Steam-Solvent Coinjection Research Articles

The impact of permeability barriers on steam-solvent coinjection – A mechanistic study using a physical model

Coinjection of steam and condensate has been studied for improving the energy efficiency of steam-assisted gravity drainage (SAGD) as solvent-assisted SAGD or SA-SAGD. However, it is not well understood how tortuous hydraulic paths under heterogeneous permeability can influence the compositional and thermal flow characteristics in SA-SAGD. We addressed this question by performing an experiment of the coinjection of steam and condensate for bitumen recovery. This paper discusses the experimental results and gives our mechanistic analysis of how the tortuous hydraulic paths affected the thermal and compositional flow and the properties of the produced bitumen in the experiment.The physical model was a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.2 m, which was filled with unconsolidated sands. Two shale plates were horizontally installed above the well pair at different elevations so that they could represent permeability barriers to cause tortuous flow paths during the SA-SAGD experiment. The porosity and permeability of the sandpack was 0.34 and 5.6 D, respectively. Initially, the oil and water saturations were 95% and 5%, respectively.After preheating for 1 day, a mixture of 98.2 mol% steam and 2.8 mol% condensate was injected at 3500 kPa for 4 days (35 cm3/min of steam, cold water equivalent). The injection and production histories along with the real-time temperature distribution were recorded during the experiment. Produced oil samples were frequently taken and analyzed for density and asphaltene content. After the experiment, the sandpack was excavated and sampled from different locations to analyze the saturation and asphaltene content of the remaining oil. The experimental results in this paper were compared with the previous SAGD and SA-SAGD experiments that used the same experimental set up with a homogeneous sandpack.Results showed that, in comparison to the homogeneous SAGD case, SA-SAGD was able to lower the cumulative steam-oil ratio (SOR) by a factor of two to three even in the presence of shale plates. Analysis of the temperature profiles indicated that the steam chamber vertically expanded from the lower part to the upper part through tortuous paths at lower temperatures. An emerging steam chamber above the shale plates occurred by convective heat from the injection well through lower-temperature flow paths between shale plates, involving light to intermediate solvent components that enabled the steam chamber to expand away from the injection well. This highlights the important role of volatile solvent components in the growth of a steam chamber in SA-SAGD under heterogeneity. The produced bitumen density in this research was closer to the original bitumen than in the homogeneous SA-SAGD case because the bitumen dilution and the solvent retention increased by the tortuous flow regime resulted in efficient drainage of oil at lower temperature.

A new experimental method for comparing solvents in steam-solvent coinjection for bitumen recovery under controlled thermodynamic conditions

Solvent-aided steam-assisted gravity drainage (SA-SAGD) involves the interplay between phase behavior and fluid flow near the edge of a steam chamber, which affects the mixing of solvent with bitumen. The mixing of solvent with bitumen (i.e., dispersion) results in dilution of the bitumen and can improve the energy efficiency of SAGD. However, it is often difficult to analyze this complex interplay through large-scale steam injection experiments because of the transient chamber-edge thermodynamic conditions.This paper presents an experimental program that compares the bitumen gravity drainage with steam injection (SAGD) and solvent-steam co-injection (SA-SAGD) under controlled thermodynamic conditions. In addition to SAGD as the base case, two sets of SA-SAGD were performed with 20 mol% C4 and 10 mol% C8 in the coinjected vapor at 3500 kPa. The experiments used a sand-pack of 3-inch diameter and 15-inch length, which was placed in a 25-L cylindrical pressure vessel. The sand-pack was surrounded by one-inch annular space, into which the vapor phase was injected under controlled pressure, temperature, and composition. Oil production and temperature profiles inside and outside the sand-pack were recorded for all experiments. Excavated samples from the sand-pack were analyzed after the experiments.The total recovery factors for SAGD, C4-SAGD, and C8-SAGD were 78%, 84%, and 89%, respectively. The recovery factors at 1 h for SAGD, C4-SAGD, and C8-SAGD were 71%, 80%, and 85%, respectively. The peak oil rate was 9.8 cm3/min with SAGD, 14.6 cm3/min with C4-SAGD, and 31.3 cm3/min with C8-SAGD. The SA-SAGD cases resulted in markedly better results than the SAGD case, and C8-SAGD yielded more rapid oil drainage than C4-SAGD.The SAGD experimental data were history-matched using a numerical simulation model. Based on the calibrated numerical model, the SA-SAGD experimental data were history-matched by adjusting the dispersion coefficient to model the mixing between the solvent and bitumen. The apparent dispersion coefficients for C4 and C8 in bitumen were determined to be 0.012 m2/day and 0.093 m2/day, respectively. The experimental program verified in this research offers a way to systematically compare different solvents for SA-SAGD with their quantifiable dispersion coefficients under given chamber conditions.

