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A review on steam-solvent processes for enhanced heavy oil/bitumen recovery
Abstract
Steam injection is widely used for heavy oil and bitumen recovery. The advantage of this process is its high recovery factor and its high oil production rate. However, the high production rate is associated with excessive energy consumption, carbon dioxide generation, and expensive post-production water treatment. Some of these disadvantages are overcome or reduced by the addition of solvent mixtures to steam. The steam-solvent processes are complex oil displacement methods involving simultaneous heat, mass, and fluid transport. These processes are not clearly understood despite their apparent importance to the oil industry. Systematic studies are essential in the design, analysis, and evaluation of the steam-solvent processes as well as in mathematical simulation. These studies provide valuable insights for petroleum engineers to improve the oil recovery efficiency when applied in a reservoir. Results of these processes are scattered in many publications over more than 40 years and are not readily available for most petroleum engineers. The purpose of the paper is to present a review of current knowledge and available data, and to delineate the steam-solvent processes.
... A similar observation has been reported by Butler et al. 15 and Mokrys 16 for the leaching rate of bitumen with toluene at room temperature (20 C) as a function of formation permeability. It is worth noting that the rate of gravity drainage for SAGD is 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 For Submission to Energy & Fuels 14 proportional to the square root of permeability. 1 This is an important finding and highlights the fact that solvent-aided leaching rates have a stronger dependency on the reservoir permeability compared to SAGD. The current work dealt with a specific system of fluids, and therefore more comprehensive studies are required to provide general scalings for the leaching rate of bitumen by various solvents. ...
... [10][11][12][13] For more details on various aspects of solvent-based recovery techniques, the interested reader is referred to the recent review paper by Fayazi and Kantzas. 14 To the best of our knowledge, none of the previous simulation studies have reported mechanistic studies of gravity drainage and bitumen leaching using solvents. In fact, most of the simulations studies have used large grid blocks (in order of meter), and thus basic processes such as viscosityand density-driven fingering could not be captured. ...
... The results also suggest that the rate of drainage is linearly proportional to the formation permeability. A similar observation has been reported by Butler et al. 15 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 For Submission to Energy & Fuels 14 proportional to the square root of permeability. 1 This is an important finding and highlights the fact that solvent-aided leaching rates have a stronger dependency on the reservoir permeability compared to SAGD. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 For Submission to Energy & Fuels 15 linearly with the reservoir permeability. This finding is in complete agreement with the previous Hele-Shaw experiments with bitumen and toluene. ...
We report highly fine-grid numerical simulations of solvent-aided bitumen leaching using propane as a solvent. These simulations allowed us to observe the detailed physics of the drainage process, which is otherwise impossible in coarse-grid simulations. Our results revealed significant fingering of solvent into bitumen as a result of viscosity and density contrasts, which is in line with the previous experimental observation of bitumen leaching by toluene. Based on our simulation results, the drainage process undergoes two distinct infinite-acting and finite-acting periods, with more than two-thirds of the drainage taking place during the former. Interestingly, the rate of drainage of bitumen is constant during the infinite-acting period, and it is independent of the formation thickness. Using the results of our simulations, we found out that the rate of drainage of bitumen is scaled linearly with formation permeability. The results of this work shed light on the fine-scale physics of the bitumen leaching process by solvents and pave the way for the development of new recovery processes.
... This approach may successfully address issues such as fuel expense, CO 2 emissions, etc. There are currently two major types of solvent addition: pure solvent injection and steam/solvent co-injection (up to 20 vol% of light hydrocarbon solvent for steam injection) [21,22]. A novel method called enhanced modified vapor recovery (EMVAPEX) efficiently addresses the issue of high solvent chamber rise resistance of solvent exploitation alone by substituting condensate gas (such as propane) for steam after the first operation of steam-aided gravity drainage (SAGD). ...
With the strategic goal of “carbon peaking and carbon neutral” in China, new requirements are also put forward for the thermal recovery of heavy oil. In view of the problems of excessive greenhouse gas emission, low steam utilization rate, poor economic efficiency, and limited reservoir application of steam stimulation replacement technology in China, the emerging technologies of medium- and low-temperature thermal fluid, solvent-assisted high-temperature steam injection, solvent-based medium- and low-temperature waterless recovery and in situ electric heating-assisted recovery are discussed in terms of technical principles, technical parameters, experimental/field effects, and technical and economic potential. The technical principles, technical parameters, experimental/field results, and techno-economic potential of low-carbon heavy oil recovery technologies are summarized and future development directions and trends are anticipated. The study’s findings indicate that some of the technologies that have been tested in the field, such as HWVP, EMVAPEX, AH-VAPEX, LASER, and ESEIEH, can be developed by relying on the original well groups for production and can reduce greenhouse gas emissions, such as CO2, by about 80% and improve crude oil recovery by 5% to 10%, while the technologies concerned have outstanding effects on increasing oil production rate and lowering upfront capital investment. Some of the technologies that have been tested significantly increase oil production rate, lower initial capital expenditure, and enable solvent recycling, among other things. Among them, COBEEOR and N-SOLV technologies can also lower the amount of asphaltene in the output crude oil, enhance the API of the recovered crude oil, and provide strong economic advantages. CSP, CHSI, and hot water solvent injection were tested in indoor two-dimensional and three-dimensional experiments to validate their feasibility, while CO2, propane, and butane solvents were initially screened and some of the technologies’ mechanisms were revealed to lay the groundwork for pilot projects. The executive summary of the research findings will serve as a guide for future low-carbon extraction technology research and development in China.
... It mainly uses injection water to supplement the formation energy and maintain the formation pressure, its oil recovery can generally reach more than 30% [5][6][7]. EOR mainly depends on improving the properties of flooding agents and oil displacing effect, which can increase oil recovery by about 20% more than water flooding [8][9][10][11][12]. ...
A high-efficiency anionic surfactant alcohol ethoxylate sodium hydroxypropyl sulfonate (AEOSHS) suitable for enhancing heavy oil recovery has been synthesized through chemical modification. Its structure and properties were characterized by FT-IR, TGA and SFT. Then, the performance of surfactant AEOSHS was better than traditional anionic surfactant sodium dodecyl sulfate (SDS) confirmed through emulsification state observation, droplet size distribution test, interfacial tension (IFT) test, rheological test and porous level emulsification visualization observation. The mechanism of surfactant AEOSHS to efficiently emulsify heavy oil and W/O emulsion was clarified. Finally, the enhancing heavy oil recovery of surfactant SDS and AEOSHS was compared through long sand-packed tube flooding experiment. Experimental results show that when surfactant concentration was 0.5%, the IFT between surfactant SDS solution and dehydrated heavy oil was 0.34 mN/m, while the IFT of AEOSHS was only 0.092 mN/m. As water content of W/O emulsion increase, its density, viscosity and IFT were all increase. Surfactant AEOSHS molecule can dissolved in heavy oil because the long carbon chain and the existence of ether bonds. It can effectively disperse the layer stacking structure of resin and asphaltene so that water in W/O emulsion can be effectively emulsified. In addition, surfactant AEOSHS can emulsify heavy oil into small droplets (7.1μm), which has high elastic modulus, so that the additional resistance was very small when it flows through porous media. Through flooding experiments, which shown that surfactant AEOSHS (0.5PV) can enhancing heavy oil recovery rate up to 18.17%, while SDS was only 8.71%. Therefore, the newly synthesized anionic surfactant AEOSHS has the ability to significantly reduce IFT and high-efficiency emulsification, and can be used for enhancing heavy oil recovery.
... 5,6 Different approaches have been proposed to measure the diffusivity of gas/liquid into liquid. 7 Pressure decay is a widely used technique which was proposed by Riazi 8 to measure the diffusion coefficients of gases in liquids in a closed PVT cell through monitoring the decaying pressure as the gas diffuses into the liquid. However, this technique has several potential issues and some authors have attempted to address them. ...
For this paper, integrated techniques have been developed to optimize the performance of the hybrid steam-solvent injection processes in a depleted post-cold heavy oil production with sand (CHOPS) reservoir with consideration of wormhole networks and foamy oil behavior. After a reservoir geological model has been built and calibrated with the measured production profiles, its wormhole network is inversely determined using the newly developed pressure-gradient-based (PGB) sand failure criterion. Such a calibrated reservoir geological model is then used to maximize the net present value (NPV) of a hybrid steam-solvent injection process by selecting injection time, soaking time, production time, injection rate, steam temperature, and steam quality as the controlling variables. The genetic algorithm (GA) has been integrated with orthogonal array (OA) and Tabu search to maximize the NPV by delaying the displacement front as well as extending the reservoir life under various strategies. Considering the wormhole network and foamy oil behavior and using the NPV as the objective function, such a modified algorithm can be used to allocate and optimize the production-injection strategies of each huff ‘n’ puff (HnP) cycle in a post-CHOPS reservoir with altered porosity and increased permeability within a unified, consistent, and efficient framework.
