Cyclic Solvent Injection Process Research Articles

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.

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.

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.

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.

Determination of Concentration-Dependent Gas Diffusivity in Reservoir Fluid Systems

One of the major mechanisms associated with gas injection to recover heavy oil is the molecular diffusion of gas, which reduces the viscosity of heavy oil. Numerous efforts have been made to estimate the diffusivity of such gas in heavy oil by assuming the gas diffusivity as a constant. Meanwhile, only limited attempts have been made to determine the concentration-dependent diffusivity from pressure decay test data by using analytical, semi-analytical, or numerical methods. In this study, a generalized methodology has been developed to determine the diffusivity of gas (e.g., CO2) in a heavy oil as an exponential function of gas concentration with consideration of oil swelling. More specifically, non-intrusive experimental measurement data obtained by dynamic volume analysis (DVA) are used to compute the concentration-dependent diffusivity by integrating the finite element method (FEM) with the particle swarm optimization (PSO) algorithm. Subsequently, concentration-dependent diffusivity of CO2 from the DVA experimental data can be obtained in the form of the exponential function and then converted to the function of liquid-phase viscosity. Then, the pressure decay test data are employed to determine the optimal diffusivity among the solutions of concentration-dependent CO2 diffusivity obtained from DVA test data by using Hayduk and Cheng’s formula together with the FEM. The final solution provides two coefficients for the exponential model and an exponent as well as a coefficient for Hayduk and Cheng’s model. It is found that the obtained concentration-dependent diffusivity of CO2 is reasonable and accurate as well as it can be converted for use at different pressures and temperatures through the determined coefficient and exponent for Hayduk and Cheng’s equation together with a linear relation between the natural logarithm of heavy oil viscosity and the dissolved gas concentration. Meanwhile, such findings in this study may be able to contribute to improve the gas injection projects such as vapor extraction or cyclic solvent injection processes.

Mechanics of Foamy Oil during Methane-Based Cyclic Solvent Injection Process for Enhanced Heavy Oil Recovery: A Comprehensive Review

Summary Foamy oil flow is a commonly encountered drive mechanism in the primary production (depletion of naturally methane-saturated heavy oil) and secondary stage (cyclic gas—mostly methane—injection after primary production). In the former, among other important parameters, pressure depletion rate has been reported to be the most crucial parameter to control the process. In the latter, type and amount of the gas (also described as “solvent”) and application conditions such as soaking time durations and depletion rates are critical. The cornerstone of the foamy oil behavior relies on its stability, which depends on parameters such as oil viscosity, temperature, dissolved gas ratio, pressure decline rate, and dissolved gas (solvent) composition. Although the process has been investigated and analyzed for different parameters in the literature, the optimal conditions for an efficient process (mainly foamy oil stability) has not been thoroughly understood, especially for the secondary recovery conditions (cyclic solvent injection, CSI). In this paper, internal and external gas drive mechanisms for foamy oil performance are reviewed in detail. The optimal conditions of the applications were compiled and listed for different primary production and secondary recovery stages. Combination of methane with other gases as a CSI practice was also discussed to accelerate the process and reduce cost in an effort to improve efficiency. It is reported that combining methane injection with air as a secondary recovery method can save up to 51% of solvent gas.

