transient production data analysis and has been so far limited to the use of empirical and approximate methods best applicable to Boundary-Dominated Flow conditions. This paper presents a novel and rigorous semi-analytical model that is applicable for the analysis of production data from multi-fractured horizontal gas wells (MFHWs) producing under early-transient variable rate/pressure production conditions. Nonlinear, pressure-dependent hydraulic diffusivity retained in pseudo-pressure-based gas diffusivity equation is straightforwardly and rigorously captured without approximation. The resulting formulation of superposition applied in nonlinear gas system is written in terms of the classical solution for the governing linear partial differential equation (PDE) plus an analytical adjustment factor that quantifies the nonlinearity of the system. Numerical examples and field cases are presented to test the validity and showcase the capabilities of proposed approach. Comparisons against available empirical and approximate models are also provided for these cases.

  • Analysis of Multiphase Reservoir Production From Oil/Water Systems Using Rescaled Exponential Decline Models
    Journal of Energy Resources Technology-transactions of The Asme, 2019
    Co-Authors: Luis F. Ayala
    Abstract:

    In this study, we present an analytical approach based on rescaled exponential models that are able to analyze production data from oil/water systems producing under Boundary-Dominated Flow conditions. The model is derived by coupling two-phase oil/water material balances with multiphase well deliverability equations. Nonlinearities introduced by relative permeability in multiphase oil/water systems are accounted for via depletion-dependent parameters applied to each of the Flowing phases. This study shows that So–Sw–p relationships based on Muskat's standard assumptions can be successfully deployed to correlate saturation and pressure changes in these two-phase systems without the need for user-provided surface production ratios or well-stream composition information. The validity of the proposed model is verified by closely matching predictions against finely gridded numerical models for cases constrained by both constant and variable bottomhole pressure production. In addition, a straight-line analysis protocol is structured to estimate the original oil and water in place on the basis of available production data using rescaled exponential models. Finally, we explore conditions for validity of the assumptions used in the proposed model, including the So–Sw–p formulation, by conducting extensive sensitivity analysis on input parameters.

  • Use of rescaled exponential models for Boundary-Dominated liquid-rich gas Flow analysis under variable bottomhole pressure conditions
    Journal of Natural Gas Science and Engineering, 2017
    Co-Authors: Madhu Singh, Miao Zhang, Hamid Emami-meybodi, Luis F. Ayala
    Abstract:

    Abstract The analysis of production data from natural gas reservoirs can serve as one of the most powerful tools to estimate remaining reserves and provide a forecast of its future performance. While fundamentals of decline for dry gas reservoirs are well described in literature, those for liquid-rich gas reservoirs are yet to be well-understood. Any predictive model used to analyze these reservoirs must account for the inherent changes in reservoir fluid composition during their producing life due to condensate dropout within the reservoir, once reservoir pressure falls below dew point pressure. This study presents a mathematical model capable of predicting non-linear Flow behavior in multiphase gas-condensate reservoirs using rescaled exponential models applicable to Boundary-Dominated Flow regimes under variable bottomhole pressure conditions. We develop a set of analytical solutions for surface oil and total hydrocarbon Flowrates, for wells producing under variable bottomhole pressure. We model hydrocarbon production from gas-condensate reservoirs by employing a material balance over produced condensate and total hydrocarbons. In this material balance approach, we use equivalent fluid molar densities in multiphase systems, resulting in analytical equations for the different Flowing phases. The developed set of analytical solutions aims at providing an accurate estimate of reservoir behavior and available reserves, which can be used to inform critical economic decisions for further development of the reservoir. The proposed rescaled models minimize assumptions and stay true to the physics of multiphase Flow. We demonstrate that the developed analytical model closely predicts the numerical simulation results for the hydrocarbon Flowrates as well as the estimated reserves where a wide range of gas-condensate reservoirs, from lean to liquid-rich, is considered.

  • Rate forecasting during Boundary-Dominated multiphase Flow: The rescaled exponential model
    Journal of Petroleum Science and Engineering, 2016
    Co-Authors: Miao Zhang, Madhu Singh, Luis F. Ayala
    Abstract:

    Abstract Well performance forecasting is an important analytical technique used for field development to guide economic decisions during the life of a reservoir. For the case of dry and liquid-rich gas wells, traditional well performance models are developed based on solving the resultant highly nonlinear gas Flow equations via pseudo-pressure and pseudo-time linearization. In this study, we provide a straightforward, density-based alternative to traditional models. We show, as done previously for the case of dry gas wells ( Ayala H. and Zhang, 2013 , Zhang and Ayala, 2014a ), that a rescaled exponential model is a rigorous decline solution that can be extended to liquid-rich gas wells producing under constant bottomhole-Flowing-pressure (BHP) during Boundary-Dominated Flow (BDF) and multiphase conditions. The proposed multiphase rescaled-exponential model is derived analytically from governing multiphase Flow equations; comparisons between numerically simulated results and proposed analytical model for a variety of combinations of reservoir and fluid properties demonstrate that the proposed rescaled-exponential model is a valid and reliable forecast model for constant-BHP liquid-rich gas wells under BDF.

