Cyclic Solvent Injection Research Articles

Microfluidic Insights into the Effects of Reservoir and Operational Parameters on Foamy Oil Flow Dynamics during Cyclic Solvent Injection: Reservoir-on-the-Chip Aided Experimental and Numerical Studies

This study examines the microfluidic characterization of foamy oil flow dynamics in heterogeneous porous media. A total of 12 microfluidic CSI experiments were conducted using reservoir-on-the-chip platforms. In addition, detailed PVT analysis was performed to characterise the heavy oil/solvent systems. Moreover, a numerical model constructed with CMG software package (2021.10) has been validated against the experimental findings in this study. A clear-cut visualization study provided by microfluidic systems revealed that factors including solvent type, pressure depletion rate, and reservoir parameters have a significant impact on foamy oil flow extension. It was found that a solvent containing a higher CO2 content demonstrated more effective performance compared with other solvent compositions, owing to its capability to reduce viscosity, enhance swelling, and offer more gas molecules due to its superior solubility. Additionally, a high pressure-depletion rate amplifies the driving force for bubble nucleation, as well as reducing the amount of time available for bubble coalescence. In addition, lower reservoir porosity impedes bubble movement and delays coalescence, thus extending the foamy oil flow. Furthermore, with the aid of a robust image analysis technique, it was discovered that utilizing 100% CO2 as a solvent resulted in a 17% increase in oil recovery over using 50% CO2 and 50% CH4. Furthermore, a 6% increase in oil recovery was achieved by applying a fast pressure depletion rate as opposed to a slow pressure depletion rate. Moreover, the numerical model constructed was found to be accurate in adjusting heavy oil recovery with an average relative error of 7.7%.

Effect of in-situ emulsification on CO2/N2-based cyclic solvent injection process for enhancing heavy oil recovery and CO2 storage

Surfactant-assisted CO2/N2-based CSI (SA CO2/N2-CSI) process emerges as a strategic solution to migrate the high energy consumption and carbon intensity associated with traditional thermal operations for heavy oil recovery. However, the interphase mass transfer makes the emulsification behavior in this process complex. In this study, the effect of in-situ emulsification on CO2/N2-CSI is assessed using a sandpack model and microchannel chip. Mesoscopically, SA CO2/N2-CSI outperforms conventional CO2/N2-CSI in terms of both oil recovery and CO2 storage, owing to the enhanced CO2 diffusion, oil solubilization, and foamy oil stability due to emulsification. Microscopically, the impact of emulsifier injection rate on oil removal efficiency in the dead-end pores becomes negligible when the injection rate exceeds 50 nL/min, providing insights to the emulsification mechanisms underlying the optimal pressure depletion rate (9 kPa/min) in SA CO2/N2-CSI. This study demonstrates the applicability of the SA CO2/N2-CSI in fostering sustainable heavy oil production and CO2 storage.

An Ethane-Based CSI Process and Two Types of Flooding Process as a Hybrid Method for Enhancing Heavy Oil Recovery

Combining multiple secondary oil recovery (SOR)/enhanced oil recovery (EOR) methods can be an effective way to maximize oil recovery from heavy oil reservoirs; however, previous studies typically focus on single methods. In order to optimize the combined process of ethane-based cyclic solvent injection (CSI) and water/nanoparticle-solution flooding, a comprehensive understanding of the impact of injection pressure, water, and nanoparticles on CSI performance is crucial. This study aims to provide such understanding through experimental evaluation, advancing the knowledge of EOR methods for heavy oil recovery. Three approaches (an ethane-based CSI process, water flooding, and nanoparticle-solution flooding) were applied through a cylindrical sandpack model with a length of 95.0 cm and a diameter of 3.8 cm. Test 1 conducted an ethane-based CSI process only. Test 2 conducted a combination approach of CSI–water flooding–CSI–nanoparticle-solution flooding–CSI. Specifically, the injection pressure of the first CSI phase in Test 2 was gradually increased from 3500 to 5500 kPa. The second and the third CSI phases had the same injection pressure as Test 1 at 5500 kPa. The CSI process ceased once the oil recovery was less than 0.5% of the original oil in place (OOIP) in a single cycle. Results show that the ethane-based CSI process is sensitive to injection pressure. A high injection pressure is crucial for optimal oil recovery. The first CSI phase in Test 2, where the injection pressure was increased gradually, resulted in a 2.9% lower oil recovery and five times as much ethane consumption compared to Test 1, which applied a high injection pressure. It was also found that water flooding improved the oil recovery in the CSI process. In Test 2, the oil recovery factor of the second CSI phase increased by 57% after the water flooding process, which is likely due to the formation of water channels and a dispersed oil phase that increased the contact area between ethane and oil. Although the nanoparticle-solution flooding only had 0.3% oil recovery, after that the third CSI phase stimulated another 10.8% of OOIP even when the water saturation achieved more than 65%. This demonstrated that the addition of nanoparticles can maintain the stability of the foam and enhance the transfer of ethane to the heavy oil. Finally, Test 2 reached a total oil recovery factor of 76.1% on a lab scale, an increase of 45% compared to the single EOR method, which proved the combination process is an efficient method to develop a heavy oil field.

