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Results
X-Ray CT Investigation of Displacement Mechanisms for Heavy Oil Recovery by Low Concentration HPAM Polymers
Skauge, Arne (University of Bergen) | Shaker Shiran, Behruz (NORCE Energy) | Ormehaug, Per Arne (NORCE Energy) | Santanach Carreras, Enric (TOTAL E&P) | Klimenko, Alexandra (TOTAL E&P) | Levitt, David (TOTAL E&P)
Abstract Polymer flooding has proved to be a successful EOR method in very heavy oil reservoirs, despite failure to achieve a favorable mobility ratio even with polymer, which was originally imagined to be a necessary criterion for success based upon fractional flow theory. In a previous study (Levitt et al. 2013), we demonstrated a surprisingly high oil recovery with low concentration (and viscosity) partially hydrolyzed polyacrylamide (HPAM) polymer solutions of only 3 cP displacing a 2000 cP oil. Additional experiments with more viscous as well as non-elastic viscosifying agents demonstrated that recovery is not sensitive to viscosity, and thus cannot be understood through fractional flow theory. The scope of this paper is to understand where additional recovery comes from through visualization using CT imaging, in order to allow operative driving mechanisms to be optimized. Two long core (30 cm) flooding experiments have been performed to understand oil recovery at adverse mobility ratio. The first experiment started with waterflooding followed with polymer flooding (3 cP), while the second experiment started with polymer flooding directly. In-situ saturations were obtained by a medical CT scanner operated at high energy level, and used two X-ray sources and two array detectors simultaneously. The procedure was to perform the waterflood or polymer flood direct in the CT scanner. That will give us the finger development from early stage until a well-established channel is developed. The frontal velocity was about 1 ft/day. The displacements were further analyzed through simulations and dynamic pore scale model to understand the changes in fluid flow. CT imaging demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density. This is in agreement with observed behavior of unstable displacements involving viscoelastic fluids in Hele-Shaw cells (Bonn et al., 1995). These results suggest that elasticity may be more significant than viscosity in optimizing oil recovery under highly unstable conditions, for example with oils of ~1000 cP or higher. Presence of fingering under both water and polymer flood was also confirmed, with dominant finger diameter on the order of 1 mm (under waterflood) to 2 mm (under polymer flood). Fingers grow in thickness and length, and near the inlet they start quickly to overlap. Fingers are formed mostly in the middle of the core and fewer fingers appear near the wall of the core. CT shows that the waterflood is dominated by viscous fingering. Experimental CT data together with simulations and pore scale modelling have demonstrated that increased oil recovery with low-concentration HPAM solutions is correlated with an increase in finger width, rather than for instance an increase in finger density or stabilization of the displacement front. Among other things, these results demonstrate that the assumption of capillary equilibrium is inappropriate under these conditions, and thus that fractional flow theory is poorly suited to predicting or optimizing recovery.
- Europe (1.00)
- Asia (0.94)
- North America > United States > Oklahoma (0.28)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
Characterization of Carboxylate Surfactant Retention in High Temperature, Hard Brine Sandstone Reservoirs
Pinnawala, Gayani (Chevron Energy Technology Company) | Davidson, Andrew (Chevron) | Taylor, Isbell (Chevron Energy Technology Company) | Yang, Hyuntae (Chevron Energy Technology Company) | Slaughter, Will (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.