In order to construct an emulsification and viscosity reduction system of temperature tolerance and salt resistance surfactants, a series of surfactants E4An (E4A6, E4A10, E4A15) with different oxyethylene groups were synthesized and studied. The structures of the optimal product were characterized by infrared (IR) and nuclear magnetic resonance (¹H NMR). According to the requirement of surfactant used for heavy oil, the physicochemical properties including cloud point (Tc), surface tension, oil/water interfacial tension (IFT), emulsification effect, heat stability and salt resistance were fully described. Experimental results showed that the surfactant E4A10 had better surface activity (γcmc = 28.79 mN/m). The HLB value of E4A10 was 13, and the Tc was 71 °C. In addition, the surfactants E4An demonstrated good temperature tolerance and salt resistance at high salinity (8246 mg/L) and high temperature (300 °C, 24 h), where viscosity reduction ratio for heavy oil of Bohai oilfield still reached 98.0 % and the particle size of the emulsion droplets for E4A10 was only 13.25 μm. The IFT of E4A10 had no obvious fluctuation before and after aging, and exhibited better interfacial activity (0.65 mN/m).
Enhancing flow and transport in porous media by acoustic stimulation has been investigated for the past several decades. Most studies focused on the effect of sound propagation in immiscible displacements. Much less emphasis has been given to understand the beneficial mechanisms during miscible displacements. In this work, a pore-scale model is developed to study the influence of acoustic excitation on dispersion and mass transfer in porous media. The modeling involves first solving for the single-phase fluid flow without the acoustic field, then calculating an external acoustic pressure field across a stationary saturated medium, and finally evaluating the interaction between the acoustic field and the flowing fluid. Simulations are run at different injection velocities, wave frequencies, and acceleration amplitudes. Concentration profiles of the pore-scale model show that the mass transfer between the mobile and immobile regions is accelerated under the sonication. In addition, the dispersion coefficient is increased due to the enhanced effective diffusivity and the additional acoustically induced velocity. To quantify the enhancement in transport, dispersion and mass transfer coefficients are calculated by matching the analytical solutions of the continuum transport model with effluent concentration profiles obtained by pore-scale simulations. At lower injection rates, dispersion coefficient is more affected by acoustic excitation compared to mass transfer coefficient. Lower frequencies and higher acceleration amplitudes of the propagated waves increase the enhancements in dispersion and mass transfer coefficients. The results at higher viscosity ratios indicate that low-frequency excitation could be a promising technique for improving miscible displacements. The effects of controlling parameters are summarized in a proposed dimensionless group of AD for designing effective acoustically assisted experiments in the laboratory.
High-temperature fluids are widely used in many industrial and scientific fields such as steam power generation, oil extraction and transportation, chemical heating catalysis, high-temperature pasteurization of pharmaceuticals and food products, high-temperature printing and dyeing, residential heating, and especially in the nuclear fusion research (baking and power generation). The high-temperature fluid supply network is a transportation channel that takes the high-temperature working fluid from the heat source to the heated areas or end users. This paper introduces the heat transfer calculation method for high-temperature fluid transmission and distribution networks. This calculation method has been verified by the high-temperature nitrogen baking process of the pipe network at EAST (Experimental Advanced Superconducting Tokamak). With the experimental results showing the method to be more than 98 % accurate. This method can be used to precisely design the flow within the distribution network while simultaneously calculating the flow rate, and temperature of the working fluid as well as safety information such as the pipe and insulation temperature throughout the network. Furthermore, this calculation method is not only suitable for the high-temperature fluid transmission and distribution network but also for that of the low-temperature fluid transmission and distribution network, making this calculation method become a very important component of the Fusion Reactor Thermal Hydraulic Analysis Method (FRTHAM).
During the thermal enhanced oil recovery (EOR) process, the hazardous hydrogen sulfide (H2S) gas among the produced gases causes significant difficulty in the exploration and development of petroleum. In this study, the effects of superheat degree on the H2S generation by heavy oil aquathermolysis were explored through simulated experiments. The crude and residual oils before and after the reaction were separated into saturate, aromatic, resin and asphaltene fractions (SARA). The oil samples were analyzed from various perspectives by various characterization methods including Fourier transform infrared (FTIR) spectroscopy, elemental analysis, and X-ray photoelectron spectroscopy (XPS). The results showed that H2S generation was favored by larger superheat degree at the same temperature, and it increased from 0.178 to 0.345 mL g⁻¹ oil with an increase in the superheat degree from 62.19 to 89.42 °C. The contents of the sulfur-containing substances, which were supposed to be the main sources of H2S generation, in the saturate and aromatic fractions decreased significantly with an increase in the superheat degree; the increase in the superheat degree led to a slight reduction in the contents of the methylene, methyl and carboxyl/carbonyl groups. Moreover, the analysis of the main sulfur existing forms before and after the reaction suggests that sulfur in the forms of sulfides, sulfones and sulfates is more likely to generate H2S under superheated steam conditions. This study provides an understanding of the mechanism of H2S generation during the process of injecting superheated steam for heavy oil recovery.
Compared with conventional steam flooding and Steam-Assisted Gravity Drainage (SAGD), Solvent-Enhanced Steam Flooding (SESF) is considered a more effective method for improving heavy oil recovery in thin reservoirs in terms of higher thermal efficiency and oil production rate. However, there remains a deficiency of accurate and efficient methods to evaluate and design an SESF project in the field. A semi-analytical model is proposed in this paper to predict the recovery performance of SESF and investigate the effects of solvent properties and injection strategies on the SESF process for thin heavy oil reservoirs. The proposed model provides a simple method to simulate not only single solvent injection but also multi-solvent injection by cooperating different values of solvent operating thickness and solvent solubility. To validate the model’s accuracy, comparisons are made between the proposed model results and the numerical simulation results for a specific heavy oil reservoir case. The results indicate that SESF can achieve a considerably higher oil production rate at the early recovery stage than steam flooding. Moreover, the paper also demonstrates that a higher injection rate results in a lower thermal efficiency increment when well spacing is constant. Nevertheless, a high injection rate may also be suitable for longer well spacing owing to the improvement of the viscosity profile beyond the edge of the steam zone caused by longer contact time between the solvent and crude oil.
Recently, Deep Eutectic Solvents (DESs) have been introduced and investigated as new EOR agents for heavy oil recovery enhancement. In this study, sequential DES and steam flooding was proposed and experimentally investigated as a new scenario for heavy oil recovery enhancement and having potentials for in-situ heavy oil upgrading. DESs used in this study are Choline Chloride:Glycerol (DES1) and Choline Chloride:Urea (DES2). Primary and secondary DES flooding at different concentration followed by high-temperature steam flooding were conducted using 16.5 °API heavy oil and Berea sandstone core plugs. DES thermogravimetric analysis (TGA) performed and results verified the relatively high thermal stability of the selected DESs. Maximum decomposition temperature was found to be 320 and 370 °C for DES1 and DES2, respectively. This improves their potential for use as chemical additives or pre-flooding agents in thermal EOR methods. Sequential steam flooding after undiluted and 2-fold diluted DES injection recovered an additional heavy oil of 12% IOIP compared to steam flooding alone. However, using more diluted solutions (i.e., 20-fold diluted DESs) caused the same and in some cases lower total recovery factor by secondary steam flooding. When followed by steam flooding, DES2 exhibited superior heavy oil recovery enhancement (8–12%) compared with DES1 (1.5–6%) at the same concentrations. Analysis of physicochemical properties of produced oil for different cases revealed the favorable role of DES in upgrading the in-situ heavy oil. Heavy oil upgrading were quantified through various measurements including increase in API gravity up to 3.5 °API, 16.6% reduction in sulphur content or desulphurization and increase in the yields of saturate hydrocarbons. Comparatively, DES1 exhibited better overall performance than DES2 in terms of in-situ heavy oil upgrading.