Mathematical modeling of dynamic mass transfer in cyclic solvent injection

In a cyclic solvent injection (CSI) process, a vaporized solvent is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is increased and decreased periodically. This causes a dynamic fluid flow across a heavy oil–solvent mixing zone, leading to a convective mass transfer in addition to molecular diffusion. This study aims at modeling the effect of convection on the heavy oil–solvent mass transfer in the transition zone of the CSI process. A convection–diffusion mathematical model is developed and semi-analytically solved. It consists of two sub-models, a pressure model and a solvent concentration model, and considers realistic viscosity and convection velocity profiles. Three practical injection and production schemes are modeled in order to provide some meaningful suggestions for the CSI field applications from the viewpoint of mass transport. Results show that convection can significantly enhance solvent dissolution during the injection period and accelerate solvent exsolution during the production period. In addition, it is also found that a smaller solvent injection rate does not make a big difference in the solvent dissolution for a long injection period. Moreover, during the production period, solvent exsolution induces a sharp pressure gradient that is believed to be a key factor for foamy-oil flow. It causes a viscosified front and solvent “inverse” diffusion that results in several rounds of foam-oil flow. Finally, a considerable amount of solvent remains dissolved in heavy oil at the end of the production period when the reservoir pressure is depleted, and is difficult to be retrieved in a short time.

Laboratory study of cyclic liquid solvent injection process for heavy oil recovery through computed tomography

The cyclic solvents injection has been considered for years as an improved non-thermal enhanced oil recovery method for the recovery of heavy oil, which includes three stages: injection, soaking, and production. This paper describes a laboratory study with Computed Tomography and Nuclear Magnetic Resonance of a cyclic solvent injection process in a porous medium, using naphtha as a liquid diluent to recover a Colombian heavy oil in a porous medium at 84 °C. The core was scanned during the soaking time to determine the expansion behavior of the mixing zone by analyzing the density profiles obtained after each scan. It was also scanned after the production stage to observe the distribution of saturation in the porous medium after each cycle. Finally, the fluids recovered from porous medium were taken to a nuclear magnetic resonance equipment to determine the recovery factor.

An experimental study on the oil-soluble surfactant-assisted cyclic mixed solvent injection process for heavy oil recovery after primary production

Cyclic solvent injection (CSI) has shown a significant potential to enhance heavy oil recovery after primary production. However, the principal limitation of this process is quick solvent liberation due to the high gas mobility and oil viscosity regainment during the production period. In this study, a novel variation of CSI, called oil-soluble surfactant-assisted cyclic mixed solvent injection (OSFA-CMSI), is proposed to overcome these limitations. During this process, an oil-soluble surfactant and a specially designed solvent mixture (produced gas and propone) are cyclically injected into reservoirs in two separate slugs. The designed solvent mixture renders the process technically sound and effectively viable, and the surfactant induces the formation of an effective foamy oil flow by dispersing the released or undissolved gaseous solvent during the production period. A series of experiments were performed by using a patented core holder to prove the viability of the OSFA-CMSI process and to study the effects of the solvent composition, pressure depletion rate, wormhole presence, and confining pressure on the OSFA-CMSI performance. The experimental results show that the selected oil-soluble surfactant FlourN™ 20158M can create an effective foamy oil phenomenon in heavy oil, which contributes to the enhanced oil swelling effect and gas dispersion that delays the formation of free gas. The OSFA-CMSI process is a potentially feasible method for heavy oil recovery after primary production, especially for post-cold heavy oil production with sand reservoirs. The most efficient test improves oil recovery by 41.64% of the original oil in place (OOIP) compared to that of the traditional CSI process. There is an optimal C3H8 content in the solvent mixture (46 mol% in this study), beyond which the performance of the OSFA-CMSI process worsens. The solvent mixture should be injected at or near its dew point without any liquefaction to achieve maximum solubility and generate an effective foamy oil flow. Increases in the pressure depletion rate and confining pressure are beneficial when using OSFA-CMSI to enhance the oil recovery factor over a short production time but result in lower final oil recovery factors.

