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Collaborating Authors
Results
Experimental and Numerical Studies of EOR for the Wolfcamp Formation by Surfactant Enriched Completion Fluids and Multi-Cycle Surfactant Injection
Zhang, Fan (Texas A&M University) | Saputra, I. W. (Texas A&M University) | Parsegov, Sergei G. (Texas A&M University) | Adel, Imad A. (Texas A&M University) | Schechter, David S. (Texas A&M University)
Abstract Field observations and laboratory experiments have proven the possibility of production enhancement of shale oil wells through surfactant addition into completion fluid and perhaps, surfactant injection for EOR. This study numerically upscaled laboratory data for multi-stage hydraulic fracturing treatment and injection process proposed for the Wolfcamp formation. A combination of rock mechanic and reservoir numerical modeling was used to approximate the field-scale performance of both techniques. Novel completion fluid formulations and optimum surfactant injection schemes were designed, based on actual completion and production data. Surfactant-Assisted Spontaneous Imbibition (SASI) experiments data for two surfactants investigated on the core-scale were upscaled to model production response of a hydraulically fractured well in Upton County, Texas, with realistic fracture geometry and conductivity. Core plugs were saturated and aged with their corresponding oil to restore the original oil saturation. Contact angle, interfacial tension (IFT), and zeta-potential were measured to investigate the role of capillary pressure for surfactant tests. We use a dual-porosity compositional model to determine the surfactant transport and adsorption. With the proposed methodology, we show that lateral heterogeneity may limit both hydraulic fracture propagation and uniform distribution of EOR fluids, which cannot be ignored for the sake of simplicity. The primary production mechanism of aqueous phase surfactant EOR is wettability alteration and the reduction of IFT. Laboratory-scale SASI experimental results revealed that 2 gpt of surfactant solutions recovered up to 30% of the original oil in place (OOIP), whereas water alone recovered 10%. Capillary pressure and relative permeability curves were generated by scaling group analysis and history-matching the results of imbibition experiments on CT-generated core-scale model. On the next step, these curves were applied to surfactant completion and injection simulation models. The field-scale model was achieved from history-matching actual well production data. We tested different soak times, injection pressure, and number of cycles in surfactant injection simulations to provide an optimum design for this scheme. Simulation results indicated that surfactant injection has further potential for higher recovery factor in addition to the incremental Estimated Ultimate Recovery (EUR) observed with application of surfactant as a completion fluid alone. Also, we investigated water-injection after primary depletion (water without surfactant) to provide another possible method for unconventional liquid reservoirs (ULR). Instead of referring to Huff-n-Puff which implies gas injection, in this manuscript we use the terminology Multi-Cycle Surfactant-Assisted Spontaneous Imbibition (MC-SASI) to describe surfactant Huff-n-Puff for EOR. This paper provides a complete workflow on SASI-EOR that has been evaluated in laboratory experiments, during the completion phase, and after primary depletion. In addition, we assessed the potential of water-injection after primary depletion in enhancing EUR. The numerical models were developed by accounting for geomechanics based on actual data combined with surfactant EOR laboratory experiments, field data, and industry-accepted simulators. A new modeling workflow for SASI-EOR is proposed to unveil the actual potential of surfactant additives.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.98)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.98)
- (3 more...)
