D.H.S. Law

Hydrogeological and numerical analysis of CO2 disposal in deep aquifers in the Alberta sedimentary basin

For landlocked large sources of CO2, the best approaches for reducing CO2 emissions into the atmosphere are its utilization and deep disposal into deep sedimentary aquifers or depleted oil and gas reservoirs. A number of coal-based power plants (total capacity of more than 4000 MW) are located near Lake Wabamun in central Alberta, Canada. A hydrogeological study of the sedimentary succession at the site was undertaken to identify and select aquifers which meet various requirements for CO2 disposal, particularly with respect to depth and confinement. The multi-phase, multi-component numerical model STARS was used to study the ability of the selected aquifers to accept and retain for long periods of time large quantities of CO2 injected in a supercritical state. The CO2 injectivity of the selected aquifers was examined for a whole series of parameters, including aquifer depth and thickness, rock and formation water properties, and injection characteristics. The numerical simulations indicate that even generally low-permeability aquifers can accept and retain large quantities of CO2, showing that injection of CO2 in a supercritical state into deep aquifers in sedimentary basins is a viable option and may be the best short-to-medium term solution for reducing CO2 emissions into the atmosphere. The CO2 injectivity is enhanced by the existence of ‘sweet’ zones of high permeability.

Enhanced coalbed methane and CO2 storage in anthracitic coals—Micro-pilot test at South Qinshui, Shanxi, China

Abstract This paper describes the results of a single well micro-pilot test performed at an existing well in the anthracitic coals of the South Qinshui basin, Shanxi Province, China. A set of reservoir parameters was obtained from the micro-pilot test. The field data was successfully history matched using a tuned reservoir model which accounted for changes in permeability due to swelling and pressure change. Prediction of initial performance showed significant production enhancement of coalbed methane while simultaneously storing the CO2. The calibrated reservoir model was used to design a multi-well pilot at the site to validate the performance prediction. The design is now completed. The recommendation is to proceed to the next stage of multi-well pilot testing and to demonstrate the enhanced coalbed methane (ECBM) technology.

Technical and economic feasibility of CO2 disposal in aquifers within the Alberta sedimentary basin, Canada

A three year study of the technical and economic feasibility of aquifer disposal of CO2 in the low permeability sedimentary rocks of the Alberta Basin has revealed several new generic concepts that may be applicable to other sedimentary basins throughout the world. High permeability aquifers are not necessarily required for CO2 disposal. Injectivity of CO2 can be maximized by siting disposal wells in targeted or “sweet” zones of locally high permeability surrounded by a low regional scale permeability [1–2]. The low regional permeability forms a “hydrodynamic” or “time” trap for CO2 [1], where the residence time of CO2 in the aquifer is of the order of 105 to 106 years. Another type of hydrodynamic trapping in sedimentary basins is produced by the “sponge” or “sink” effect of rebounding shales [3–4]. On a smaller time scale, over hundreds of years, “mineral” or “inert” trapping [5–6] by reaction of the CO2 with basic aluminosilicate minerals will occur in siliciclastic aquifers. Consequently, stratigraphic traps may not be necessary for safe disposal of CO2 in the subsurface. n nAquifer disposal of CO2 is expensive, on the order of

Numerical Simulator Comparison Study for Enhanced Coalbed Methane Recovery Processes, Part I: Pure Carbon Dioxide Injection

52/tonne. Although there are many possibilities to reduce CO2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted.