Salam Al-rbeawi - One of the best experts on this subject based on the ideXlab platform.

  • Pressure-rate convolution and deconvolution response for fractured conventional and unconventional reservoirs using new decline rate model
    Petroleum, 2019
    Co-Authors: Salam Al-rbeawi, Jalal F. Owayed
    Abstract:

    Abstract This paper introduces new approach for pressure-rate convolution and deconvolution analysis of multi-stages hydraulically fractured conventional and unconventional reservoirs. This approach demonstrates the impact of variable Sand face Flow rate on reservoir performance. A new model for P/R deconvolution is used to convert pressure pulse from variable Flow rate to single and constant rate response. The target of this study is fractal reservoirs with and without stimulated and unstimulated reservoir volume. Multi-linear Flow regimes approach is used to describe pressure behavior in the reservoirs while decline Flow rate behavior is described by newly proposed model in this study. This model depicts, instead of van Everdingen model, indirectly the declining rate with time by using pressure responses with production time. Decline Flow rate behavior simulated by linear and bi-linear Flow models are also studied and compared with the one obtained by the new model. Several analytical models are used in this study by applying P/R convolution and deconvolution technique and solved for constant and variable Flow rate considering different reservoir configurations and operating conditions. The results are interpreted and analyzed for better understanding pressure behaviors, Flow regime types, and productivity index trends for continuously changing Flow rate especially at early production time. Estimating stimulated reservoir volume ( V s r v ) is considered one of the applications of convolved pressure since it is calculated from pseudo-steady state Flow when late time boundary dominated Flow regime is reached. The outcomes of this study can be summarized as: 1) Introducing new approach for pressure-rate convolution and deconvolution technique for multi-stages hydraulically fractured reservoirs by applying new decline Flow rate model that indirectly simulates variable Flow rate with time. 2) Generating analytical models for dimensionless pressure and Flow rate for constant and variable Flow rate using the concept of P/R convolution and deconvolution. 3) Comparing the result of newly proposed models with the results obtained by applying van Everdingen model for decline rate behavior. 4) Studying the applicability of linear and bi-linear Flow models in converting variable Flow rate pressure response to single and constant Flow rate pressure response. 5) Applying the deconvolution technique to simulate pressure response at late production time to estimate stimulated reservoir volume. The most interesting points are: 1) The main difference in wellbore pressure behavior between variable and constant Flow rate can be seen at early production time, however intermediate production time could also show very limited changes for the case of variable rate wellbore pressure. 2) A unit slope line Flow regime could be developed for varied Flow rate pressure response at very early production time similar to the wellbore storage dominated Flow regime. 3) Productivity index calculated by the proposed models for variable Flow rate is greater than the index for constant Flow rate. 4) The impact of petrophysical properties of porous media and hydraulic fracture characteristics on pressure response are similar in the two cases of variable and constant Flow rate. 5) The decline rate models for linear and bi-linear Flow are not applicable in pressure deconvolution technique.

  • Transient and Pseudo-Steady-State InFlow Performance Relationships for Multiphase Flow in Fractured Unconventional Reservoirs
    Transport in Porous Media, 2019
    Co-Authors: Salam Al-rbeawi
    Abstract:

    The objective of this paper is developing new methodology for constructing the inFlow performance relationships (IPRs) of unconventional reservoirs experiencing multiphase Flow. The motivation is eliminating the uncertainties of using single-phase Flow IPRs and approaching realistic representation and simulation to reservoir pressure–Flow rate relationships throughout the entire life of production. Several analytical models for the pressure drop and decline rate as wells productivity index of two wellbore conditions, constant Sandface Flow rate and constant wellbore pressure, are presented in this study. Several deterministic models are also proposed in this study for multiphase reservoir total mobility and compressibility using multi-regression analysis of PVT data and relative permeability curves of different reservoir fluids. These deterministic models are coupled with the analytical models of pressure drop, decline rate, and productivity index to construct the pressure–Flow rate relationships (IPRs) during transient and pseudo-steady-state production time. Transient IPRs are generated for early-time hydraulic fracture linear Flow regime and intermediate-time bilinear and trilinear Flow regimes, while steady-state IPRs are generated for pseudo-steady-state Flow regime in case of constant Sandface Flow rate and Boundary-Dominated Flow regime in case of constant wellbore pressure. The outcomes of this study are as follows: (1) introducing the impact of multiphase Flow to the IPRs of unconventional reservoirs; (2) developing deterministic models for reservoir total mobility and compressibility using multi-regression analysis of PVT data and relative permeability curves; (3) developing analytical models for different Flow regimes that could be developed during the entire production life of reservoirs; (4) predicting transient and steady-state IPRs of multiphase Flow for different wellbore conditions. The study has pointed out: (1) Multiphase Flow conditions have significant impact on reservoir IPRs. (2) Multiphase reservoir total mobility and compressibility exhibit significant change with reservoir pressure. (3) Constant Sandface Flow rate may demonstrate IPR better than constant wellbore pressure. (4) Late production time is not affected by multiphase Flow conditions similar to transient state Flow at early and intermediate production time.