Effect of N2 impurity on CO2-based cyclic solvent injection process in enhancing heavy oil recovery and CO2 storage

CO2-based CSI (CO2–CSI) process is an effective EOR technique for heavy oil reservoirs after primary production. However, the application of CO2–CSI in the field is limited by the massive requirement and cost of pure CO2. To address this limitation, the effect of N2 impurities on the CO2–CSI process is evaluated by experiments using a 1D sand pack model. The results illustrated that the oil recovery significantly decreases when the N2 content surpasses 17.2 % because of the low solubility of N2 content in the oil phase and the lower viscosity reduction effect. Additionally, the N2 impurity component in the reservoir displaces some of the pore volume available for CO2 storage, but the CO2 storage ratio, the CO2 storage amount out of the consumption amount, is similar to that of the pure CO2–CSI process. An economic analysis is conducted for the material cost of each unit oil production in cases with different N2 impurities. The results indicate that the material cost follows a pattern of initially declining and then rising along with the increase of N2 content. In this study, the optimal N2 content in CO2 for the CSI process is approximately 17 %, considering its high CO2 storage ratio, high oil recovery factor, and low material costs compared to other N2 purity schemes. The findings of this study provide valuable insights for optimizing the solvent components in the CO2–CSI process, contributing to the economic and sustainable development of heavy oil resources and considerable CO2 storage.

Multiphase Multicomponent Transport Modeling of Cyclic Solvent Injection in Shale Reservoirs

Summary A thorough understanding of fluid transport in ultratight shale reservoirs is crucial for designing and optimizing cyclic solvent injection processes, known as huff ’n’ puff (HnP). We develop a two-phase multicomponent numerical model to investigate hydrocarbon and solvent transport and species mixing during HnP. Unlike the conventional modeling approaches that rely on bulk fluid (advective) transport frameworks, the proposed model considers species transport within nanopores. The chemical potential gradient is considered the driving force for the movement of nonideal fluid mixtures. A binary friction concept is adopted that considers friction between different fluid molecules and between fluid molecules and pore walls. After validating the developed model against analytical solutions and experimental data, the model examines solvent HnP enhanced oil recovery (EOR) mechanisms by considering four-component oil and Eagle Ford crude oil systems. The impacts of injection pressure, primary production duration, soaking time, and solvent type on the oil recovery are examined. The results reveal that the formation of a solvent-oil mixing zone during the huff period and oil swelling and vaporization of oil components during the puff period are key mechanisms for enhancing oil recovery. Furthermore, the incremental recovery factor (RF) increases with injection pressure, even when the injection pressure exceeds the minimum miscibility pressure (MMP), implying that MMP may not play a critical role in the design of HnP in ultratight reservoirs. The results suggest that injecting solvents after a sufficient primary production period is more effective, allowing reservoir pressure depletion. Injecting the solvent without enough primary production may result in significant production of the injected solvent. The results show that the solvent-oil mixing zone expands, and the solvent recycling ratio decreases as soaking time increases. However, short soaking periods with higher HnP cycles are recommended for improving oil recovery at a given time frame. Finally, CO2 HnP outperforms CH4 or N2 HnP due to the higher ability of CO2 to extract a larger amount of intermediate and heavy components into the vapor phase, which has higher transmissibilities as compared with the liquid phase.