Steam-Oil Ratio in Steam-Solvent Coinjection Simulation for Homogeneous and Heterogeneous Bitumen Reservoirs

This research presents a mechanistic analysis of expanding-solvent steam-assisted gravity drainage (ES-SAGD) for heterogeneous reservoirs in terms of cumulative steam-oil ratio (SOR) as a function of cumulative bitumen production. Simulation case studies for SAGD and ES-SAGD with normal hexane at 35 bars are conducted for geostatistical realizations of two types of heterogeneous Athabasca-bitumen reservoirs. For the first type, low-permeability mudstone barriers are oriented horizontally. For the second type, they are inclined and more representative of the middle McMurray member. The solubility of water in the oleic phase at elevated temperatures is properly modeled to ensure reliable comparison between steam-assisted gravity drainage (SAGD) and ES-SAGD. Simulation results show that ES-SAGD is less sensitive to heterogeneity than SAGD in terms of cumulative SOR. On average, the reduction in SOR due to steam-solvent coinjection is simulated to be greater under heterogeneity. The reduction in SOR is greater for reservoir models with inclined mudstone barriers than in those with horizontal mudstone barriers. Analysis of simulation results indicates that the injected solvent tends to accumulate more significantly under heterogeneity, which enhances the mechanisms of ES-SAGD, such as dilution of bitumen by solvent and reduced thermal losses to the overburden. Tortuous hydraulic paths and slower gravity drainage under heterogeneity enhance the mixing between solvent and bitumen in the transverse direction along the edge of a steam chamber. Then, a larger amount of the accumulated solvent tends to facilitate lower temperatures near the chamber edge.

Mechanistic simulation study of expanding-solvent steam-assisted gravity drainage under reservoir heterogeneity

Expanding-solvent steam-assisted gravity drainage (ES-SAGD) is a potential method to reduce steam-oil ratio (SOR) of SAGD, which is a critical concern especially for highly-heterogeneous reservoirs. The main objective of this research is to investigate the flow characteristics of heterogeneous reservoirs in which solvent is more likely to lower SOR of SAGD.SAGD and ES-SAGD with normal hexane are simulated for fifty geostatistical realizations consisting of clean sand and shale, qualitatively representative of the middle member of the McMurray formation. Thermodynamic models are calibrated with experimental phase behavior data for reliable comparison between SAGD and ES-SAGD, including the water solubility in oil at elevated temperatures.Results show that the SOR reduction by steam-solvent coinjection is positively correlated with the increase in SAGD's SOR due to heterogeneity. Enhancement of bitumen flow by dilution is more important for lowering SOR for those reservoirs in which the permeability variation makes slow-flow regions during SAGD.Simulation results show that a larger amount of bitumen tends to be diluted by solvent in those reservoirs for which SAGD exhibits slow production of bitumen. Then, the observed results are analyzed by use of SAGD analytical equations that clarify several influential factors for bitumen flow beyond the edge of a steam chamber. It is shown that dilution of bitumen by solvent in steam-solvent coinjection becomes more significant where flow barriers limit the local bitumen flow under SAGD even at high temperatures. In such slow-flow regions, the bitumen flow rate can be substantially increased by accumulation of solvent in ES-SAGD, which reduces the oleic-phase viscosity and increases the oleic-phase saturation and, therefore, relative permeability. Solvent accumulation within a steam chamber can also reduce thermal losses because of lower operating-chamber temperatures.