Study on Chemical Combination Formulations for High Temperature and High Salinity Carbonate Reservoirs
Zhang, Fan (PetroChina) | Yang, Siyu (PetroChina) | Ma, Desheng (PetroChina) | Lv, Jianrong (PetroChina) | Zhang, Qun (PetroChina) | Luo, Wenli (PetroChina) | Zhou, Zhaohui (PetroChina) | Tian, Maozhang (PetroChina) | Cai, Hongyan (PetroChina)
Abstract Chemical flooding technique is one of effective EOR (Enhanced Oil Recovery) ways to improve the oil recovery for mature oilfield in China. It is usually applied successfully in low temperature and low salinity sandstone reservoirs, such as Daqing oilfield (45°C, 5,100 mg/L) and in Changqing oilfield (50°C, 4,700 mg/L). However, it is great challenges to develop chemical EOR formulations for the high temperature and high salinity carbonate reservoir. On the one hand, the high temperature and high salinity condition may cause decomposition of the conventional chemical agents with poor long-term stability. On the other hand, the oil types and compositions, rock surface property and pore structure are all different for sandstone and carbonate reservoirs. Therefore, it is necessary and important to development low cost and high efficiency chemical formulations for high temperature and high salinity carbonate reservoirs. In this paper, the betaine surfactant has been synthesized with cheap raw material of fatty acid, and its functional group of hydroxyl propyl sulfo hydrophilic group can improve the heat resistant and salt tolerant abilities; the star-polymer has been developed and the introduction of multi-functional monomer can inhibit the hydrolysis at high temperature and high salinity conditions. The new SP and ASP chemical formulations have been developed, and show good properties for high temperature and high salinity carbonate reservoir. The SP chemical formulations of the betaine and star-polymer show good heat resistant and salt tolerant capability. It could achieve ultra-low interfacial tension (less than 1.0×10mN/m) with temperature range from 30°C to 95°C, or salinity range from 5,000 mg/L to 220,000 mg/L. The effect of alkalis on interfacial tensions were studied, including Na2CO3, Na2SiO3, Na3PO4 and Na2B4O7. The ASP combination formulas with Na2B4O7 showed the best interfacial properties. The SP and ASP chemical formulations had good long term stability, and could maintain ultra-low IFT within 180 days, and the viscosity retention rates were greater than 90%. The dynamic adsorptions of this betaine were less than 1.0 mg/g rock, which can meet the requirement of field applications. After water flooding, the oil recoveries of the SP and ASP formulations increased about 22% (OOIP, Original Oil In Place) and the oil displacement efficiencies of chemical combination flooding reached to 75%. Excellent properties of chemical formulations with the sulfobetaine and star-polymer indicate that this EOR technology can be applied in high temperature and high salinity carbonate reservoir with or without alkaline.
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Ningxia > Ordos Basin > Changqing Field (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract In our previous publications (Tovar 2017; Tovar et al. 2018a, 2018b; Tovar et al. 2014), we presented a philosophy for the operation of gas injection processes in unconventional liquid reservoirs (ULR) that consisted in using a huff-and-puff scheme at the maximum possible pressure, regardless of the MMP. We also postulated a kinetically slow peripheral vaporizing gas drive as the main recovery mechanism underlying the rationale for such operational philosophy. We based all of our findings in a collection of 21 experiments performed using crude oil and core plugs from the Wolfcamp. The main focus of this paper is that the fundamentally different production mechanisms taking place in ULR cause the recovery factor to continue increasing when pressure is increased beyond the MMP. We do this using core plugs and crude oil from a different field, the Eagle Ford. Confirmation of this finding is necessary, since it directly contradicts the behavior in conventional reservoirs. We also demonstrate the addition of a dopant, into the crude oil, has little effect in the phase behavior, which widens the validity of all our work so far; and provides additional insights into the gas transport in the porous media. The production of oil from unconventional liquid reservoirs (ULR) has seen a significant increase in the last decade due to the implementation of horizontal drilling and hydraulic fracturing technologies. However, these reservoirs have mainly been exploited through primary production, which exhibits fast production decline and low ultimate recovery. Therefore, the need to understand different transport mechanisms and to develop enhanced oil recovery (EOR) techniques to improve ultimate oil recovery and extend the life of the asset is critical. This work investigates the effects of miscibility on enhancing recovery and the implementation benefits we can obtain from it. We performed five additional core-flooding experiments. The cores were cleaned using an extended Dean-Stark extraction and re-saturated to known initial oil in place in the laboratory. Gas injection through a hydraulic fracture was simulated using high permeability glass beads surrounding the cores that were then packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and reservoir temperature. The production was monitored using a CT