Experimental evaluation of the impact of induced fractures on cyclic solvent injection performance in low-permeability hydrocarbon reservoirs

Recovery factors associated with primary recovery (pressure depletion) schemes are often small (<5–10%) for low-permeability hydrocarbon reservoirs. As a result, cyclic solvent injection (CSI) schemes, using CO2 and produced gas, are currently being considered for enhanced hydrocarbon recovery (EOR). Fracture networks, generated during hydraulic fracturing stimulation, affect both primary and enhanced recovery by increasing the surface area contacted with the low-permeability reservoir matrix. However, experimental studies of the impact of induced (hydraulic) fractures on CSI performance are sparse, particularly those that provide a realistic representation of the fracturing process by inducing fractures under stress to better represent fracture conditions (e.g., fracture surface area, fracture surface roughness). Therefore, the primary objective of this work is to develop a laboratory-based workflow for evaluating the effectiveness of fracture system in tight oil reservoirs to enhance the oil recovery during a typical CSI cycle using a combination of core-scale techniques.An in-house core-flooding methodology, that combines ‘in situ’ fracturing and cyclic gas injection, was applied. The experimental procedure includes: 1) performing multiple cycles of lean gas (i.e., 80% C1 + 20% C2) injection into an oil-saturated ‘intact’ core plug until maximum oil recovery (5%) is reached, 2) artificially fracturing the core plug under stress, 3) repeating multiple cycles of lean gas injection into the artificially-fractured core plug, under similar experimental conditions as those used for the intact core, until maximum oil recovery (23%) is reached, and 4) measuring the fractured-core liquid permeability. A well-characterized tight siltstone core plug sample obtained from the Canadian Montney Formation was analyzed as an example. The experimental results indicate that 1) fracturing under stress results in an increase in surface area and permeability, and 2) the recovery factor is enhanced by ∼ 18% after fracturing (e.g., from ∼ 5% for intact core plug to ∼ 23% for artificially-fractured core plug).This study provides a proof-of-concept experimental approach for evaluating the impact of induced fractures on CSI recovery using an identical core plug sample (intact and fractured). The proposed experimental methodology could serve as a workflow for laboratory-scale evaluation of the impact of induced fractures on CSI performance in tight hydrocarbon reservoirs.

Propane–Bitumen Interactions during Cyclic Solvent Injection─A Cold Lake Case Study

Propane–Bitumen Interactions during Cyclic Solvent Injection─A Cold Lake Case Study

Numerical simulation of foamy-oil flow in a cyclic solvent injection process

Cyclic solvent injection (CSI) has emerged as a promising and environment-friendly heavy oil production process. One of its main recovery mechanisms is foamy-oil flow. This study first experimentally observes the foamy-oil flow under reservoir conditions in a sand-packed CSI test, and then theoretically interpret the flow pattern through mathematical modeling. Finally, the oil recovery mechanisms of CSI are investigated. Results show that foamy oil flows in an intermittent instead of continuous manner during the production period. Multiple waves of foamy oil start from the transition zone and push oil toward the producer. This is well predicted by our newly developed theoretical model: the oil and gas productions increase stepwise during a production period. Besides, the foamy-oil flow occurred 2–4 times, which is because the position of equilibrium state in the transition zone keeps changing during the pressure drawdown process. Moreover, larger diffusivity, higher initial solvent content, slower pressure depletion, and slower formation rate of free gas leads to more waves of foamy-oil flow and higher oil production. This study provides some meaningful insights into foamy-oil flow process, as well as cleaner recovery of heavy oil reserves through solvent-based technique.