  • Deep insights to transient pressure behavior and stabilized productivity index of multilateral wells in laterally and spatially anisotropic reservoirs
    Journal of Natural Gas Science and Engineering, 2018
    Co-Authors: Salam Al-rbeawi
    Abstract:

    Abstract The objective of this paper is focusing deep insights on stabilized productivity index (PI) and transient pressure behaviors and Flow regimes of multilateral wells. It introduces an integrated approach for the performance of reservoirs depleted by multilateral wells extending in arbitrary trajectories. The study introduces new practical solutions for estimating stabilized pseudo-steady state (PSS) productivity index and starting time of PSS as well as transient PI behavior of multilateral wells in single and dual porous media with laterally and spatially anisotropic characteristics. Several analytical models are used in this study for describing pressure and pressure derivative behavior of multilateral wells considering different reservoir configurations and types and different wellbore lengths and directions. These models are developed for laterally and spatially anisotropic reservoirs consisting of single homogenous and dual heterogeneous porous media (Naturally fractured reservoirs) and depleted by multilateral wells extending from single vertical wellbore at different horizons and directions. The models are modified to identify the staring time of PSS Flow or the time when boundary dominated Flow regime is developed. They are also applied to estimate the time variant transient PI and time invariant stabilized PSS PI for constant single lateral Flow rate or constant vertical wellbore commingled Flow rate. The outcomes of this study are summarized in: 1) Developing new analytical solutions for pressure distribution in porous media drained by multilateral wells. 2) Developing new integrated approach for estimating stabilized PSS productivity index. 3) Understanding pressure, pressure derivative, and PI behavior of finite acting reservoir depleted by multilateral horizontal wells during transient and PSS production. 4) Investigating the impacts of different reservoir configurations and types, wellbore lengths and directions, permeability anisotropy characteristics, and single and dual porous media petrophysical properties on stabilized PSS productivity index. The novel points in this study are: 1) The optimum reservoir configuration that gives the maximum stabilized PI is the rectangular shape reservoir with reservoir length to width ratio of ( 2 − 4 ) . 2) The lateral with long wellbore and the slightly deviated from the horizontal directions gives the greatest stabilized productivity index. Stabilized PI is impacted by the length and direction of each multilateral as well as lateral wellbore location in the vertical plane. 3) Lateral reservoir anisotropy exhibits bad PI compared to the spatial anisotropy. 4) PI of conventional dual porous media reservoirs is greater than the index of unconventional reservoirs at early and late production time, but the index at intermediate production time demonstrates the greater value for unconventional reservoirs.

  • Analytical models & type-curve matching techniques for reservoir characterization using wellbore storage dominated Flow regime
    Petroleum, 2017
    Co-Authors: Salam Al-rbeawi
    Abstract:

    Abstract The applicability of early time data in reservoir characterization is not always considered worthy. Early time data is usually controlled by wellbore storage effect. This effect may last for pseudo-radial Flow or even boundary dominated Flow. Eliminating this effect is an option for restoring real data. Using the data with this effect is another option that could be used successfully for reservoir characterization. This paper introduces new techniques for restoring disrupted data by wellbore storage at early time production. The proposed techniques are applicable for reservoirs depleted by horizontal wells and hydraulic fractures. Several analytical models describe early time data, controlled by wellbore storage effect, have been generated for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. The relationships of the peak points (humps) with the pressure, pressure derivative and production time have been mathematically formulated in this study for different wellbore storage coefficients. For horizontal wells, a complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. Another complete set of type curves has been established for fractured formations based on the number of hydraulic fractures, spacing between fractures, and wellbore storage coefficient. The study has shown that early radial Flow for short to moderate horizontal wells is the most affected by wellbore storage while for long horizontal wells; early linear Flow is the most affected Flow regime by wellbore storage effect. The study has also emphasized the applicability of early time data for characterizing the formations even though they could be controlled by wellbore storage effect. As a matter of fact, this paper has found out that wellbore storage dominated Flow could have remarkable relationships with the other Flow regimes might be developed during the entire production times. These relationships can be used to properly describe the formations and quantify some of their characteristics.

