Coinjection Of Steam Research Articles

Temperature distribution considering the film-wise condensation and its impact on multi-stage oil production during the co-injection of steam-CO2

The co-injection of steam and CO2 into oil sands reservoirs has proved to be one of the most efficient and environmentally friendly methods to produce bitumen. Nevertheless, the condensation mechanism of steam in the reservoir is film-wise condensation under the effect of CO2, which reduces the heat transfer efficiency of steam. To obtain accurate oil production during the co-injection of steam-CO2, it is critical to predict the temperature distribution considering the film-wise condensation and clear its impact on oil production. In this study, laboratory experiments with different injectors were conducted to clear the effect of film-wise condensation on temperature distribution in the formation. Then, a mathematical model considering film-wise condensation was established to predict the temperature distribution and oil production, compared with the measured experiment result and multi-stage oil production from field data. Finally, the effect of temperature distribution on multi-stage oil production was analyzed through different injection volumes. The results indicated that the impact of film-wise condensation inhibits the development of the steam zone(Ts) but explicitly expands the hot water zone(Ts ∼ Tr). Moreover, the different injection components affect film-wise condensation, and CO2 has a more pronounced effect, whereas steam has little impact on the hot water zone despite its significant effect on steam zone expansion by weakening the film-wise condensation. Furthermore, the oil production exhibits the multi-stage characteristic controlled by different heating zones(the steam zone and the hot water zone), such that the steam zone contributes to higher oil production in the rising stage, and a larger hot water zone induces a longer life of the rising stage and the stable stage.

A Study of Dimethyl Ether-Steam Coinjection Using a Large-Scale Physical Model

Summary Dimethyl ether (DME) as a water-soluble solvent has been studied as a potential additive to steam for improving the energy efficiency of steam-assisted gravity drainage (SAGD). The main objective of this research was to study in-situ flow characteristics and energy efficiency of DME-SAGD using a large-scale physical model. Results from DME-SAGD were compared with the control experiment of SAGD with no solvent injection using the same experimental setup. The main novelty of this research lies in the experimental data that demonstrated enhanced bitumen drainage by DME-SAGD in comparison with SAGD. The experiment was conducted in a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.22 m, which contained a sandpack with a porosity of 0.34 and a permeability of 5.0 darcies. The DME-SAGD experiment used a DME concentration of 10 mol% and a steam coinjection rate of 27.6 cm3/min [cold-water equivalent (CWE)] at 3000 kPa. Temperature distributions within the sandpack, along with injection and production histories, were recorded during the experiment. Subsequently, numerical simulations were performed to history match the experimental data, and the calibrated simulation model was used to analyze the details of compositional flow characteristics. Results showed that the 10 mol% DME-SAGD experiment yielded a recovery factor (RF) of 92.7% in 4.2 days, and the SAGD experiment yielded an RF of 68.6% in 6.0 days; for both experiments, the first 2 days were the preheating and the steam-only injection (SAGD) stages. The peak rate of bitumen production was 43.8 mL/min in the DME-SAGD experiment, which was more than twice greater than the peak rates observed in the SAGD experiment. The substantially increased rate of bitumen production resulted in a cumulative steam/oil ratio in DME-SAGD that was less than half of that in SAGD. Analysis of experimental results indicated that the solubility of DME in the aqueous and oleic phases caused different flow characteristics between DME-SAGD and SAGD. For example, the oleic and aqueous phases were more uniformly distributed in the sandpack in the former. Simulations indicated that DME-SAGD had a greater distribution of grid-scale inverse mobility ratio and increased oleic-phase mobilities in comparison with SAGD.