Experimental study on the effect of pressure decline rate on foamy oil flow characteristics in a heavy oil–CO2‐C3H8 system

AbstractCO2‐based cyclic solvent injection (CSI) processes have gained great interest and have been piloted to enhance heavy oil recovery sustainably. Although the performance of pure CO2 injection is encouraging, it is still not commercially feasible. In order to improve the performance of the CSI process, CO2 (72%) and C3H8 (28%) were chosen to be mixed with a heavy oil sample, and then four pressure depletion tests were conducted to investigate the effects of decline rates on the enhanced oil recovery performance and foamy oil flow behaviour. The production behaviour can be divided into three phases: volume expansion production phase (7% contribution), foamy oil flow production phase (73% contribution), and solution‐gas drive phase (20% contribution). The experimental results showed that depletion rates positively correlated with oil recovery factors in the last two phases. Additionally, the foamy oil flow phase was further divided into two zones: Zone‐1 (bubble nucleation and growth dominant zone) and Zone‐2 (bubble coalescence and disengagement dominant zone). The results showed that higher pressure depletion rates lead to larger pressure differences which in turn resulted in an increasing bubble nucleation rate in Zone‐1. While coalesced bubbles in Zone‐2 lead to a stronger discontinuous gas flow and the relative permeability of the oil phase decreased sharply. Compared with relatively lower heavy oil recovery factors (19.4%) in pure heavy oil–CO2 system, the heavy oil–CO2‐C3H8 system took advantage of a higher oil recovery factor (23.44%). Furthermore, the relatively lower average gas recovery factor and cumulative gas–oil ratio (cGOR) indicated that CO2 can be sequested in heavy oil reservoirs more efficiently.

Mathematical modeling of foamy-oil flow in a cyclic solvent injection process

Foamy-oil flow is one of the main mechanisms for cold heavy oil production with sand (CHOPS) and cyclic solvent injection (CSI) processes. The flow pattern of foamy oil was observed in previous experimental studies under reasonable reservoir conditions. This study aims to investigate the foamy-oil flow mechanisms through theoretical modeling. A mathematical model is developed, which couples a solvent concentration field and a pressure field through flow velocity and oil viscosity, in which a pseudo-chemical reaction is used to describe the release of gas. The model is numerically solved by the Newton−Raphson iterative method. Results show that, firstly, during the pressure drawdown process, propane concentration decreases and oil viscosity increases with solvent exsolution in the transition zone, which restricts the bubbles coalescence and conduces to the formation of foamy oil. Secondly, the existence of bubbles leads to the buildup of local pressure gradient and causes the spatial difference of flow velocity. Moreover, when the threshold velocity is reached, the bubbles coalesce rapidly to form free gas, pushing the oil in the foamy region forward to the gas zone. Finally, the total waves of foamy-oil flow are generally 2 to 4, depending on the initial solvent concentration, oil viscosity, and pressure depletion rate. Higher initial solvent concentration, faster pressure depletion, and lighter original heavy oil lead to the easier induction of foamy-oil flow.

Comprehensive investigation of non-equilibrium properties of foamy oil induced by different types of gases

The foamy oil phenomenon has a positive influence on cyclic solvent injection (CSI) processes for oil recovery because it affects the properties of heavy oil (HO). However, there is still a lack of mathematical methods and basic experimental data for the physical properties of foamy oil during CSI processes. The effects of injection gas type and mole fraction on foamy oil behavior and non-equilibrium properties are still not well understood. In this study, a new type of non-equilibrium swelling experiment was proposed to determine the properties of foamy oil induced by CH4, CO2, and C3H8. The effects of gas type, mole fraction, and pressure were analyzed experimentally, and foamy oil behavior was observed by utilizing a high-pressure cell that was designed specifically for this purpose. Then, a mathematical model was developed to calculate the non-equilibrium properties of foamy oil. The results show that higher pressures are needed to dissolve and disperse gas in HO to induce foaming, and the lifetime of foamy oil increases with increasing mole fraction of injected gas. The formation of foamy oil can effectively swell HO, and the swelling factor (SFb) and pseudo-swelling factor (SFpb) increase gradually with increasing mole fraction of injected gas. Compared to CO2 and C3H8, CH4 is advantageous for inducing foamy oil phenomena. Lower apparent density and higher compressibility were observed in the HO-CH4 systems than in the HO-CO2 and HO-C3H8 systems at the same gas mole fractions.

