The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Yu, Wei (Texas A&M University) | Zhang, Yuan (China University of Geosciences Beijing) | Varavei, Abdoljalil (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Zhang, Tongwei (The University of Texas at Austin) | Wu, Kan (Texas A&M University) | Miao, Jijun (SimTech LLC)
The effectiveness of CO2 injection as a Huff-n-Puff process in tight oil reservoirs with complex fractures needs to be investigated due to the fast decline of primary production and low recovery factor. Although numerous experimental and numerical studies have proven the potential of CO2 Huff-n-Puff, relatively few numerical compositional models exist to comprehensively and efficiently simulate and evaluate CO2 Huff-n-Puff considering CO2 molecular diffusion, nanopore confinement, and complex fractures based on an actual tight-oil well. The objective of this study is to introduce a numerical compositional model with an embedded discrete fracture model (EDFM) method to simulate CO2 Huff-n-Puff in an actual Eagle Ford tight oil well. Through non-neighboring connections, the EDFM method can properly and efficiently handle any complex fracture geometries without the need of local grid refinement (LGR) nearby fractures. Based on the actual Eagle Ford well, we build a 3D reservoir model including one horizontal well and multiple hydraulic and natural fractures. Six fluid pseudocomponents were considered. We performed history matching with measured flow rates and bottomhole pressure using the EDFM and LGR methods. The comparison results show that a good history match was obtained and a great agreement between EDFM and LGR was achieved. However, the EDFM method performs faster than the LGR method. After history matching, we evaluated the CO2 Huff-n-Puff effectiveness considering CO2 molecular diffusion and nanopore confinement. The traditional phase equilibrium calculation was modified to calculate the critical fluid properties with nanopore confinement. The simulation results show that the CO2 Huff-n-Puff with smaller CO2 diffusion coefficients underperforms the primary production without CO2 injection; nevertheless, the CO2 Huff-n-Puff with larger CO2 diffusion coefficients performs better than the primary production. In addition, both CO2 molecular diffusion and nanopore confinement are favorable for the CO2 Huff-n-Puff effectiveness. The relative increase of cumulative oil production after 7300 days with CO2 diffusion coefficient of 0.01 cm2/s and nanopore size of 10 nm is about 12% for this actual Eagle Ford well. Furthermore, when considering complex natural fractures, the relative increase of cumulative oil production is about 8%. This study provides critical insights into a better understanding of the impacts of CO2 molecular diffusion, nanopore confinement, and complex natural fractures on well performance during CO2 Huff-n-Puff process in the Eagle Ford tight oil reservoirs.
Sheng, Kai (The University of Texas At Austin) | Argüelles-Vivas, Francisco J. (The University of Texas At Austin) | Baek, Kwang Hoon (The University of Texas At Austin) | Okuno, Ryosuke (The University of Texas At Austin)
Water is the dominant component in steam injection processes, such as steam-assisted gravity drainage (SAGD). The central hypothesis in this research is that in-situ oil transport can be enhanced by generating oil-in-water emulsion, where the water-continuous phase acts as an effective oil carrier. As part of the research project, this paper presents an experimental study of how oil-in-water emulsion can improve oil transport in porous media at elevated temperatures from 373 K to 443 K.
Dimethyl amine (DEA) was selected as the organic alkali to form oil-in-water emulsions with Athabasca bitumen and NaCl brine at 1000 ppm salinity and 0.5 wt% alkali concentration. This composition had been confirmed to be optimal in terms of oil solubility in the water-external emulsion phase at a wide range of temperatures. Then, flow experiments with a glass-beads pack were conducted to measure effective viscosities for emulsion samples at shear rates from 5 to 80 sec−1.
Results show that the effective emulsion viscosity is not sensitive to temperature. At an estimated shear rate of 11 sec−1, for example, the emulsion viscosity was 35 cp at 373 K and 31 cp 403 K. The efficiency of in-situ bitumen transport was evaluated by calculating bitumen molar flow rate under gravity drainage with the new experimental data. Results show that oil-in-water emulsion can enhance in-situ bitumen transport by 1.5 to 7 times at temperatures below 403 K, in comparison with the gravity drainage of oil-water two phases in conventional SAGD. This is mainly because the mobility of the bitumen-containing phase is enhanced by the reduced viscosity and increased effective permeability. A marked difference between alkaline solvents and conventional hydrocarbon solvents is that only a small amount of alkaline solvent enables to enhance in-situ transport of bitumen.
