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University of Calgary Summary Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process. In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate. In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship. Introduction The performance of MFHWs completed in ultralow permeability unconventional reservoirs is a function of various reservoir and fracture properties.
- North America > United States (1.00)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (7 more...)
Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly โtextbookโ quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.
- North America > Canada (0.94)
- North America > United States > Texas (0.94)
- Oceania > Australia > Northern Territory (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (0.68)
- Geophysics > Seismic Surveying (0.46)
- Oceania > Australia > Northern Territory > Beetaloo Basin > Beetaloo Extension Basin > EP 98 > Kalata South Field > Kalata South 1 Well (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (5 more...)
Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly โtextbookโ quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.
- North America > Canada (0.94)
- North America > United States > Texas (0.94)
- Oceania > Australia > Northern Territory (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Borehole Geophysics (0.68)
- Geophysics > Seismic Surveying (0.46)
- Oceania > Australia > Northern Territory > Beetaloo Basin > Beetaloo Extension Basin > EP 98 > Kalata South Field > Kalata South 1 Well (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (5 more...)
Summary Reduction of fracture/well spacing and increases in hydraulic fracture stimulation treatment size are popular strategies for improving hydrocarbon recovery from multifractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which can not only negatively impact the overall production but also introduce complexities for production data analysis. A semianalytical model is therefore developed to analyze production data from two communicating MFHWs and applied to a field case. The new semianalytical model uses the dynamic drainage area (DDA) concept and assumes three porosity regions. The three-region model is comprised of a primary hydraulic fracture (PHF), an enhanced fractured region (EFR) adjacent to the PHF, and a nonstimulated region (NSR). Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history-matching framework to estimate the communication between the wells by matching the production data. The semianalytical model is first verified against a more rigorous, fully numerical simulation model for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the fully numerical simulation model results and the new semianalytical model. The semianalytical model is then employed to history-match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. For the purpose of history matching the data, only strong communication between pairs of wells (intrapair communication) is considered in the three-region model, and the results show good agreement with the field data. A flexible, yet simple, semianalytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.
- North America > United States (0.68)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.28)
Optimizing the Huff โnโ Puff Gas Injection Performance in Shale Reservoirs Considering the Uncertainty: A Duvernay Shale Example
Hamdi, Hamidreza (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Esmail, Ali (Ovintiv Corporation) | Sousa, Mario Costa (University of Calgary)
Summary Recent studies have indicated that huff โnโ puff (HNP) gas injection has the potential to recover an additional 30 to 70% oil from multifractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution) and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example. Compositional simulations are conducted that incorporate a tuned pressure/volume/temperature (PVT) model and a set of measured cyclic injection/compaction pressureโsensitive permeability data. MarkovโChain Monte Carlo (MCMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The MCMC process is accelerated by using an accurate proxy model (kriging) that is updated using a highly adaptive sampling algorithm. Gaussian processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (ฮผโฯ) of cumulative oil production (after 10โyears) across a fixed ensemble of uncertain variables sampled from posterior distributions. The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective halfโlength, are narrower, whereas wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of approximately 1.5โmonths, a production time of approximately 2.5โmonths, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubblepoint are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production. The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced techniques for optimization under uncertainty, resulting in better decision making.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Asia (1.00)
- (3 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.84)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (19 more...)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (1.00)
Summary Straightโline analysis (SLA) methods, which are a subgroup of modelโbased techniques used for rateโtransient analysis (RTA), have proved to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulicโfracture information, whereas boundaryโdominatedโflow (BDF) data can be interpreted for fluidโinโplace estimates. Because transientโflow 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 variableโrate/pressure data for lowโpermeability (unconventional) reservoirs. A logโlog plot of CFIP vs. materialโbalance time (for liquids) or materialโbalance pseudotime (for gas) is created, which typically exhibits powerโlaw 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 SLAโmethod derivation, which allows the linearโflow parameter (LFP) to be extracted from the yโintercept (at materialโbalance time or materialโbalance pseudotimeโ=โ1 day) of a straightโline 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 squareโrootโofโtime plot) and the OFIP (e.g., the flowing materialโbalance 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 coreโanalysis technique were also analyzed using the new SLA method. In all cases, the new SLAโmethod 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 hydrocarbonโinโplace assessment. This method should provide important, complementary information to traditionally used methods, such as squareโrootโofโtime and flowing materialโbalance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs. The method is currently limited to cases exhibiting singleโphase flow, the flowโregime sequence of TLF to BDF, and reservoir homogeneity. In future work, these limitations will be resolved.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