Effects of Diffusion, Adsorption, and Hysteresis on Huff-n-Puff Performance in Ultratight Reservoirs with Different Fluid Types and Injection Gases

Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO2, C2H6, and C3H8). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C2H6 provides the highest recovery for the black oil and volatile oil systems, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

Determination of individual concentration-dependent diffusivity of binary gas-mixtures in reservoir-fluid systems

Diffusion is one of the main mass transfer principles associated with a gas injection process, e.g., vapor extraction (VAPEX) and cyclic solvent injection (CSI), to reduce the viscosity of heavy oil by dissolution of light gas(es). A few efforts have been made to estimate the diffusivity of each gas component of a binary gas-mixture in heavy oil as a constant, but no attempts have been made to determine individual diffusivity of each gas component in the binary gas-mixture as concentration-dependent. In this study, the concentration-dependent diffusivities of CO2 and C3H8 in a CO2/C3H8 mixture, which preferentially diffuses in a Lloydminster heavy oil, are evaluated implicitly as a power function of gas concentration, pressure, and temperature through the oil viscosity. The coefficient and exponent of such a power function for each gas are determined once the deviations between the measured and calculated values for oil swelling factors and composition of each gas dissolved in heavy oil at the completion of a dynamic volume analysis (DVA) test are minimized by applying the 1D time-dependent finite element method (FEM). Compared with the constant diffusivities for the same test, considering concentration-dependency of the dissolved gases reproduces the experimentally measured oil swelling factors and compositions at the end of the test with a significantly enhanced accuracy. Then, such obtained concentration-dependent diffusivities are extended to reproduce the experimentally measured swelling factors of a pressure-decay test performed with another CO2/C3H8 gas-mixture and the same heavy oil. From such an evaluation, it can be inferred that the coefficient and exponent of the diffusivity correlation associated with a binary gas-mixture are functions of pressure, temperature, feed gas composition, and test duration, respectively. This is because the coefficient and exponent for one gas component may be affected by the presence of the other as the latter alters the composition of heavy oil in which the former diffuses.

Numerical Simulation of Nonequilibrium Foamy Oil for Cyclic Solvent Injection in Reservoirs after Cold Heavy Oil Production with Sand

SummaryNonequilibrium foamy oil behavior and solvent transport are two important recovery mechanisms for cyclic solvent injection (CSI) processes in post-cold heavy oil production with sand (CHOPS) reservoirs. The nonequilibrium solvent exsolution and gas bubbles generated during the pressure depletion stage have the typical characteristics of foamy oil flow. In this paper, a field-scale post-CHOPS model is constructed and upscaled from a core model, which was calibrated against detailed experimental data involving various propane (C3H8)-based and carbon dioxide (CO2)-based solvent mixtures. The field model is upscaled from the core model to analyze the impacts of simulation scales, heterogeneous wormholes, and the operating schedules on foamy oil behavior of different solvent systems.Reaction kinetics are implemented to represent the nonequilibrium gas dissolution and exsolution for foamy oil flow. A fractal wormhole network is modeled. To analyze the impacts of pressure depletion strategies, single-stage pressure depletion involving three oil solvent systems, as well as two cycles of CSI production processes, are examined. Detailed sensitivity analyses involving different solvent compositions are discussed.The results illustrate that both C3H8-based and CO2-based solvents exhibit significant nonequilibrium foamy oil characteristics, enabling the oil viscosity to remain close to its value with dissolved solvent during the pressure depletion process. However, the amount of nonequilibrium foamy oil flow is strongly dependent on the pressure depletion rate: A faster depletion rate is beneficial for higher oil recovery. The core model results are more sensitive to the solvent types, whereas the field-scale simulations show comparable recovery performance for both C3H8-based and CO2-based solvents. This observation highlights the significance of domain size, time scale, and wormhole heterogeneities on the ensuing foamy oil behavior.Although several post-CHOPS models were developed in the past, detailed field-scale models that simulate nonequilibrium foamy oil kinetics in a realistic wormhole network are lacking. The simulation model developed here has been calibrated against detailed experimental measurements and upscaled from a core-scale model. Improving our understanding of solvent dissolution/exsolution would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.