The macro and micro analysis on EOR mechanisms during steam and solvent thermal recovery in heavy oil reservoirs

Using only pure steam as a driving medium in heavy oil reservoirs may result in a low oil recovery factor. Solvent is a good oil displacement medium that can be dissolved in heavy oil, which can greatly reduce the viscosity and improve the mobility of heavy oil. Therefore, the method of solvent assisted displacement and drainage has the unique advantage during steam flooding. In this paper, a quantitative method is proposed to choose appropriate solvents. Then a series of experiments are carried out, including oil displacement experiment to measure oil displacement efficiency, 2D visualization experiment to analyze the sweep efficiency and remaining oil distribution, and 3D scaling physical simulation setting with bottom water condition, which are used to analyze production performance, the expanding characteristics of steam chamber and study reservoir fluid distribution. The results show that steam moving upwards to heat and drive heavy oil to production well under the action of displacement and drainage. In a heavy oil reservoir with thin bottom water, if only steam is injected into reservoir, then there is no obvious stage of stable oil production and the oil recovery factor is only 32.7%. However, when solvent and steam are co-injected into reservoir, the stage of stable oil production maintaining about 0.6 PV and the oil recovery factor is 43.2%. During steam and solvent flooding, solvent can greatly reduce the oil viscosity to improve its mobility; meanwhile solvent can promote the expansion of steam chamber. The co-injection of steam and solvent can obviously expand steam chamber and increase oil recovery factor in heavy oil reservoirs (even connecting with bottom water layer). The method of steam and solvent flooding further enriches EOR technologies of thermal recovery in heavy oil reservoirs.

Experimental study of the distillation mechanism during coinjection of flue gas and steam for heavy oil development

As an industrial waste gas, flue gas achieves a favorable performance in assisting steam to develop heavy oil, where steam distillation plays a crucial role. However, there are few studies of the physical changes in heavy oil and the distillation mechanism during flue gas-steam coinjection, which seriously inhibits flue gas applications in oil fields. Herein, the comparative steam and flue gas + steam distillation experiments (superheat of 120 °C) and flue gas + steam distillation experiments at three superheat levels (0 °C, 48 °C and 100 °C) were conducted using a high-temperature and high-pressure distillation kettle. The carbon number distribution of distillates during distillation and heavy oil properties before and after distillation were compared and analyzed. The results showed that the effect of flue gas on steam distillation was significant, and the flue gas + steam distillation yield reached 20.24%, which was 3.88% higher than that of pure steam. With increasing steam superheat during flue gas–steam coinjection, the carbon number distribution range of the distillates gradually expanded, the distillation yield gradually increased, and the flue gas + steam distillation yields under the three superheat levels were 13.5%, 15.49% and 16.59%, respectively. Compared to pure steam distillation levels, resin hydrocracking and allosterism in the flue gas + steam distillation process were intensified, the resin content decreased, and the saturate, aromatic and asphaltene contents increased. Moreover, the heat exchange and heat utilization rates between steam and crude oil were improved under the flue gas effect, and the upper limit of the distillate carbon number significantly increased. The research results are significant for further refining the mechanism of flue gas enhanced steam development of heavy oil.

Study on Flow Characteristics of Flue Gas and Steam Co-Injection for Heavy Oil Recovery

Flue gas is composed of N2 and CO2, and is often used as an auxiliary agent for oil displacement, with good results and very promising development prospects for co-injection with steam to develop heavy oil. Although research on the oil displacement mechanism of flue gas has been carried out for many years, the flow characteristics of steam under the action of flue gas have rarely been discussed. In this paper, the flow resistance and heat transfer effect of flue gas/flue gas + steam were evaluated by using a one-dimensional sandpack, a flue gas-assisted steam flooding experiment was carried out using a specially customized microscopic visualization model, and the microscopic flow characteristics in the process of the co-injection of flue gas and steam were observed and analyzed. The results showed that flue gas could improve the heat transfer effect of steam whilst accelerating the flow of steam in porous media and reducing the flow resistance of steam. Compared with pure steam, when the volume ratio of flue gas and steam was 1:2, the mobility decreased by 2.8 and the outlet temperature of the sandpack increased by 35 °C. This trend intensified with an increase in the proportion of flue gas. In the microscopic oil displacement experiments, the oil recovery and sweep efficiency of the flue gas and steam co-injection stage increased by 4.7% and 32.9%, respectively, compared with the pure steam injection stage due to the effective utilization of blocky remaining oil and corner remaining oil caused by the expansion of fluid channels, the flow of flue gas foam, and the dissolution and release of flue gas in heavy oil.

