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Collaborating Authors
Results
Abstract Carbon dioxide (CO2) flooding is a conventional process in which the CO2 is injected into the oil reservoir to increase the quantity of extracting oil. This process also controls the amount of released CO2 as a greenhouse gas in the atmosphere which is known as CO2 sequestration process. However, the mobility of the CO2 inside the hydrocarbon reservoir is higher than the crude oil and always viscous fingering and gravity override problems occur during a CO2 injection. The most common method to overcome these problems is to trap the gas bubbles in the liquid phase in form of aqueous foam prior to CO2 injection. Although, the aqueous foams are not thermodynamically stable, the special care should be considered to ensure about bulk foam preparation and stability. Selection of a proper foaming agent from a large number of available surfactants is the main step in the bulk foam preparation. To meet this purpose, many chemical and crude oil based surfactants have been reported but most of them are not sustainable and have disposal problems. The objective of this experimental study is to employ Lingosulfonate and Alkyl Polyglucosides (APGs) as two sustainable foaming agents for the bulk foam stability investigations and foam flooding performance in porous media. In the initial part, the bulk foam stability results showed that APGs provided more stable foams in compare with Lingosulfonate in all surfactant concentrations. In the second part, the results indicated that the bulk foam stability measurements provide a good indication of foam mobility in porous media. The foaming agent’s concentration which provided the maximum foam stability also gave the highest value of mobility reduction in porous media.
- Asia (0.96)
- North America > United States > Texas (0.47)
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.34)
Surfactant Enhanced Oil Recovery from Naturally Fractured Reservoirs
Lu, Jun (The University of Texas at Austin) | Goudarzi, Ali (The University of Texas at Austin) | Chen, Peila (The University of Texas at Austin) | Kim, Do Hoon (The University of Texas at Austin) | Britton, Christopher (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Weerasooriya, Upali P. (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract Large volumes of oil remain in naturally fractured carbonate oil reservoirs and water floods are often very inefficient because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with low to extremely low matrix permeability. In addition, some of the world's largest oil reservoirs are fractured carbonates with high reservoir temperature and high salinity formation brine and some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. We have developed a stable surfactant that shows promising results even when all of these conditions are present at the same time. Both static and dynamic imbibition experiments were done using a fractured carbonate core. These results were interpreted using a mechanistic chemical reservoir simulator.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- 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)
Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants
Golabi, Elyas (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.) | Azad, Fakhry Seyedeyn (2Department of Chemical Engineering, University of Isfahan, Isfahan, Iran) | Ayatollahi, Sayed Shahabuddin (3EOR Research Center, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran.) | Hosseini, Sayed Nooroldin (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.) | Akhlaghi, Naser (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.)
Abstract The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection. In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system. Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C12TAB (dodecyl trimethyl ammonium bromide), C16TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80°C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C16TAB, C12TAB and SDBS to alter the wettability of the rock.
- North America > United States (1.00)
- Asia > Middle East > Iran (0.29)
Abstract The viability of any Enhanced Oil Recovery (EOR) method lies with its ability to increase oil recovery in an economically efficient manner. The practicality of carrying out a CO2/surfactant enhanced oil recovery operation is affected by the high cost and large volume of surfactant needed in the field. This paper presents the results of a numerical simulation study that was carried out to analyze and establish critical parameters that can be used to obtain the minimum but most effective volume of surfactant needed for generation of foam in a porous medium which will in turn yield optimum oil production. The results obtained from laboratory experiments, which were based on the comparison of a low and high injected surfactant concentration, serve as inputs to a reservoir simulator for modeling and estimating surfactant requirements. Numerical models were designed to simulate the co-injection of carbon dioxide and surfactant solution into a Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters used include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm/min, with CO2 injected at 0.3 cm/min and surfactant solution at 0.1 cm/min, which gives a volumetric flow ratio of 3:1 and foam quality of 75%. Results indicate that injecting a solution with a larger surfactant concentration increased foam strength with a corresponding increase in pressure drop. A decrease in CO2 relative permeability is also observed as more gas is trapped within the rock due to foam blocking. Carbon dioxide is thereby able to contact more of the oil contained within the reservoir.
