Simulating Carbon Dioxide Sequestration/ECBM Production in Coal Seams: Effects of Permeability Anisotropies and Other Coal Properties (original) (raw)
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SPE Reservoir Evaluation & Engineering, 2005
Coalbed methane now accounts for a significant fraction of domestic natural-gas production. Injection of carbon dioxide (CO 2 ) into coal seams is a promising technology for reducing anthropogenic greenhouse-gas emissions and increasing ultimate production of coalbed methane. Reservoir simulations are an inexpensive method for designing field projects and predicting optimal tradeoffs between maximum sequestration and maximum methane production. Optimum project design and operation are expected to depend on the anisotropy of the permeability along the face-cleat and butt-cleat directions, the spacing between cleats, and the sorption isotherms for methane and CO 2 .
The injectivity of coalbed CO2 injection wells
Energy, 2004
Though it may be possible to enhance methane production from coal by injecting CO 2 , because coal is poorly permeable it is usually necessary to inject under fracturing conditions to achieve acceptable injectivity. Concomitantly, the process of replacing the methane by the injected the CO 2 causes the matrix to swell. These two processes-the fracturing of the coal and the swelling-have opposite effect on the injectivity. TNO-NITG have pressure data from a CO 2 injection test in a coalbed methane field. We used the SIMED II coalbed methane simulator to history match the test behaviour and to find the most sensitive parameters affecting the injectivity of the CO 2 injection well. An analysis of the pressure records revealed both the occurrence of fracturing and the reduction in permeability that swelling induced. When applied to an extended injection simulation, the simulator showed that the most sensitive parameters influencing the injectivity were the permeability, the fracture conductivity, and the cleat system porosity. Unfortunately, due to the adsorption of the CO 2 and the fluctuations in pressure during injection tests, all these vary over time.
All Days, 2002
Carbon dioxide sequestration is a promising technology for reducing anthropogenic greenhouse gas emissions while fossil fuels are still being used. The costs associated with CO 2 sequestration are often high; however, in certain circumstances (e.g., enhanced oil recovery) these costs can be more than offset by the benefits of additional incremental hydrocarbon production. Primary production of coalbed methane is a well-developed technology, but secondary production, through the injection of CO 2 or N 2 has undergone relatively little study. Recent research suggests that carbon dioxide preferentially sorbs to coal, displacing methane, making CO 2-enhanced coalbed methane production an ideal candidate for CO 2 sequestration. We use PSU-COALCOMP, a dual-porosity coalbed methane simulator, to model primary and secondary production of methane from coal, for a variety of coal properties and operational parameters. Our base well pattern consists of four horizontal production wells that form a square, with four smaller horizontal producers/injectors at the square's center. Primary production of methane and water is simulated until a specified reservoir pressure is reached, after which CO 2 is injected in the center wells to displace methane, extending the reservoir's production of methane. Production continues until the CO 2 concentration in the produced gas is too high. By modifying coal properties, such as permeability, porosity, degree of anisotropy, and sorption rates, we have approximated different types of coals. By varying operational parameters, such as injector length, injection well pressure, time to injection, and production well pressure, we can evaluate different production schemes to determine an optimum for each coal type. Any optimization requires considering a tradeoff between total methane produced (or CO 2 sequestered) and the rate of methane production. Values of aggregate methane production and methane production rate are presented for multiple coal types and different operational designs.
CO2 Sequestration in Coalbed Methane Reservoirs: Experimental Studies and Computer Simulations
2002
One of the approaches suggested for sequestering C02 is by injecting it in coalbed methane (CBM) reservoirs. Despite its potential importance for C02 sequestration, to our knowledge, C02 injection in CBM reservoirs for the purpose of sequestration has not been widely studied. Furthermore, a key element missing in most of the existing studies is the comprehensive characterization of the CBM reservoir structure. CBM reservoirs are complex porous media, since in addition to their primary pore structure, generated during coal formation, they also contain a variety of fractures, which may potentially play a key role in C02 sequestration, as they generally provide high permeability flow paths for both CO2 and C&. In this report we present an overview of our ongoing experimental and modeling efforts, which aim to investigate the injection, adsorption and sequestration of CO2 in CBM reservoirs, the enhanced C& production that results, as well as the main factors that affect the overall operation. We describe the various experimental techniques that we utilize, and discuss their range of application and the value of the data generated. We conclude with a brief overview of our modeling efforts aiming to close the knowledge gap and fill the need in this area. ..
Modeling of CBM production, CO2 injection, and tracer movement at a field CO2 sequestration site
International Journal of Coal Geology, 2012
Sequestration of carbon dioxide in unmineable coal seams is a potential technology mainly because of the potential for simultaneous enhanced coalbed methane production (ECBM). Several pilot tests have been performed around the globe leading to mixed results. Numerous modeling efforts have been carried out successfully to model methane production and carbon dioxide (CO 2) injection. Sensitivity analyses and history matching along with several optimization tools were used to estimate reservoir properties and to investigate reservoir performance. Geological and geophysical techniques have also been used to characterize field sequestration sites and to inspect reservoir heterogeneity. The fate and movement of injected CO 2 can be determined by using several monitoring techniques. Monitoring of perfluorocarbon (PFC) tracers is one of these monitoring technologies. As a part of this monitoring technique, a small fraction of a traceable fluid is added to the injection wellhead along with the CO 2 stream at different times to monitor the timing and location of the breakthrough in nearby monitoring wells or offset production wells. A reservoir modeling study was performed to simulate a pilot sequestration site located in the San Juan coal basin of northern New Mexico. Several unknown reservoir properties at the field site were estimated by modeling the coal seam as a dual porosity formation and by history matching the methane production and CO 2 injection. In addition to reservoir modeling of methane production and CO 2 injection, tracer injection was modeled. Tracers serve as a surrogate for determining potential leakage of CO 2. The tracer was modeled as a non-reactive gas and was injected into the reservoir as a mixture along with CO 2. Geologic and geometric details of the field site, numerical modeling details of methane production, CO 2 injection, and tracer injection are presented in this paper. Moreover, the numerical predictions of the tracer arrival times were compared with the measured field data. Results show that tracer modeling is useful in investigating movement of injected CO 2 into the coal seam at the field site. Also, such new modeling techniques can be utilized to determine potential leakage pathways, and to investigate reservoir anisotropy and heterogeneity.