The pore-level recovery mechanisms of the SA-SAGD process were recently studied for the first time in the literature in Porous Media Lab at the University of Waterloo using glass-etched micromodels. The experiments were conducted at controlled environmental conditions of an inverted-bell vacuum chamber to reduce the excessive heat loss to the surroundings. Different chemical additives (n-pentane and n-hexane) were added to steam prior to injecting into the models. An integrated data acquisition and control system was used to control, monitor and adjust the environmental vacuum pressure as well as to monitor and record local temperatures along the model's height and width. The pore-scale events were videotaped, and the captured snapshots were analysed thoroughly using image processing techniques. The pore-scale visualizations revealed that gravity drainage process takes place in the mobilized region, formed ahead of the pore-scale oil–vapour mixture interface in which all the flowing fluid phases are present. The interplay between gravity and capillary forces results in the drainage of the mobile oil with a reduced viscosity due to combined pore-level heat and mass transfer. Heat transfer at the pore level is believed to take place by conduction as well as convection. The solvent content of injected vapour mixture diffuses into the oil phase and hence reduces its viscosity following dilution as a result of molecular diffusion as well as convective mass transfer. Asphaltene precipitation was observed when the condensed solvent reached the bitumen interface. The average horizontal advancement velocity of the pore-scale SA-SAGD interface was measured and then correlated with operating temperature, macroscopic and pore-scale properties of porous media and bitumen properties within the range of experimental conditions. Quantitative analysis of the experimental results revealed that n-C 6 is a more effective steam additive compared with n-C 5 at similar operating condi-123 438 O. Mohammadzadeh et al. tions. Greater solvent content of the injecting vapour accelerates the pore-scale recovery by increasing the pore-scale interface advancement velocity. When all the other experimental variables were remained unchanged, smaller in situ oil viscosity values resulted in superior pore-scale production performance of the SA-SAGD process. The pore-level sweep rate was also found to be a function of the pore-scale dimensional characteristics of the porous media including pore-to-pore distance, pore body width, pore throat width and diffusion distance. Keywords Steam-assisted gravity drainage (SAGD) · Solvent-aided steam-assisted gravity drainage (SA-SAGD) · Micromodel · Visualization · Bitumen
The hybrid steam-solvent injection scheme has been applied but limited results have been reported in the literature. The optimum solvent concentration to maximize economics and to reduce the CO2 emission is still in question. A synthetic reservoir model was developed using real field data to study such an injection. Results indicate that the optimal solvent concentration is 5.0% by volume fraction and as the concentration increases the CO2 emission reduces. The optimum case has 21% gain in the net present value discounted by 12% per annual and 9.1% reduction in the CO2 emission comparing to the pure steam injection.
Solvent Assisted-Steam Flooding (SA-SF) was developed to address the environmental and economic challenges associated with steam generation. The solvent composition can greatly affect its interaction with both the asphaltenes present in the oil as well as the clays in the reservoir; therefore solvent selection plays a major role in the process. This study explores the wettability alteration mechanism of oil recovery, and how the solvent selection impacts its performance.
Five experiments were conducted; two chemical flooding (E1 and E2), one steam flooding (E3) and two SA-SF (E4 and E5) experiments. The solvents tested were n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5). The wettability alteration caused by the different enhanced oil recovery methods was established through contact angle measurements. The asphaltene and clay content of the produced oil was determined using standard methods. The residual oil content was measured by washing the postmortem samples with toluene, an asphaltene soluble solvent capable of removing all the oil present in the rock. The oil recovery rate was used to measure the performance of each experiment.
Although all experiments had a final wettability that is considered oil-wet, they varied among each other. Experiment E4 showed the least oil-wet surface, while E5 showed the most. At the same time E4 yielded the highest oil recovery of the SA-SF experiments. Lowest clay content and highest asphaltene content was observed in the produced oil of E5, while the opposite was seen in E4. Asphaltene-clay-water interactions in the pores affect the wettability of the rock while the solvent used directly impacts the quantity of asphaltene and clay present. Asphaltenes as insoluble in n-hexane, therefore they precipitate out of the oil onto the rock, interacting with the clay and water to produce a less oil-wet surface, the CS however is composed of heavy dearomatized hydrocarbons which range from C11-C16 and enable more asphaltene production, as all produced oil samples showed.
This study provides a data set for wettability alteration during steam-solvent processes. Our finding suggests that solvents control the wettability alteration due to their interaction with asphaltenes. Wettability varies according to the precipitated asphaltenes polarity and the distance from injection well.
During processes such as solvent-steam co-injection and tertiary CO2 flooding, oil may be prevented from direct contact with solvent by a water barrier which greatly affects microscopic displacement efficiency. As a result of diffusion through the water barrier, both oil and water phases swell progressively. If oil swelling displaces the blocking water completely, direct contact between solvent and oil can be achieved which results in high oil recovery. In this study, a moving mesh technique is applied to simulate swelling of a trapped oil blob by CO2 diffusion through a blocking water at pore scale. A moving interface between oil and water is considered to track the swelling process. The modeling results were validated with micromodel experiments on the recovery process of water-shielded oil in a dead-end pore. The water film rupture time for typical oil and water thicknesses (in micro scale) was calculated using experimental data for oil-water-CO2 system. Finally, a dimensionless rupture time was introduced and it was used to predict trapped oil recovery as a function of contact time for various pore body and throat size distributions. The results can be used to estimate the time scales necessary for having maximum trapped oil recovery.
Flue gas is industrial waste gas produced by the burning of fossil fuels. Its main compositions are 10% - 15% of carbon dioxide and 80% - 85% of the nitrogen, two key components needed for gas flooding. Adding a certain amount of flue gas into steam in displacement could decrease steam partial pressure, improve the steam quality and reduce heat loss, resulting in reduction of steam injection amount and improvement of development performance. The objective of the research is to investigate the mechanism of enhanced oil recovery (EOR) of flue gas assisted steam flooding which has a dual significance of reducing greenhouse gas emissions and improving oil displacement efficiency.
In this paper, PVT measurements at high temperature and high pressure (HTHP) were firstly conducted to analyze the effect of flue gas on property of heavy oil. Then sandpack displacement experiments containing 5 sub-experiments: steam flooding, flue gas assisted steam flooding, first steam flooding then flue gas assisted steam flooding, water flooding, flue gas assisted water flooding, were operated to compare the contribution of heat and gas on recovery. In the experiment of flue gas assisted steam flooding, the production rate and composition of gas were measured and analyzed, and the form of the produced oil was also compared with steam flooding.
The PVT measurements results show that with flue gas dissolved, viscosity of heavy oil declines and volume expands. The solubility of flue gas in heavy oil decreases with temperature and increases with pressure. The greater the solubility of flue gas, the lower viscosity of heavy oil, the larger volume. At the same solubility, as the temperature increases, the viscosity reduction effect of flue gas weakens and the volume expansion effect enhances.
The displacement experiments results indicate that the addition of flue gas to steam can significantly improve oil displacement efficiency compared with steam injected alone. In the test of flue gas assisted steam flooding, the heavy oil was produced in the form of foamy oil because of dissolution of flue gas, especially CO2, which could expand oil volume and reduce the flow resistance of heavy oil to a certain extent. Besides, the cumulative volume of the produced gas was smaller than the injected gas, and in the produced gas the proportion of CO2 was less than the injected proportion. Furthermore, the contribution of flue gas to recovery when injected with steam is greater than with water because of the synergistic effect of heat and gas.
In this study, three types of constant composition expansion tests on foamy oil flow are conducted in the pressure/volume/temperature (PVT) cell: (a) the constant pressure depletion rate test, (b) the constant volume withdraw rate test, and (c) the step-by-step test. The tests investigate the effect of depletion methods and depletion/withdraw rates on a heavy oil-methane system in the bulk phase. Pure methane is recombined into a typical Manatokan dead heavy oil sample to generate a live oil sample. Totally, nine experiments are undertaken using constant composition expansion (CCE) methods, four experiments for the constant pressure depletion rate test, four experiments for the constant volume withdraw rate test, and one experiment for the step-by-step test.
The effect of coinjection of hydrocarbon solvents (C4, C5, C6, C7, and C8), with steam at low pressure, on heavy oil recovery is addressed. It is concluded that the coinjection of solvents reduced cumulative steam oil ratio and the lighter solvents performed better in reducing cumulative net energy oil ratio (CEOR, GJ/m³). The work illustrated that C6 was the best-performing solvent with respect to oil recovery (EOR) at 20 wt%, CEOR with an optimum of 30 wt%. An explanation on the reason for the highest EOR at 20 wt% is given. The coinjection with CO2 has also been addressed here with different schemes.
The main challenges faced by oil sands operators are the cost of operations and the environmental intensity of the recovery processes. The Athabasca oil sands deposit contains bitumen with viscosity typically over 1 million cP. To lower the viscosity of the bitumen so that it can be drained from these reservoirs, it is heated with injected steam by using Steam-Assisted Gravity Drainage (SAGD). This process is effective and enables recovery factors over 60%. The major cost in the recovery process is steam generation and associated water treatment and handling. The combustion of natural gas to generate steam is the main origin of the carbon dioxide emissions associated with SAGD. An alternative to steam injection is the use of solvents co-injected with steam. Solvents dilute bitumen leading to an oil phase with reduced viscosity. Also, there is potential to recycle solvent for re-injection. Thus, solvent added to steam can improve the steam-to-oil ratio and as a consequence can lower the carbon dioxide emissions per unit volume oil produced. In this extended abstract, we describe a phased solvent and heat process that yields improved performance beyond that of SAGD and current solvent-aided SAGD processes.