Experimental and computational evaluation of cyclic solvent injection in fractured tight hydrocarbon reservoirs

Multi-fractured horizontal wells have enabled commercial production from low-permeability (‘tight’) hydrocarbon reservoirs but recoveries remain exceedingly small (< 5–10%). As a result, operators have investigated the use of solvent (gas) injection schemes, such as huff-n-puff (HNP), to improve oil recovery. Previous HNP laboratory approaches, classified primary as ‘flow-through-matrix’ and ‘flow-around-matrix’ typically (1) are not fully representative of field conditions at near-fracture regions and (2) require long test times, even when performed on fractured cores. The objectives of this proof-of-concept study are to (1) design and implement a new experimental procedure that better reproduces HNP schemes in near-fracture regions and (2) use the results, simulated with a compositional lab-calibrated model, to explore the controls on enhanced hydrocarbon recovery in depleted tight oil plays. Performing multiple CO2 and (simplified) lean gas HNP cycles, the integrated experimental and simulation approach proposed herein achieves the ultimate recovery factors in a significantly shorter time frame (25–50%) compared to previous studies. The integrated experimental and computational approach proposed herein is valuable for core-based evaluation of cyclic solvent (CO2, CH4) injection in tight hydrocarbon reservoirs for (1) hydrocarbon recovery and (2) subsurface greenhouse (CO2, CH4) gas disposal/storage applications.

Experimental and Numerical Study of Strategies for Improvement of Cyclic Solvent Injection in Thin Heavy-Oil Reservoirs

SummaryTo overcome the problems of slow mixing in the vapor-extraction (VAPEX) process and regaining high oil viscosity in the cyclic solvent process (CSP), we introduce a new process for thin heavy-oil reservoirs known as the enhanced cyclic solvent process (ECSP). In ECSP, two types of hydrocarbon solvents are cyclically injected in two separate slugs: one slug is more volatile (methane) and the other is more soluble (propane or ethane) in heavy oil. In this study, experiments of primary depletion, CSP, cyclic gas-alternating-water (GAW) or inverse water-alternating-gas (WAG) injection, ECSP, and surfactant-enhanced CSP at relatively low-to-intermediate pressures in a visual rectangular sandpack (with a thickness/length ratio of 1:32) filled with crude oil, gas, and brine (replicating the actual field conditions pertaining to a thin reservoir after the primary depletion) are presented. The effect of operational pressure, initial production pressure, more soluble solvent type (propane/ethane), propane-slug size, and initial oil saturation on the ECSP performance are evaluated. Moreover, the effects of well location, initial production pressure, production end pressure, system repressurization using water injection, and adding an oil-soluble surfactant before methane injection on the CSP are investigated. The performance of CSP is compared with that of ECSP, cyclic inverse WAG, surfactant-enhanced CSP, and extended waterflood (EWF). The experimental results indicate that the performance of cyclic solvent injection decreases in this order: ECSP using methane/propane, surfactant-enhanced CSP, cyclic inverse WAG using water/methane, ECSP using methane/ethane, and CSP using methane. ECSP using methane/propane outperforms surfactant-enhanced CSP and cyclic inverse WAG only if a relatively larger propane-slug size (20 to 35%) is injected. The cyclic inverse WAG (using an offset to the CSP well to repressurize the sandpack by water before conducting methane CSP) significantly improves the recovery and its rate, and it reduces the gas requirement. Also, injecting an oil-soluble foaming surfactant before methane enhances the CSP recovery factor (RF) and rate by one order of magnitude, making them comparable with those of ECSP using methane and a large slug of propane. In discussing these results, the significance of and the interplay between various recovery mechanisms in CSP, ECSP, and surfactant-enhanced CSP is highlighted in the order in which they occur during the injection cycle (viscous fingering, phase change and dissolution of solvent, diffusion and convective dispersion, and capillary mixing), soaking (solvent diffusion and mixing, oil swelling, and viscosity reduction), and the production cycle (foamy-oil flow, solution gas drive, and wellbore inflow). The results of this mechanistic analysis of CSP, ECSP, and surfactant-enhanced CSP during the injection, soaking, and production cycles render an improved paradigm for a holistic performance evaluation and understanding of cyclic solvent-injection processes. The interplay between various observed recovery mechanisms reveals various advantages of ECSP, surfactant-enhanced CSP, and cyclic inverse WAG over traditional CSP.

