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This paper summarizes numerical and experimental simulation results of a cyclic solvent injection process study, which was part of a continuing investigation into the use of solvents as a follow up process in Cold Lake and Lloydminster reservoirs that have been pressure depleted by cold heavy oil production with sand (CHOPS). Typically only 5 -10% of the original oil in place (OOIP) is recovered during cold production, so an effective follow-up process is required.The cyclic solvent injection (CSI) experiment consisted of primary production followed by 6 solvent (28% C 3 H 8 -72% CO 2 ) injection cycles. Oil recovery after primary production and six solvent cycles was 50%, which indicates the potential viability of the CSI process.Concurrently with the laboratory physical simulation, a numerical simulation model was developed to represent the physical behavior of the experimental results. A history match of the primary production portion of the experiment was obtained using an Alberta Research Council foamy oil model. This resulted in the characterization (fluid saturations and pressures) of the oil sand pack at the start of the solvent injection process. The history match of the subsequent 6 solvent injection cycles was used to validate the numerical model of the CSI process developed at the Alberta Research Council.This model includes non-equilibrium rate equations that simulated the delay in solvent reaching its equilibrium concentration as it dissolves or exsolves in the oil in response to changes in the pressure and/or gas phase composition. Dissolution of CH 4 , C 3 H 8 , and CO 2 in oil and CO 2 in water were considered, as was exsolution of CH 4 , C 3 H 8 , and CO 2 from oil and CO 2 from water.Reduced gas phase permeabilities resulting from gas exsolution were also included.The history match simulations indicated that:• The important mechanisms were represented in the simulations • Significant oil swelling by solvent dissolution occurs during solvent injection periods. This can reduce solvent injectivity and penetration into a heavy oil reservoir during solvent injection periods • Low oil and gas phase relative permeabilities are required during production periods to match the experimental oil and gas production during solvent cycles A parametric simulation study showed that the quantity of gas injected in an injection period was relatively insensitive to the oil phase diffusion coefficients but was sensitive to solvent solubility in oil, dissolution rates, gas phase diffusion coefficients, molar densities in the oil phase, gas phase relative permeability, and capillary pressure. It was shown that oil production is highly dependent on how quickly solvent can dissolve in the oil during injection and exsolve from the oil during production

Summary This paper summarizes numerical and experimental simulation results of a cyclic solvent injection process study, which was part of a continuing investigation into the use of solvents as a follow-up process in Cold Lake and Lloydminster reservoirs that have been pressure-depleted by cold heavy oil production with sand (CHOPS). Typically only 5% - 10% of the original oil in place (OOIP) is recovered during cold production; therefore, an effective follow-up process is required. The cyclic solvent injection (CSI) experiment consisted of primary production followed by six solvent (28% C3H8  - 72% CO2) injection cycles. Oil recovery after primary production and six solvent cycles was 50%, which indicates the potential viability of the CSI process. Concurrently with the laboratory physical simulation, a numerical simulation model was developed to represent the physical behaviour of the experimental results. A history match of the primary production portion of the experiment was obtained using an Alberta Innovates - Technology Futures (AITF) foamy oil model. This resulted in the characterization (fluid saturations and pressures) of the oil sandpack at the start of the solvent injection process. The history match of the subsequent six solvent injection cycles was used to validate the numerical model of the CSI process developed at AITF. This model includes nonequilibrium rate equations that simulated the delay in solvent reaching its equilibrium concentration as it dissolves or exsolves in the oil in response to changes in the pressure and/or gas-phase composition. Dissolution of CH4, C3H8 and CO2 in oil and CO2 in water were considered, as was exsolution of CH4, C3H8 and CO2 from oil and CO2 from water. Reduced gas-phase permeabilities resulting from gas exsolution were also included. The history match simulations indicated that: The important mechanisms were represented in the simulations. Significant oil swelling by solvent dissolution occurs during solvent injection periods. This can reduce solvent injectivity and penetration into a heavy oil reservoir during solvent injection periods. Low oil and gas-phase relative permeabilities are required during production periods to match the experimental oil and gas production during solvent cycles. A parametric simulation study showed that the quantity of gas injected in an injection period was relatively insensitive to the oil-phase diffusion coefficients, but was sensitive to solvent solubility in oil, dissolution rates, gas-phase diffusion coefficients, molar densities in the oil phase, gas-phase relative permeability and capillary pressure. It was shown that oil production is highly dependent on how quickly solvent can dissolve in the oil during injection and exsolve from the oil during production.