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

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

Insights into in-situ upgrading of bitumen in the hybrid of steam and combustion process: From experimental analysis aspects

In situ combustion (ISC) has been evaluated as a follow up process in the steam injection process for heavy oil and bitumen recovery. Except for providing energy or heat to reduce bitumen viscosity, in situ upgrading of bitumen is another advantage of ISC process. In situ upgrading of bitumen through co-injection of steam and oxygen is evaluated in this work. Three different types of laboratory experiments, including one static thermal cracking experiment, one ramped temperature oxidation (RTO) experiment, and one combustion tube test, were performed to examine the produced oil properties and the potential of bitumen in situ upgrading. A comprehensive analysis of produced oil properties and gas composition was performed. Bitumen was significantly upgraded in the thermal cracking experiment at a temperature of 430 °C, in which Saturates fraction increased to 56%, while Resin and Asphaltene fractions reduced to 6.7% and 6.8%, respectively. The thermal cracking of Resin and Asphaltene contribute to the production of the light oil and gases, leading to the upgrading of the bitumen. Dynamic properties of produced oil were measured in the RTO and combustion tube test in terms of produced oil viscosity, density, boiling point temperature distribution, and produced oil compositions, etc. In the RTO test, the extent of bitumen upgrading is greater with the increase of temperature, further proving that the high temperature generated by the combustion front is able to effectively crack the bitumen. Furthermore, the lack of light hydrocarbon in the produced oil indicates light hydrocarbon participates in the high temperature oxidation reactions. Different from thermal cracking experiment and RTO test results, combustion tube test results indicated that the bitumen was slightly upgraded in late stage of the combustion tube test and most produced bitumen are similar with original bitumen. By examining the temperature distribution along the combustion tube, it is found that upgraded bitumen cannot be effectively displaced to the producer. This implies the limitation of in situ upgrading in the conventional in situ combustion process. Proper well configuration was recommended for the future field application of the hybrid steam and combustion process to achieve the high oil recovery factor and partial in situ upgrading of bitumen.

Multi-Component Thermal Fluid Injection Performance in Recovery of Heavy Oil Reservoirs

Field observations discern that the oil production rate decreases substantially and water cut increases rapidly with the increase of steam injection cycles. Compared with steam drive, the advantage of flue gas (also called multi-component thermal gas) co-injection with steam is that flue gas can increase the reservoir pressure and expand the heating chamber. In this paper, the flue gas generated by fuel burning in the field was injected with steam to improve heavy oil recovery. This technique was investigated in the large laboratory 3D model and implemented in the field as well. The huff-n-puff process efficiency by flue gas, steam, and flue gas–steam co-injection was compared in the experiments. The field practice also demonstrated that the addition of non-condensable gas in the steam huff-n-puff process recovered more oil than steam alone. The temperature profile in the wellbore with flue gas injection is higher than that with steam injection since the low thermal conductivity of N2 reduces the heat loss. With the increase of stimulation cycles, the incremental oil recovery by flue gas injection declines significantly.

Steam alternating non-condensable gas injection for more heavy oil recovery

Recent studies and field operations show that co-injection of steam and non-condensable gas could reduce the steam-oil ratio significantly, which means the steam and gas push process (SAGP) could be more environmentally friendly than the conventional steam-assisted gravity drainage (SAGD) process. However, this modification may eventually cause a drop in the cumulative volume of produced oil. In this paper, we develop a technique to overcome the adverse impact of SAGP on the final oil recovery: this technique employs alternate steam and a mixture of steam and non-condensable gas injection into the viscous oil reservoir to take advantage of a high steam chamber volume, pushing pressure at the reservoir top and lower heat loss to overburden rocks, simultaneously. The technique (so-called SANG) is examined numerically in a reservoir with average properties from Athabasca, and the results are compared to the conventional SAGD and SAGP. Effects of changing reservoir properties and operating conditions on the performance of the SANG together with a cost-benefit analysis and CO2 emissions are elucidated. Based on the results, the SANG would effectively improve the performance of the thermal gravity process within viscous oil reservoirs and, provided it is validated, it can replace the conventional SAGD and SAGP.