A comparison study between N-Solv method and cyclic hot solvent injection (CHSI) method

Steam injection is one of the major recovery methods to exploit heavy oil reservoirs. Replacing steam with hot solvent is an innovative idea to immensely decrease environmental pollution and energy consumption in steam-based recovery methods. The current hot solvent injection method attracts attention to the vapor solvent extraction (VAPEX) process. In comparison with the VAPEX process, cyclic solvent injection (CSI) process has been acknowledged as a high oil rate method due to the driving force of foamy oil flow. Hot solvent injection method is potentially applicable in the CSI process, which may increase the oil production rate and avoid the disadvantage of the VAPEX method. In this study, two experiments have been conducted to compare the production performance between the hot solvent-based CSI method and the hot solvent-based VAPEX method. The hot solvent-based CSI method is named the cyclic hot solvent injection method (CHSI). The hot solvent-based VAPEX method refers to the N-Solv method. N-solv is a patented method where the solvent is injected at the dew point temperature under the reservoir pressure condition. Due to the temperature difference between the reservoir and injected solvent, the injected solvent will condense in the reservoir and the condensed solvent will generate latent heat that can heat the reservoir chamber and thus reduce the oil viscosity (Nenniger and Gunnewiek, 2009). In this study, the N-Solv method has been studied in a laboratory test for the first time in N-Solv research history (Cao, 2011; Nenniger, 2005; Nenniger and Gunnewiek, 2009).According to experimental results, either of the two methods demonstrates some advantages in comparison with the other method from various aspects. From the production performance point of view, the recovery factor of the CHSI method is nearly 10% higher than that of the N-Solv method. The longer high oil rate period of the CHSI method in contrast with the N-Solv method indicates that the foamy oil behavior is more beneficial to the oil production compared with the gravity drainage and the solvent diffusion effect. In addition, it is shown from the solvent chamber growth difference that the gas flooding effect can enhance oil production in the CHSI process because the oil from gas-flooded area in the reservoir is clearly extracted out. However, according to the production GOR data, CHSI is a solvent-consuming method where a tremendous volume of free gas tends to be trapped in the solvent chamber as a result of gas flooding, which may offset the positive effect of gas flooding due to large consumption of solvent. The phenomenon of free gas trapping has not been found in the N-Solv process.

Design of field‐scale cyclic solvent injection processes for post‐CHOPS applications

AbstractOil recovery factors in cold heavy oil production with sand (CHOPS) are typically lower than 15 %. Solvent‐aided processes, such as cyclic solvent injection (CSI) are common post‐CHOPS approaches, where wormhole networks could offer increased reservoir contact. However, grid block sizes in field‐scale simulations are much larger than the wormhole scale and large‐scale dispersivity values are assigned arbitrarily based on history matching. This work implements a statistical scale‐up workflow that facilitates the construction of coarse‐scale models for CSI simulation, whose relevant parameters are calibrated against simulation results using high‐resolution wormhole networks. The formulated workflow can be integrated with commercial reservoir simulators to effectively simulate solvent processes at multiple scales.Multiple injection scenarios are analyzed. Extended soaking periods may positively impact the ultimate recovery with a slower decline at later times, while a lower initial rate is observed. Interestingly, when an economic limit is imposed, the optimal soaking time is not necessarily the longest one. It depends on the trade‐off between extracting additional oil recovery at late times versus producing at a higher rate at early times. The analysis also reveals that the initial cycles contribute the most to the final recovery. In addition, when the amount of solvent available is limited, the results would support the strategy of injecting all the solvent in 1 single cycle, with an extended soaking period, rather than performing shorter consecutive cycles.

Experimental investigation of cyclic solvent injection based on mixture solvent of carbon dioxide and propane