- North America > United States > Oklahoma (0.28)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
Abstract The gelling performance of VES acid systems dramatically weakens at high temperature. Therefore, these fluids are typically limited to placement in relatively low-temperature carbonate formations. This study was conducted to introduce a new VES system that can gel and maintain useful viscosity up to 300F. The new surfactant system is completely compatible with HCl, brine, and even high iron contamination. Rheological studies defined the operational temperature limit where viscosity was sufficient for the new VES system to be used successfully as diversion agent. It was found that initial acid concentration and the degree of acid neutralization were critical parameters affecting the new VES system diversion performance at elevated temperatures. The effects of four corrosion inhibitors were examined. One is recommended for use with this system because it minimizes negative effects on the operational temperature range. Also, it enhances the values of elastic modulus, which enhances the VES system's diversion performance. Coreflood studies using limestone and dolomite cores confirmed that the new VES system increased differential pressure sufficiently to achieve diversion. For limestone cores, the pressure drop increased by a factor of 10 during VES acid injection; for dolomite cores, the pressure drop increased by a factor of 100. The pressure drop changed in a cycling manner, where the crest and trough of each cycle increased with time. Cycling of the pressure drop indicates that the acid was able to change its direction inside the core. Coreflood testing also indicated that there is no need for a breaker, as 18% permeability enhancement was observed with CaCl2 brine flowback. This paper will discuss the results obtained and recommend the conditions under which the new system is most likely to be successful in the field.
- North America > United States > Texas (0.95)
- Asia (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.46)
Abstract A new sulfonate surfactant from non-edible vegetable oils is developed. The sulfonate surfactant was synthesized from C16-18 fatty acid and evaluated for stability, Interfacial Tension (IFT) and core flooding experiments for its capability to enhance oil recovery. The feedstock is composed mostly of unsaturated fatty acid derived from jatropha curcas oil which can be converted to fatty acid methyl ester. The methyl ester is epoxidized and hydrolyzed to hydroxyl groups, which subsequently were sulfonated to form a product named Methyl Ester Sulfonates (MES). The performance of the synthesized surfactant was studied for its stability, IFT and core flooding experiments. The stability shows that surfactant solution in produced water is clear and free of precipitation. Based on IFT experiments optimum surfactant concentration is 1 wt% which resulted in a lowest possible IFT of 0.19 mN/m in the presence of Na2CO3 as alkali. By conducting a displacement test, an improvement in oil recovery is observed. Surfactant floods perform to test how effectively a surfactant formulation can recover oil on tertiary oil recovery. The results confirmed that there is a possibility of developing new surfactants from vegetable oils. It can obviate the need for using petrochemicals substances in synthesizing surfactants.
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
A CT Scan Study of Immiscible Foam Flow in Porous Media for EOR
Simjoo, M.. (1 Delft University of Technology) | Dong, Y.. (2 now with Shell China E&P) | Andrianov, A.. (3 Shell Global Solutions International) | Talanana, M.. (3 Shell Global Solutions International) | Zitha, P. L. (1 Delft University of Technology)
Abstract A systematic CT scan aided laboratory study of N2 foam in Bentheimer sandstone cores is reported. The aim of the study was to investigate whether foam can improve oil recovery from clastic reservoirs subject to immiscible gas flooding. Foam was generated in-situ in water-flooded sandstone cores by co-injecting gas and surfactant solution at fixed foam quality. It was stabilized using two surfactants, namely C14-16 alpha olefin sulfonate (AOS) and mixtures of AOS and a polymeric fluorocarbon (FC) esther. Effects of surfactant concentration, injection direction, surfactant pre-flush and core length on foam behavior were examined in detail. Stable foams were obtained in the presence of waterflood residual oil. It was found that foam strength (mobility reduction factor) increases with surfactant concentration. Foam development and, correspondingly, oil recovery without surfactant pre-flush were delayed compared to the case with pre-flush. Gravity stable foam injection caused a quick increase of foam strength and an incremental oil recovery almost twice that for unstable flow conditions. Core floods reveled that the incremental oil recovery by foam was as much as 23±2% of the oil initially in place after injection of 4.0 PV of foam (equals to injection of 0.36 PV of surfactant solution) compared with water flooding. Incremental oil recovery was only 5.0±0.5% for gas flooding at the same injection conditions. It appears that oil production by foam flooding occurs due to the following main mechanisms: (1) residual oil saturation to gas flooding is lower than to water flooding, (2) formation of an oil bank in the first few injected pore volumes, which coincides with a large increase of capillary number and (3) transport of dispersed oil by the flowing foam lamellae, leading to long tail production at a fairly constant capillary number. Observations of this study support the concept that foam is potentially an efficient EOR method.