Gas Pressure Cycling (GPC) and Solvent-Assisted Gas Pressure Cycling (SA-GPC) Enhanced Oil Recovery Processes in a Thin Heavy Oil Reservoir

In this paper, gas pressure cycling (GPC) and solvent-assisted gas pressure cycling (SA-GPC) were developed as two new and effective enhanced oil recovery (EOR) processes. Eight coreflood tests were conducted by using a 2-D rectangular sandpacked physical model with a one or two-well configuration. More specifically, two cyclic solvent injection (CSI), three GPC, and three SA-GPC tests were conducted after the primary production, whose pressure was declined in steps from Pi = 3.0 MPa to Pf = 0.2 MPa. It was found that the CSI tests had poor performances because of the known CSI technical shortcomings and an additional technical issue of solvent trapping found in this study. Quick heavy oil viscosity regainment resulted in the solvent-trapping zone. In contrast, C3H8-GPC test at a pressure depletion step size of ∆PEOR = 0.5 MPa and C3H8-SA-CO2-GPC test at ∆PEOR = 1.0 MPa had the highest total heavy oil recovery factors (RFs) of 41.9% and 36.6% of the original oil-in-place (OOIP) among the two respective series of GPC and SA-GPC tests. The better performances of these two tests than C3H8- or CO2-CSI test were attributed to the effective displacement of the foamy oil toward the producer in the two-well configuration. Thus the back-and-forth movements of the foamy oil in CSI test in the one-well configuration were eliminated in these GPC and SA-GPC tests. Furthermore, C3H8-GPC test outperformed C3H8-SA-CO2-GPC test in terms of the heavy oil RF and cumulative gas-oil ratio (cGOR) because of the formation of stronger foamy-oil flow and the absence of CO2, which reduced the solubility of C3H8 in the heavy oil in the latter test. In summary, different solvent-based EOR processes were ranked based on the heavy oil RFs as follows: C3H8-GPC &gt; C3H8-SA-CO2-GPC &gt; CO2-GPC &gt; C3H8-CSI &gt; CO2-CSI.

A review of in situ upgrading technology for heavy crude oil

With the growing demand of oil worldwide, heavy oil has increasingly become vital in the world energy market. However, further development of heavy oil reservoirs are limited by regular enhanced oil recovery (EOR) methods. In situ upgrading technology provides potential for the development of heavy oil and bitumen reservoirs. This study reviews three categories of in situ upgrading methods: solvent-based, in situ combustion (ISC), and catalytic. Solvent-based methods, including cyclic solvent injection, vapor extraction, and hybrid processes, have recently received attention and have been progressed in both laboratory and field applications. However, high solvent costs in relation to the low price of heavy oil have continued to limit the field applications of these techniques. ISC, which may have the potential to develop particularly harsh reservoirs with extremely viscous crude oil, involves complex reaction mechanisms and consists of three main steps: oxidation, combustion, and gas flooding. Yet, complex operating conditions and a low success rate have restricted its application. Catalytic methods, which have demonstrated the potential to refine and upgrade crude oil in a more economic and environmentally friendly way, are often accompanied by conventional thermal EOR methods, such as steam flooding and ISC, and involve a series of hydroprocessing or hydrotreating reactions, such as hydrocracking, hydrodesulfurization, hydrodenitrogenation, hydrodeoxygenation, and hydrodemetallization. However, the high cost and complexity of the reaction mechanisms have limited their applications.