Cyclic solvent injection (CSI) process has been suggested as the most effective and promising solvent-based method in some heavy oil reservoirs in which thermal-based methods are not suitable due to economic constraints and environmental concerns. In solvent-based methods, many studies indicated that pure propane can more significantly reduce the viscosity of crude heavy oil than methane or carbon-dioxide, especially when the propane is injected with gaseous phase under the pressure slightly lower than its dew point. Actually in field application, to achieve a great effect of viscosity reduction with gaseous solvent, the mixture solvent rather than pure propane is injected to guarantee the saturation pressure of injected solvent higher than the reservoir pressure. However, most current studies have been done only by the pure solvent for investigating mechanisms of the CSI process. Therefore, it’s very necessary to conduct further investigation on CSI process by the mixture solvent.In this study, three CSI tests by the mixture solvent (60% mol. CO2 and 40% mol. C3H8) with the decline rate of 12.5 kPa/min, 5.0 kPa/min and 1.0 kPa/min respectively were conducted in a sand-pack model with the diameter of 15.24 cm and the length of 30.48 cm. Three pure propane CSI tests from previous study, also with the decline rate of 12.5 kPa/min, 5.0 kPa/min and 1.0 kPa/min respectively, were used to perform comparison analyses with three mixture solvent CSI tests for better understanding driving mechanisms of the CSI process. Comparison results show that pure propane tests had larger recovery factor and average oil production per single cycle than mixture solvent tests. The amount of the propane diffusing into the heavy oil in mixture solvent tests was lower than that in pure propane tests because of the negative effects of the carbon-dioxide. The asphaltene precipitation and production time significantly impacted the recovery factor of diluted oil in mixture solvent tests. It’s indicated that the effects of the decline rate on the asphaltene precipitation were more sensitive in mixture solvent tests. As well as in pure propane tests, the decline rate can also be optimized in mixture solvent tests. It’s suggested that 5.0 kPa/min is the optimal decline rate with the largest recovery factor and average production per single cycle in mixture solvent tests. In addition, hysteresis of the declined pressure of the sand-pack model led to a high pressure difference and intensive oil production between 300 kPa and 200 kPa in the 1.0 kPa/min mixture solvent test.

Characterization of gas-oil flow in Cyclic Solvent Injection (CSI) for heavy oil recovery

Cyclic Solvent Injection (CSI) has emerged as an effective follow-up process to the primary cold production, namely, Cold Heavy Oil Production with Sand (CHOPS). In this recovery process, the solvent is designed to maintain a strong nature of gas at in-situ conditions. As a result, the porous medium is spatially divided into two zones with differing fluid properties, which are gas zone, also called solvent chamber, and heavy oil zone. The CSI process is governed by the gas-oil flow as the solvent chamber is predominated by free gas-oil flow and the heavy oil zone by dispersed gas-oil flow (i.e. foamy oil flow).The gas-oil flow in CSI considerably differs from that in heavy oil solution gas drive, and therefore, needs to be investigated separately. The differences mainly arise from the origin of free gas. In CSI, the free gas originates at the solvent chamber, whereas in heavy oil solution gas drive, it evolves from solution gas. The free gas, in accordance with where it originates, yields occurrence time and quantity that have different dependency on the pseudobubblepoint pressure of oil. Consequently, the gas-oil flow in CSI results in the characteristics far more susceptible to the quantity of free gas and the nonequilibrium nature of foamy oil than heavy oil solution gas drive.This study is aimed at characterizing the gas-oil flow in CSI under the effects of pressure depletion rate as well as the solvent chamber. To fulfill this objective, the gas-liquid relative permeability curves were inferred with the use of numerical simulations and modified fractional flow models. The numerical simulations were carried out to history-match seven lab-scale CSI tests performed at different pressure depletion rates. The modified fractional flow models were applied to describe the foamy oil flow. The distinct characteristics of the gas-oil flow were examined based on sensitivity analysis and comparison to the previous findings on heavy oil solution gas drive.The results suggest that, at low pressure depletion rates, the gas-oil flow in CSI yield the characteristics that have also been observed in heavy oil solution gas drive. At sufficiently high pressure depletion rates, however, the free gas that exists even when the dispersed gas bubbles are immobile results in the different behavior of critical gas saturation and gas phase mobility. The solvent chamber misleads the gas-liquid relative permeability curves if the critical gas saturation is too high to properly describe the simultaneous flow of free gas and foamy oil. The solvent injectivity is also affected by the pressure depletion rate due to the foamy oil that has remained as unproduced in the solvent chamber during a previous production period.