Pore-scale analysis of steam-solvent coinjection: azeotropic temperature, dilution and asphaltene deposition

Steam assisted gravity drainage is the main technologically and economically feasible method for in situ bitumen extraction. However, SAGD is energy intensive with economic and environmental challenges. Steam-solvent coinjection has proposed to improve SAGD performance, where hydrocarbon solvent is simultaneously injected with steam to increase the production rate and lower the steam-oil-ratio. The addition of solvent, however, complicates an already complex multicomponent thermal-chemical process. Microfluidics is well suited to quantify the pore-scale of steam-solvent coinjection with a tight control over experimental parameters. In this study, a high-pressure high-temperature micromodel combined with optical and thermal imaging is used to probe the pore-scale of steam-solvent coinjection process at relevant reservoir conditions. The effects of butane and hexane, as well as two industrial solvents, condensate and naphtha, on the pore-scale mechanisms are quantified and compared. The in situ thermal data is used to profile and analyze the condensation zone behavior and steam-solvent azeotropic temperature for all steam-solvent cases. We find that overall performance depends on the difference between steam-solvent azeotropic temperature and steam saturation temperature, the degree of solvent-bitumen dilution, and the degree of asphaltene precipitation in the condensing zone. In contrast with pure solvents and condensate, naphtha results in the highest recovery due to a higher steam-solvent azeotropic temperature, effective dilution, with minimal asphaltene deposition.

Reliable characterization of bitumen based on perturbation from n-alkanes for steam-solvent coinjection simulation

Bitumen recovery by steam-solvent coinjection involves the coupled thermal/compositional mechanisms for reduction of bitumen viscosity. Reliable design of such processes requires reservoir flow simulation based on a proper phase-behavior model so that the oleic-phase viscosity near the steam-chamber edge can be modeled reliably. However, the effect of bitumen characterization (e.g., the number of pseudo components used) on steam-solvent coinjection simulation has not been studied in detail, and can be realized only after running multiple reservoir simulations, which is time consuming.There are two main objectives in this paper. One is to develop a reliable method for bitumen characterization by improving the fluid characterization method that was recently developed based on perturbation from n-alkanes (PnA). The other is to develop a novel analytical method for assessing the sensitivity of a particular coinjection simulation to bitumen characterization without having to perform reservoir simulations. A simulation case study is given to validate this analytical method.A proper number of pseudo components for bitumen characterization cannot be determined without considering the effect of phase behavior on the oleic-phase viscosity at chamber-edge conditions in steam-solvent coinjection simulation. Results show that the analytical method developed in this research can detect the sensitivity of recovery simulation to bitumen characterization without performing multiple flow simulations using different sets of fluid models. The PnA-based method developed for bitumen characterization gives reliable predictions of phase behavior for bitumen/solvent mixtures with a small amount of experimental data.

In-situ recovery of heavy-oil from fractured carbonate reservoirs: Optimization of steam-over-solvent injection method

Abstract In this paper, a hybrid global optimization framework is used to optimize the design of a new process called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) proposed by Al-Bahlani and Babadagli (2008. Heavy-oil recovery in naturally fractured reservoirs with varying wettability by steam solvent co-injection. In: Paper 117626 Presented at SPE International Thermal Operations and Heavy Oil Symposium, Calgary, Canada, 20–23 October. doi:10.2118/117626-MS), Al-Bahlani and Babadagli (2009a. Steam-over-solvent injection in fractured reservoirs (SOS-FR) for heavy-oil recovery: experimental analysis of the mechanism. In: Paper 123568 Presented at SPE Asia Pacific Oil and Gas Conference & Exhibition, Jakarta, Indonesia, 4–6 August. doi: 10.2118/123568-MS), Al-Bahlani and Babadagli (2009b. Laboratory and field scale analysis of steam-over-solvent injection in fractured reservoirs (SOS-FR) for heavy-oil recovery. In: Paper 124047 Presented at SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 4–7 October. doi: 10.2118/124047-MS), Al-Bahlani and Babadagli (2011a. J. Petrol. Sci. Eng. 78 (2): 338–346), Al-Bahlani and Babadagli (2011b. Energy Fuels 25: 4528–4539). The hybrid framework integrates genetic algorithm with orthogonal arrays and response surface proxies for better convergence behavior and higher computational efficiency. The SOS-FR technique consists of a heating phase using steam injection, subsequent solvent injection, and low temperature steam injection for solvent retrieval and additional oil recovery. Solvent injection can be continuous or cyclic where the solvent is injected, soaked, and then fluids are produced. This paper studies both scenarios over single and multiple matrix field scaled reservoirs by adjusting the injections’ durations and rates. As a result, about 30 design elements for four base benchmark models are optimized, and the profit and efficiency is doubled comparing with the benchmark models using optimal injection scheme suggested by our optimization framework.