Flue gas and nitrogen co-injection during cyclic steam stimulation in heavy oil reservoirs: a numerical evaluation

In this study, steam co-injection with flue gas or N2 was numerically reproduced to determine the best gas composition to be deployed in a Colombian heavy crude oil, using a commercial reservoir simulation software. The oil mixture was characterized via EoS parameters, withtuning average errors of 5%. Injection conditions were evaluated with thermal simulations to analyze the response in oil production, allowing to find a deployment strategy having the highest recovery with the lowest gas injection volume. Results agree with experimental observations regarding the starting times for co-injection and help to narrow the uncertainty range where gas and steam co-injection is asuitable recovery technique in heavy oil reservoirs. The study showed that the incremental oil recovery factor can be enhanced, at least, in 40% when optimizing the deployment of steam and flue gas co-injection for the well studied here

Steam Conformance along Horizontal Well with Different Well Configurations of Single Tubing: An Experimental and Numerical Investigation

Summary Dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can effectively delay the occurrence of steam fingering and homogenize the steam injection profile along the horizontal wellbore. In this paper, first, we built a cylindrical wellbore physical model to experimentally study the steam injection profiles of a single-pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along the horizontal wellbore with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semianalytical model for the gas/liquid two-phase flow in the horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated. Experimental results indicated that under the same steam injection condition, an application of dual-pipe well configuration can significantly enhance the oil drainage volume by approximately 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable mass flowing behavior and pressure drops, the wellbore segment close to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along the wellbore. Compared with a pure steam injection process, the coinjection of steam and noncondensable gas (NCG) can improve the effective heating wellbore length by more than 25%. This model is also applied to predict the steam conformance of an actual horizontal well in Liaohe Oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation.

2-D physical model experimental study of ethyl acetate and steam co-injection for in-situ bitumen recovery

In this work, we evaluate ethyl acetate (EA) as a solvent for bitumen recovery using a 2-D sand-pack physical model for the first time. EA was considered for co-injection with steam due to the promising results obtained from our recent experimental phase behavior and reservoir simulation studies. Two experiments were conducted by co-injection of 10 and 20 vol% of EA with steam to evaluate expanding solvent steam assisted gravity drainage (ES-SAGD). An experiment was also conducted for the steam assisted gravity drainage (SAGD) as a reference case. The results showed that co-injection of EA increases the bitumen rate. Both ES-SAGD experiments showed a higher production rate compared to SAGD and the superiority of ES-SAGD. The results of 10 and 20 vol% EA co-injection revealed ~65% and ~75% bitumen recovery, respectively, compared to 50% in the case of the SAGD experiment. Co-injection of EA with steam also decreased the cumulative steam-oil-ratio (cSOR), which is desirable in bitumen recovery processes. ES-SAGD experiments reduced the cSOR by 1.5 to 2.5 units, which is 20 to 32% lower than SAGD. This reduction in cSOR results in significant energy savings and lower greenhouse gas emission intensity. The cumulative energy-oil-ratio was also measured, and the results showed that co-injection of EA decreases the energy-oil-ratio by 17–22% compared to SAGD. Moreover, it was observed that implementation of EA significantly reduces the water-oil emulsion stability, which is favorable in oil/water separation and treatments of the produced water.