Solvent-based processes have shown technical advantages over thermal techniques for recovery of heavy oil and bitumen. The success of these processes relies on accurate computation of molecular diffusion coefficient which determines how fast a solvent penetrates into oil. Concentration profile measurements of solvent in oil are used for the determination of the molecular diffusion coefficient. Although numerous experimental techniques have been proposed, the accurate estimation of this parameter is still a topic of debate in the literature. In this work, 1-D Nuclear Magnetic Resonance Imaging (MRI) is employed to obtain diffusivity data for a toluene-heavy oil system. Diffusion of toluene in heavy oil was monitored for 20 days at a controlled temperature of 35 °C and ambient pressure. Over time, toluene diffusion into oil leads to changes in spatial distribution of T1 and T2 that affect the received signal. This serves as the basis of the solvent and heavy oil concentration estimation. Consequently, concentration profiles were established by converting the MRI signals to concentration values. This conversion was achieved by creating samples with known concentrations of heavy oil-toluene and measuring their response in the same environment and parameter settings. A concentration-dependent diffusion coefficient was obtained from concentration profiles. The results show that relaxation based 1D MRI is an accurate and robust tool to obtain diffusivity data in complex fluids such as heavy oil.
The goal of solvent-steam-flooding is enhancing bitumen displacement by the simultaneous development of solvent miscibility and reduction of oil viscosity. Though this strategy reduces greenhouse gas emissions, solvents are generally expensive. Additionally, bitumen recovery performance is affected by oil/solvent/clay/asphaltene interactions on the pore-scale level. Therefore, solvent dosage and type must be optimized to maximize recovery, while minimizing environmental impacts and operational costs. To investigate the performance of solvent-steam processes, six-core flooding experiments were conducted on a Canadian bitumen sample with 8.8 °API and 54,000 cP at room temperature. Propane-steam flooding was tested and compared to steam-flooding. The effect of reservoir clays is studied by carrying out experiments in the presence and absent of clays. Three propane flow rates were tested to examine the impact of solvent dosages. After the experiments, asphaltene, clay, viscosity, and water contents in produced oil were measured. The results indicated that propane-steam flooding increased recovery factors, accelerated production, and had higher quality oil than steam-flooding. The lowest propane flow rate (1:9 v/v) improved oil recovery by 23%, indicating that higher solvent concentration may not be needed. This work reveals that bitumen microscopic displacement efficiency is enhanced by the addition of solvent to steam flooding. It is proposed that pore-scale interactions, solvent flow rate, and clays also highly influence produced oil quality and oil recovery rates.
Heavy-oil reservoirs with thin-pay and bottomwater can be exploited effectively by thermal recovery process assisted by flue gas and n-hexane. The interface properties between flue gas/n-hexane and heavy oil and viscosity reduction of the heavy oil were investigated by laboratory experiments. Steam flooding, flue gas assisted steam flooding, n-hexane assisted flooding and flue gas and n-hexane assisted steam flooding were conducted to research the displacement pressure difference, oil displacement efficiency and component variation of produced and residual oils. The results show that the flue gas dissolving in heavy oil can effectively reduce oil viscosity, increase the flow capability, and make the heavy oil swell. Higher pressure reduces surface tension of heavy oil and gas, and higher temperature increases surface tension. Compared with flue gas, n-hexane can reduce heavy oil viscosity and surface tension more obviously. The flue gas and n-hexane can effectively improve the development effect of the steam flooding. The pressure difference of steam flooding assisted by flue gas and n-hexane is the lowest, the oil production rate is greatest, and the oil recovery efficiency can reach 80%. Flue gas and n-hexane can effectively change crude oil properties. The heavy components, molecular weight of asphaltene and oil viscosity for the produced oil all reduced. The heavy components and molecular weight of asphaltene for the residual oil in sandpacks all increased. The effect of flue gas and n-hexane together on heavy oil is the greatest. The asphaltenes component in the residual oil is not as stable as that in produced oil. The experimental results not only show that flue gas and n-hexane can successfully improve the performance of steam flooding process, but also provide a deep understanding of properties changes of produced and residual oils for the flooding.
The recovery efficiency of primary production for heavy oil reservoirs is generally poor meaning that significant quantities of oil still remain in place. Waterflood has been, and continues to be, the first intervention method for oil recovery in many oil reservoirs. However, heavy oil is considerably more viscous than water and hence, a significant fraction of the oil is bypassed by waterflood. In this study, we present the results of two coreflood experiments which have been performed under reservoir conditions to investigate the potential of tertiary CO2 injection for heavy oil recovery. In addition, the mechanisms involved in this process and their impacts on the efficiency of oil recovery are identified and discussed. The same crude oil and gas were used to prepare live oil for both experiments. Despite the difference in the viscosity of oil samples, secondary waterflood showed relatively similar behavior in both experiments and 22% and 24% of the initial oil were recovered after 2 and 1.1 pore volumes (PVs) of water injection in the first and second experiments, respectively. The oil production results show that tertiary CO2 injection recovered 23% of the remaining oil after 6 PVs of injection in the first experiment and after 3 PVs of injection in the second experiment. Another waterflood followed the tertiary CO2 injection which recovered 14% of the remaining oil in both experiments. The main mechanisms contributing to oil recovery by CO2 injection are the oil viscosity reduction by CO2 dissolution, the liberation of methane from oil, oil swelling, and the extraction of hydrocarbons by CO2. The results imply that viscous fingering dominates the flow of water or CO2 for heavy oil recovery. The compositional analysis of the core effluent shows that tertiary injection of CO2 alters the physical properties of heavy oil in the core and a higher quality oil (e.g. lower density and viscosity) than the original oil in place is recovered by CO2 injection. It is also discussed that CO2 can diffuse into the oil surrounded by water. The transport of CO2 into the oil results in the oil being saturated and this leads to the nucleation of a CO2−rich phase among the trapped oil ganglia. By continuing CO2 injection, the nucleated CO2−rich phase grows further and causes oil swelling by the extraction of light and intermediate components of the oil.
With increasing world demand for energy, greater attention has been given to the exploitation of the huge resources present in the form of heavy oil and bitumen. Although thermal methods such as steam assisted gravity drainage (SAGD) have been successful in recovering heavy oil and bitumen, the low thermal efficiency of the process and the high level of greenhouse gas emissions and water usage remain major concerns.
Co-injection of solvent with steam has shown to be promising in enhancing oil rates as well as in reduction of energy and water consumption with lower environmental impacts. In hybrid steam-solvent methods, there is a balance between the solubility of the solvent and its ability to reduce bitumen viscosity, and the viscosity reduction due to temperature increase. Therefore, proper selection of the solvent for the operating conditions is key to improving the overall efficiency of the steam-solvent process over the steam-only method.
A steady state semi-analytical model is developed to predict the oil flow rate during spreading and depletion phases of steam chamber development in the solvent-aided SAGD (SA-SAGD) process. The model assumes steady state temperature and unsteady state concentration distribution ahead of the linear steam-bitumen interface. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution employing the Integral Method.
The model is validated against CMG-STARS® thermal simulator and also SAGD experimental results for hexane co-injected with steam. It is shown that by adjusting a few parameters using SAGD results, the model can fairly predict the oil production and cumulative steam-to-oil ratio for the solvent-aided process with average absolute deviations up to 7% and 20%, respectively. The results suggest that the steady state model can be used as a screening tool for SA-SAGD. Also, it may be employed to find the optimum solvent candidate and the operational variables to maximize the flow rate of the SA-SAGD process. The model can also be applied for a mixture of solvents provided that the equilibrium experimental phase behavior data are available for a given solvent-bitumen system.
Solvent-steam processes gained popularity in recent years in the extraction of high-asphaltenes-content heavy hydrocarbons. However, while solvent selection is key for the success of these processes, the criteria for solvent selection are still not fully established. In this study, three asphaltenes insoluble (propane, n-hexane, carbon dioxide) and one asphaltenes soluble (toluene) solvents were tested on solvent-aided steam processes to extract a bitumen sample from Alberta, Canada. Both steam flooding and SAGD performances were analyzed. The impact of clay presence was investigated by conducting experiments with and without the addition of clays, consisting of an illite-kaolinite mixture. The results of this study suggest that the produced oil samples from steam injection processes are in the form of water-in-oil emulsions. It has been observed that the amount of asphaltenes in produced oil determines the amount of water trapped in the form of emulsions. Co-injection of solvent with steam decreases the interfacial film between water and asphaltenes. However, asphaltenes insoluble solvents were found to be more effective to eliminate the forces at the oil-water interface. Presence of clays also reduced the water content of emulsions. The results of this study suggest that carbon dioxide, which is a non-hydrocarbon asphaltenes-insoluble solvent, yields the greatest quality oil with the lowest amount of water and clay in produced oil and provides high oil recovery. Hence, it is recommended to use asphaltenes-insoluble, non-hydrocarbon solvents for the extraction of low API gravity, high viscosity, and high asphaltenes content reservoirs.
