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Simulated production history and decline Fig. 6-Decline curve analysis of simulated data for behavior for the single-layer base case. the single-layer base case at the five-year time period.
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This paper presents results of a simulation study designed to evaluate the applicability of Arps' [1945] decline curve methodology for assessing reserves in coalbed methane reservoirs. We simulated various coal properties and well/operational conditions to determine their impact on the production decline behavior as quantified by the Arps decline c...
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Five Polish bituminous coals from Upper Silesian Coal Basin were studied for adsorption and desorption of CH4 and CO2 under laboratory conditions at elevated temp. and pressure. Correlations between sorption capacity of CO2 and CH4 desorption ability, pressure of CH4 in the coal deposit and characteristic parameters of coal beds were established. A...
The mechanical properties of coal are important parameters for coalbed methane (CBM) extraction and gas outburst control. However, the effect of adsorbed gas on strength cannot be evaluated quantitatively yet. To better understand the weakening mechanisms of free and adsorbed gas on the strength of coal, normal coal, and deformed coal are chosen to...
Citations
... Numerical simulation was applied to match field data of two mature Fairway wells and examine the significance of gas diffusion in CBM production. A three-dimensional and dual-permeability model was built with Computer Modeling Groups' GEM (Generalized Equation-of-State Model) simulator [43], which is capable of modeling every storage and flow phenomena characteristics of coalbed methane reservoirs [65]. Over the course of depletion, the permeability growth was modeled by P-M model, and the evolution of diffusion flow was evaluated through the modeling of diffusive matrix permeability as suggested in Fig. 10. ...
Exploitation of coalbed methane (CBM) acts as a synergy between increased natural gas demand and reduced greenhouse gas emissions to the atmosphere. However, substantial CBM resources lie undeveloped because of unfavorable economic conditions. Accurate forecast of production based on a thorough understanding of physical mechanisms is the key to increase and sustain CBM recovery. CBM production involves complex multi-scale phenomena ranging from desorption and diffusion in nanoporous matrix at molecular level to Darcy flow of free gas in cleats at macroscopic level. Current computational modeling built on fracture flow and neglecting multi-scale coupled flow phenomena underestimates long-term production performance. In fact, experimental evidence indicated that matrix experienced a much greater increase in gas deliverability than cleats. In this work, apparent matrix permeability was derived to characterize diffusion rate and directly coupled into current modeling to decipher matrix deliverability and multi-scale flow. The proposed modeling workflow was applied to two field cases in San Juan Fairway with long production history of over 20 years, which assembled adequate forecast to field data. Besides, sensitivity analysis suggested that simulations neglecting matrix flow and solely updating fracture flow were prone to elevated prediction errors for long-term production when diffusive mass flux took the predominant role in overall gas transport. The multi-scale CBM model is convenient for elucidating complex gas transport physics in coal. The outcome of this work implies that a proper diffusion enhancement method can improve overall production rate and elongate total productive lifetime of CBM fields.
... It can help in extracting well geometry, fracture and reservoir properties, and well productivity during different flow regimes: linear or bilinear flow (fracture half-length and fracture conductivity), elliptical flow (reservoir permeability and fracture length), radial flow regime (skin and reservoir permeability), and boundary-dominated flow (original-gas-in-place (OGIP) and flow coefficient) [13,14]. Production decline analysis has been widely applied to estimate the drainage volume and ultimate recovery in tight reservoirs [15,16]. Decline models used include Arps decline-curve methodology [17], "power-law exponential" [18] and "stretched-exponential" [19], which can consider the longterm transient and transitional flow in tight and shale gas reservoirs. ...