A Multiphase, Multicomponent Reservoir-Simulation Framework for Miscible Gas and Steam Coinjection

SummaryThe solvent thermal resource innovation process (STRIP), a downhole steam-generation technology, has the capacity to show improved recovery factors with a significantly reduced environmental footprint compared with traditional thermal-enhanced-oil-recovery (TEOR) methods, most notably by delivering all the combustion heat to the pay zone. In this effort, a quarter-symmetry inverse-five-spot model and a multiphase, multicomponent reservoir-simulation framework were used to simulate the STRIP technology. Commercial simulators such as STARS - Thermal and Advanced Processes Reservoir Simulator [Computer Modelling Group Ltd. (CMG), Calgary, Alberta, Canada; CMG 2015b] often use the K-value approach to simulate TEOR. However, the method cannot simulate STRIP's carbon dioxide (CO2) and steam coinjection because the K-value method does not consider miscible gas injection. On the other hand, CMG's GEM - Compositional and Unconventional Simulator (CMG 2015a) includes the effects of miscible gases but does not provide comprehensive support for steam-injection processes, which are better handled by STARS. The novel simulation framework developed here leverages and combines the individual strengths of STARS (thermal features) and GEM (compositional features). In this framework, STARS simulated steam injection (but cannot directly simulate the effects of CO2) and was the governing model that synchronized temperature, pressure, and phase saturations for two parallel iterations of the GEM models (GEM-1 and GEM-2) at each timestep. Immiscible methane (CH4) was added to GEM models to maintain gas saturations equivalent to the STARS model. GEM-1 simulated hot-water and CH4 injection, but at increased rates to yield a pressure field and gas saturations equivalent to STARS. A final run of GEM-1 injected both CO2 and hot water and demonstrated the expected increase in oil production. Calibrated injection rates from GEM-1 were specified in GEM-2 to ensure equivalence of the pressure field. Next, the GEM-2 model also simulated hot-water and CH4 injection, but matched both water and oil productions along with oil saturations from the final GEM-1 run by altering relative permeabilities. Finally, the updated relative permeabilities were fed back to STARS, and iteration proceeded. Results from this framework were verified against a STARS steam-injection simulation. Finally, when considering coinjection of CO2, STRIP's superior performance was demonstrated through increased oil recovery and a lower steam/oil ratio (SOR).

Gas injection assisted steam huff-n-puff process for oil recovery from deep heavy oil reservoirs with low-permeability

The primary objective of this paper is to evaluate the possibility of using gas assisted cyclic steam stimulation for enhanced oil recovery in Xinjiang low-permeability heavy oil reservoirs. Several attempts have been made in this paper to improve the recovery efficiency, which include hydraulic fracturing horizontal wells, flue-gas and CO2 assisted cyclic steam co-injection, alternating injection of steam and CO2 scheme.To reduce the heavy oil viscosity and heat losses, cyclic flue-gas/steam injection method was proposed to make the gas penetrate deep into the formation and expand the steam chamber. Numerical simulations were carried out to examine the thermal process recovery efficiency of gas assisted steam injection in producing low-permeability heavy oil.The numerical results indicated that gaseous additives such as CO2 or flue-gas were feasible to improve the performance of cyclic steam injection. Without a gas blanket filling the chamber, the heat losses would become significant. Our research results indicated that the CO2/steam coinjection yielded higher oil recovery than flue-gas/steam and pure cyclic steam injection process. The thermal recovery performance is largely dependent on the contacted area of the steam with the oil reservoir. One reason is that the cumulative injected enthalpy of the CO2/steam is higher than flue-gas/steam and pure steam. Another reason is that the addition of nitrogen or carbon dioxide acts a role as thermal isolation to reduce the heat losses along the wellbore due to their low conductivity. The interaction of CO2 injection with reservoir heavy oil under temperature effect was discussed. Compared with the case without considering the temperature effect, the oil rate and cumulative oil recovery was higher for the case including the temperature dependent relative permeability.