- Geology > Mineral (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Abstract Injection of modified salinity brines modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks is relevant to improved oil recovery operations. Many reports in the literature relate the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which cause wettability alterations at the rock surface. Little attention seems to have been placed on fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigate the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations are correlated to visual observations of displacement processes to investigate the role of crude oil snap-off. A series of microfluidic chips featuring pore throats that are 50μm in diameter are used to observe snap-off as a function of salinity in the displacing fluid. The flow experiments suggest that, in a water-wet constricted pore throat, SWS brines suppress crude oil snap-off as compared to FWS brine. This behavior is correlated to the higher surface elasticity of oil-SWS interface than that of oil-FWS interface. Higher surface elasticity suppresses the expansion of the thin water film coating pore throat walls and hence increases the capillary number at which snap-off of the crude oil phase is expected to occur. Moreover, water interacts with the polar components to form reverse micelles called microdispersions. These microdispersions are observed in the aged chip near the oil-brine interface in the pore-network of a microfluidic device. Similarly, in a vial test performed by Tetteh and Barati, (2019), microdispersion formation was only observed very close to the oil-brine interface, caused by the transport of water molecules into the oil phase. These microdispersions remobilize and redistribute the oil, and along with a slight change in wettability in the medium, they improve the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributable to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Abstract Clays are known to act as a catalyst during the in-situ combustion (ISC) process. This work investigates the role of clay in reaction kinetics of a bitumen sample. Several Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) experiments were conducted on a Canadian bitumen and its saturates, aromatics, resins, and asphaltenes (SARA) fractions in the presence and absence of a clay (kaolinite and illite) mixture. The role of each fraction in ISC reactions was investigated at low temperature oxidation (LTO) and high temperature oxidation (HTO) regions by calculating the total activation energy and the heat of combustion. The activation energy calculations were based on the Arrhenius approximation and the heat of reaction was estimated by a simple integration of the DSC curve below the standard zero heat generation line. Accordingly, we have observed that saturates act like ignitors and their ignition characteristics are enhanced in the presence of clay. Bitumen oxidation in LTO region requires more heat for asphaltenes only in the absence of clay. In the presence of clays, bitumen oxidation in LTO region requires more heat for the mutual interaction of resins with asphaltenes. The required heat for the bitumen oxidation and combustion in HTO region is reduced due to contribution of mainly saturates fraction in the presence of clays. The generated heat (heat of combustion) is increased both in LTO and HTO regions for clay presence case. This is mainly due to the mutual interaction of aromatics fraction with resins fraction in LTO region and the mutual interaction of aromatics fraction with saturates fraction in HTO region. It has also been found that bitumen sample contains emulsified water, which reduces the combustion process performance.
- North America > United States > Texas (0.69)
- North America > Canada > Alberta (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.78)
- North America > United States > Kansas > Iola Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Use of In-Situ CO2 Generation in Liquid-Rich Shale
Ogbonnaya, Onyekachi (University of Oklahoma, Norman, Oklahoma, USA) | Wang, Shuoshi (Southwest Petroleum University, Chengdu, China) | Shiau, Benjamin (University of Oklahoma, Norman, Oklahoma, USA) | Harwell, Jeffrey (University of Oklahoma, Norman, Oklahoma, USA)
Abstract Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
- North America > United States > Oklahoma (1.00)
- Europe (0.93)
- 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)
- (26 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (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)
- (5 more...)
