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Results
Abstract Currently, many reservoirs in the region approach the end of primary recovery phase where new techniques are needed to enhance recovery. Therefore, the need to optimize oil recovery from the current resources is very well understood by regional oil companies. To enhance oil recovery from current oil resources, field operators need to overcome the forces responsible for oil entrapment. Enhanced Oil Recovery techniques (EOR) introduce new energy into oil reservoirs to reduce the influence of these forces. Most of these resources contain light oil and are considered suitable candidates for either miscible or chemical EOR techniques. The first technique is challenged by the availability of suitable miscible gas. While, chemical EOR techniques are challenges by the high salt concentrations in the maturing oil reservoirs. The high salinity conditions encourage deficiencies in the performance of chemical EOR processes. Therefore, minimizing the effect of in situ salt on the injected chemical would impose tremendous improvement that leads to higher oil recovery. One way to diminish salt effect is to condition the oil reservoirs by injecting a slug of preflush water prior to chemical injection. In this paper, the performance of polymer flooding, after preflush slug, in high salinity reservoir is investigated by numerical simulation means. The injected slugs, both preflush and polymer, are driven by water. The objective is to identify the relationship between preflush, polymer, and drive water characteristics and oil recovery. Seven parameters were considered: preflush slug size, preflush salinity, polymer slug size, polymer concentration, polymer slug salinity, and drive water salinity. The results show that these parameters have various degree of influence on oil recovery. For example, increasing the preflush slug size would results in more oil recovery especially during the early time. Detailed findings will be presented in the paper.
- North America > United States (0.94)
- Asia > Middle East > Kuwait (0.15)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
A Comprehensive Evaluation of the Performances of Alkaline/Surfactant/Polymer in Conventional and Unconventional Reservoirs
Dang, Cuong T. (University of Calgary) | Nguyen, Ngoc T. (University of Calgary) | Chen, Zhangxin (John) (University of Calgary) | Nguyen, Huy X (Sejong University) | Bae, Wisup (Sejong University) | Phung, Thuoc H. (Vietsovpetro JV)
Abstract Chemical flooding, especially alkaline/polymer/surfactant (ASP) flooding is of significant increasing interest in mature reservoirs because of high oil prices and larger energy demands. However, it is a very complicated process, and the success of ASP has been mostly demonstrated in laboratory scale. Additionally, ASP is very sensitive to reservoir heterogeneity; therefore, it is urgent and necessary to have a comprehensive investigation of ASP flooding in different reservoir types for a wider and more successful implementation. This paper aims to solve the prior problems for achieving a new insight vision of ASP flooding. Firstly, a series of laboratory experiments were conducted to optimize the ASP solution. A new mixture of single and double tail anionic surfactant was proposed as a promising approach for high temperature and hardness reservoirs. These mixtures are also more compatible with polymer and increase the optimum salinity. All of the important factors such as alkaline/polymer/surfactant concentration, pH, temperature, salinity, ionic strength were taken in account. And, the experimental result was analyzed by experimental design techniques which allow for evaluating the interaction among those factors which were usually eliminated in literature. Based on these above achievements in laboratory, full fields scale simulations have been done to assess the performance of ASP in various real field conditions from conventional to unconventional reservoirs which are including traditional sandstone reservoir, tight sandstone oil reservoir, naturally fractured basement reservoir. As an observation result, ASP flooding brings a higher oil recovery (about 10 to 28%), and lower water cut than traditional waterflooding in all of four case studies. However, the incremental amount is not similar since geology characteristics have strong effects on ASP process. The simulation result proved that the fractured reservoirs with low matrix permeability are not suitable candidates for ASP. On the contrary, ASP has great potential for enhancing heavy oil recovery, especially in small and thin reservoirs. A sensitivity analysis was performed for determining the optimal ASP solution and injective scheme for each reservoir condition.
- Research Report > New Finding (0.47)
- Research Report > Experimental Study (0.46)
Laboratory and Simulation Study of Optimized Water Additives for Improved Heavy Oil Recovery
Wang, X.. (Saskatchewan Research Council) | Luo, P.. (Saskatchewan Research Council) | Zhang, Y.. (Saskatchewan Research Council) | Charkovskyy, V.. (Saskatchewan Research Council) | Huang, S.. (Saskatchewan Research Council)
Abstract This paper discusses a laboratory evaluation of the feasibility of different chemical flooding strategies and a simulation study to optimize the feasible strategies for a west-central Saskatchewan heavy oil reservoir. The integrated experimental approach was composed of oil/brine interfacial tension (IFT) measurements, polymer viscosity measurements, wetting tendency measurements, and sandpack coreflood tests. The experimental results showed that the equilibrium interfacial tension between reservoir oil and formation brine could be lowered to an ultralow level (0.05 mN/m) by adding a certain concentration of alkali and surfactant into the brine. The addition of alkali and surfactant caused the wettability characteristics in all tested systems to become oil-wet. All of the polymer solutions exhibited pseudo-plastic behaviour, i.e., the apparent viscosity decreased with increasing shear rate. A series of sandpack coreflood tests were carried out to investigate the recovery performance of alkali + surfactant, polymer, and alkali + surfactant + polymer (ASP) floods. Enhanced oil recoveries (from the chemical flood and extended waterflood) varied significantly from 0.71 to 14.65% OOIP. The coreflood results suggest that in enhanced waterflooding for recovering viscous heavy oil, mobility control by polymer is more important than IFT reduction by alkaline/surfactant. In the simulation study, the relative permeability curves were obtained through history matching. Then, as the sensitive operating parameters, the ASP slugs and polymer concentrations were tuned to show their effects on enhanced heavy oil recovery (EHOR). In summary, ASP flooding provides synergistic effects that can maximize the recovery performance.
