Author: Trevor Storm Pollock Publisher: ISBN: Category : Languages : en Pages : 0
Book Description
A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254). This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines. The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine. Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs.
Author: James J. Sheng Publisher: Elsevier Inc. Chapters ISBN: 0128057688 Category : Science Languages : en Pages : 43
Book Description
In this chapter, the fundamentals of surfactant flooding are covered, which include microemulsion properties, phase behavior, interfacial tension, capillary desaturation, surfactant adsorption and retention, and relative permeabilities. The surfactant–polymer interactions are discussed. The mechanisms and screening criteria are briefly discussed. The field cases presented include low-tension waterflooding (Loma Novia, Wichita County Regular field), sequential micellar/polymer flooding (El Dorado, Sloss), micellar/polymer flooding (Torchlight and Delaware-Childers), and Minas SP project preparation and SP flooding (Gudong).
Author: Hourshad Mohammadi Publisher: ISBN: Category : Enhanced oil recovery Languages : en Pages : 856
Book Description
Alkaline/surfactant/polymer (ASP) flooding is of increasing interest and importance because of high oil prices and the need to increase oil production. The benefits of combining alkali with surfactant are well established. The alkali has very important benefits such as lowering interfacial tension and reducing adsorption of anionic surfactants that decrease costs and make ASP a very attractive enhanced oil recovery method provided the consumption is not too large and the alkali can be propagated at the same rate as a synthetic surfactant and polymer. However, the process is complex so it is important that new candidates for ASP be selected taking into account the numerous chemical reactions that occur in the reservoir. The reaction of acid and alkali to generate soap and its subsequent effect on phase behavior is the most crucial for crude oils containing naphthenic acids. Using numerical models, the process can be designed and optimized to ensure the proper propagation of alkali and effective soap and surfactant concentrations to promote low interfacial tension and a favorable salinity gradient. The first step in this investigation was to determine what geochemical reactions have the most impact on ASP flooding under different reservoir conditions and to quantify the consumption of alkali by different mechanisms. We describe the ASP module of UTCHEM simulator with particular attention to phase behavior and the effect of soap on optimum salinity and solubilization ratio. Several phase behavior measurements for a variety of surfactant formulations and crude oils were successfully modeled. The phase behavior results for sodium carbonate, blends of surfactants with an acidic crude oil followed the conventional Winsor phase transition with significant three-phase regions even at low surfactant concentrations. The solubilization data at different oil concentrations were successfully modeled using Hand's rule. Optimum salinity and solubilization ratio were correlated with soap mole fractions using mixing rules. New ASP corefloods were successfully modeled taking into account the aqueous reactions, alkali/rock interactions, and the phase behavior of soap and surfactant. These corefloods were performed in different sandstone cores with several chemical formulations, crude oils with a wide range of acid numbers, brine with a wide range of salinities, and a wide range of temperatures. 2D and 3D sector model ASP simulations were performed based on field data and design parameters obtained from coreflood history matches. The phenomena modeled included aqueous phase chemical reactions of the alkaline agent and consequent consumption of alkali, the in-situ generation of surfactant by reaction with the acid in the crude, surfactant/soap phase behavior, reduction of surfactant adsorption at high pH, cation exchange with clay, and the effect of co-solvent on phase behavior. Sensitivity simulations on chemical design parameters such as mass of surfactant and uncertain reservoir parameters such as kv/kh ratio were performed to provide insight as the importance of each of these variables in chemical oil recovery. Simulations with different permeability realizations provided the range for chemical oil recoveries. This study showed that it is very important to model both surface active components and their effect on phase behavior when doing mechanistic ASP simulations. The reactions between the alkali and the minerals in the formation depend very much on which alkali is used, the minerals in the formation, and the temperature. This research helped us increase our understanding on the process of ASP flooding. In general, these mechanistic simulations gave insights into the propagation of alkali, soap, and surfactant in the core and aid in future coreflood and field scale ASP designs.
Author: Changli Yuan Publisher: ISBN: Category : Languages : en Pages : 242
Book Description
The depletion of oil reserves and higher oil prices has made chemical enhanced oil recovery (EOR) methods more attractive in recent years. Because of geological heterogeneity, unfavorable mobility ratio, and capillary forces, conventional oil recovery (including water flooding) leaves behind much oil in reservoir, often as much as 70% OOIP (original oil in place). Surfactant/polymer flooding targets these bypassed oil left after waterflood by reducing water mobility and oil/water interfacial tension. The complexity and uncertainty of reservoir characterization make the design and implementation of a robust and effective surfactant/polymer flooding to be quite challenging. Accurate numerical simulation prior to the field surfactant/polymer flooding is essential for a successful design and implementation of surfactant/polymer flooding. A recently developed unified polymer viscosity model was implemented into our existing polymer module within our in-house reservoir simulator, the Implicit Parallel Accurate Reservoir Simulator (IPARS). The new viscosity model is capable of simulating not only the Newtonian and shear-thinning rheology of polymer solution but also the shear-thickening behavior, which may occur near the wellbore with high injection rates when high molecular weight Partially Hydrolyzed Acrylamide (HPAM) polymers are injected. We have added a full capability of surfactant/polymer flooding to TRCHEM module of IPARS using a simplified but mechanistic and user-friendly approach for modeling surfactant/water/oil phase behavior. The features of surfactant module include: 1) surfactant component transport in porous media; 2) surfactant adsorption on the rock; 3) surfactant/oil/water phase behavior transitioned with salinity of Type II( - ), Type III, and Type II(+) phase behaviors; 4) compositional microemulsion phase viscosity correlation and 5) relative permeabilities based on the trapping number. With the parallel capability of IPARS, commercial scale simulation of surfactant/polymer flooding becomes practical and affordable. Several numerical examples are presented in this dissertation. The results of surfactant/polymer flood are verified by comparing with the results obtained from UTCHEM, a three-dimensional chemical flood simulator developed at the University of Texas at Austin. The parallel capability and scalability are also demonstrated.