Non-condensable gas (NCG) with steam co-injection makes steam assisted gravity drainage less energy-intensive as well as reduces greenhouse gas emission and water consumption. Numerous studies have shown that the technology called steam and gas push (SAGP) is feasible for heavy oil and bitumen. However, most of these studies have focused on shallow heavy oil reservoirs and only a few works have investigated moderate-depth heavy oil reservoirs. In this study, laboratory experiments and numerical simulations were conducted to study shape change, steam chamber expansion, and temperature change after co-injecting NCG with steam into an actual moderate-depth heavy oil reservoir. Results showed that after co-injecting NCG with steam, the transverse expansion rate of the steam chamber accelerated, vertical expansion slowed down, thermal utilization increased, and oil-steam ratio improved. In addition, the injection parameters of SAGP were also optimized via numerical simulation, which indicated that SAGP could effectively improve development effect and recovery for moderate-depth heavy oil reservoirs. © 2016 Eastern Macedonia and Thrace Institute of Technology. All rights reserved.
Heavy-oil and bitumen recovery requires high recovery factors to offset the extreme high cost of investments and operations. Attention has been given to solvent injection for this purpose, and it has been observed that high recoveries are achievable when it is combined with steam injection. Heavier (“liquid”) solvents (liquid at ambient conditions) are especially becoming more popular because of availability and transportation. High oil prices will allow the application of this kind of technique if a proper design is made to retrieve the injected solvent efficiently. “Liquid” solvents are advantageous because they yield a better-quality mixing (especially with very heavy oils and bitumen) but a lower diffusion rate than lighter solvents such as propane or butane. Despite this understanding, there still is not a clear screening criterion for solvent selection to mitigate both diffusion rate and the quality of the mixture.
In this study, two main solvent-selection-criteria parameters—diffusion rate and mixing quality—were considered to evaluate solvent-injection efficiency at different temperatures. An optical method under static conditions and image-processing techniques were proposed to determine 1D diffusivity of liquid solvent into a wide range of oil samples in a capillary tube. This sampling range varies from 40-cp oil to 250-cp oil, for which digital-image treatment was developed. X-ray computerized tomography (CT) was applied for heavier (and darker) oils (viscosity range of 20,000 cp to 400,000 cp). The diffusion coefficients were then computed through nonlinear curve fitting on the basis of an optimization algorithm to ensure that the obtained values were in agreement with available analytical solutions. Next, viscosity measurements and asphaltene precipitation for the same heavy-oil/solvent mixtures were performed to determine the mixing quality. The ideal solvent types for different oil types were determined by using the results from the diffusion-rate and mixing-quality experiments.
The experimental and semianalytical outcome of this research would be useful in the determination of the best solvent type for a given oil and in understanding the key factors that influence the quality of mixtures including viscosity reduction and probable asphaltene precipitation.
Solvent-based processes are often used as potential recovery agents in bitumen systems, with and without the addition of heat to the solvent. Solvents can sometimes be applied as a liquid phase, during SAGD start-up operations or processes aimed at developing injectivity into the oil. Light hydrocarbon liquids are traditionally tested for this application. Solvent injection may also occur in a vapour state and its objective is to reduce oil viscosity and improve mobility of bitumen under low temperatures <100°C. In general, hydrocarbon solvents such as propane are often used for this application. The objective of this study is to conduct CT-based measurement of static mixing of bitumen and both liquid and vapour phase solvents, and to quantify some of the time-dependent changes that occur during solvent mixing with bitumen.
Diffusion experiments have been conducted with propane and DME (vapour phase) and with propane, DME, pentane and toluene (liquid phase) solvent systems. Solvents are mixed with medium viscosity Peace River bitumen and high viscosity Grosmont bitumen. The Tests are run under constant pressure and temperature, and Computer-Assisted Tomography (CT) is used to monitor mass transfer of solvent into oil as a function of time. The outcome of this study is measurements of mass transfer rates of solvent into oil, and the degree of oil phase swelling during the tests.
During solvent injection processes in the field, the rate of mixing is a key parameter that will help in deciding which solvent is optimal for different processes. This study focuses on the rate of solvent mixing with oil. In vapour phase solvent systems, the analysis of the CT images allows for an understanding of the impact of oil phase swelling on the effective rate of penetration of solvent into oil. Overall, the test data provided in this work demonstrates that DME mixes into oil faster than other solvents, and leads to more swelling in a vapour solvent-bitumen system. The analysis of CT data provides an understanding of concentration-dependent diffusion coefficients and limitations from predicting mass transfer using constant coefficients in liquid and vapour solvent systems.
Expanding Solvent Steam Assisted Gravity Drainage (ES-SAGD) is a hybrid steam-solvent oil recovery process that can be used to extract oil from heavy oil and bitumen reservoirs. It is a variation of the SAGD process in which only steam is used. In ES-SAGD, the mobilization of highly viscous oil is enhanced through a combination of heat and mass transfer processes, which results in significantly reduced volumes of water and natural gas to generate the injected steam. This as a result makes ES-SAGD more energy efficient and environmentally sustainable relative to SAGD. Both SAGD and ES-SAGD use the same well configuration and solvent co-injection in existing SAGD projects requires limited facility modifications. This study investigates different aspects of ES-SAGD experimentally, based on typical Long Lake reservoir properties and operating conditions, using different concentrations of gas condensate. Furthermore, this study provides phase behaviour insights to govern the selection of appropriate solvents for use in ES-SAGD. The performance of the gas condensate ES-SAGD cases in this study exceeded that of the baseline SAGD case in terms of oil production rates, energy efficiency and post-production water handling. These findings were instrumental in the design and implementation of a field pilot project by Nexen Energy ULC in the Athabasca Oil Sands that is currently in progress.
A generalized methodology has been developed and successfully applied to determine diffusion coefficient of alkane solvent-CO2-heavy oil systems with consideration of swelling effect. Theoretically, a one-dimensional and one-way mass transfer model incorporating the volume translated Peng-Robinson equation of state (PR EOS) has been developed to describe the mass transfer from alkane solvent-CO2 mixture to heavy oil, which accounts for the oil swelling effect resulted from gas dissolution. The heavy oil sample has been characterized as three pseudocomponents, while the binary interaction parameter (BIP) correlations are tuned with the experimentally measured saturation pressures. Both apparent diffusion coefficients for gas mixtures and individual diffusion coefficient of each component of a mixture are determined once the discrepancy between the measured and calculated dynamic swelling factors of heavy oil has been minimized. The volume translated PR EOS with the three characterized pseudocomponents and the tuned BIP correlations is able to accurately predict the phase behavior of alkane solvent-CO2-heavy oil systems. Compared to the apparent diffusion coefficient, better agreements between the measured and calculated dynamic swelling factors have been obtained by use of the individual diffusion coefficients. Addition of C3H8 into CO2 stream is found to not only diffuse faster into heavy oil than CO2 but also contribute to a larger degree of oil swelling, leading to a faster and enhanced swelling effect of C3H8-CO2-heavy oil system in comparison with the CO2-heavy oil system.
The application of steam injection in different forms of processes is widely used for thermal heavy oil recovery. Several studies have been carried out to evaluate the effect of injecting steam with gaseous additives such as, Hexane, Nitrogen, Carbon Dioxide, Propane and air. However there is very little literature about addition of methane or natural gas to steam in order to improve steam injection process. This experimental study, investigates the effect of methane as an additive to steam. A consolidated core sample of an Iranian carbonate heavy oil reservoir (12°API) was used. The experiments involved injecting steam with methane in various methane/steam ratios ranging from 0:100 to 10:100 at reservoir conditions pressure and fluid saturations. Superheated steam was injected at 1200 psi which is higher than reservoir pressure at datum depth. Oil production rates, pressure drops and methane/steam ratios were measured to compare the effect of methane on oil recovery and other parameters at various fluid injection rates as well as steam temperatures. With optimum methane/steam ratio it was noticed that oil production is accelerated, steam injectivity is increased and also recovery is higher when compared to injection of pure steam.
Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone.
Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure.
An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process.
The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage.
In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer.
Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.
Steam-assisted gravity drainage (SAGD) is a proved enhancedoil- recovery technique for oil-sand extraction. However, the environmental and the economic challenges associated with steam generation limit the application of this technology. To address these issues, we have investigated the effectiveness of expandingsolvent- SAGD (ES-SAGD) over base SAGD on a bitumen sample (8.8 API). Experimental studies are conducted with a 2D physical model. Different strategies for solvent injection are tested (coinjection and cyclic injection) to examine the impact of the deposition of the asphaltene fraction of the bitumen on porous media and the behavior of the asphaltene fraction in produced oil. Toluene is used as asphaltene-soluble solvent, and n-hexane is selected as asphaltene-insoluble. Steam-chamber development is monitored with temperature profiles from 47 separate positions. The oil rate, recovery factor, and the produced-oil quality are evaluated together. The effectiveness of SAGD and ES-SAGD is discussed by considering the role of asphaltenes and their interactions with clays in both produced- And residual-oil samples. This study reveals that coinjection of hydrocarbon solvents with steam enhances the steam-chamber development with higher oil-production rate. Moreover, ES-SAGD results in recovery of moreupgraded oil and has a lesser environmental impact. We observe that the selections of solvent type and injection strategy are the most crucial parameters for the design of a hybrid SAGD process, and solvent cost and toxicity can be minimized with the recycling of solvent for continuous injection of solvents. High-energy consumption for steam generation during the SAGD process can be reduced by coinjection of proper solvent type with steam at a proper injection strategy. Our study reveals that the ES-SAGD process has environmental and economic benefits that are preferable to those of the base SAGD. However, some solvents can cause undesirable effects because of asphaltene destabilization and precipitation in production or transportation lines. The results of this work show that not only asphaltenes but also the other fractions of oil, along with the reservoir-clay type and the clay amount, affect the ES-SAGD performance.