Summary Only 5-10% of the oil in Lloydminster heavy-oil reservoirs is recovered during cold heavy-oil production with sand (CHOPS). CSI is currently the most active post-CHOPS process. In CSI, a solvent mixture (e.g., methane/propane) is injected and allowed to soak into the reservoir before production begins (Fig. 1). CSI has been focused on heavy-oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by Nexen and Husky and was a fundamental part of the CDN40 million joint implementation of vapour extraction (JIVE) solvent pilot program that ran from 2006 through 2010. This paper describes field-scale simulations of CSI performed with a comprehensive numerical model that uses "mass-transfer" rate equations to represent nonequilibrium solvent-solubility behaviour (i.e., there is a delay before the solvent reaches its equilibrium solubility in oil). The model contains mechanisms to consider foaming or to ignore it, depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results. The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high-permeability zone, (2) a dual-permeability zone, (3) a dilated zone around the well, (4) wormholes (20-cm-diameter spokes) extending from the well without branching, and (5) wormholes extending from the well with branching from the main wormholes. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance. The impacts of grid size, upscaling, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared with when a delay in solvent dissolution and exsolution was allowed for. Increasing the gridblock size by a factor of nine reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%.

Hollow-fiber-based adsorbers for gas separation by pressure-swing adsorption (PSA) was studied experimentally. The high efficiency of hollow-fiber-based adsorbers for gas .separation was illustrated by hydrogen separation using fine-powder-activated carbon and molecular sieve as adsorbents. The adsorption equilibrium and dynamics of the hollow-fiber adsorbers were determined. The pressure drop of the gas flowing through the adsorbers was also examined. The adsorbers were tested for hydrogen separation from nitrogen, carbon dioxide, and a multicomponent gas mixture simulating ammonia synthesis purge gas. The PSA systems using the hollow-fiber adsorbers were uely effectiue for hydrogen purification. The high separation efficiency is derived from the fast masstransfer rate and low pressure drop, two key features of hollow-fiber-based adsorbers.

A new in-situ combustion strategy, the top down process, is currently under detailed laboratory study. The process, aimed at overcoming some of the problems that have restricted the successful application of in-situ combustion in oil sand and heavy oil formations, involves the stable propagation of a combustion front from the top to the bottom of a reservoir, exploiting gravity drainage of the mobilized oil to a lower horizontal well. Operational parameters that have been investigated and presented here include: air injection flux, degree of pre-heating, internal steam flood pre-heating and injection of normal air versus injection of oxygen enriched air. To compliment the experimental investigation, the thermal numerical simulator STARS has been applied to the in-situ combustion process by incorporating reaction kinetics for Athabasca oil sand. A successful history match of an experimental test is presented accompanied by a discussion of application of the model to field scale. Introduction In-situ combustion has long been recognized as having the potential for being an economical thermal oil recovery process in heavy oil and oil sand deposits. The energy required to supply heat to the reservoir compares quite favourably with steam. The estimated cost1 to place 1 GJ of energy in a 7 MPa reservoir is $2.6-$4.4 using steam and $ 1.0 for in-situ combustion using air (assuming $2/GJ fuel cost, capital cost not included). In-situ combustion is not compromised by large heat losses to overburden and underburden in thin formations or by high heat losses from the well bore to the overburden in deep formations as is the case with steam injection. Also in-situ combustion theoretically has important applications in reservoirs containing bottom water and as a follow up process to waterflooded and steamflooded formations. Previous in-situ combustion field projects, however, have been less successful than steam, primarily because of the difficulty in controlling the combustion front advancement. The customary in-situ combustion operation of the past involved the injection of an oxygen containing gas into a central vertical injection well surrounded by a number of vertical production wells (typically as part of a larger pattern of injection and production wells). Combustion was initiated near the injection well and horizontally propagated radially outwards, aiming to drive the mobilized oil towards the production wells. The problem frequently encountered was that the combustion fronts tended to advance erratically with the vertical sweep constrained by gravity override of the displacing gas and the areal sweep reduced by preferential flow to one well of the pattern. Injected oxygen, overriding the combustion zone, created problems at the production end and the overriding hot steam and combustion gases did little to heat the formation ahead of the burn zone. The displacement geometry of the process requires that the mobilized oil be displaced ahead of the combustion front into the colder immobile oil, increasing oil saturation and further reducing mobility, with the limited producibility of the vertical production wells unable to alleviate the situation. P. 487

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