scanning technology throughout the length of the experiments to track changes in composition and saturation as a function of time and space. Soak time was maintained constant and the experimental pressures were selected above and below the slim-tube MMP to show the effect of MMP on recovery. Our results are consistent with a kinetically slow, peripheral vaporizing gas drive production mechanism. Recovery factor was 50% at the highest pressure of 3,500 psig. This is higher than the maximum of 40% we previously observed in the Wolfcamp, possibly due to the higher concentration of intermediate hydrocarbon components in the Eagle Ford, and the higher experimental pressure. Recovery factor increases with pressure, even above the MMP. The addition of 5% Iodobenzene in the Wolfcamp oil, increased the MMP by only 136 psig, or 7 %, indicating our conclusions are valid. This work confirms our previous findings, which challenge the paradigm that establishing miscibility is enough to achieve the highest recovery factors during CO2 flooding, as is the case in conventional reservoirs. This finding has a significant impact on field operations and should be considered during the design of gas injection EOR processes in ULR.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Recovery factors (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Scaling for Wettability Alteration Induced by the Addition of Surfactants in Completion Fluids: Surfactant Selection for Optimum Performance
Zhang, Fan (Texas A&M University) | Saputra, I. W. R. (Texas A&M University) | Adel, Imad A. (Texas A&M University) | Schechter, David S. (Texas A&M University)
Abstract Experimental laboratory evidence of enhanced production by spontaneous imbibition via the addition of surfactants into completion fluids, as well as field observations, indicate a significant improvement in EUR with the use of surfactants to improve oil recovery from unconventional liquid reservoirs (ULR). During a hydraulic fracture treatment, the surfactant molecules interact with the rock surface, altering its wettability and interfacial tension. The wettability alteration of the rock surface from oil-wet to water-wet enables the spontaneous imbibition of water into the matrix, which expels the oil out of the pore space towards the fractures. Several laboratory and numerical studies have investigated the effectiveness of surfactant-assisted spontaneous imbibition (SASI) on various ULR. However, the understanding of surfactant selection for the optimization of enhancing recovery in ULR is not well studied. Capillary pressure is the dominant force for spontaneous imbibition process. Contact angle (CA) and interfacial tension (IFT) are essential terms in the Young-Laplace capillary pressure equation as well as in published scaling analysis of the spontaneous imbibition process. With the large amount of data released on SASI, it is natural to develop a correlation between the two properties to the recovery factor. However, no work has been conducted to investigate the relationship of contact angle and IFT on ultimate recovery by spontaneous imbibition in ULR. In this manuscript, a compilation of CA, IFT, and spontaneous imbibition experiments from two of the most prolific shale reservoirs is presented to give an insight into the relationship between the three variables. Then, based on the observed trends and correlations, a new scaling model for SASI in ULR is proposed. The ultimate goal is to develop a surfactant selection method based on scaling analysis results and laboratory data for optimal performance in ULR. A total of 35 independent SASI correlated experiments data were compiled, which includes CA, IFT, recovery factor, porosity, core plug dimensions, and capillary pressure calculated from the Young-Laplace equation. Experimental procedure on each data point followed the robust data gathering methodology that was already developed for the past four years. The reliable procedure ensures the representability of the reservoir condition in the laboratory measurements to provide an accurate description of the effectivity of different surfactants on a corresponding oil/water/rock system. Two systems were analyzed and assembled into three groups, Wolfcamp, Eagle Ford A, and Eagle Ford B. An inversely proportional correlation between CA and recovery factor was observed, while on the IFT and recovery factor analysis, a less apparent correlation was found. Theoretically, a directly proportional correlation between capillary pressure and recovery factor can be expected due to spontaneous imbibition that is primarily dominated by capillary forces, which is consistent with experimental data analysis. The high dependence of recovery factor on contact angle and the less significant effects from IFT lead us to conclude that a substantial wettability altering surfactant is highly preferred to enhance through SASI. In addition, based on the observed correlation, a new dimensionless scaling equation fully accounting for the effect of surfactant addition was developed to generalize the flow behavior of SASI.
- North America > United States > Texas (1.00)
- Asia (0.67)
- Research Report > Experimental Study (0.66)
- Research Report > New Finding (0.47)
- North America > United States > Texas > Permian Basin > Midland Basin > Spraberry Field > Spraberry Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.94)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.94)
- (25 more...)