We present results of a detailed investigation of the steam/ solvent-coinjection-process mechanism by use of a numerical model with homogeneous reservoir properties and various solvents. We describe condensation of steam/solvent mixture near the chamber boundary. We present a composite picture of the important phenomena occurring in the different regions of the reservoir and their implications for oil recovery. We compare performances of various solvents and explain the reasons for the observed differences. An improved understanding of the process mechanism will help with selecting the best solvent and developing the best operating strategy for a given reservoir.
Results indicate that as the temperature drops near the chamber boundary, steam starts condensing first because its mole fraction in the injected steam/solvent mixture (and hence its partial pressure and the corresponding saturation temperature) is much higher than the solvent's. As temperature declines toward the chamber boundary and steam continues to condense, the vapor phase becomes increasingly richer in solvent. At the chamber boundary where the temperature becomes equal to the condensation temperature of both steam and solvent at their respective partial pressures, both condense simultaneously. Thus, contrary to steam-only injection, where condensation occurs at the injected steam temperature, condensation of steam/solvent mixture is accompanied by a reduction in temperature in the condensation zone and the farther regions. However, there is little change in temperature in the central region of the steam chamber.
The condensed steam/solvent mixture drains outside the chamber, leading to the formation of a mobile liquid stream (drainage region) where heated oil, condensed solvent, and water flow together to the production well. The condensed solvent mixes with the heated oil and further reduces its viscosity. The additional reduction in viscosity by solvent more than offsets the effect of reduced temperature near the chamber boundary. As the steam chamber expands laterally because of continued injection and as temperature in the hitherto drainage region increases, a part of the condensed solvent mixed with oil evaporates. This lowers the residual oil saturation (ROS) in the steam chamber. Therefore, ultimate oil recovery with the steam/solvent-coinjection process is higher than that in steam-only injection. The higher the solvent concentration in oil at a location, the greater is the reduction in the ROS there. Our explanation is corroborated by the experimental results reported in the literature, which show smaller ROS in the steam chamber after a steam/solvent-coinjection process.
A lighter solvent has a lower viscosity, a higher volatility, and a higher molar concentration of solvent in the drainage region. Thus, a lighter solvent causes a greater reduction in the viscosity of the heated oil and also leads to a lower ROS. Therefore, the lightest condensable solvent (butane, under the conditions investigated) provides the most favorable results in terms of enhancements in oil rate and oil recovery. This is different from the prior claims in the literature.
The Vapex (vapor extraction) process may be a viable technique for the recovery of highly viscous heavy oil and bitumen. The size of the estimated heavy oil and tar sand resources in the United States amounts to 100 billion bbl and 62 billion bbl of oil in place (OIP), respectively. Although this represents a small fraction of the total world reserves, it is about one-third of the total estimated crude oil discovered in the United States. The world estimate of this resource is about 6 trillion bbl, six times the conventional oil reserves, and may be the future source of energy. Efficient extraction of these highly viscous crude oils poses a serious challenge to petroleum engineers. In some of the heavy oil reservoirs steam flooding and in-situ combustion processes were partially successful. For thick tar sand reservoirs, the steam-assisted gravity drainage (SAGD) process proved to be effective. However, thermal processes, in addition to other disadvantages, suffer from energy inefficiency caused by heat losses.
The Vapex process involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oi1 drains by gravity to a horizontal production well. Recent research has shown that the process is highly energy efficient, environmentally friendly, causes in-situ upgrading, and requires low capital investment compared to its competitive process, SAGD. The applicability of the Vapex process may even surpass SAGD in thin reservoirs, reservoirs underlain by aquifer, offshore operations, etc. Some experimental results, a theoretical analysis, and the feasibility of this process for implementation in heavy oil and bitumen reservoirs will be presented.
A compositional steam injection simulator was used to study the effects of noncondensable gas injection on oil recovery by steam flooding. Steam flooding oil recoveries resulting from injection of various mixtures of gas and steam were investigated for both light- and heavy-oil reservoirs.
The results indicate that noncondensable gas injection with steam can accelerate production significantly early in the life of a typical heavy-oil project, but the cumulative recovery over a 5-year steam injection period is about the same as that obtainable with steam injection alone. The early production increase was seen to result mainly from the additional sweep of the reservoir provided by the injected gas.
In a typical light-oil reservoir, the injection of non-condensable gas was seen to accelerate the oil recovery as a result of increased volume of the displacing gas phase and lowering of the oil viscosity by gas dissolution in the oil. There also was a small (6 to 7%) increase in oil recovery over a 5-year steam injection period. This increase is attributable to enhanced steam distillation and viscosity reduction of the oil by oil-soluble gas.
Introduction
A number of new processes for generating steam, including downhole steam generators, involve injection of noncondensable gas with steam into the reservoir-notably, the downhole steam generator developed by Sandia Natl. Laboratories and Zimpro's surface-operated direct wet air oxidation process.
Companies marketing steam generation systems involving simultaneous injection of steam and noncondensable gas (CO2 and N2) have suggested that improved oil production resulting from the presence of a noncondensing production resulting from the presence of a noncondensing gas phase in the reservoir might be possible. Many mechanistic theories have been advanced to support this improved recovery, and some limited laboratory experiments tend to corroborate these theories. However, how oil recovery is affected by a complex, three-phase (water/oil/gas), multicomponent environment generated by gas/steam injection has not been studied in detail.
More recently, reservoir simulation studies have evaluated the effects of noncondensable gas injection with steam on heavy-oil recovery. Some of these have shown dramatically accelerated oil recovery when CO2 is injected with steam as compared with steam injection alone. Other studies, however, show that the acceleration is only marginal-not enough to justify the additional costs of noncondensable gas injection. The results of these studies indicate that the response to noncondensable gas injection depends on reservoir and operating conditions and that a more comprehensive study is needed to determine the true potential of gas-steam injection to improve steamflood performance.
Our study was carried out to determine if noncondensable gas injection can indeed accelerate and/or increase oil recovery and, if so, which recovery mechanisms contribute to the improved steam flood performance. A thermal compositional simulator was used for this study.
Reservoir and Fluid Models
Reservoir Grid
The reservoir model was an areal 7 × 4 grid system representing one-eighth of a repeated five-spot pattern (Fig. 1). The area is 5.3 acres [21 450 m 2]; the distance between the injector and producer is 340 ft [ 104 m]. The area was divided into seven blocks in the x direction, parallel to the line between the injecter and the producer, and four blocks in the y direction. Apex cells in the three corners of the triangle were combined with blocks adjoining them, resulting in a total of 22 active blocks in each layer.
The massive 100-ft [31-m] sand was divided equally into four layers, all of which were open to injection and production. production. Reservoir Properties. Two types of reservoirs were considered for this study: heavy oil and light oil. The heavy-oil reservoir is characterized by shallow depth (less than 1,000 ft [305 m]), high permeability (4,000 md), and a spongy formation (compressibility: 2 × 10 -3 psi -1 [2.9 × 10–4 kPa -1). The initial oil saturation is 60 %; the initial oil in place (OIP) in the one-eighth of a five-spot is 100,000 bbl [15 900 m3] for the 100-ft [31-m] thick sand.
The light-oil reservoir, on the other hand, is typified by a greater depth (more than 2,500 ft [762 m]), lower permeability (40 md), and a less compressible formation permeability (40 md), and a less compressible formation (compressibility: 5 × 10 -5 psi -1 [7.25 × 10 -6 kPa -1 ]). The initial oil saturation is 40%; the initial OIP is 64,500 bbl [10 250 m3] for the 100-ft [31-m]-thick sand.
Table 1 shows important reservoir parameters used in the simulation study for both reservoir types. In all cases, the reservoir properties were assumed uniform. The vertical permeability was assumed to be 50% of the horizontal permeability. permeability. JPT
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The solvent based recovery process "Vapex" has a great potential for the recovery of heavy oil and bitumen resources, due to the low energy intensity and reduced GHG emission associated with the process. The process has been extensively investigated in the laboratory models and through numerical simulation studies. This has indicated the technical viability of the process as an alternative to thermal recovery processes, viz. SAGD. In the last few years several proprietary pilot has been developed to establish the commercial viability of this concept.