- Europe (1.00)
- Asia > Middle East (0.93)
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Abstract The loss of surfactant from aqueous solutions during the propagation in the reservoirs, especially carbonate reservoirs, is one of the major concerns with chemical oil recovery processes. This is due to the loss of effectiveness of the chemical solution to reduce the oil-water interfacial tension and thus renders the process economically unfeasible. This paper presents, in detail, 10 runs of core flooding tests on dynamic adsorption and desorption of an amphoteric surfactant (OCT-1) onto permeable carbonate rocks, which were conducted in natural carbonate core plugs at reservoir temperature of 100°C and pore pressure of 3100 psi. The surfactant solution was continuously injected into the core plug until the effluent surfactant concentration approached that of the injected surfactant solution, followed by seawater injection until no surfactant was present in the effluent. The effluent surfactant concentrations were analyzed by means of titration technique. Amount of dynimc adsorption and desorption of surfactant solutions was calculated using a new definite integral method. The results showed that the adsorption of the surfactant decreases with increase in the value of the pore geometry parameter, (K/Ф). The adsorption ranges from 0.223 mg/g-rock to 0.597 mg/g-rock for the rocks with permeabilities from 688 md to 110 md. For surfactant concentration of 0.2 wt% OCT-1 in seawater that was used in the study, this level of adsorption implies the surfactant is applicable from adsorption point of view. It was also observed that the adsorption varied with the initial surfactant concentration, as well as relationship between dynamic adsorption and despersion. The value of dispersion, mechanical mixing coefficients and matching adsorption were obtained using dispersion/adsorption equations to match experimental data. This paper presents insights into the adsorption and desorption of the amphoteric type of surfactant on carbonate rocks which could help the application design for a chemical flooding process.
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Abstract Wettability modification of solid rocks by using surfactants is an important process that is used in practical applications such as oil recovery from reservoirs. When wettability is altered, both capillary pressure and phase relative permeability change wherever the porous rock is contacted by surfactant. Due to the complexity of reservoir rock, alteration of the wettability is not uniform throughout the swept area. Although there are several numerical studies in the literature to simulate the effect of wettability alteration on oil recovery from oil-wet rock systems, these wettability alteration models permit alteration of the rock wettability uniformly and independently from time. Properties such as capillary pressure, oil and water relative permeability, and interfacial tension are calculated by the use of an interpolation scaling factor between two wettability extremes: oil-wet and water-wet. In the present study, a novel time-dependent wettability alteration model is proposed in which the contact angle is correlated to the surfactant concentration through an empirical correlation developed by using experimental data. The model allows the rock wettability to be altered in a heterogeneous manner with time. The proposed model was tested against a number of experimental and simulation results. Very good quantitative agreements between the simulation outcomes and experimental data from the literature were shown. The simulation of surfactant solution imbibition in laboratory scale cores using the proposed new model showed that the wettability alteration should be considered as a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. Also, we found that gravity force is the primary cause of surfactant solution getting into the core and changing the rock wettability toward a less oil-wet state.
- North America > United States > Texas (0.93)
- Asia (0.68)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
Abstract This study deals with simulation model of Foam Assisted Water Alternating Gas (FAWAG) method that had been implemented to two Norwegian Reservoirs. Being studied on number of pilot projects, the method proved successful, but Field Scale simulation was never understood properly. New phenomenological foam model was tested with sensitivity analysis on foam properties to provide a guideline for the history matching process (GOR alteration) of FAWAG Pilot of Snorre Field (Statoil). The aim was to check the authenticity of presented new foam model in commercial software whether it is implementable on a complex geological model for quick feasibility studies, either for onward practical pilot or as justification for more detailed technical study. The simulation showed that Foam model is applicable. The mismatch between history and actual GOR in some periods of injection is due to the complexity of the fluid flows control inside reservoir. The way; how specific properties control the time of gas arrival and values of GOR are described. The analyses of the improvements in the injection schedule are shown. With increasing number of CO2 and FAWAG methods in preparation worldwide, the use of the simulation contributes to more precise planning of the schedule of water and gas injection, prediction of the injection results and evaluation of the method efficiency. The testing of the surfactant properties allows making grounded choice of surfactant to use. The analysis of the history match gives insight in the physics of in-situ processes. Detailed Qualitative analysis is presented for foam modeling against the FAWAG historical data that provides sharp idea of the behavior of Foam model for different foam factors, which in turn provides reasons for the unpredictable foam behavior in WFB Project and also serve as quick reference for future general foam pilot simulations at field scale.
- North America > United States (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.34)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 104 > Block 30/9 > Oseberg Field > Oseberg Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 079 > Block 30/9 > Oseberg Field > Tarbert Formation (0.99)
- (15 more...)