Simulating the ES-SAGD Process With Solvent Mixture in Athabasca Reservoirs

The injection of carbon dioxide (CO2) in deep, unmineable coalbeds can enhance the recovery of coalbed methane (CBM) and at the same time it is a very attractive option for geologic CO2 storage as CO2 is strongly adsorbed onto the coal. Existing CBM numerical simulators which are developed for the primary CBM recovery process, have many important features such as: (1) a dual porosity system; (2) Darcy flow in the natural fracture system; (3) pure gas diffusion and adsorption in the primary porosity system; and (4) coal shrinkage due to gas desorption; taken into consideration. However, process mechanisms become more complex with CO2 injection. Additional features such as: (1) coal swelling due to CO2 adsorption on coal; (2) mixed gas adsorption; (3) mixed gas diffusion; and (4) non-isothermal effect for gas injection; have to be considered. This paper describes the first part of a comparison study between numerical simulators for enhanced coalbed methane (ECBM) recovery with pure CO2 injection. The problems selected for comparison are intended to exercise many of the features of CBM simulators that are of practical and theoretical interest and to identify areas of improvement for modeling of the ECBM process. The first problem set deals with a single well test with CO2 injection and the second problem set deals with ECBM recovery process with CO2 injection in an inverted five-spot pattern. Introduction The injection of carbon dioxide (CO2), a greenhouse gas (GHG), in coalbeds is probably one of the more attractive options of all underground CO2 storage possibilities: the CO2 is stored and at the same time the recovery of coalbed methane (CBM) is enhanced. The revenue of methane (CH4) production can offset the expenditures of the storage operation. Coalbeds are characterized by their dual porosity: they contain both primary (micropore and mesopore) and secondary (macropore and natural fracture) porosity systems. The primary porosity system contains the vast majority of the gas-in-place volume while the secondary porosity system provides the conduit for mass transfer to the wellbore. Primary porosity gas storage is dominated by adsorption. The primary porosity system is relatively impermeable due to the small pore size. Mass transfer for each gas molecular species is dominated by diffusion that is driven by the concentration gradient. Flow through the secondary porosity system is dominated by Darcy flow that relates flow rate to permeability and pressure gradient. The conventional primary CBM recovery process begins with a production well that is often stimulated by hydraulic fracturing to connect the wellbore to the coal natural fracture system via an induced fracture. When the pressure in the well is reduced by opening the well on the surface or by pumping water from the well, the pressure in the induced fracture is reduced which in turn reduces the pressure in the coal natural fracture system. Gas and water begin moving through the natural and induced fractures in the direction of decreasing pressure. When the natural fracture system pressure drops, gas molecules desorb from the primary-secondary porosity interface and are released into the secondary porosity system. As a result, the adsorbed gas concentration in the primary porosity system near the natural fractures is reduced. This reduction creates a concentration gradient that results in mass transfer by diffusion through the micro and mesoporosity. Adsorbed gas continues to be released as the pressure is reduced. When CO2 (which is more strongly adsorbable than CH4) is injected into the coal natural fracture system during the ECBM recovery process, it is preferentially adsorbed into the primary porosity system. Upon adsorption, the CO2 drives 2 DAVID H.-S. LAW, L.G.H. (BERT) VAN DER MEER AND W.D. (BILL) GUNTER SPE 75669 CH4 from the primary porosity into the secondary porosity system. The secondary porosity pressure is increased due to CO2 injection and the CH4 flows to production wells. The CO2 is stored in-situ and is not produced unless the injected gas front reaches the production wells. The process, in general, is terminated at CO2 breakthrough. A full understanding of all the complex mechanisms involved in the enhanced coalbed methane recovery process with CO2 injection (CO2-ECBM) is essential to have more confidence in the numerical modeling of the process. The objective of this study of comparison of numerical simulators is to provide the incentive to improve existing CBM simulators for capability and performance assessment of the CO2-ECBM recovery process. Decription of CBM Simulators Existing commercial and research CBM simulators are developed, in general, to model primary CBM recovery process taken into account of many important features such as: • dual porosity nature of coalbed; • Darcy flow of gas and water (i.e., multiphase flow) in the natural fracture system in coal; • diffusion of a single gas