The most important uncertainty about this process is the rate of mixing of solvent molecules with high viscosity hydrocarbons. Due to low molecular diffusivity the theoretical predictions of extraction rates are significantly lower than the SAGD process. However, the results of physical model experimental carried out by this author showed a considerably higher mass transfer rate at the solvent bitumen interface. The process, whether in the laboratory model or in the reservoir porous media, takes place in a microscopic level. An experimental evidence of this phenomenon will be presented in the paper.
Transferring this microscopic phenomenon into a macroscopic simulation model presents a serious challenge. Artificially higher diffusion or dispersion coefficients are used to match the experimental data. Even with that both the production rate and the solvent saturation profile can not be matched simultaneously. For example the higher dispersion coefficient results in deep penetration of the solvent, resulting in a diffusion zone, thicker than the experimentally determined value. Lower dispersion coefficient results in a lower production rate. Some of these simulation results are presented in this paper. A recent development in the simulation model, Dynamic Grid Refinement, improves the simulation match by allowing the use of smaller grid blocks at the diffusion boundary layer.
The Vapex process represents a unique application of the horizontal well for the recovery of heavy oil and bitumen. In this process low molecular weight hydrocarbon solvent vapour is injected into the reservoir using horizontal well and the solvent diluted oil due to its low viscosity drains by gravity to another horizontal well. The rate of transfer of the solvent molecules in the crude directly reflects on the extraction rate. The higher area of contact between solvent vapour and the crude yields higher rate of mass transfer of the solvent. By using horizontal wells the area of contact for mass transfer is increased enormously. It was observed that in the initial phase, when the solvent vapour rises above the injector forming the extraction chamber, due to the countercurrent nature of the extraction the production rate is about 2–3 times higher than the subsequent gravity drainage rate. In this paper the possibility of enhancing the extraction rate by combining the effect of extended solvent-oil contact and the countercurrent mode of extraction throughout the project life is investigated.
In a reservoir underlain by aquifer the injected steam may preferentially pass through the water zone and condense causing a great loss of energy. In the Vapex process however, the high injectivity in this zone may be utilized to spread the solvent vapour underneath the reservoir extending the solvent-oil contact under the entire pattern simulating a planar well. Both injector and the producer should be placed near the water oil contact, separated by a distance that depends on the oil viscosity and reservoir parameters. The rising solvent vapour contacts oil countercurrently and the diluted oil is carried to the production well. With the remarkable advancement in the technology of drilling multi laterals it is possible to spread the solvent vapour effectively. A mathematical model for this extraction process is presented along with the experimental results that show 4-10 times higher extraction rate in this upward leaching process than in the usual spreading chamber.
Introduction
The Vapex process is emerging as an alternative to the thermal processes for the recovery of the huge resources of heavy and extra heavy oil worldwide. The concept is analogous to that of the Steam Assisted Gravity Drainage (SAGD) process, which has gained tremendous popularity in the industry for its usefulness in producing high viscosity heavy oil and bitumen. Unlike steam in SAGD, in the Vapex process vaporized hydrocarbon solvents are injected into the reservoir through a horizontal well. The injected solvent vapour dissolves in the high viscosity oil at the interface and diffuses through it. In this process the viscous oil gets diluted and drains to the horizontal production well by gravity. Initially the injected solvent vapour rises countercurrently with the draining diluted oil and a rising vapour chamber is created. Once the chamber reaches the top of the reservoir, it spreads sideways until the pattern boundary is encountered. The process may still be continued with a falling interface period until the rate becomes prohibitively low. The Vapex process is highly energy efficient, environmentally friendly, causes in-situ upgrading by deasphalting of the crude and requires lower capital investment compared to steam processes. The applicability of the Vapex process may even surpass the steam processes in thin reservoirs, reservoirs underlain by aquifer, offshore operations etc.
The principal use of horizontal wells is to expose a larger area of the reservoir to the well bore thereby increasing the productivity and to reduce the drawdown. The extended contact of the horizontal well with the reservoir is very useful in case of thermal processes e.g, SAGD or solvent extraction processes like Vapex. In SAGD heat is transported by conduction through the sand matrix containing oil and water. Use of horizontal well increases the area of heat conduction thereby increasing the heat transfer rate. For example with a 0.5 km long well pair in a 30 m thick reservoir with a fully developed steam chamber width at the top, say, 20 m, the area of heat conduction will be greater than 3.6 × 104 m2 compared to 755 m2 for a vertical well with an inverted cone shaped steam chamber of 20 m radius at the top.
As mentioned earlier, the Vapex process involves the diffusion of solvent into the bitumen or heavy oil. Production rates are directly related to the viscosity reduction which in turn depends on the amount of solvent dissolved in the crude. Since the molecular diffusivity of solvent in bitumen is orders of magnitude lower than the thermal diffusivity of the reservoir matrix, it is generally expected that production rates will be much lower in this solvent process than those in a steam process.
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A limited number of laboratory and field evidences showed that steam-solvent coinjection can lead to a higher oil production rate, higher ultimate oil recovery, and lower steam-oil ratio, compared with steam-only injection. However, a critical question still remains unanswered: Under what circumstances the above mentioned benefits can be obtained when steam and solvent are coinjected? To answer this question requires a detailed knowledge of the mechanisms involved in coinjection and reflection of this knowledge to its numerical simulation. Our earlier studies demonstrated that the determining factors for improved oil production rates are relative positions to the temperature and solvent fronts, the steam and solvent contents of the chamber at its interface with reservoir bitumen, and solvent diluting effects on the mobilized bitumen just ahead of the chamber edge. Then, the key mechanisms for improved oil displacement are solvent propagation, solvent accumulation at the chamber edge, and phase transition.
This paper deals with this unanswered question by deriving a systematic workflow for selecting an optimum solvent and its concentration in coinjection of a single-component solvent with steam. The optimization considers the oil production rate, ultimate oil recovery, and solvent retention in situ. Multiphase behavior of water-hydrocarbon mixtures in the chamber is explained in detail analytically and numerically. The proposed workflow is applied to simulation of the Senlac SAP pilot project to investigate reasons for its success.
Results show that an optimum volatility of solvent can be typically observed in terms of the oil production rate for given operation conditions. This optimum volatility occurs as a result of the balance between two factors affecting the oil mobility along the chamber edge; i.e., reduction of the chamber-edge temperature and superior dilution of oil in coinjection of more volatile solvent with steam. It is possible to maximize oil recovery while minimizing solvent retention in situ by controlling the concentration of a given coinjection solvent. Initiation of coinjection right after achieving the inter-well communication enables the enhancement of oil recovery early in the process. Subsequently, the solvent concentration should be gradually decreased until it becomes zero for the final period of the coinjection. Simulation case studies show the validity of the oil recovery mechanisms described.
The vapor extraction (VAPEX) process is a promising technology for recovering heavy oil and bitumen resources in an economically viable and environmentally friendly way. Although a number of laboratory experiments have been conducted to study the VAPEX process, the oil recovery mechanisms by gravity drainage in this process are not well understood yet. In this paper, both experimental and theoretical approaches are adopted to study the effects of gravity and the capillary force on gravity drainage in the VAPEX process. First, the interfacial tensions between a heavy oil sample and four different solvents (methane, ethane, propane, and carbon dioxide) are measured at different pressures below their respective vapor pressures by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case. Then, the Bond number, which is defined as the ratio of gravity to the capillary force, is calculated for the VAPEX process in a heavy oil reservoir and in a physical model of sand pack, respectively. It is found that the measured interfacial tension between the heavy oil and a solvent is reduced almost linearly with pressure for the four heavy oil-solvent systems tested. Correspondingly, the Bond number increases with pressure. An increased Bond number indicates relatively large effect of gravity on the VAPEX process and thus enhanced oil recovery.
This paper describes the process of injecting a liquid (C5+) hydrocarbon as a steam additive in a CSS mode of operations. The process has been termed LASER, for "Liquid Addition to Steam for Enhancing Recovery".
The process concept was first tested in a 3D physical model apparatus using Cold Lake bitumen. A sustained uplift in bitumen production was observed in later CSS cycles when compared to other tests conducted without liquid addition. Based on numerical simulations, these effects can be attributed to additional viscosity reduction of heated bitumen when contacted with solvent. For bitumen-diluent mixtures, Shuh’s method of viscosity prediction of bitumen with liquid hydrocarbons is adequate to make realistic viscosity predictions based on actual measurements. Field-scale simulations were used to support LASER performance trends from the physical model and establish the optimal timing for applying the technology in the field.
The key recovery performance indicators for LASER technology are (1) bitumen uplift over continued CSS performance and (2) fractional recovery of the injected diluent. A field pilot has been designed based on expectations of (1) an improvement of 33% in the cycle Oil-Steam Ratio (OSR) and (2) diluent recovery of 66% using 6% v/v of diluent injection with steam. The pilot location was chosen based on various factors, including improved characterization of historical performance within and around the pilot location. This was achieved by developing a novel multivariate analysis technique to correlate current OSR field performance and reduce associated background noise.