Numerical modeling of carbon dioxide injection at a pilot sequestration site
Over the past several years, lessons learned from various sequestration sites have identified deep, unmineable coal seams as favorable and profitable reservoirs for commercial carbon dioxide (CO 2) sequestration and long-term CO 2 storage. Long-term consequences, however, have not been completely identified and understood. In order to assess the aptitude of such deep unmineable coal seams for a possible commercial sequestration site, a reservoir modeling study was performed at an ongoing Pump Canyon, NM sequestration site located in the coalbed methane (CBM) fairway region of the well-established San Juan basin. The demonstration at the Pump Canyon pilot area is a part of the Southwest Regional Partnership on CO 2 sequestration sponsored by the U.S. Department of Energy to evaluate availabletechnologies and practices to capture and store greenhouse gases such as CO 2. The present paper includes three objectives-(1) to study the history of CBM production in the region and construct an appropriate reservoir model based on the cleat geometry and available geological information, (2) to identify any unknown reservoir and geologic properties at the site through a history matching process, and (3) to model CO 2 and tracer injections to aid in understanding fluid flow through the system.. CBM production data over past two decades demonstrates an adequate facility for deploying the first commercial sequestration in the San Juan basin. A reservoir model was constructed using a modified existing simulator and based on available reservoir and geologic data. Several simulations were performed to obtain a historymatch and analyze the CBM production history before and after CO 2 injection. During CO 2 injection a tracer was injected into the reservoir for tracking purposes. The tracer's movement through the reservoir system was tracked using data from nearby producing wells. Tracer breakthrough occurred when nearby wells began to produce significant quantities of the injected tracer. Several simulations were performed to obtain matches with breakthrough data and tracer properties and further refine the model. The successful performance of this reservoir identifies the San Juan basin as a promising site for commercial sequestration of carbon dioxide.
Enhanced Coalbed Methane ( ECBM ) and CO 2 Sequestration with Horizontal Wells
2004
Injection of carbon dioxide into unmineable coal seams is a promising technology for reducing anthropogenic gas emissions and increasing ultimate recovery of coalbed methane. The combination of incremental methane produced and possible tax incentives might compensate for the costs associated with CO2 injection. Currently the U.S. Department of Energy (DOE) is co-funding a pilot CO2 sequestration and enhanced coalbed methane (ECBM) project in the Appalachian Basin, in a thin coal seam. Horizontal wells have been drilled in the seam to increase CO2 injectivity and methane production rate. Previously, the reservoir simulations we performed for the planned pilot pattern indicated an optimum length for the horizontal injectors to maximize methane recovery and CO2 storage. By varying operational parameters such as time of primary production, injector length, injection pressure, injection timing, and production well pressure, we can evaluate different production alternatives to determine p...
Reservoir Management of CO2 Injection: Pressure Control and Capacity Enhancement
Energy Procedia, 2013
The transition to large-scale CO 2 storage as part of a low Carbon-fuels energy mix will require intelligent use of reservoir management methods, and can draw from many decades of experience from Enhanced Oil Recovery (EOR) projects. CO 2 EOR is also proposed as an important CO 2 storage option, but has not yet been optimized for CO 2 storage. We focus here on the application of reservoir management methods for optimizing CO 2 storage.
Impact of CO2 Injection on Flow Behavior of Coalbed Methane Reservoirs
Transport in Porous Media, 2010
On the basis of observations at four enhanced coalbed methane (ECBM)/CO 2 sequestration pilots, a laboratory-scale study was conducted to understand the flow behavior of coal in a methane/CO 2 environment. Sorption-induced volumetric strain was first measured by flooding fresh coal samples with adsorptive gases (methane and CO 2). In order to replicate the CO 2-ECBM process, CO 2 was then injected into a methane-saturated core to measure the incremental "swelling." As a separate effort, the permeability of a coal core, held under triaxial stress, was measured using methane. This was followed by CO 2 flooding to replace the methane. In order to best replicate the conditions in situ, the core was held under uniaxial strain, that is, no horizontal strain was permitted during CO 2 flooding. Instead, the horizontal stress was adjusted to ensure zero strain. The results showed that the relative strain ratio for CO 2 /methane was between 2 and 3.5. The measured volumetric strains were also fitted using a Langmuir-type model, thus enabling calculation of the strain at any gas pressure and using the analytical permeability models. For permeability work, effort was made to increase the horizontal stress to achieve the desired zero horizontal strain condition expected under in situ condition, but this became impossible because the "excess" stress required to maintain this condition was very large, resulting in sample failure. Finally, when CO 2 was introduced and horizontal strain was permitted, permeability reduction was an order of magnitude greater, suggesting that the "excess" stress would have reduced it significantly further. The positive finding of the work was that the "excess" stresses associated with injection of CO 2 are large. The excess stresses generated might be sufficient to cause microfracturing and increased permeability, and improved injectivity. Also, there might be a weakening effect resulting from repeated CO 2 injection, as has been found to be the case with thermal cycling of rocks.