component (i.e., pure gas) from the coal matrix to the natural fracture system; • adsorption/desorption of a single gas component (i.e., pure gas) at the coal surface; and • coal matrix shrinkage due to gas desorption. However, Law et al. have suggested that in order for a CBM simulator to correctly model the more complicated mechanisms involved in the CO2-ECBM recovery process, it has to be improved, taking into account many additional features such as: • coal matrix swelling due to CO2 adsorption on the coal surface; • compaction/dilation of the natural fracture system due to stresses; • diffusion of multiple gas components (i.e., mixed gas) between the coal matrix and the natural fracture system; • adsorption/desorption of multiple gas components (i.e., mixed gas) at the coal surface; • non-isothermal adsorption due to difference in temperatures between the coalbed and the injected CO2; and • water movement between the coal matrix and the natural fracture system. Five CBM simulators have participated in the comparison study: (1) GEM, Computer Modelling Group (CMG) Ltd., Calgary, Alberta, Canada; (2) ECLIPSE, Schlumberger GeoQuest, Abingdon, Oxon, United Kingdom; (3) COMET 2, Advanced Resources International (ARI), Arlington, Virginia, U.S.A.; (4) SIMED II, Commonwealth Scientific and Industrial Research Organization (CSIRO), Kinnoull Grove, Syndal, Victoria, Australia and the Netherlands Institute of Applied Geoscience TNO, Utrecht, The Netherlands; and (5) GCOMP, BP, Houston, Texas, U.S.A.. These simulators except GCOMP are all commercial in nature. The numerical simulators, GEM and SIMED II, are compositional simulators with additional features for CBM modeling. Due to nature of these simulators, GEM and SIMED II are capable to handle multiple (i.e., 3 or more) gas components. On the other hand, the numerical simulators, ECLIPSE (CBM model) and COMET 2, are black oil simulators with additional features for CBM modeling and only capable to handle two gas components (e.g., CH4 and CO2 only). The newly developed COMET 3 by ARI can handle three gas components. This feature is essential in modeling ECBM recovery processes with flue gas (i.e., a mixture of CO2 and nitrogen (N2)) injection. The numerical simulator, GCOMP, is a compositional simulator converted to model the CBM recovery process based on the approach suggested by Seidle and Arri. With the assumption that the diffusion of gases from the primary porosity system into the natural fracture system of the coal is instantaneous, a single porosity approach can be used instead of the dual porosity approach. This approach allows many conventional oil and gas compositional simulators to model CBM recovery processes. A summary of the CBM features, which some have been in existence for several years and others are recently developed, in the five aforementioned simulators is given in Table 1. Although dual porosity approach can be used in GCOMP, single porosity approach is recommended by BP for CBM modeling. Therefore, GCOMP is incapable to handle mixed gas diffusion in this case. On the other hand, ECLIPSE does not incorpate the extended Langmuir isotherm theory in the CBM model. However, it has a feature (i.e., relative adsorption for each gas component) to allow the simulator to take into account the “non-ideal” adsorption behaviour of a two-gas mixture. Approach The approach used in this comparison study, in general, follows those used by a series of SPE comparison studies. The authors organize and manage the simulator comparison study; facilitate the development and selection of appropriate test problems; distribute them to identified software developers with commercial CBM simulators and other interested groups of scientists and engineers who want to participate in this exercise; and solicit, collect, reconcile, and document solutions. Development and selection of sample test problems is made on the basis of major mechanisms expected to occur in the CO2-ECBM recovery process, taking into account the existing simulation capabilities and future needs. The test NUMERICAL SIMULATOR COMPARISON STUDY FOR ENHANCED COALBED METHANE SPE 75669 RECOVERY PROCESSES, PART I: PURE CARBON DIOXIDE INJECTION 3 problems do not necessary represent real field situations. The initial two sets of test problems emphasize the comparison of the performance of CBM simulators, which may only have the features to model the primary CBM recovery process. At a later stage, two more sets of test problems will be developed that address more complicated process mechanisms. At this stage, improvement on some of the existing CBM simulators by incorporating the additional features for CO2-ECBM recovery process is necessary. Finally, performance of CBM simulators will be compared for their capability to history match field test data collected by the ARC through performing “micro-pilot tests” by CO2 injection into coal seams in Alberta, Canada. The first two sets of test problems have been assembled, which are intended to initiate