Abstract We investigated the combined contributions of gravity drainage and miscibility as recovery mechanisms during CO2 flooding. The effects of gravity stable and unstable CO2 fronts under immiscible, near miscible and miscible displacements of crude oil by CO2 are presented. We contrast our results in porous media, with slim tube experiments, core floods, and bead packed tubes. Standard slim-tube, vertically and horizontally oriented bead packed tubes, as well as vertical and horizontal reservoir core flood experiments, were used to investigate the role of the gravitational forces in improving oil recovery under different conditions regarding the crude oil – CO2 miscibility. Three crude oils with different minimum miscibility pressure (MMP) values were used in this study. Our results show the gravity drainage mechanism has a much greater significance than previously thought when compared to the effects of phase behavior or the miscibility alone. Not surprisingly, vertically stable, downward displacement resulted in better performance compared to horizontal displacement in all cores and bead packed tubes in our experiments. Recovery is only slightly higher in the gravity stable floods when miscibility is achieved. However, in immiscible and near miscible displacements, recovery is significantly higher in the gravity stable floods, reaching up to 90% RF at 250 psi below the MMP value, compared to only 33% in horizontal floods. Our results suggest that achieving miscibility is not necessary to obtain high recovery efficiency during a gravity-stable displacement. Breakthrough is reached faster in horizontal floods as a consequence of fingering and gravity override. This work challenges the paradigm that miscibility is required to achieve high recovery factors during CO2 flooding, and highlights the overlooked role of gravity drainage as a displacement mechanism. This finding has an essential impact on field operations as it allows for lower operating pressures in CO2 flooding processes under stable gravity displacement that will result in positive impact on economics. The relevance of our results is exacerbated by the current low crude oil price environment.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Laboratory Study on a New Surfactant/Polymer Formulation for Both Sandstone and Carbonate Reservoir
Zhang, Fan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Luo, Wenli (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Yang, Siyu (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhang, Qun (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Zhou, Zhaohui (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing) | Tian, Maozhang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development, Beijing)
Abstract Chemical flooding technique of alkali-surfactant-polymer (ASP) has been successfully applied in China for sandstone reservoir. However, challenges to develop chemical EOR formulations without alkali are significant and unique for both sandstone and carbonate reservoir. On the one hand, it is very difficult to achieve ultra-low interfacial tension and good oil displacement effect without the help of alkali. On the other hand, the oil types, rock mineral compositions, rock surface property, matrix pore structure and orientation are all different for sandstone and carbonate reservoir. In fact, the ASP technologies successfully used in Daqing sandstone oilfield cannot be simply extrapolated to SP combination flooding and carbonate reservoir. The key technology is development low cost and high efficiency surfactant and polymer. In this paper, the new surfactant/polymer formulation has been developed, and show good properties for both sandstone and carbonate reservoir. The novel sulfobetaine with intellectual property has been obtained with raw material of cheap fatty acid, and the carbon-carbon double bond can improve the solubility and emulsifying property. The star-shaped polymer has been developed, and could effectively increase the rigidity of polymer molecular chain and the regularity of molecular structure, which can make the curliness of polymer chain become difficult, and increase the revolving hydraulic radius of molecular chain. The new surfactant/polymer formulation had wide adaptability and could achieve ultra-low interfacial tension (IFT, less than 1.0×10mN/m) in different sandstone and carbonate reservoir conditions, and the temperature were from 45 ℃ to 90℃, and the salinity were from 4,500 mg/L to 100,000 mg/L. The SP system has good long term stability at different reservoir conditions. The IFT results were in the range from 10mN/m to 10mN/m with duration of 180 days, and the retention rates of viscosity were more than 90%. The new surfactant/polymer formulation had good emulsifying capacity, and emulsion Winsor III was observed. It could change the wettability from oil wet to water wet, and had good stripping film capacity. The alkali-free SP formulation showed good oil displacement effect. After water flooding, it could increase oil recovery 21.5% (OOIP) in Daqing oilfield in China for sandstone reservoir; for carbonate reservoir, it could increase oil recovery 23.42% (OOIP) in the oilfield of Middle East. This paper presents the new alkali-free surfactant/polymer combination flooding green technology, which provide promising chemical EOR technique for both sandstone and carbonate reservoir.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Development of Large-hydrophobe Betaine Surfactants for Chemical Enhanced Oil Recovery in Low/High Salinity Reservoirs