This study presents an integrated approach to evaluate the efficiency of fracturing stimulation and predict well production performance. As the pressure disturbance propagates
throughout the reservoir during long-time transient flow regimes, it will shape an expanding drainage volume. A macroscopic “compressible tank model (CTM)” using weak (integral) form of mass balance equation is derived to relate dynamic drainage volume (DDV) and average reservoir pressure to production history in extremely shale reservoirs. Fluids and rock compressibility, desorption parameters (for shale or coal gas), and
production rates control the speed at which the boundaries advance. After the changes of average reservoir pressure within the expanding drainage volume are obtained, a new empirical inflow performance relationship (transient IPR) correlation is proposed to describe well performance during long transient flow periods in shale reservoirs. This new empirical correlation shows better match performance with field data than that of
conventional Vogel-type IPR curves. The integrated approach of both CTM model and transient IPR correlation is used to determine and predict the optimal fracturing spacing and the size of horizontal section for few wells from one of shale oil plays in U.S. The results suggest the existence of optimal fracture spacing and horizontal well length for multistage fractured horizontal wells in shale oil reservoirs. In practice, this paper not
only provides an insight in understanding the long transient flow production characteristics of shale reservoirs using concept of expanding drainage volume. Neither methods require comprehensive inputs for the strong form (differential) nor any prior knowledge about the sophisticated shale reservoir features (shape, size, etc.), the ultimate drainage volume, the ultimate recovery, optimal fracture spacing, and the length of horizontal section for each well can also be easily obtained by this new integrated analytical method.
... Production analysis has been widely applied to estimate the drainage volume and ultimate recovery in tight reservoirs (Blasingame and Rushing, 2005;Rushing et al., 2008). Decline models consists of Arps decline-curve methodology (Asps, 1945), "Power-law exponential" (Ilk et al., 2008) and "Stretched-exponential" (Valko and Lee, 2010), which can consider the long-term transient and transitional flow in tight and shale gas reservoirs. ...
his study presents a novel approach to predict the production performance and evaluate the efficiency
of fracturing stimulation. Despite the great success of fracturing operation in production from unconventional oil/gas resources, prediction of well performance is yet to be understood.
We develop a mathematical model relating dynamic drainage volume and well deliverability in
extremely low permeable formations. As the pressure disturbance created at the production well starts
propagating throughout the reservoir, it will shape an expanding drainage volume; the boundaries of
drainage volume are pushed back expanding the size of productive region as production continues. We
treat the expanding drainage volume as moving boundary problem. In our mathematical model, the
weak (integral) form of mass balance equation is written for the productive region. Fluids and rock
compressibility, desorption parameters (for shale gas), and production rates are controlling the speed at
which the boundaries are advancing.
The calculated well deliverability is used to determine optimal fracturing spacing for wells completed
in one of the oil shale plays in the United States. Two approaches are studied: 1) keep the original
horizontal length and change the number of fracture clusters; 2) keep the original fracture spacing and
change the horizontal length.
For the wells studied here, changing the fracture spacing and the horizontal length result in various
level of performance enhancement. Through the study, we determine the optimal parameters: optimal
fracture spacing and optimal well spacing.
The ultimate drainage volume (effective stimulated reservoir volume) and optimal fracture spacing can
be obtained by the proposed method; therefore, neither comprehensive inputs required for the strong
form (differential) nor any pre-knowledge about the productive region (shape, size,…) are needed for the
new approach.
... It can help in extracting well geometry, fracture and reservoir properties, and well productivity during different flow regimes: linear or bilinear flow (fracture half-length and fracture conductivity), elliptical flow (reservoir permeability and fracture length), radial flow regime (skin and reservoir permeability), and boundary-dominated flow (original-gas-in-place (OGIP) and flow coefficient) [13,14]. Production decline analysis has been widely applied to estimate the drainage volume and ultimate recovery in tight reservoirs [15,16]. Decline models used include Arps decline-curve methodology [17], " power-law exponential " [18] and " stretched-exponential " [19] , which can consider the longterm transient and transitional flow in tight and shale gas reservoirs . ...
This study presents an integrated approach to evaluate the efficiency of fracturing stimulation and predict well production performance. As the pressure disturbance propagates throughout the reservoir during long-time transient flow regimes, it will shape an expanding drainage volume. A macroscopic "compressible tank model (CTM)" using weak (integral) form of mass balance equation is derived to relate dynamic drainage volume (DDV) and average reservoir pressure to production history in extremely shale reservoirs. Fluids and rock compressibility, desorption parameters (for shale or coal gas), and production rates control the speed at which the boundaries advance. After the changes of average reservoir pressure within the expanding drainage volume are obtained, a new empirical inflow performance relationship (transient IPR) correlation is proposed to describe well performance during long transient flow periods in shale reservoirs. This new empirical correlation shows better match performance with field data than that of conventional Vogel-type IPR curves. The integrated approach of both CTM model and transient IPR correlation is used to determine and predict the optimal fracturing spacing and the size of horizontal section for few wells from one of shale oil plays in U.S. The results suggest the existence of optimal fracture spacing and horizontal well length for multistage fractured horizontal wells in shale oil reservoirs. In practice, this paper not only provides an insight in understanding the long transient flow production characteristics of shale reservoirs using concept of expanding drainage volume. Neither methods require comprehensive inputs for the strong form (differential) nor any prior knowledge about the sophisticated shale reservoir features (shape, size, etc.), the ultimate drainage volume, the ultimate recovery, optimal fracture spacing, and the length of horizontal section for each well can also be easily obtained by this new integrated analytical method.