An extensive monitoring program has been developed for the pilot. This program is critical for developing a reliable characterization of the diluent recovery. Diluent injection began in April 2002, and the pilot is expected to last approximately 2 years, corresponding to the average length of CSS cycle 7 at Cold Lake.
Co-injection of solvent with steam in SAGD has shown promise for enhancing oil rates as well as in reduction of energy and water consumption. Modeling and optimization of hybrid steam-solvent recovery processes with commercial numerical simulators can be very time consuming. In addition, the complex interaction of heat and solvent effects in mobilizing heavy oil at the vapour chamber boundary are often difficult to ascertain from the numerical models. Semi-analytical mathematical models can provide insight into the physics of the processes and may be used to estimate production rates and thermal efficiency in much less time.
In this study, an unsteady-state semi-analytical model was developed to predict the oil flow rate in the steam-solvent assisted recovery process. The model assumes a curved interface with transient temperature and solvent distribution in the mobile zone. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution. The oil flow rate and interface profile are predicted at each time in an iterative fashion. The results show that the coefficient of diffusion-concentration function significantly affects the solvent penetration depth and its distribution. The semi-analytical model was able to predict oil production rates using different solvents co-injected with steam, in agreement with reported experimental data.
The proposed model reveals the complex interaction of heat and solvent solubility and diffusion as they affect mobilization and production of viscous oil. This model may be used to find the optimal operation parameters for the process over a range of different reservoir qualities and pressures, in a very time-efficient manner. The final outcome may lead to an efficient design of a steam-solvent recovery process that utilizes less water and reduces the amount of energy and gas emissions per barrel of oil produced.
North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (<90m) and thus 85% of the oilsands (232 billion bbl recoverable reserves) must be recovered using in-situ techniques. Steam Assisted Gravity Drainage (SAGD) has become the method of choice for oilsand producers and it is therefore critical to optimize this process.
ES-SAGD or expanding solvent steam assisted gravity drainage involves the co-injection of a hydrocarbon solvent and steam to improve recovery from the SAGD process. The hydrocarbon solvent is soluble in bitumen at reservoir conditions and serves to decrease its viscosity thereby increasing the production rate over a process driven solely by steam.
This paper investigates several ES-SAGD pilot projects with a focus on the Nexen-OPTI ES-SAGD project at Long Lake. Additionally, a literature search was performed and the data, found in public ES-SAGD papers on steam-solvent labs and simulation studies, is summarized. Nexen is also currently involved in a lab experiment being operated by AGAT involving a comparison of the performance of different hydrocarbon solvents for assisting the SAGD process.
ES-SAGD should be pursued because successful implementation would significantly improve profitability by accelerating production, decreasing water losses and decreasing steam requirements. Additionally this will address environmental concerns by decreasing CO2 emissions. ES-SAGD will also increase reserves both per well pair and on a total oilsands basis.
In this paper, we present a microfluidic approach to measure liquid solvent diffusivity in Athabasca bitumen. The method has three distinguishing features: (a) a sharp initial condition enabled by the high wettability of the solvent; (b) one-dimensional diffusive transport (in the absence of convection) ensured by microscale confinement; and (c) visible-light-based measurement enabled by the partial transparency of the bitumen at small scales. The method is applied to measure the diffusion of toluene into bitumen by imaging transmitted light profiles over time, and relating intensities to the mass fractions. Plotting toluene mass fraction versus distance/sqrt(time), results in a tight superposition of all curves (time-dependent mass fractions) demonstrating the diffusion dominated nature of the system and the robustness of the method. The diffusion transport equations were solved and fit to a constant diffusion coefficient as well as a variety of concentration-dependent diffusion coefficient relations found in the literature. For intermediate toluene mass fractions (0.2–0.8), a constant diffusion coefficient of 2.0 × 10–10 m2/s provides an appropriate representation. However, at low toluene mass fractions (<0.2), significantly reduced diffusive transport is observed, and endpoint analysis indicates diffusion coefficients trending toward 4.3 × 10–11 m2/s. At high toluene mass fractions (>0.8), the values trend toward 1.5 × 10–10 m2/s. This microfluidic method provides an inexpensive and rapid mutual diffusion coefficient evaluation, with significantly improved spatial/composition resolution vis-à-vis competing measurement methods.
The vapor extraction process may be suitable for the recovery of huge resources available in the form of highly viscous heavy oil and bitumen. Vaporized hydrocarbon solvents are used to reduce the viscosity; the diluted oil drains by gravity. Low energy consumption, less environmental pollution, in situ upgrading, lower capital costs, etc., make the process superior to the currently used thermal processes. Experiments were carried out in a Hele–Shaw cell and in a scaled packed cell to evaluate the performance of this process and study the mechanism. The experimental results showed that in porous media, the process performs as much as an order of magnitude better than expected from typical calculation using molecular diffusivity alone. In porous media, the process takes place in a contact zone. In this zone, the high-viscosity oil contacts the solvent vapor in the fine capillaries that offer a higher interfacial area of contact. The process involves transient diffusion of solvent into the bitumen at the interface. As soon as the oil at the interface attains mobility due to viscosity reduction, it drains, exposing a new interface of bitumen having a very low concentration of solvent. Surface renewal, aided by capillary imbibition, yields a higher mass transfer rate that enhances the rate of extraction.
The combined pressure-decay technique with rheometry is developed to measure the diffusivity of carbon dioxide (CO2) in bitumen at temperatures of 30, 50, and 70 °C and pressures of 2 and 4 MPa. Mixing due to shear imposed by a rheometer allows rapid direct measurement of the equilibrium pressure in CO2–bitumen systems accurately. The comparison of the measured equilibrium pressures with the values obtained from the data regression demonstrates significant discrepancies, which can lead to a great deviation in the diffusivity, up to 5-fold different than the true values. The measured values for the diffusivity of CO2 into the bitumen increase with temperature, following the Arrhenius equation. By changing the temperature from 30 °C to 70 °C, the diffusivity increases by 88% at 2 MPa and 54% at 4 MPa. The diffusivity also increases with the pressure, suggesting the ease of diffusion at the presence of the CO2 molecules in the liquid phase. The effect of pressure is more dominant at lower temperatures while the diffusivity increase is 53% at 30 °C, compared to 25% at 70 °C. Furthermore, the findings demonstrate that the CO2–bitumen system does not follow any constant pattern in the diffusivity–viscosity–temperature relationships, which is due to the ongoing phase change at the studied temperature range.
Steam-assisted gravity drainage (SAGD) is the most widely used method for in-situ bitumen recovery. Expanding-solvent-SAGD (ES-SAGD) has been proposed as an alternative to SAGD to improve its efficiency. In ES-SAGD, steam is coinjected with a small amount of solvent. Detailed oil recovery mechanisms near the chamber edge are little known due to the complex interaction of fluid and energy flow, and phase behavior. Prior research on ES-SAGD explains that coinjected solvent can further decrease oil viscosity near the chamber edge by dilution, in conjunction with heat.
In this paper, we conduct a detailed investigation on oil displacement mechanisms and the placement of solvent near the chamber edge using fine-scale reservoir simulation. The importance of properly considering both phase behavior and flow to design ES-SAGD is demonstrated. Results show that ES-SAGD can achieve a higher displacement efficiency than SAGD. Oil production rate in ES-SAGD can be two times higher than that in SAGD. As a result, the ultimate oil recovery of ES-SAGD is enhanced by almost 20%, compared to SAGD in this research. The oil saturation reduction results from condensed solvent bank and phase transition near the chamber edge. The condensed solvent bank lowers the oil-component concentrations there. The diluted oil with solvent is then redistributed in the gaseous and oleic phases in the presence of the water phase on the phase transition at the chamber edge. The resulting amount of the oleic phase can be significantly small, yielding lowered oil saturations in the ES-SAGD chamber.
This patent describes a method for enhancing the recovery of petroleum from a production well penetrating a petroleum-bearing formation. It comprises introducing into the formation one or more thiocarbonate salts of the form (X)â(CS{sub y})â, wherein X is an organonitrogen radical, y ranges from 3 to 4, and z is the valence of X, the thiocarbonate salt being introduced into the petroleum-bearing formation through one or more injection wells and with the petroleum being removed from the formation, at least in part, through the production well at a daily crude oil production rate.
A miscible displacement process for the recovery of petroleum from a petroleum bearing formation is performed in situ by use of a solvent miscible with the petroleum. The solvent has a density greater than water and is followed by an aqueous driving fluid. The process involves introducing a slug of the solvent capable of dissolving formation hydrocarbons into the upper portion of an oil reservoir and forcing the solvent through the reservoir to some lower point, the driving fluid being an aqueous fluid. (23 claims)