  • Analysis of pressure behaviors and Flow regimes of naturally and hydraulically fractured unconventional gas reservoirs using multi-linear Flow regimes approach
    Journal of Natural Gas Science and Engineering, 2017
    Co-Authors: Salam Al-rbeawi
    Abstract:

    Abstract This paper targets the applicability of multi-linear Flow regimes approach in gas reservoirs having multiple porous media: matrix, natural fractures, and hydraulic fractures. The approach attempts to understand pressure profiles and Flow regimes developed in some of unconventional shale layers that have already been naturally fractured. In this paper, the main focus is given to fluid Flow phenomenon from the matrix towards naturally induced fractures and from these fractures to the hydraulic fractures. Studying the impact of matrix, natural fracture and hydraulic fracture parameters on reservoir performance is another objective for this paper. Purposefully, several mathematical models have been developed to investigate transportation phenomenon of reservoir fluid in porous medium. The porous medium is assumed to be finite rectangular reservoir having different configurations. It is divided into two zones; inner porous medium close to the horizontal wellbore where multiple-hydraulic fractures propagate to some distance and outer porous medium where naturally induced fractures exist in the drainage area close to the outer boundary. Reservoir fluids, in the outer zone, are assumed to Flow from the matrix to natural fractures and then from natural fractures to the inner zone. In the inner porous medium, fluids Flow from matrix to natural fractures in addition to fluids Flowing from the outer porous medium. Then all fluids Flow by natural fractures to hydraulic fractures and finally from hydraulic fractures to the wellbore. The mathematical models for fluid Flow in the two zones of the reservoir have been solved and three main Flow regimes have been characterized. For each Flow regime, an analytical model is used to describe its pressure profile with time and production performance. Bilinear Flow regime, typically observed at early time, refers to simultaneous linear Flow inside hydraulic fractures and Flow from inner porous medium to the hydraulic fractures while linear Flow describes fluids Flow from inner zone to hydraulic fractures and late linear or boundary dominated Flow regime describes fluids Flow from the outer to the inner porous media. The main outcomes of this study are: 1) The ability to characterize reservoirs with triple porous media using multi-linear Flow regimes approach. 2) Understanding the impact on pressure distribution of inner porous medium caused by the characteristics of hydraulic fractures such as fracture width and conductivity in addition to hydraulic fracture storativity. 3) Understanding the effect of reservoir configuration, matrix, and natural fractures characteristics on pressure distribution in the outer porous media. 4) Pressure distribution and Flow regimes obtained by applying transient Flow approach are not similar to those obtained by applying pseudo-steady state Flow approach. 5) Characterization of different linear Flow regimes, controlled by different parameters, with respect to production time.

Thomas Alwin Blasingame - One of the best experts on this subject based on the ideXlab platform.

  • Beyond Decline Curves: Life-Cycle Reserves Appraisal Using an Integrated Work-Flow Process for Tight Gas Sands
    SPE Annual Technical Conference and Exhibition, 2007
    Co-Authors: Jay Alan Rushing, Kent Edward Newsham, Albert Duane Perego, Joseph Thomas Comisky, Thomas Alwin Blasingame
    Abstract:

    Decline curve analysis is often either the only or the primary tool used for reserve evaluations in tight gas sands. However, the Flow and storage properties characteristic of lowpermeability sands often preclude accurate assessments using only or primarily decline curve analysis, especially early in the productive life. The most accurate reserve estimates incorporate multiple data sources and the appropriate evaluation techniques. Therefore, this paper presents a reserves appraisal work-Flow process that complements traditional decline curve analyses with comprehensive and systematic data acquisition and evaluation programs that integrate both static and dynamic data. Our approach—which has been developed specifically to incorporate the production characteristics of tight gas sands— is an adaptive process that allows continuous but reasonable reserve adjustments over the entire field development and production life cycle. Implementing this process will prevent unrealistic (either too low or high) reserve bookings. Although it is applicable during any field development phase, our work-Flow process is most beneficial during early stages before true Boundary-Dominated Flow conditions have been reached and when reserve evaluation errors are most likely.

  • Estimating Reserves in Tight Gas Sands at HP/HT Reservoir Conditions: Use and Misuse of an Arps Decline Curve Methodology
    SPE Annual Technical Conference and Exhibition, 2007
    Co-Authors: Jay Alan Rushing, Albert Duane Perego, Richard Burl Sullivan, Thomas Alwin Blasingame
    Abstract:

    This paper presents the results of a simulation study designed to evaluate the applicability of an Arps decline curve methodology for assessing reserves in hydraulically-fractured wells completed in tight gas sands at high-pressure/high-temperature (HP/HT) reservoir conditions. We simulated various reservoir and hydraulic-fracture properties to determine their impact on the production decline behavior as quantified by the Arps decline curve exponent, b. We then evaluated the simulated production with Arps' rate-time equations at specific time periods during the well's productive life and compared estimated reserves to the true value. To satisfy requirements for using Arps' models, all simulations were conducted using a specified constant bottomhole Flowing pressure condition in the wellbore. Our study indicates that the largest error source is incorrect application of Arps' decline curves during either transient Flow or the transitional period between the end of transient and onset of Boundary-Dominated Flow. During both of these periods (principally the transient period), we observed bexponents greater than one and corresponding reserve estimate errors exceeding 100 percent. The b-exponents generally approached values between 0.5 and 1.0 as Flow conditions approached true Boundary-Dominated Flow. Agreement between Arps' suggested b-exponent range and our results using simulated performance data also indicates that, if applied under the correct conditions, the Arps rate-time models are appropriate for assessing reserves in tight gas sands at HP/HT reservoir conditions. Introduction Tight gas sands constitute a significant percentage of the domestic natural gas resource base and offer tremendous potential for future reserve and production growth. According to a recent study by the Gas Technology Institute (GTI), tight gas sands in the US comprise 69 percent of gas production from all unconventional natural gas resources and account for 19 percent of total gas production from both conventional and unconventional sources. The same study estimates total domestic producible tight gas sand resources exceed 600 Tcf, while economically recoverable gas reserves are 185 Tcf. Most of the resources assessed in the 2001 GTI study were at depths less than 15,000 ft, yet the natural gas industry continues to extend exploration and development activities to much greater depths. In some geologic basins, those depths are approaching 20,000 to 25,000 ft. Many of these deep natural gas resources are not only characterized by lowpermeability, low-porosity reservoir properties, but these reservoirs also exhibit abnormally high initial pore pressure and temperature gradients — i.e. high-pressure/hightemperature (HP/HT) reservoir conditions. Similar to conventional natural gas resources, tight gas sand reserves are routinely assessed with Arps’ decline curve techniques. The original Arps paper suggested the decline curve exponent, b, should fall between 0 and 1.0 on a semilog plot. However, we often observe values much greater than 1.0, particularly in tight gas sands at HP/HT reservoir conditions. Deviations in observed b-exponents from the expected range suggest Arps' rate-time relationships may not be valid for modeling the decline behavior of tight gas sands at HP/HT conditions. More importantly, inappropriate use of the Arps models may cause significant reserve estimate errors in these unconventional natural gas resources. Since these depths and extreme reservoir conditions require wells that are very expensive to drill, complete and operate; it is imperative that we understand both the well productivity and production decline behavior. We also need to determine the applicability of the Arps rate-time equations for assessing reserves. To address these concerns, we have conducted a series of single-well simulation studies to develop a better understanding of both the shortand long-term production decline behavior and to identify those parameters affecting the production decline. In this study we simulated a range of reservoir and hydraulic fracture properties, including: Vertical heterogeneity from layering, permeability contrast among layers, horizontal permeability anisotropy, and stressdependent reservoir properties; 2 J.A. Rushing, A.D. Perego, R.B. Sullivan, and T.A. Blasingame SPE 109625 Variable effective fracture conductivities and lengths, unequal fracture wing lengths, two-phase and non-Darcy Flow, and stress-dependent fracture properties; and Reservoir temperatures ranging from 300 to 400F and initial pore pressure gradients ranging from 0.60 to 0.90 psi/ft. We evaluated the simulated production with the Arps ratetime equations. Reserve estimates were obtained at various time periods during the well’s productive life by extrapolating the best-fit Arps model through the simulated production. Our assumed economic conditions for estimating reserves were either a rate of 50 Mscf/d or a producing time period of 50 years, whichever came first. Reserve estimate errors were computed by comparing those estimated reserves to the “true” value. For this paper, we define the “true” estimated ultimate recovery (EUR) to be the 50-year cumulative production volume. For reference, we also summarize the Arps rate-time equations in Table 1, given below: Table 1 — Summary of the Arps' rate-time relations (Ref. 1)

  • Estimation of Reserves Using the Reciprocal Rate Method
    Rocky Mountain Oil & Gas Technology Symposium, 2007
    Co-Authors: Thomas Alwin Blasingame, Parker D. Reese
    Abstract:

    In this work we develop, validate, and apply the "reciprocal rate method" to estimate oil reserves using only rate-time production data. This approach requires the development of Boundary-Dominated Flow, and can be used to validate reserve extrapolations from numerical/analytical reservoir models. The methodology does presume that Flowing well bottomhole pressures are approximately constant — but we will demonstrate that the method is tolerant of substantial changes in the Flowing bottomhole pressure.

  • A Semi-Analytic (p/z) Rate-Time Relation for the Analysis and Prediction of Gas Well Performance
    SPE Mid-Continent Gas Symposium, 1996
    Co-Authors: Joseph Ansah, R.s. Knowles, Thomas Alwin Blasingame
    Abstract:

    In this paper we present a rigorous theoretical development of solutions for Boundary-Dominated gas Flow during reservoir depletion. These solutions were derived by directly coupling the stabilized Flow equation with the gas material balance equation. Due to the highly nonlinear nature of the gas Flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions do provide a rigorous linearization of the gas Flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history, which in most cases is simply not available. Our approach uses functional models to represent the viscosity-compressibility product as a function of the reservoir pressure/z-factor (p/z) profile. These models provide approximate, but direct, solutions for modeling gas Flow during the Boundary-Dominated Flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as the prediction of rate or cumulative production. We also provide verification of our new Flow rate and pressure solutions using the results of numerical simulation and we demonstrate the application of these solutions using a field example.