... Production analysis has been widely applied to estimate the drainage volume and ultimate recovery in tight reservoirs (Blasingame and Rushing, 2005;Rushing et al., 2008). Decline models consists of Arps decline-curve methodology (Asps, 1945), "Power-law exponential" (Ilk et al., 2008) and "Stretched-exponential" (Valko and Lee, 2010), which can consider the long-term transient and transitional flow in tight and shale gas reservoirs. ...
... A commercial oil and gas reservoir simulation software (CMG's GEM) (Law et al., 2001(Law et al., , 2002a was used for the simulation of gas production from coal seams, in which the CBM reservoir is considered as a dual porosity system, as shown in Fig. 7, and the coal bed is divided into numerous matrix bodies by micro fractures (Laubach et al., 1998;Rushing et al., 2008;Seidle et al., 1992). In order to simulate the well productivity of various well types, a grid system of 64 × 64 × 3 was used (the numbers refer to the grid system in I, J, K directions), with the main grid size being 10 m × 10 m. ...
Analyses have been widely applied in production forecasting of oil and gas production in both conventional and unconventional reservoirs. In order to forecast production, to estimate reservoir properties, or to evaluate resources, various statistical and machine learning approaches have been applied to various reservoir analysis methods. Nevertheless, many of these methods are suboptimal in detecting production trends in different wells due to data artifacts (noise, data scatter and outliers, inadequate SCADA systems, production allocation problems) that obscure unit reservoir signals, production trends, and more leading to large forecast error, or fail due to lack of data access (inadequate SCADA systems, missing or abhorrent data, and production allocation problems). This work outlines a method that is currently being used in a commercial setting which combines advanced analytics and machine learning with a modern cloud architecture, provide rapid, repeatable, unbiased estimates of original hydrocarbon -in-place (OHIP), estimated ultimate recovery (EUR), and remaining recoverable (RR), and even deliverability forecasts - all in the presence of abhorrent data.
The cleat compressibility of coal is a key parameter that is extensively used in modeling the coal reservoir permeability for Coal Bed Methane (CBM) recovery. Cleat compressibility is often determined from the permeability measurement made at different confining pressures but with a constant pore pressure. Hence, this parameter ignores the sorption strain effects on the cleat compressibility. By using the transient pulse decay (TPD) technique, this study presents the results from a laboratory characterization program using coal core drilled from different bedding directions to estimate gas permeability and coal cleat compressibility under different pore pressures while maintaining effective stress constant. Cleat compressibility was determined from permeability and sorption strain measurements that are made at different pore pressures under an effective stress constant. Results show that the cleat compressibility of coal increases slightly with the increase of pore pressure. Moreover, the cleat compressibility of Sample P (representing the face cleats in coal) is larger than that of Sample C (representing the butt cleats in coal). This result suggests that cleat compressibility should not be regarded as constant in the modeling of the CBM recovery. Furthermore, the compressibility of face cleats is considerably sensitive to the sorption-induced swelling/shrinkage and offers significant effects on the coal permeability.
Production data from hydraulically fractured well in coalbed methane (CBM) reservoirs was analyzed using decl ine curve analysis (DCA), flow regime analysis, and flowing material balance to forecast the production performance and to determine estimated ultimate recovery (EUR) and timing for applying the DCA. To generate synthetic production data, reservoir models were built based on the CBM propertie of the Appalachian Basin, USA. Production data analysis shows that the transient flow (TF) occurs for 6~16 years and then the boundary dominated flow (BDF) was reached. In the TF period, it is impossible to forecast the production performance due to the significant errors between predicted data and synthetic data. The prediction can be conducted using the production data of more than a year after reached BDF with EUR error of approximately 5%.