Experimental Study of Heavy Oil Recovery Mechanisms during Cyclic Solvent Injection Processes

Summary The cyclic solvent injection (CSI) process has recently shown to be a promising method for enhanced heavy oil recovery in Canada. Laboratory testing is often run before development of field pilots to assess the effect of parameters, such as solvent choice and process conditions, on the CSI response. However, differences between laboratory results vs. field applications have been observed. CSI laboratory studies work for only two to three cycles due to low incremental oil in subsequent cycles, whereas field pilots continue for years over multiple cycles. This experimental study is intended to capture the production mechanisms responsible for heavy oil production in CSI. Primary production and CSI tests were conducted using sandpack models saturated with live heavy oil of 9530 mPa·s viscosity. The experiments were conducted in horizontal and vertical mode injection at high- and low-pressure depletion rates using two solvent mixtures of CH4 and C3H8. The sandpacks were scanned after every cycle to analyze the evolution of gas and oil saturations using computed tomography (CT). Three cores were used to study the effect of several parameters: gravity forces, pressure depletion rate, solvent composition, and initial oil saturation on the performance of CSI processes. CSI cycles run after primary production in horizontal systems produced negligible incremental oil for both slow and fast drawdown rates due to the large void space and high free gas saturation inhibiting the pressure buildup to push the solvent-diluted oil. These CSI experiments were only initially successful in dead oil systems, in which the initial oil saturation was higher and appropriate pressure gradient was generated through fast depletion rates. During the vertical alignment, CSI cycles exhibited higher incremental oil recovery per cycle. Slow depletion cycles were more efficient in terms of pressure and incremental recovery per cycle; however, faster depletion cycles performed better as a function of time. These results are more in line with the repeated recoveries measured over multiple cycles in field CSI pilot studies. More volume of diluted oil was drained out of the core when the solvent mixture with higher propane (C3H8) content was injected. These results demonstrate the importance of gravity drainage in the CSI process and its significance on successful oil recovery rates. This study illustrates the limitations of previous horizontal laboratory tests and shows an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.

Analysis of non-equilibrium foamy oil flow in cyclic solvent injection processes

Non-equilibrium phase behavior (i.e., solvent dissolution/exsolution) and solvent transport are key recovery mechanisms in many non-thermal post-CHOPS (Cold Heavy Oil Production with Sand) processes, such as cyclic solvent injection (CSI), in western Canada and Venezuela. Foamy oil refers to the non-equilibrium phenomenon where gas bubbles are dispersed in the oil phase during exsolution, resulting in a decrease in oil viscosity. This is a well-recognized behavior in heavy oil primary production (CHOPS) and has implications in recovery during CSI. In this paper, a mechanistic simulation model is constructed based on a set of pressure depletion experiments, and the calibrated model is used to analyze the effects of solvent compositions and operating schedules on recovery efficiency.First, a series of pressure depletion tests are conducted using both bulk fluid systems and porous media to examine the non-equilibrium release of solvent (CO2, CH4 and C3H8) from saturated live oil during the production cycles of CSI. The non-equilibrium live oil viscosity profile is inferred from calibrated NMR measurements. Different combinations of solvent mixtures and pressure depletion rates are tested to examine their impacts of gas exsolution. Next, a detailed mechanistic simulation model is constructed and calibrated against a set of experimental measurements. A fluid model is defined based on equilibrium saturation pressures and gas-oil ratios corresponding to different combinations of solvent and dead oil. A viscosity model is formulated using measurements at different temperatures and solvent-oil mixtures. Reaction kinetics is implemented to represent the non-equilibrium exsolution of gas from solution gas to bubble gas and free gas in foamy oil flow.The simulation model shows the response of viscosity and oil production as a function of pressure for a porous medium saturated with live oil in a single depletion cycle. The model predicts a delay in free gas formation in the sand pack, as observed in the experimental program. Propane-based and carbon dioxide-based solvent mixtures exhibit significant foamy oil characteristics, enabling the oil viscosity to remain close to its live oil value even with pressures that are much lower than saturation pressure. The rates of gas exsolution and oil production are strongly dependent on the pressure depletion schedule, as well as the solvent compositions and properties.Although a number of models were developed in the past to describe the dissolution of solvent and bubble formation, calibration of these models against actual observations remain challenging. The model developed in this study is calibrated and corroborated by detailed experimental observations; hence, it can be further scaled up to study recovery performance at the pilot or field scales. Many existing solvent technologies suffer from low production rates due to limited solvent/heavy oil interaction. Improving our understanding of solvent dissolution/exsolution under different pressure conditions would aid in the design of operating strategies (e.g., pressure depletion and solvent injection schemes) for enhanced solvent/oil mixing and transport.