Christopher R Clarkson - One of the best experts on this subject based on the ideXlab platform.

  • A new low-permeability reservoir core analysis method based on rate-transient analysis theory
    Fuel, 2020
    Co-Authors: Christopher R Clarkson, Amin Ghanizadeh, Abedin Vahedian, Chengyao Song
    Abstract:

    Abstract Unconventional reservoirs such as shales (mudrocks) and coals may exhibit an ultra-low matrix permeability ( Rate-transient analysis (RTA) is a technique used to quantitatively analyze production data from wells drilled into unconventional reservoirs to extract reservoir (e.g. permeability, hydrocarbons-in-place) and hydraulic fracture (conductivity, fracture length) properties. Multi-fractured horizontal wells (MFHWs) producing from low-permeability reservoirs commonly exhibit the Flow-regime sequence of transient linear Flow, where hydrocarbons Flow through the reservoir orthogonal to hydraulic fractures or the horizontal well, followed by Boundary-Dominated Flow caused by pressure interference between adjacent hydraulic fractures or wells. Transient linear Flow may be analyzed using RTA methods to extract fracture or well-length (if permeability is known); the end of linear Flow can be used to estimate permeability of the reservoir, and Boundary-Dominated Flow to estimate hydrocarbons-in-place. In this work, a new experimental procedure and set-up, applied to core plugs under stress conditions, is developed to mimic well operating conditions encountered in the field (i.e. producing from a subsurface unconventional reservoir). After injection of methane gas into one end of the core plug, and pressure stabilization, the gas is Flowed out of the same end of the core plug at constant pressure (with the aid of a backpressure regulator), and Flow rates are measured with a Flow meter. This procedure is applied to a core plug extracted from a low-permeability siltstone of the Montney Formation (western Canada). Repeated testing consistently demonstrated a transient linear Flow period, as the gas pressure transient propagated along the core plug, followed by Boundary-Dominated Flow after the pressure transient reached the end of the core plug; this sequence is identical to what is commonly observed in the field. Permeability was estimated using both the slope of a square-root of time plot (a common RTA method used to analyze transient linear Flow), and the time at the end of linear Flow combined with the linear Flow distance of investigation (DOI) equation. Permeability from both techniques is in good agreement (±5% for both experiments performed), providing an important redundancy to the analysis procedure. Pore volume (and hence porosity, with bulk volume known) may be estimated from the time at the end of linear Flow and the slope of the square-root of time plot – the calculated value is in excellent agreement (±2% for both experiments performed) with that obtained from pore volume/porosity estimates using a helium pycnometer (combined with calipered dimensions). Finally, test times for the ∼0.0007 md core plug sample, after the initiation of the production phase, are on the order of only a few minutes to obtain the two independent estimates of permeability and pore volume, which is faster than that achievable from a PDP test. The new innovative experimental procedure is successful in reproducing the physics of Flow in unconventional reservoirs, with the results being analyzable with the same techniques applied to field data.

  • Dynamic coupling of analytical linear Flow solution and numerical fracture model for simulating early-time Flowback of fractured tight oil wells (planar fracture and complex fracture network)
    Journal of Petroleum Science and Engineering, 2019
    Co-Authors: Linsong Cheng, Christopher R Clarkson, Shijun Huang, J. D. Williams-kovacs, Suran Wang, Deqiang Wang
    Abstract:

    Abstract Quantitative analysis of Flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase Flow data prior to hydrocarbon breakthrough and multi-phase Flow data after hydrocarbon breakthrough during Flowback. This study provides a new model to simulate Flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture Flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-Flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear Flow from the matrix to each segment. To model this behavior, matrix Flow is simulated using the analytical transient linear Flow solution which is dynamically coupled with the fracture Flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-Flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear Flow period (first linear Flow in the fracture) followed by Boundary-Dominated Flow (first Boundary-Dominated Flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear Flow in the fracture develops. The final Flow period is Boundary-Dominated Flow (second Boundary-Dominated Flow in the fracture), indicating the end time of the Flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear Flow in the matrix, which is the first Flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of Flow regimes. The second transient linear Flow for this case has not been discussed in the literature. The development of this Flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the Flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from Flowback data and for forecasting.