Author: Tejas S. Ghorpade Publisher: ISBN: Category : Enhanced oil recovery Languages : en Pages : 148
Book Description
Enhanced oil recovery (EOR) is essential to recover bypassed oil and improve recovery factor. Alkaline-surfactant-polymer (ASP) flooding is a chemical EOR method that can be used to recover heavy oil containing organic acids from sandstone formations. It involves injection of alkali to generate in situ surfactants, improve sweep efficiency, and reduce interfacial tension (IFT) between displacing and displaced phase, and injection of a polymer to improve mobility ratio; typically, it is followed by extended waterflooding. The concentration of alkali, surfactant, and polymer used in the process depends on oil type, salinity of solution, pressure, temperature of the reservoir, and injection water quality. This project evaluates the effect of waterflooding on recovery, calculates the recovery factor for ASP flooding, and optimum concentration of alkali, surfactant, and polymer for an Alaskan reservoir. Also, the effects of waterflooding and improvement with ASP flooding are evaluated and compared. Studies of these effects on oil recovery were analyzed with a Computer Modeling Group (CMG)-generated model for the Alaskan North Slope (ANS) reservoir. Based on a literature review and screening criteria, the Western North Slope (WNS) 1 reservoir was selected for the ASP process. A CMG - WinProp simulator was used to create a fluid model and regression was carried out with the help of actual field data. The CMG - WinProp model was prepared with a 5 spot well injection pattern using the CMG STARS simulator. Simulation runs conducted for primary and waterflooding processes showed that the recovery factor increased from 3% due to primary recovery to 45% due to waterflooding at 500 psi drawdown for 60 years with a constant producing gas oil ratio (GOR). ASP flooding was conducted to increase recovery further, and optimum ASP parameters were calculated for maximum recovery. Also, effect of alkali, surfactant and polymer on recovery was observed and compared with ASP flood. If proved effective, the use of ASP chemicals for ANS reservoirs to increase the recovery factor could replace current miscible gas injection with chemical EOR. It will help to develop chemical flooding processes for heavier crude oil produced in harsh environments and create new horizons for chemical industries in Alaska.
Author: Muhammad Mansour Alhotan Publisher: ISBN: Category : Languages : en Pages : 280
Book Description
The vast global demand for energy coupled with the decreasing oil production capabilities of maturing fields raises the need for Enhanced Oil Recovery (EOR) technologies. Much of the oil in these maturing fields are yet to be extracted and remains in the reservoir as residual oil. Chemical EOR (CEOR) is a widely known and effective method in extracting the remaining oil in the reservoir post-secondary flooding. Surfactant-polymer flooding is a type of CEOR that enhances oil recovery by applying mobility control, forming micelles, and reducing interfacial tension. Simulation of CEOR floods before field application is essential to avoid deployment obstacles and to ensure the good design of the chemical formulations. In this thesis, reservoir simulators that utilize two-phase microemulsion model (CMG-STARS) and three-phase microemulsion model (UTCHEMRS & INTERSECT) are used to simulate surfactant-polymer flooding to determine and compare their results. Different models are used in the simulators to describe the physical behavior of injected chemicals inside the reservoir. Therefore, these models were examined and matched when possible. An extensive study was performed on the relative permeability models of INTERSECT and UTCHEMRS. For simulations, the physical behavior models of polymer and surfactant were constructed and validated on a 1D scale reservoir model. Then, the reservoir model was extended to a 3D model, where the physical models and results were further validated. Finally, simulations were conducted in a field-scale reservoir containing 680,400 grids, where results were compared and analyzed. The results for the relative permeability study demonstrated that the INTERSECT relative permeability model is complex, and more information is required to follow the sequence of equations and their dependencies. For the simulation, the 1D and 3D model results suggest an excellent match between the different simulators in modeling surfactant-polymer floods. In the case of the field-scale model, the simulators matched in terms of oil recovery and produced and injected total fluids while having similar average reservoir pressures
Author: Trevor Storm Pollock
Author: Dinesh Ochhavlal Shah
Author: Razieh Solatpour
Author: Abhijit Samanta
Author: 
Author: James J. Sheng
Author: Hourshad Mohammadi
Author: Changli Yuan
Author: Tejas S. Ghorpade
Author: Muhammad Mansour Alhotan