Mukherjee, Biplab (The Dow Chemical Company) | Patil, Pramod D. (The Dow Chemical Company) | Gao, Michael (The Dow Chemical Company) | Miao, Wenke (The Dow Chemical Company) | Potisek, Stephanie (The Dow Chemical Company) | Rozowski, Pete (The Dow Chemical Company)
Steam injection is a widespread thermal enhanced oil recovery (EOR) method to increase oil mobility. The introduction of steam heats the reservoir, ultimately lowering oil viscosity and in turn enhancing heavy oil recovery. In the steam injection process, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies that there is a large consumption of steam and incomplete reservoir drainage. Injection of surfactant with steam and a non-condensable gas such as nitrogen can generate foam
In this paper, a systematic approach to screen surfactants for field applications at high temperature is presented. A feasibility test was conducted with the surfactant formulation (HSF-X) at target reservoir conditions to understand the thermal stability and adsorption behavior of the surfactant. Investigation found that the thermal decomposition and adsorption of the surfactant on sandstone rock under static conditions was mimimum at 200°C. In core flood testing conducted using silica sand and natural sandstone cores, foam generated by injecting N2 and HSF-X surfactant solution was able reduce steam mobility between 40 to 100 times at 100°C and 10 to 15 times at 200°C more compared to steam mobility in the absence of the foam. Finally oil recovery experiments at 200°C using silica sand cores indicated the ability of the HSF-X surfactant to foam in the presence of oil and enhance recovery of oil (a +20% increase in the original oil in place (OOIP) was observed).
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Performance predictions of In-Situ Combustion (ISC) process is a challenge as it involves complicated chemical reactions, fluids movement, phase changes, and heat and mass transfer. This study investigates how the aquathermolysis reactions and their chemical products can affect the ISC performance through combination of combustion tube and Thermogravimetric Analysis and Differential Scanning Calorimetry (TGA/DSC) experiments.
Combustion tube experiments were conducted with two different crude oil without water (Swi=0%) and with the presence of water (Swi=34%). Experimental conditions were kept constant (3 L/min air injection rate and 100 psig pack pressure) for all four experiments conducted with two different oil samples. To determine the chemical reactions occurred during combustion tube experiments, the initial crude oil samples and their Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions were subjected to TGA/DSC experiments under air injection at two constant heating rates with and without water addition. Because during combustion tube experiments, two heating rates were observed, 5°C/min was used to represent the slow heating region (Steam Plateau and Evaporation & Visbreaking) and 20°C/min was used to mimic the rapid heating region (Cracking Region and Combustion Zone). To better understand the complicated mutual interactions of functional groups in crude oil, TGA/DSC experiments were repeated on normal-decane (an alkane), decanal (an aldehyde), decanone (a ketone), and decanol (an alcohol) which may represent the low temperature oxidation (LTO) products. Note that these chemicals have constant carbon number (C10).
The combustion tube experiments showed that Oil1 was able to burn for both conditions (with and without water), while Oil2 could only sustain combustion with water. To study the reason for this difference in burning behavior, the burning behavior of the crude oils and their individual SARA fractions with and without water addition was studied through TGA/DSC experiments. At high heating rate (20°C/min), heat generation does not vary for both crude oil. However, in low heating rates (5°C/min), Oil1 generates higher amount of energy at high temperature oxidation (HTO) zone. We have observed similarities between the decanone (a ketone) burning behaviors with aromatics fractions for Oil1 which may indicate that aromatics fraction may contain ketone functional groups as LTO products Because upon burning, ketones generate higher energy than any LTO products, Oil1 may have functional groups in its structure more like ketones which promotes its combustion more than Oil2. While presence of water does not change the burning behavior of Oil1, we observed that aromatics fraction of Oil2 in the presence of water generates components similar to decanol (an alcohols) burning behavior. Note that alcohols generate more heat than aldehydes upon burning which explains the enhancement of Oil2 burning behavior in the presence of water, however, produced less energy than ketones, hence, combustion performance of Oil2 was poorer than Oil1. Our results suggest that the chemical structure of aromatics fraction is critical for the success of ISC. Water and aromatics fraction interaction at elevated temperature favors ISC reactions.
The main objective of this paper is show the design, implementation and results of a nitrogen + steam pilot implemented in a Colombian heavy oil reservoir. Given that the answer to the cyclic steam injection has declined significantly in some wells of the interest field due to the high number of cycles, a pilot project to assess the feasibility of injecting nitrogen accompanied cyclic steam was raised. The determination of optimum volumes and injection scheme by numerical simulation was performed in a sector model. Eleven schemes of steam plus nitrogen injection were evaluated. In all schemes, it was tested remained constant volume of injected steam, while the volume of nitrogen varied according to the scheme (pre-injection, post-injection, co-injection or a combination of the above). In all cases, it assumed the injection of nitrogen according to real drive capacity 1200 m3/hour (1017072 ft3/day).