Numerical investigation of the mechanisms in co-injection of steam and enriched air process using combustion tube tests

Co-injection of steam and enriched air process has great potential to recover oil sands especially when the oil sands are sufficiently preheated by SAGD. Before applying such a process in the field, it is important to understand the involved reaction kinetics and displacement mechanisms. In this work, numerical modelling has been performed to investigate the performance of co-injection processes, in which enriched air (95% oxygen) was introduced after a period of hot water and steam flooding. A group of combustion tube tests were conducted to measure combustion front velocity, temperature profiles along the tube, oil production, and produced gas compositions. A three-dimensional radial numerical model was developed using CMG STARS to reproduce the combustion tube test results. A reaction kinetic model derived from Ramped Temperature Oxidation (RTO) tests was incorporated and further tuned to match dynamic experimental measurements. The close agreement between the measured and simulated combustion characteristics, including combustion front velocity, temperature profiles, and gas production, confirms that the key chemical reactions have been captured. Also, there is a great match between the measured and simulated liquid production, indicating that the drive mechanisms have been adequately understood. It is found co-injection of steam and enriched air has the potential to improve oil recovery because ISC is able to recover a portion of the residual oil left behind by the steam flooding. Steam still plays a dominant role in displacement of bitumen. The ultimate recovery factor was about 90% of OOIP for the aforementioned combustion tube tests. Using enriched air concentration of 12 to 35 vol.%, the steam front propagated faster than the combustion front, the velocity of which is controlled by the fuel consumption rate and oxygen injection rate. Even at low oxygen injection rates, high temperature oxidation (HTO) was observed. It is suggested that high initial temperature for co-injection of steam and enriched air helps reduce the amount of low temperature oxidation (LTO) and therefore decreased coke deposition, leading to higher combustion front velocity and stable high temperature combustion. The reaction model is able to reproduce all measured results and represent all of the aforementioned phenomena.

Disposal of flue gases in oil reservoirs with high-viscosity oil in order to increase oil recovery and improve the environmental situation

The reserves of highly viscous oils and natural bitumen are several times higher than the stocks of light oils. In the development of such oils by thermal methods, steam is produced, the development of which is accompanied by significant emissions into the atmosphere of flue gases, including carbon dioxide. According to estimates, the extraction of high-viscosity oils annually releases about 34.5 million tons of carbon dioxide into the atmosphere. However, carbon dioxide emissions from steam generation can be reduced to zero by injecting flue gases along with steam into the formation. In addition to environmental benefits, the technology of co-injection of water vapor and combustion gases (nitrogen and carbon dioxide) has a complex (thermal and physico-chemical) effect on the formation with a synergistic effect. The article is devoted to the analysis of the mechanisms affecting the increase in oil recovery during the co-injection of steam with flue gases, the description of equipment for the injection of flue gases into the reservoir, as well as the analysis of field experience in using this technology. The calculations for one of the fields of high-viscosity oil show the high efficiency of co-injection of water steam with flue gases.

Nanoparticles as Foam Stabilizer for Steam-Foam Process

Summary Steam foams have been considered effective additives for unconventional oil-recovery processes. Conventionally, for steam-foam applications, chemical additives are injected with steam. However, this procedure can have serious challenges because of poor thermal stability of additives and high volume of additives loss caused by adsorption to the rock surface. To overcome these limitations, nanoparticles can be used as novel additives to improve generation and stabilization of the foams for steam-foam applications. In this study, silica nanoparticles in synergy with surfactants have been used as steam additives. Dynamic light scattering (DLS), a foam-height test using N2 at reservoir conditions, and thermal-stability analysis were designed to measure nanoparticle size distribution in brine, foamability, and thermal stability of the additive solutions, respectively. Subsequently, coreflooding tests were performed to evaluate the synergistic effect of nanoparticles and surfactants on the foam performance and oil recovery. We observed an optimal ratio of nanoparticle and surfactant that yields the best foam-generation performance in bulk medium. Herein, surface-treated silica nanoparticles have been tested with two of our candidate surfactants. The nanoparticles alone generate a small amount of foam, whereas each surfactant generates a small-to-moderate amount of foam. Synergy is demonstrated by the system that contains 0.1-wt% nanoparticles (the optimal concentration) and 0.5-wt% surfactant solution at neutral pH (≈7), as it leads to approximately 67 and 50% greater foam height, respectively, for Surfactants A and B than foam height observed in tests with surfactants only, in bulk medium. Corefloods with coinjected steam and water containing nanoparticles and surfactant confirm the synergy, exhibiting measurable improvement in mobility-reduction factor (MRF) and steam control, compared with coinjection of steam and water containing only surfactant.