Production Data Analysis of Coalbed-Methane Wells
Clarkson, Christopher R. (ConocoPhillips) | Jordan, Colin L. (Apache) | Gierhart, Roger R. (BP Amoco PLC) | Seidle, John P. (MHA Petroleum Consultants)
Summary Recent advances in production data analysis (PDA) techniques have greatly assisted engineers in extracting meaningful reservoir and stimulation information from well-production and flowing-pressure data. Application of these techniques to coalbed-methane (CBM) reservoirs requires the unique coal storage and transport properties to be accounted for. In recent work, the authors [ex. Clarkson et al. (2007a) and Jordan et al. (2006)] and others [ex. Gerami et al. (2007)] have demonstrated how new techniques such as the flowing material balance (FMB) and production type curves may be adapted to account for CBM storage mechanisms (i.e., adsorption), but, to date, the focus has been on relatively simple CBM reservoir behavior such as single-phase (gas) reservoirs with static effective permeability. The major contribution of the current work is the adaptation of modern PDA techniques (by use of modified material balance time/pseudotime and pseudopressure definitions) to analyze producing wells completed in CBM reservoirs exhibiting several possible flow characteristics: single-phase flow of gas in dry CBM reservoirs, single-phase flow of water (in undersaturated reservoirs), and two-phase (gas and water) flow (in saturated reservoirs). The latter reservoir type commonly exhibits effective permeability changes during depletion (because of relative and/or absolute permeability changes) and changing gas composition caused by relative adsorption effects, both of which have been accounted for in the current work. Specifically, the FMB technique is modified to include several complex CBM reservoir characteristics, and production type curves are applied to some scenarios. Although dry-CBM-well analysis was covered previously [ex. Clarkson et al. (2007a)], we will also discuss FMB development in these reservoirs for completeness. Several synthetic and field examples are given to demonstrate how FMB, type-curve analysis, and analytical simulation can be used in parallel to provide a particularly useful data-analysis toolset and workflow. These techniques were used successfully to extract quantitative reservoir information from single- and two-phase CBM-simulated and field-production pressure data. The PDA techniques developed for two-phase CBM require further evaluation, however.
- North America > Canada (0.94)
- North America > United States > West Virginia (0.68)
- North America > United States > Alabama (0.46)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Pennsylvania > Appalachian Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Information Technology > Modeling & Simulation (0.93)
- Information Technology > Data Science (0.80)
Summary Coalbed-methane (CBM) reservoirs commonly exhibit two-phase-flow (gas plus water) characteristics; however, commercial CBM production is possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed with techniques commonly applied to conventional reservoirs. Complicating application, however, is the unique nature of CBM reservoirs; coal gas-storage and -transport mechanisms differ substantially from conventional reservoirs. Single-phase CBM reservoirs may also display complex reservoir behavior such as multilayer characteristics, dual-porosity effects, and permeability anisotropy. The current work illustrates how single-well production-data-analysis (PDA) techniques, such as type curve, flowing material balance (FMB), and pressure-transient (PT) analysis, may be altered to analyze single-phase CBM wells. Examples of how reservoir inputs to the PDA techniques and subsequent calculations are modified to account for CBM-reservoir behavior are given. This paper demonstrates, by simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from PDA of CBM reservoirs only if appropriate reservoir inputs (i.e., desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve, FMB, and PT analysis methods for PDA are not used in isolation for reservoir-property estimation, but rather as a starting point for single-well and multiwell reservoir simulation, which is then used to history match and forecast CBM-well production (e.g., for reserves assignment). CBM reservoirs have the potential for permeability anisotropy because of their naturally fractured nature, which may complicate PDA. To study the effects of permeability anisotropy upon production, a 2D, single-phase, numerical CBM-reservoir simulator was constructed to simulate single-well production assuming various permeability-anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics. Multilayer reservoir characteristics may also be observed with CBM reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve, FMB, and PT analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multilayer CBM (plus sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multilayer) production in the simple two-layer case. Introduction Commercial single-phase (gas) CBM production has been demonstrated recently in the Horseshoe Canyon coals of western Canada (Bastian et al. 2005) and previously in various basins in the US; there is currently a need for advanced PDA techniques to assist with evaluation of these reservoirs. Over the past several decades, significant advances have been made in PDA of conventional oil and gas reservoirs [select references include Fetkovich (1980), Fetkovich et al. (1987), Carter (1985), Fraim and Wattenbarger (1987), Blasingame et al. (1989, 1991), Palacio and Blasingame (1993), Fetkovich et al. (1996), Agarwal et al. (1999), and Mattar and Anderson (2003)]. These modern methods have greatly enhanced the engineers' ability to obtain quantitative information about reservoir properties and stimulation/damage from data that are gathered routinely during the producing life of a well, such as production data and, in some instances, flowing pressure information. The information that may be obtained from detailed PDA includes oil or gas in place (GIP), permeability-thickness product (kh), and skin (s), and this can be used to supplement information obtained from other sources such as PT analysis, material balance, and reservoir simulation.