Hongyan, Cai (SKL-EOR, RIPED, CNPC,) | Jian, Fan (SKL-EOR, RIPED, CNPC,) | Dong, Han (CNODC, CNPC) | Zhang, Fan (SKL-EOR, RIPED, CNPC,) | Zhu, Youyi (SKL-EOR, RIPED, CNPC,) | Hu, Ziqiao (RIPE, SINOPE)
Abstract For chemical enhanced oil recovery in high temperature, high salinity (HTHS) reservoirs, the development of surfactant faces great technical challenges. Conventional surfactants industrially applied such as heavy alkyl benzyl sulfonate, petroleum sulfonate, and polyoxyethylene ether are excluded due to poor properties in high salinity or high temperature conditions. Heat tolerant and salt resistant criteria dramatically narrow the screening window and make it very difficult to obtain a suitable surfactant candidate. On the other side, for reservoirs with low to medium salinity, it is not easy to find suitable surfactants either. Less of salts in solution needs surfactant having higher interfacial activity to attain ultralow interfacial tension (i.e. IFT, 10 mN/m magnitude). In this study, two betaine surfactants, amidobetaine and etherbetaine were developed from long chain fatty acid and alcohol. Properties with respect to long term thermal stability, salt resistance, interfacial activity were evaluated. Besides, the synergistic effect of combined surfactants were also studied. After that, core flooding tests were conducted to evaluate the performance of the concerned betaine/polymer SP formulation. The prepared betaine surfactants showed high interfacial activity with several crude oil, reaching ultralow IFT within surfactant concentration range of 0.05%-0.30%. For amidobetaine surfactant, excellent salt resistant property was observed at salinity as high as 200,000 mg/L. Sound stability of betaine solutions at high temperature, high salinity conditions were observed within 90 days aging test. In addition, the combined amidobetaine and conventional long-chain betaine/gemini surfactant demonstrated positive synergistic effect at low salinities. Moreover, amidobetaine surfactant showed remarkable viscosifying capability, displaying mobility control potential. Core flooding tests of binary amidobetaine/polymer formulation showed an average incremental oil recovery of around 17%. The developed betaine surfactants provide good chemical candidates for CEOR in HTHS reservoirs.
- North America > United States > Oklahoma (0.16)
- Asia > Middle East > Saudi Arabia (0.15)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Lab Study and Field Application of Surfactant Induced Imbibition for Low Permeability Reservoirs
Zhang, Fan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhu, Youyi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Luo, Wenli (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Cai, Hongyan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Song, Wenfeng (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Qun (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhou, Zhaohui (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development)
Abstract Low permeability reservoirs are widely distributed in various countries, which contribute an important percentage of oil output in the world. At present the main exploitation mode is water flooding, but the oil recovery is very low. So it is very necessary to develop effective development technology. Chemical flooding technique is one of effective ways to enhanced oil recovery (EOR). However, low permeability may cause injection difficulty of conventional chemical agents (polymers and formulations of chemical combination flooding). Moreover, high temperature or high salinity condition may cause decomposition of the surfactant and polymer with poor long-term stability. For these harsh condition reservoirs, surfactant induced imbibition is an important and promising technology to enhance oil recovery. The key technology is to develop high efficiency surfactant with low cost. In this paper, the novel anionic surfactant has been developed with good capabilities, including good wettability alteration performance, low adsorptions, wide adaptability, good heat resistant and salt tolerant abilities, and high oil displacement efficiencies. Above all, the field test results are good in China. The anionic surfactant could alter wettability from oil-wet to water-wet effectively and had good stripping film capacity. Contact angles were changed remarkably from more than 130° to less than 50°, and oil film could be peeled off in 180 seconds rapidly. The surfactant had good anti-adsorption ability, and it could maintain ultra-low interfacial tension for 5 times adsorption with the natural sand. The dynamic adsorptions of the anionic surfactant on the rock were less than 1.0 mg/g rock, which will meet the requirement of field applications. The anionic surfactant has wide adaptability and good heat resistant and salt tolerant capabilities. The maximum temperature was 160°C, and the maximum salinity was 220,000 mg/L. Core flooding tests demonstrated an average incremental recovery of 12.5% was achieved utilizing imbibition technology. For Qinghai oilfield (low permeability 26×10µm, high temperature 126°C, high salinity 200,000 mg/L) in China, field pilot test of imbibition oil recovery technology was successful. 18 tons of imbibition agents were injected and increased oil production of 3660 tons. Excellent properties of the anionic surfactant indicate that it is a promising surfactant, which can be applied in low permeability reservoirs, especially for high temperature and high salinity reservoirs.