Field-Scale Numerical Simulation of SAGD Process With Top-Water Thief Zone

The ES-SAGD process was developed to improve the energy and oil drainage efficiency of the SAGD process. The idea of the ES-SAGD process is to co-inject solvent with steam and the co-injected solvent mixes with the bitumen to further reduce the viscosity of the heated bitumen along the boundary of the steam chamber thus enhances the oil recovery. Practically, the co-injected solvent will be a solvent mixture (such as diluent /naphtha) because of its availability and reduced cost than a pure hydrocarbon. This paper reports the results of an ES-SAGD lab test conducted with steam and diluent co-injection using Athabasca bitumen. To simulate the ES-SAGD test, a pseudo-component scheme to represent the complex solvent mixture in the numerical model is derived, based on the diluent composition and measured PVT data. The behaviours and ef- fects of the co-injected solvent in the ES-SAGD process are analyzed through detailed history matching of the ES-SAGD test. Numerical sensitivity analyses are also performed to investigate the effects of some key parameters in the numerical approach.

Code Intercomparison Builds Confidence in Numerical Models for Geologic Disposal of CO2

There is a major concern that the existence of thief zones, such as top water and/or a gas cap overlying the oil sand deposit, has a detrimental effect on the oil recovery in the application of the steam-assisted gravity drainage (SAGD) process. The objective of this numerical study is to investigate SAGD performance in the Athabasca oil sands in the presence of a top water zone. The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd., has been previously validated based on a 3D SAGD laboratory experiment with top water that was conducted at the Alberta Research Council (ARC). It is believed that the numerical simulation captured the major mechanism of oil movement from the pay zone into the top water zone, as was observed in the experiment. In the field-scale simulation, SAGD performance in the presence of confined and non-confined top water zones was investigated. The operating strategies under the conditions of non-depleted top water/non-depleted pay zones and depleted top water/non-depleted pay zones were considered. Numerical findings indicated that: (1) there is a detrimental effect of a top water zone on SAGD performance; (2) plugging of a top water zone with oil was not observed in this study for a top water thickness of 8 m; and, (3) operating conditions that lead to a higher pressure difference between the steam chamber and the top water, either by depletion of the top water zone pressure or a higher steam injection pressure, results in a more detrimental effect on the SAGD performance.

Settling behaviour of heavy and buoyant particles from a suspension in an inclined channel

Publisher Summary Different kinds of subsurface reservoirs have been proposed for geologic disposal of greenhouse gases, including saline aquifers (brine formations), depleted or depleting oil and gas reservoirs, and coalbeds. Injection of greenhouse gases into such formations will give rise to complex coupled processes of fluid flow, mechanical and chemical changes, and heat transfer. Mathematical models and numerical simulation tools will play an important role in evaluating the feasibility of geologic disposal of CO 2 , and in designing and monitoring CO 2 disposal operations. The models must accurately represent the major physical and chemical processes induced by injection of CO 2 into potential disposal reservoirs, such as miscible and immiscible displacement, partitioning of CO 2 among different fluid phases, chemical reactions, thermal effects, and geomechanical changes from increased pore pressures. It is essential to test and evaluate numerical simulation codes to establish their ability to model these processes in a realistic and quantitative fashion. The code inter-comparison study reported in this chapter is a first step in this direction.

Comparison of Numerical Simulators for Greenhouse Gas Storage in Coal Beds, Part II: Flue Gas Injection

Etude experimentale et theorique des caracteristiques de sedimentation de suspensions bidispersees contenant des particules legeres et des particules lourdes dans des canaux inclines. Visualisation de lecoulement montrant la formation de zones distinctes avec des interfaces claires. Il ny a pas de segregation laterale des particules. On adopte le modele de sedimentation de Ponder-Nakamura-Kuroda

SAGD Wind-Down: Lab Test and Simulation

Publisher Summary The injection of carbon dioxide (CO 2 ), a greenhouse gas (GHG), in coal beds is probably one of the more attractive options of all underground CO 2 storage possibilities, because the CO 2 is stored and the recovery of coalbed methane (CBM) is enhanced at the same time. The revenue of methane (CH 4 ) production can offset the expenditures of the storage operation. Deep, unmineable coal beds are a very attractive geological formations for the storage of CO 2 . Numerical simulators are useful tools in the development of the GHG storage technology. It is essential to test and evaluate these numerical simulators, to establish their ability to model the complex mechanisms involved. This chapter describes the second part of a simulator comparison study for CO 2 storage in coal beds with flue gas injection. The first part of the study was with pure CO 2 injection. Two problem sets—one that deals with a single well test with flue gas injection and the other that deals with flue gas injection/enhanced CBM production in an inverted five-spot pattern—have been presented in this chapter along with preliminary simulation results obtained from various numerical simulators. The problems selected for comparison are intended to exercise many of the CBM related features of the simulators that are of practical and theoretical interest.