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Rohilla, Neeraj (Dow Chemical International Pvt. Ltd.) | Katiyar, Amit (The Dow Chemical Company) | Rozowski, Pete M. (The Dow Chemical Company) | Gentilucci, Adrianno (The Dow Chemical Company) | Patil, Pramod D. (Rock Oil Consulting Group) | Pal, Mayur (North Oil Company) | Saxena, Prabhat (North Oil Company)
Abstract Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains. An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases). The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
Insight Gained From Experimental Gas-Cycling Eor in the Unconventional Montney and Duvernay Formations
Thomas, F. Brent (resopstrategies.com) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir)
Abstract A radial-flow, matrix-frac experimental procedure was developed to incorporate the mechanisms of Gas-Cycling Enhanced Oil Recovery (GCEOR) phase behavior, IFT change, swelling, viscosity reduction and residual-liquid shrinkage in the presence of porous media possessing propped hydraulic fractures and matrix. Relatively large hydrocarbon pore volumes are possible using this technique whereby effluent compositions, densities and volumes are measured. The importance of rock and fluid properties is investigated along with operating pressure, injection gas composition and levels of primary depletion. More than fifty primary depletions followed by GCEOR Huff and Puff operations have been conducted and some of the more interesting results have been assembled for discussion. Two dominant flow regimes are incorporated: matrix mass transfer into and from the fracture(s) and flow within the fracture(s). Reservoirs tested exhibited pressures from 3000 to over 5000 psi and temperatures from 140 to 220 F. Design parameters were changed from run to run allowing for insight into GCEOR operation and design. Of particular note is the ability to run different fluid systems in the same porous media in order to breathe insight into the relative importance of geology and phase behavior. Simulation of some experimental results with subsequent scale-up for field forecasting was performed, although not all systems were simulated as yet. Measured results indicate that recovery of OOIP can be more than doubled compared to primary production, in some cases, by implementing GCEOR. The role of injection gas composition, operating pressure, soak/ Huff time is commented on and appears to change from system to system. Analyzing measured oil flux in the experiments allowed the calculation of experimental Peclet numbers, indicating the relative importance of convection compared to diffusion. From the accumulated data base, the following have been observed: Cycling pressure should be optimized (highest pressure does not necessarily perform the best). Gas quality can, in some cases, play a major role but should be considered and quantified in GCEOR applications. Soak time/ Huff time may be optimized to maximize production cycles and minimize injection cycles. Gas utilization values, for well-designed GCEOR systems, are low compared to conventional continuous gas injection projects causing Huff and Puff GCEOR to approach gas storage performance. Gas utilization appears to be sensitive to the mechanisms at work in GCEOR. Less depletion before GCEOR initiation may accelerate recovery and may, in some cases, access residual oil that was not produced at higher levels of primary depletion. However, significant increases in recovery factor have not been observed with decreased degree of depletion on primary production. Contrary to expectation, the rock character may dominate GCEOR performance. In a subset of this testing, the rock heterogeneity had a more dominant role than fluid properties including miscibility. It appears from this ongoing testing that design of GCEOR projects may be dominated by different parameters from field to field, and possibly well to well. Simulation would provide a good approach in order to bridge the experimental measurements to field design. Experimental GCEOR measurements provide an objective means in order to calibrate the mathematical models in order to forecast field GCEOR upside.
- 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)
- North America > Canada > Alberta > Peak Field > Cdn-Sup Et Al Zaman 10-14-119-5 Well (0.99)
Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and its Pertinence for Low Salinity EOR
Jennifer, Duboué (Total SA) | Maurice, Bourrel (Total SA) | Théo, Dusautoir (Total SA) | Enric, Santanach Carreras (Total SA) | Alexandra, Klimenko (Total SA) | Nicolas, Agenet (Total SA) | Nicolas, Passade-Boupat (Total SA) | François, Lequeux (ESPCI Paris)
Abstract The phenomenon of auto-emulsification occurring when crude oil is gently contacted with water was investigated using various techniques. This spontaneous emulsification which creates a micro-droplet layer at the oil/brine interface is believed to be linked to the improved oil recovery during low salinity Enhanced Oil Recovery (EOR). Crude oils and a model system (asphaltenes solubilized in toluene) have been studied. Observations were facilitated when using the model system, this allowed to have a better insight into the underlying mechanism of micro-droplet formation. It was established that the water micro-droplets appear in the oil phase due to an osmotic phenomenon: molecular water diffuses from the bulk water which provokes the water micro-droplets swelling. The kinetics of the micro-droplet formation is directly linked to the brine salinity in contact with the crude oil: salt addition slows down the emulsification process. This was further confirmed by the evaluation of the water chemical activity in the oil phase from calorimetry measurements. Micromodel experiments showed a higher oil recovery when water micro-droplets are present in the system, irrespective of the initial wettability imposed to the micromodel material. Dilatational rheology measurement did not show significant visco-elasticity arising from the water micro-droplet presence; hence, the visco-elasticity difference cannot completely explain the higher recovery. Manipulation of crude oil droplet during dilatational rheology experiments highlighted the impact of micro-droplets on the shape of the macroscopic oil droplet. The nucleation of micro-droplets at oil/brine or solid/oil interface suggests an explanation for the EOR effect. We have observed that micro-droplets organize at the oil/water interface, while others nucleate at the oil/solid interface or sediment on the solid surface. The interaction of asphaltenes with water molecules dissolved in the oil phase may promote wettability alteration. The micro-droplet formation indicates the magnitude of this interaction for a given asphaltenes/brine system.