- Asia > China > Qinghai Province (0.26)
- North America > United States > Louisiana (0.25)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Laboratory Study on Surfactant Induced Spontaneous Imbibition for Carbonate Reservoir
Qi, Ziyuan (Saudi Aramco) | Han, Ming (Saudi Aramco) | Fuseni, Alhasan (Saudi Aramco) | Alsofi, Abdulkareem (Saudi Aramco) | Zhang, Fan (RIPED of China National Oil Corporation) | Peng, Yuqiang (RIPED of China National Oil Corporation) | Cai, Hongyan (RIPED of China National Oil Corporation)
Abstract Chemical flooding has been successfully applied in sandstone reservoirs using surfactant-related formulations due to their abilities to reduce interfacial tension (IFT) between injection fluid and oil. This scheme need to be modified to fit the requirement of effective application in carbonate reservoirs that present preferably oil-wet or mixed wet. In this case, the wettability alteration should be triggered by a kind of surfactants that can change the wettability towards water-wet and induce the spontaneous imbibition of injection fluid into the carbonate matrix for higher oil recovery. In this study, 16 surfactant samples were screened aiming at an Arabian carbonate reservoir, among which 3 surfactant samples were selected for spontaneous imbibition experiments using Amott cells at 95°C. The experimental results presented the imbibition was induced by the surfactant solutions compared to effect of the brine. It also showed that brine imbibition recovery decreases with the increase of permeability and initial water saturation. Surfactant can effectively improve imbibition recovery, and cores with higher permeability show better increased imbibition recovery. Imbibition can be divided into three types based on the value of bond number, and recovery as well as recovery rate can also be correlated with bond number. The imbibition model is validated by two imbibition modes – surfactant imbibition and brine imbibition then surfactant imbibition – using UTCHEM simulator. This paper demonstrates the effect of surfactant induced spontaneous imbibition on oil recovery, which should be taken into account in the chemical flooding application for carbonate reservoirs.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Development of Novel Surfactant for Alkali-free Surfactant/Polymer Combination Flooding Green Technology
Zhang, Fan (State Key Laboratory of Enhanced Oil Recovery) | Zhang, Qun (State Key Laboratory of Enhanced Oil Recovery) | Zhou, Zhaohui (State Key Laboratory of Enhanced Oil Recovery) | Cai, Hongyan (State Key Laboratory of Enhanced Oil Recovery)
Abstract Alkali - surfactant - polymer (ASP) combination flooding technique is one of the effective enhanced oil recovery ways for mature oilfields. However, alkali can lead to difficulty of the scaling and emulsification problems in lifting and produced liquid treatment. So alkali-free surfactant - polymer (SP) combination flooding is a green technology can solve these problems caused by alkali. The key technology of SP flooding is development low cost and high efficiency surfactants. In this paper, the novel betaine surfactant was synthesized with cheap raw material of fatty acid, which had intellectual property and excellent properties. Experimental results showed that the surfactant had wide adaptability and could achieve ultra-low interfacial tension (IFT, less than 1.0×10mN/m) in different reservoir conditions, not only for low temperature and low salinity oilfield (45°C, 5,100 mg/L), but also for high temperature and high salinity oilfield (90°C, 100,000 mg/L). The dynamic adsorptions of this betaine were less than 1.0 mg/g rock, and it could maintain ultra-low IFT for 9 times adsorption with the natural sand. The alkali-free SP formulations with the betaine had long term stability, and could maintain ultra-low IFT within 180 days, and the viscosity retention rates were greater than 90%. The systems of the novel betaine surfactant had good emulsifying capacity and stripping film capacity. The alkali-free SP formulations with the betaine had high oil-displacement efficiency. After water flooding, it could increase oil recovery 21.5% (OOIP, Original Oil In Place) in Daqing sandstone oilfield, 23.4% (OOIP) in high temperature and high salinity carbonate reservoir rock, 15.5% (OOIP) in Changqing low permeability oilfield. Excellent properties of this novel betaine surfactant indicate that it is a promising surfactant for alkali-free SP combination flooding applied in different reservoirs.
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Ningxia > Ordos Basin > Changqing Field (0.99)
- (5 more...)