- North America > Canada (1.00)
- North America > United States > New Mexico (0.66)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Information Technology > Data Science (0.84)
- Information Technology > Modeling & Simulation (0.69)
Summary The unique properties and complex characteristics of coalbed methane (CBM)reservoirs, and their consequent operating strategies, call for an integrated approach to be used to explore for and develop coal plays and prospects economically. An integrated approach involves the use of sophisticated reservoir, wellbore, and facilities modeling combined with economics and decision-making criteria. A new CBM prospecting tool (CPT) was generated by combining single-well(multilayered) reservoir simulators with a gridded reservoir model, Monte Carlo(MC) simulation, and economic modules. The multilayered reservoir model is divided into pods, representing relatively uniform reservoir properties, and a" type well" is created for each pod. At every MC iteration, type-well forecasts are generated for the pods and are coupled with economic modules. A set of decision criteria contingent upon economic outcomes and reservoir characteristics is used to advance prospect exploration from the initial exploration well to the pilot and development stages. A novel approach has been used to determine the optimal well spacing should prospect development be contemplated. CPT model outcomes include a distribution of after-tax net present value (ATNPV), mean ATNPV (expected value), chance of economic success(Pe), distribution of type-well and pod gas and water production, reserves, peak gas volume, and capital. An example application of CPT to a hypothetical prospect is provided. An integrated approach also has been used to assist with production optimization of developed reservoirs. For example, an infill-well locating tool(ILT) has been constructed to provide a quick-look evaluation of infill locations in a developed reservoir. ILT, like CPT, is used for multiwell applications, combining the single-well simulator with a multilayered reservoir model and economics. An application of ILT to a CBM reservoir is provided, and the results are compared with the predictions of an Eclipse reservoir simulation. Introduction CBM reservoirs have a relatively short history of development compared to conventional reservoirs; therefore, few analog fields may be relied upon for extrapolation to new basins and new plays. Further, key reservoir properties such as absolute permeability vary greatly within and between existing developing basins, which complicates prediction of these parameters for new plays. The production performance of CBM reservoirs in new plays or basins, in which few reservoir data exist, is correspondingly difficult to predict. Existing conventional reservoir fields cannot be relied upon as analogs for CBM play analysis because coal-gas reservoirs differ from conventional reservoirs in their fluid-storage and -transport mechanisms. Coals act as source rocks and reservoirs to gas, and a significant amount of gas may be stored in the adsorbed state relative to the free-gas state. CBM reservoirs are often naturally fractured and may be modeled as dual-porosity, or even triple-porosity, reservoirs. Gas-transport mechanisms vary depending on the scale and location within the reservoir. For example, gas transport at the scale of the matrix between natural fractures is caused by the mechanism of diffusion, whereas Darcy flow occurs in the fracture system. Single- or two-phase (gas and water) flow can occur, and, hence, relative permeability characteristics are important. Permeability and gas content are two critical parameters that dictate the economic viability of CBM reservoirs. Unfortunately, there are many controls upon these parameters. For example, gas content is a function of the amount of organic matter within these rocks, the organic matter composition, organic matter thermal maturity, in-situ PT conditions, gas composition, and matrix and fracture gas-saturated porosity. Absolute permeability is dependent upon natural-fracture existence, frequency, orientation (with respect to in-situ stress), and degree of mineralization. Natural-fracture permeability is also stress- and/or desorption-dependent. Although the range of expected parameter values for a new unconventional play may be reduced by knowledge of basin hydrodynamic characteristics, tectonic regime, local and regional stratigraphy and sedimentology, local and regional structural geology, and existing production within the basin, the uncertainty associated with key reservoir variables is still likely to preclude a deterministic evaluation of reservoir producibility and recoverable reserves. Because of the variability in reservoir parameters that could be expected when exploring for CBM in existing or new basins, it is natural to use a statistically based (stochastic) approach in the prediction of gas in place, recoverable reserves, well performance, and economic return. A comprehensive study by Roadifer et al. demonstrated the use of MC simulation for screening key parameters affecting CBM production. Well performance is a key factor determining the economic viability of CBM reservoirs. Accurate prediction of well performance is required for development strategies such as optimized well spacing, completion gathering system, and wellsite design. The current work discusses how to integrate reservoir simulation and economics for the purpose of optimizing CBM exploration and development strategies. Central to the discussion is the use of single-well (multilayered)simulators, which were constructed in Excel* and incorporate many attributes of CBM reservoirs. These single-well (tank) models are discussed in the following section and have some utility for exploration and development applications when used on their own, but they are particularly powerful when integrated with reservoir, surface, and wellbore models, MC simulation,7 and economics. Two new tools (CPT and ILT) described in this work are examples of integrated tools for application to exploration and development, respectively.
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- (2 more...)