- North America > United States (0.46)
- Europe > Norway > Norwegian Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.54)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (0.68)
A Novel EOR Technique for the Attic Oil in Dipping Faulted Reservoirs by Utilizing Gas Oil Countercurrent and Water Flooding Assistance
Ma, Kang (China University of Petroleum-Beijing) | Jiang, Hanqiao (China University of Petroleum-Beijing) | Dong, Rencheng (University of Texas at Austin) | Wheeler, Mary (University of Texas at Austin) | Li, Junjian (China University of Petroleum-Beijing) | Zhang, Rongda (China University of Petroleum-Beijing)
Abstract After long-term water flooding in dipping faulted reservoirs, attic oil is formed and located above the structurally highest wells. A novel technique that combines the Gas Oil Countercurrent (GOC) and Water Flooding Assistance (WFA) is proposed in this paper in order to recover this type of remaining oil. The basic GOC mode includes three procedures, that is, gas injection, well shut-in to form a Secondary Gas Cap (SGC), and production. For the new method GOC-WFA, the WFA is considered in the gas injection and production stage. In this paper, the basic GOC and GOC-WFA experiments are performed to elaborate the EOR mechanism and efficiency of the new method. Three experiment cycles are performed in each experiment. The experiment results illustrate that the WFA can improve the production efficiency by shortening the well shut-in time. The SGC condition is much better in GOC-WFA compared to the GOC in the same well shut-in time. The well shut-in time can be shortened by 50%. In the production stage, the SGC expansion and WFA create Double Displacement Process (DDP). The WFA can inhibit the gas channeling and lower the pressure decline rate. Besides, WFA can also displace the remaining oil located between the production and injection well that cannot be displaced by the gas cap expansion. Compared to the basic GOC, the total oil production volume is nearly doubled. Based on the production model of GOC-WFA, the sensitivity of various operational and geological parameters is analyzed by the reservoir simulation method. Then, the fault-block reservoir screening condition for GOC-WFA is established; the injection-production parameters in the gas injection and production stage are optimized. Finally, the EOR feasibility of the GOC-WFA in the fault-block reservoir is testified by the experimental and simulation results. Therefore, the GOC-WFA can effectively enhance oil recovery in the sealed mature fault-block reservoir.
- Research Report (0.94)
- Overview > Innovation (0.54)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- North America > United States > Louisiana > China Field (0.99)
Abstract Most tight carbonate reservoirs have low oil recovery factors after the primary and secondary recovery stages. High-temperature carbonate reservoirs tend to be oil-wet/mixed-wet due to positively charged minerals and negatively charged oil molecules, hence reducing oil relative permeability. This study aims to enhance oil recovery from tight carbonates by virtue of wettability alteration using surfactants. Twenty different surfactants of different classes and different functional groups are systematically evaluated by first testing their aqueous stability at reservoir conditions. The aqueous stable surfactants were tested for contact angles on the mineral surface. Seven surfactant candidates were selected for spontaneous imbibition experiments, where oil recovery was monitored as a function of time. Wettability-altering surfactants increase the oil recovery by spontaneous imbibition. Up to 190% increase in oil recovery from outcrop core plugs was observed compared to the control sample with sea water.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)