- North America > United States (0.93)
- North America > Canada > Saskatchewan (0.25)
Abstract Surfactant-polymer (SP) flooding is one of the chemical EOR processes that are used to recover residual oil saturation. In high salinity/high hardness and high temperature applications many chemical flooding methods would not be effective. During the 80’s BP proposed low-tension polymer flooding (LTPF) method to overcome some of the challenges caused by using high concentration of surfactant during some early SP flooding projects and to reduce the cost of operation. Amphoteric surfactant shows high thermal and chemical stability in these environments was evaluated in this study. An experimental study was conducted to evaluate the performance of the low-tension polymer flooding (LTPF) process in recovering water flood residual oil using two types of amphoteric surfactants, two types of anionic surfactants, and two types of polymers that are suggested to be used for high salinity / high hardness at elevated temperature. Surface and interfacial tension, zeta potential and core flood experiments were conducted to study the surfactant-polymer interaction at high salinity brine, ability of the solution to lower IFT, surface charge to predict chemical retention, tertiary oil recovery, oil cut and pressure drop during chemical propagation in the porous media. In this study Berea sandstone cores with 1.5 in. diameter and 20 in. length were used to determine the above parameters. The core flood experiments were conducted at temperature and brine salinity of 95° C and around 172,000 ppm, respectively. Amphoteric surfactant showed association with two types of polymers, HPAM and AMPS that caused reduction in surface activity until polymer-free aggregate concentration was reached. Increasing polymer concentration increases the surfactant concentration needed to reach to polymer-free aggregate concentration. When HPAM polymer used in preparing chemical slug, it shows higher injectivity decline compared to AMPS. Anionic surfactant showed less chemical retention due to the negative surface charge on Berea sandstone particles when this type of surfactant is used. No significant recovery was obtained during surfactant flooding, which prove that IFT reduction can’t improve recovery without the aid of mobility control by polymers.
- North America > United States > Texas (0.46)
- North America > United States > West Virginia (0.45)
- North America > United States > Pennsylvania (0.45)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.82)
- Geology > Geological Subdiscipline > Geomechanics (0.81)
Abstract Relatively high oil prices, modest polymer prices, and advances that promote higher injectivity for polymer solutions have allowed polymer flooding to be applied in reservoirs with notably more viscous oils than in previous years. This paper describes a polymer flooding pilot project in the Tambaredjo field in Suriname. The average viscosity of the produced oil is ~1,700 cp, but solution gas reduces the effective oil viscosity in the reservoir to 400–600 cp (through the "foamy oil" mechanism). Interestingly, the primary drive mechanism in the pilot area is compaction—leading to ~20% OOIP recovery. Because various restrictions preclude application of thermal methods, polymer flooding was explored as a means to enhance oil recovery. The average permeability of the sand exceeds 4darcys, but the level of heterogeneity is significant (>10:1 permeability contrast is common). The first simulation efforts suggested that injection of 25–40-cp polymer solutions might be optimum, considering both displacement and injectivity. Consequently, ~40-cp polymer solutions were injected during the first part of the pilot. However, later analysis revealed that sweep efficiency could be improved significantly using polymer solutions up to 160 cp. Although injection was done at pressures below what was believed to be the formation parting pressure, injectivity data from several water injection cycles shows that partition of the formation followed by partial sustenance of the fracture did occur. Analysis of produced water salinities, polymer and tracer concentrations, water/oil ratios (WOR), and inter-well pressure responses all indicated that severe channeling (i.e., through fracture-like features) did not occur. Instead, analysis of the project response indicated that (1) sweep could benefit from injecting more viscous polymer solutions, (2) injectivity for more viscous polymers would not be a problem because of controlled (i.e., not detrimental) fracture extension, and (3) oil production rates could be enhanced (without sacrificing WOR) by increasing injection rates. Consequently, these ideas are currently being field tested in our project. This paper details results to date for this polymer pilot.
- North America > United States > Oklahoma (0.28)
- South America > Suriname > North Atlantic Ocean (0.24)
- South America > Guyana > North Atlantic Ocean (0.24)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Simulation of Gel Filter Cake Formation, Gel Cleanup, and Post-Frac Well Performance in Hydraulically Fractured Gas Wells
Charoenwongsa, S.. (Colorado School of Mines) | Kazemi, H.. (Colorado School of Mines) | Fakcharoenphol, P.. (Colorado School of Mines) | Miskimins, J. L. (Colorado School of Mines)
Abstract Polymer and gel damage is a major issue in the cleanup of hydraulically fractured gas wells. This paper addresses this issue by using a gas-water flow model which simulates fracture propagation with gel filter cake formation as mechanical trapping of polymer molecules on the fracture face and filtrate transport into the adjacent matrix. The model accounts for polymer as a chemical component. This approach is different than treating polymer as a highly viscous gel phase, which is the common method in most literature. In this model, the gel filter cake thickness is calculated based on experimental data. For leakoff, the model allows only the sheared polymer molecules, which are the major cause of formation permeability reduction, to cross the fracture face into the formation and adsorb on the matrix. Other features of the model include water blockage, non-Newtonian flow, non-Darcy flow, and proppant and reservoir compaction.
- North America > United States (1.00)
- Europe (1.00)