The best case corresponds to start injecting only one day with nitrogen, followed by five days of co-injection and ending with a single nitrogen day. Under this scheme an incremental production of 5642 barrels of oil a trial period of six months, with average oil production of 53 BOPD in the same period and maximum rate of 142 BOPD. According to the simulation results, it was decided to implement the pilot steam + nitrogen injection, following the best injection scheme given above; that is, a day of pre-injection (nitrogen only), five days of co-injection (steam + nitrogen) and one day post-injection (nitrogen only). The results of the pilot show that oil production has increased compared to previous cycles, reaching similar results to the numerical simulation forecast. A methodology to implement steam injection enhanced with nitrogen is proposal in this paper, which can be applied in any field of heavy crude scheme developed under cyclic steam stimulation.
Huff and Puff gas injection through horizontal wells in shale petroleum reservoirs is moving cautiously from being a promising theoretical possibility, to becoming a reality for increasing oil recovery. This study investigates how oil recoveries from shales can be increased by (1) a combination of refracturing and huff and puff gas injection, and (2) huff and puff gas injection when the length of the gas injection and production cycles are increased over time.
The possibility of improving oil recoveries from shales by a combination of refracturing and huff and puff gas injection is investigated using a compositional simulation approach. Previous studies published in the literature, have considered the implementation of regular constant-time cycles throughout the huff and puff process. This may not be the optimum strategy. In this work, the use of cycles with increasing time-lengths is investigated with a view to maximize the oil recovery by huff and puff gas injection.
The combination of (1) huff and puff gas injection followed by (2) refracturing and (3) stopping gas injection is found to be a good option to increase oil recovery from shale petroleum reservoirs when the initial hydraulic fracturing (IHF) has been successful. The benefits of this approach are demonstrated through a comparison made when refracturing is carried out without previous huff and puff injection. If the IHF has not been implemented properly, the huff and puff gas injection does not provide attractive recoveries. In this case, a refracturing job followed by huff and puff gas injection is shown to improve recoveries significantly. A comparison of the different scenarios considered in this paper shows that proper design of the injection and production schedule is very important in the development of a huff and puff gas injection. Optimizing the schedule by using the appropriate cycles with variable increasing-time spans can lead to improving the huff and puff performance.
This study investigates how to increase oil recovery from shale petroleum reservoirs by (1) the combined use of refracturing and huff and puff gas injection, and (2) the use of cycles of variable length as opposed to the regular-length constant-time cycles considered in previous publications. To the best of our knowledge, the two cases considered in this paper are novel and have not been published previously in the literature.
Jin, Fu (Petrochina Research Institute of Petroleum Exploration & Development) | Xi, Wang (CNPC Drilling Research Institute) | Shunyuan, Zhang (Petrochina Research Institute of Petroleum Exploration & Development) | Bingshan, Liu (CNPC Drilling Research Institute) | Chen, Chen (CNPC Drilling Research Institute)
Liaohe Oilfield is well-known for wide distribution of heavy oil resoures whose viscosity is around 6.2×104mPa·s (degassed crude oil at 45°C). Heavy oil resources are usually found at the depth of 500-1700m. An integrated research has been completed to study the most efficient utilization of steam huff and puff methodology.
In order to compare the new steam injection method with the conventional EOR method, we selected 7 wells in which steam injection was simulated by software. The high temperature gel particle plugging agents, high temperature frothers and resins were tested. The overall sweep efficiency and oil production rate of these wells were compared with that of adjacent wells that depended on conventional steam injection methodologies.
The multi-well steam injection requires injecting steam into a specific group of wells, so that an overall thermal field may be created. In this way, steam channeling caused by longitudinal heterogeneity of heavy oil reservoirs may be overcome. CO2 has the best role in reducing the oil viscosity, while natural gas and nitrogen follow it. So CO2 is the most appropriate EOR gas. CO2's dissolubility declines as temperature goes up and improves as pressure increases. Temperature of liquefied CO2 varies a lot with different injection speeds, in that the heat diffusion time is different. The faster CO2 is injected, the shorter the heat diffusion time is, which makes downhole temperature change less. As CO2 is injected into formation, it dissolves rapidly with heavy oil and makes it expand. Steam is injected then to heat the borehole, while CO2 diffuses rapidly and its dissolubility declines as temperature goes up, which makes CO2 separated from oil and diffused by scale. Thus, clean-up additives and steam are widely distributed. After shut-in CO2 spreads until it keeps balanced dynamically with viscosity reducers.
The daily production rate used to start to decrease after 5 rounds of steam injection. By injecting steam and CO2 into a group of wells we succeeded in improving the sweep efficiency and production rate.
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.