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Collaborating Authors
Results
The Effect of Phase Distribution on Imbibition Mechanisms for Enhanced Oil Recovery in Tight Reservoirs
Wang, Mingyuan (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Abstract The main objective of this research was to investigate the impact of initial water on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for components: oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Abstract Low recovery of fracturing water is partly due to fracturing fluid leak-off into formation and water trapping in matrix. In our previous studies (Soleiman Asl et al. 2019 and Yuan et al. 2019), we showed that using surfactant solutions in fracturing fluid can significantly enhance imbibition oil recovery. However, there is one critical question remained unanswered: What are the consequences of these additives on well performance during flowback and post-flowback processes? Can they block the pore-throats of rock matrix and induce formation damage? To answer this question, we develop and apply a comprehensive laboratory protocol on a tight core plug to simulate leak-off and flowback processes under reservoir pressure, with and without initial water saturation (Swi). We evaluate the possibility of pore-throat blockage by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in a microemulsion (ME) solution. We also investigate the effects of Swi on effective oil permeability (ko) after the flowback process. The results of leak-off and flowback tests using tap water as the base case shows that ko after flowback is lower than that before the leak-off, mainly due to phase trapping. However, results of the tests using the ME solution show that ko after flowback is greater than ko before leak-off. This observation suggests that the leak-off of ME solution enhances regained oil relative permeability during flowback by reducing phase trapping and water blockage. When Swi = 0, the blockage of leaked-off fluid reduces ko during the flowback process. The mean size of self-assembled structures (referred to as "particles" here) formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than the size of formed particles, suggesting low chance of pore-throat blockage by the suspended particles.
- North America > Canada > Alberta (0.93)
- North America > United States (0.68)
- North America > Canada > British Columbia (0.68)
- Geology > Geological Subdiscipline (0.93)
- Geology > Mineral > Silicate (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
Abstract Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data. Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells. This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
- North America > United States (0.68)
- North America > Canada > Alberta (0.47)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
Abstract In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses. The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.84)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
Quantifying Oil-Recovery Mechanisms During Natural-Gas Huff n Puff Experiments on Ultratight Core Plugs
Tran, Son (Department of Civil & Environmental Engineering, University of Alberta, Alberta, Canada) | Yassin, Mahmood Reza (Department of Civil & Environmental Engineering, University of Alberta, Alberta, Canada) | Eghbali, Sara (Department of Civil & Environmental Engineering, University of Alberta, Alberta, Canada) | Doranehgard, Mohammad Hossein (Department of Civil & Environmental Engineering, University of Alberta, Alberta, Canada) | Dehghanpour, Hassan (Department of Civil & Environmental Engineering, University of Alberta, Alberta, Canada)
Abstract Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70/30) HnP experiments on an ultratight core plug collected from the Montney tight- oil Formation, under reservoir conditions (P = 137.9 bar and T = 50°C). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling (i) gas transport into the plug during injection and soaking phases, and (ii) oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (ΔPi = Pg – Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number (NPe) analysis to quantify the contribution of each transport mechanism during the soaking period. We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe= 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ΔPi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the ‘puff period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30 mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.
- North America > Canada > Alberta (0.93)
- North America > United States > Texas (0.67)
- Europe > United Kingdom > North Sea > Central North Sea (0.25)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.70)
- Geology > Mineral > Silicate > Phyllosilicate (0.68)
- Geology > Petroleum Play Type > Unconventional Play (0.68)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
Instow a Full Field, Multi-Patterned Alkaline-Surfactant-Polymer Flood – Analyses and Comparison of Phases 1 and 2
Pitts, Malcolm J. (Surtek, Inc.) | Dean, Elio (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.) | Skeans, Elii (Surtek, Inc.) | Deo, Dalbir (Crescent Point Energy) | Galipeault, Angela (Crescent Point Energy) | Mohagen, Dallas (Crescent Point Energy) | Humphry, Colby (Crescent Point Energy)
Abstract An Alkaline-Surfactant-Polymer (ASP) project in the Instow field, Upper Shaunavon formation in Saskatchewan Canada was planned in three phases. The first two multi -well pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 35% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 47% PV ASP solution. Polymer drive continues in both phases with Phase 1 and Phase 2 injected volume being 55% PV and 35% PV, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.5% to 12 to 16% and an increase in oil rate from approximately 3,200 m/m (20,000 bbl/m) to 8,300 m/m (52,000 bbl/m) in Phase 1 and from 2,200 m/m (14,000 bbl/m) to 7,800 m/m (49,000 bbl/m) in Phase 2. Phase 1 pattern analysis indicates the pore volumes of ASP solution injected varied from 13% to 54% PV of ASP with oil recovery percentage increasing with increasing injected volume. Oil recoveries in the different patterns ranged from 3% OOIP up to 21% OOIP with lower oil recoveries correlating with lower volume of ASP injected. The response from some of the patterns correlates with coreflood results. Wells in common to the two phases show increase oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Oil recovery as of August 2019 is 60% OOIP for Phase 1 and 57% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost would be approximately C$26/bbl resulting in the decision to move forward with Phase 2.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock (0.46)
- North America > Canada > Saskatchewan > Williston Basin > Shaunavon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Instow Field > Shaunavon Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (8 more...)
Abstract While CO2 flooding is expected to increase oil recovery, deviations of actual production from predicted values add significant challenges when optimizing flood design under uncertain conditions. The aim of this paper is to introduce a comprehensive optimization process with uncertainty analysis to obtain a more plausible decision for a field application scenario. In this paper, a comprehensive optimization process is developed to optimize the production performance of entire production lifespan for a CO2-WAG EOR process in Pubei reservoir, Turpan-Hami Basin. Start times of the waterflooding and CO2 WAG proess (i.e., durations of the primary production and waterflooding) are also included in the optimization process as well as the producer's bottomhole pressures and injection rates, in addition to the water and gas injection rates for the WAG process, WAG ratio, and well bottomhole pressures at the producers. The comparison is then performed between the conventional WAG optimization processes with the comprehensive optimization process. A total of 80 reservoir realizations is generated and history-matched to consider the impacts of the geological uncertainty on the optimization process. Finally, the reliability of this optimization design is quantified under the geological uncertainty. Results from a deterministic comprehensive optimization design demonstrate that the oil recovery and NPV of the optimized CO2-WAG process are increased by 23.4% and 51.3%, respectively, in comparison to the optimal case obtained by the conventional WAG optimization process. After incorporating uncertainties into the geological model, the distributions of oil recovery and NPV, including P10, P50, P90 are quantified. Based on uncertainty assessment, it is found that the optimized CO2-WAG scheme is a reliable scheme for the reservoir development. This paper provides quantitative insights on the significance of both geological and operational factors on the reliability of optimal design over the entire life span of a CO2 WAG operation. It is expected that the integrated workflow will help operators to optimize well performance more efficiently and predict production performances with higher reliability.
- North America > Canada > Alberta (0.47)
- North America > Canada > Saskatchewan (0.46)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
Abstract 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.
- South America > Venezuela (1.00)
- Asia > Middle East (1.00)
- Asia > China (1.00)
- (7 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.92)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- South America > Brazil > Espírito Santo > South Atlantic Ocean > Campos Basin > Block BM-C-30 > Jubarte Field (0.99)
- (40 more...)
Abstract We present the first comprehensive experimental evaluation of gas injection for EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays. The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments. Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate. This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (0.68)
- North America > United States > Montana (0.68)
- North America > United States > North Dakota > Mountrail County (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
Abstract The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.