  • A novel method for interpreting water data during Flowback and early-time production of multi-fractured horizontal wells in shale reservoirs
    International Journal of Coal Geology, 2018
    Co-Authors: Linsong Cheng, Christopher R Clarkson, Shijun Huang, Yonghui Wu, J. D. Williams-kovacs
    Abstract:

    Abstract In recent years, analysis of Flowback data has provided an early opportunity to evaluate key fracture parameters (e.g. fracture permeability and fracture volume) in unconventional reservoirs. A combination of diagnostic plots, straight-line methods and simulation model history-matching techniques have been used for this purpose. For many shale gas wells, immediate gas and water production occurs on Flowback. In this paper, a novel method is developed and demonstrated for analysis of water data during two-phase (gas + water) Flowback and early-time production of shale gas wells. In previous studies, it has been demonstrated that, during the late-time water Flow period, the water phase exhibits Boundary-Dominated Flow (BDF) characteristics due to the limited volume of water in fractures or surrounding matrix. The gas phase exhibits transient linear Flow (TLF) characteristics within matrix, which is one of the first Flow-regimes typically observed after Flowback during online production. By introducing a new pseudotime with a modified total compressibility, the water Flow equation during two-phase (gas + water) Flow period is linearized. Accordingly, a modified Flowing material balance (FMB) equation is developed for analyzing water Boundary-Dominated Flow which considers water relativity permeability and the saturation- and pressure-dependent total compressibility. Thus, a novel method is developed by combination of the water FMB equation and an iteration technique, to estimate the facture half-length and fracture permeability during Flowback of shale gas wells. The approach is validated using several numerically-simulated cases. Results show that the accuracy of the new method is influenced by the pressure and saturation gradient in the fracture. With an increase in fracture permeability, the calculated fracture parameters become very close to the expected values. The calculated fracture half-length starts to deviate from the expected values with an increase in fracture half-length. However, the derived fracture permeability values are in excellent agreement for all cases studied. The matrix permeability has little effect on the calculated fracture parameters (half-length and permeability). Although there are some deviations between the interpreted and excepted values, both the values generally agree within 5%. Finally, practical application of the method is demonstrated using a Marcellus Shale well in northeast US north-east and a Changning Shale well in southwest China. The new techniques demonstrate the importance of accounting for phase relative permeability and correcting total compressibility, even when the gas phase dominates the Flowback period.

  • Production data analysis of gas condensate reservoirs using two-phase viscosity and two-phase compressibility
    Journal of Natural Gas Science and Engineering, 2017
    Co-Authors: Hamid Behmanesh, Hamidreza Hamdi, Christopher R Clarkson
    Abstract:

    Abstract Due to the occurrence of multi-phase Flow in gas condensate reservoirs, production data of such reservoirs cannot be accurately analyzed using single-phase, dry gas models. In this work, we established a new semi-analytical method for rate-transient analysis of gas condensate reservoirs producing during Boundary-Dominated Flow. In particular, the single-phase Flow assumption in the development of the material-balance pseudotime function for dry gas reservoirs is alleviated by incorporating two-phase viscosity and two-phase compressibility into a modified two-phase pseudotime function. Introducing the definition of two-phase pseudotime achieves the goal of (approximately) linearizing the governing diffusivity equation. Using the principle of superposition applied to the constant rate solution, this methodology is extended for wells with dynamic changes in well operating conditions (i.e. rates and pressures). Original gas-in-place (OGIP) can also be quantified through a specialized plotting technique. To validate the developed method, synthetic production data using fine grid compositional simulations for both lean and rich gas condensate fluids are analyzed. In all cases, the proposed approach provides reasonable estimates of simulator input reservoir properties (e.g. OGIP). The presented technique is successfully applied to the analysis of field cases. This work provides a practical and simple engineering workFlow for production data analysis of conventional gas condensate reservoirs with multi-phase Flow during Boundary-Dominated Flow.

  • Flow behavior analysis of two-phase (gas/water) Flowback and early-time production from hydraulically-fractured shale gas wells using a hybrid numerical/analytical model
    International Journal of Coal Geology, 2017
    Co-Authors: Linsong Cheng, Christopher R Clarkson, J. D. Williams-kovacs
    Abstract:

    Abstract In recent years, quantitative analysis of Flowback and early-time production data for interpretation of hydraulic fracture properties in shale has received significant attention. With high-resolution phase rates and Flowing pressures, analysis of Flowback and early-time production data provides an early opportunity to determine key parameters for well performance forecasting. The main purpose of this paper is to quantify Flow characteristics associated with two-phase Flowback and early-time production of shale gas wells exhibiting both planar fractures and a complex fracture network using a rigorous and efficient Flow model. To study Flow characteristics of this complex system, a hybrid numerical/analytical model is developed in which matrix and hydraulic fracture Flow is accounted for. The finite-difference method is used to numerically model unsteady-state two-phase fracture Flow. The analytical matrix Flow model, derived using the line-source function, is dynamically coupled with the fracture Flow model by imposing continuity of pressure and flux on the fracture surface. The main advantage of the hybrid solution over more conventional numerical simulation is reduced model setup and run time, without loss of the important physics. Detailed Flow regime analysis reveals that the gas/water Flowback and early-production of a horizontal well with a planar fracture geometry may the following complex sequence of Flow-regime: 1) radial Flow of water in the fracture; 2) a first transient linear Flow of water in the fracture; 3) a second transient linear Flow of water in the fracture; 4) Boundary-Dominated Flow of water in the fracture and gas linear Flow in matrix. Water primarily depletes in the first three Flow periods. Development of the water Boundary-Dominated Flow and gas linear Flow indicates the system indicate that the system is at the end of Flowback period and proceeds early-time production. Specially, the second water linear Flow period develops when both gas and water production are dominating the system, and is caused by the pressure maintenance associated with gas flux from matrix. A complex fracture network with the same total fracture length as a planar fracture system will exhibit the same sequence of Flow regimes. Due to the accelerated water drainage caused by multiple contact points between fractures and the wellbore in complex fracture network, the system also exhibits a shortened second water transient linear Flow period and earlier water Boundary-Dominated Flow. Finally, the new model is also applied to match Flowback data obtained from a multi-fractured horizontal well completed in the Marcellus Shale. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from Flowback data and for forecasting.

C. S. Kabir - One of the best experts on this subject based on the ideXlab platform.

  • Assessing the hyperbolic trend in well response involving pressure, fluid and heat-Flow rates
    Journal of Natural Gas Science and Engineering, 2020
    Co-Authors: P. Sharma, A. Q. Al Saedi, C. S. Kabir
    Abstract:

    Abstract 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.

  • An approach to modeling production decline in unconventional reservoirs
    Journal of Petroleum Exploration and Production Technology, 2018
    Co-Authors: B. A. Ogunyomi, S. Dong, N. La, L. W. Lake, C. S. Kabir
    Abstract:

    Most decline curve methods have two main limitations; the model parameters as a rule are not functions of reservoir parameters and may yield unrealistic (nonphysical) values of expected ultimate recovery (EUR) because Boundary-Dominated Flow may not develop in unconventional reservoirs. Over the past few years, several empirical models have emerged to address the second limitation, but they are challenged by the time to transition from infinite-acting Flow period to the Boundary-Dominated Flow. In this study, we performed statistical and model-based analysis of production data from hydraulically fractured horizontal oil wells and present a method to mitigate some of the limitations highlighted above. The production data were carefully analyzed to identify the Flow regimes and understand the overall decline behavior. Following this step, we performed model-based analysis using the parallel Flow model (sum of exponential terms), and the logistic growth model. After the model-based analysis, the model parameters were analyzed statistically and cross-plotted against available reservoir and well completion parameters. Based on the conclusion from the cross-plots and statistical analysis, we used design of experiments (DoE) and numerical reservoir simulations to develop functions that relate the model parameters and reservoir/well completion properties. Results from this work indicate that the production characteristics from these wells are highly variable. In addition, the parallel Flow model indicates that there are at least two to three different time domains in the production behavior and that they are not the result of operational changes, such as well shut-in or operating pressure changes at the surface. All the models used in this study provide very good fits to the data, and all provide realistic estimates of EUR. The cross-plots of model parameters and some reservoir/well completion properties indicate that there is some relationship between them, which we developed using DoE and Flow simulations. We have also shown how these models can be applied to obtain realistic estimates of EUR from early-time production data in unconventional oil reservoirs.

  • analyzing variable rate Flow in volumetric oil reservoirs
    Journal of Petroleum Science and Engineering, 2015
    Co-Authors: Ar R Elgmati, Ralph E Flori, C. S. Kabir
    Abstract:

    Abstract Estimating average-reservoir pressure ( p av ) and its evolution with time is critical to analyzing and optimizing reservoir performance. Normally, selected wells are shut in periodically for buildup tests to determine p av over time. Unfortunately, shutting-in wells leads to loss of production. Today, however, real-time surveillance—the continuous measurement of Flowing pressures and rate data from the oil and gas wells—offers an attractive alternative technique to obtain average-reservoir pressure while avoiding loss of revenue. A direct method for estimating p av from Flowing pressures and rate data is available. However, the method is for an idealized case that assumes constant production rate during pseudosteady-state (PSS) Flow, which is generally untrue for real wells. This paper extends that approach so that it can be used to analyze field data with variable rates/variable pressures during Boundary-Dominated Flow (BDF). This approach is based on a combination of rate-normalized pressure and superposition-time function. The mathematical basis is presented in support of this approach, and the method is validated with synthetic examples and verified with field data. This modified approach is used to estimate average-reservoir pressure that uses Flowing pressures and production rates during BDF, allowing the classical material balance calculations to be performed. These calculations, in turn help determine the reserves, recovery factor, and reservoir drive mechanisms, allowing the reservoir performance and management to be properly evaluated. Furthermore, this method can be used to calculate both connected oil volume and reservoir drainage area as a function of time. Finally, this approach provides a reasonable estimation of the reservoir's shape factor.