Mathematical model for one-dimensional oil displacement by steam injection with solvent addition

Recently, co-injection of steam and solvent has shown to be an attractive technique to increase oil recovery, combining the advantages of viscosity reduction due to the heat transfer achieved from steam injection with the benefits of mass transfer obtained from miscible flooding. In this work, the problem of one-dimensional displacement of oil by steam injection combined with solvent is analyzed. The mathematical model is based on the mass conservation of components oil and solvent, and conservation of system energy. The solution, composed by shock and rarefaction waves and constant states, is obtained using the method of characteristics. Different solution structures were found for particular sets of reservoir-fluid system parameters, which are defined by the ratio between the value of Henry's constant and the system pressure. The results presented here may be used for fast and efficient evaluation of technical aspects of the best Enhanced Oil Recovery method for a particular field, specially for thin shallow viscous heavy oil reservoirs. This model is also useful for the development of streamlines simulators, where gravity and capillary effects are neglected.

The Experimental Analysis of the Role of Flue Gas Injection for Horizontal Well Steam Flooding

Heavy oil is an important hydrocarbon resource that plays a great role in petroleum supply for the world. Co-injection of steam and flue gas can be used to develop deep heavy oil reservoirs. In this paper, a series of gas dissolution experiments were implemented to analyze the properties variation of heavy oil. Then, sand-pack flooding experiments were carried out to optimize injection temperature and injection volume of this mixture. Finally, three-dimensional (3D) flooding experiments were completed to analyze the sweep efficiency and the oil recovery factor of flue gas + steam flooding. The role in enhanced oil recovery (EOR) mechanisms was summarized according to the experimental results. The results show that the dissolution of flue gas in heavy oil can largely reduce oil viscosity and its displacement efficiency is obviously higher than conventional steam injection. Flue gas gradually gathers at the top to displace remaining oil and to decrease heat loss of the reservoir top. The ultimate recovery is 49.49% that is 7.95% higher than steam flooding.

Experimental study on viscosity reducers for SAGD in developing extra-heavy oil reservoirs

Steam assisted gravity drainage (SAGD) is an effective in situ oil recovery technology in developing extra-heavy oil reservoirs. Large volumes of steam are needed, however, to heat the extra-heavy oil because of its high viscosity. Steam generation consumes large amounts of natural gas, which adversely affects the economics of SAGD, especially when oil prices are low. Moreover, environmental concerns arise because of excessive freshwater use and greenhouse gas emissions from the burning of the fossil fuels to generate steam. Considering these limitations and concerns, this paper evaluates the effectiveness of different viscosity reducers to decrease the steam consumption and improve SAGD performance. We conducted a series of screening experiments, including viscosity-reduction ratio, thermal stability, and core flooding, for nine types of viscosity reducers, based on an extra-heavy oil sample from a commercial SAGD project in China. The results indicate that water-soluble viscosity reducer #8, a nanoemulsion, is suitable for SAGD. It has a viscosity-reduction ratio of 98.0% at 50 °C and is still effective after high-temperature and high-pressure (200 °C, 4.0 MPa) treatment, with a viscosity-reduction ratio of 92.6%. The displacement efficiency is improved by 29.1%, and the cumulative steam-to-oil-ratio is reduced by 45.3% compared with pure steam flooding. Despite viscosity-reduction, the effect of interfacial tension reduction plays an important role in improving displacement efficiency during the coinjection of steam and viscosity reducer #8 has good potential to improve SAGD performance in developing extra-heavy oil reservoirs.