Browsing by Subject "Polymer flooding"

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An investigation of viscoelastic polymer flooding in high permeability sandstones
(2019-08) Jin, Julia Liu; Balhoff, Matthew T.; Mohanty, Kishore Kumar
Recovery of oil is the key consideration of oil production in underground reservoirs. The correlated decline in oil discoveries and increase in demand for oil have created a scenario in which enhanced oil recovery (EOR) technologies have become increasingly necessary to compensate for the growing energy demand. Polymer flooding has been used as one EOR technique to increase oil recovery. Several authors have observed reduction of residual oil in porous media using polymers that are viscoelastic. Five coreflood experiments were completed using aqueous hydrolyzed polyacrylamide (HPAM) and scleroglucan (EOR-grade) polymer solutions. HPAM polymers were solubilized in low salinity brine which created viscoelastic solutions. All experiments were completed in high-permeability (>1000mD) Bentheimer and Boise sandstones. Two Bentheimer cores were chemically treated to be considered oil-wet. Three other water-wet Boise cores were also used. All experiments were completed using light (4-6 cP) oil. The elastic polymer floods were formulated so that they would have high relaxation times, and therefore high Deborah numbers. Each elastic flood was followed by an inelastic polymer flood with a similar viscosity. The Deborah number for the inelastic polymer floods were less than or close to 1. Following the successful experiments using alternating elastic and inelastic polymer floods in Bentheimer sandstones, these experiments were conducted in different mediums to see if this phenomenon could be replicated under different circumstances. Experiment #1 replicated previous work completed using viscoelastic polymers and alternating elastic and inelastic floods. The results in coreflood #1 showed extremely promising results in the comparatively more heterogeneous Boise sandstone. After alternating between elastic and inelastic polymer floods, the residual oil saturation decreased to lower than 6%. The viscoelastic polymer floods following a waterflood decreased residual oil saturation. In four of the five experiments, the residual saturation after viscoelastic polymer floods closely matched the predicted saturation given by the Elastic Desaturation Curve (EDC) developed by Qi (2018). Except for one flood, the actual experimental S [subscript orp] values were within 1-3% of the predicted S [subscript orp]
Application of different types of solvents for heavy oil recovery : experimental study on dimethyl ether, organic alkalis, and surface active solvents
(2020-09-10) Baek, Kwang Hoon; Okuno, Ryosuke, 1974-; Huh, Chun; DiCarlo, David; Mohanty, Kishore K; Azom, Prince N
Various challenges in heavy oil recovery come from the low mobility of reservoir oil. For example, the heavy-oil displacement by water results in a large mobility ratio and therefore, inefficient volumetric sweep. Polymer flooding is the traditional method to improve the frontal stability of the oil displacement, but the polymer mobility is often optimized to be greater than the oil mobility because increasing the polymer viscosity adversely affects the oil production rate. The low mobility of reservoir oil also results in a large amount of steam required in steam-assisted gravity drainage (SAGD), one of the commercially successful methods of bitumen recovery. This research investigated the application of unconventional solvents for heavy oil recovery, such as dimethyl ether (DME), organic alkalis, and surface active solvents (SAS), as a potential additive to the injection fluid. These solvents are not conventionally used for enhanced oil recovery (EOR). The first part of the dissertation presents potential methods of improving the efficiency of SAGD by using water-soluble solvents. Phase-behavior data were obtained for mixtures of bitumen and water-soluble solvents. Experimental results indicated that use of organic alkalis at low concentrations (e.g., 0.5 wt% pyrrolidine) in low-salinity brine can yield efficient emulsification of bitumen in water. The affinity of the organic alkali for asphaltic bitumen was important for oil-in-water emulsification at a wide range of temperatures. The second part of the dissertation presents a potential method of improving polymer flooding by SAS that reduces the interfacial tension (IFT) between the oleic and aqueous phases. Results showed that the IFT reduction by three orders of magnitude (i.e., 15.8 to 0.025 dynes/cm) gave a reduced residual oil saturation and a delayed polymer breakthrough in polymer flooding experiments with no preceding water flood. When the straight polymer flooding resulted in an oil recovery factor of 47% at 1.0 pore-volume injected (PVI), the SAS-improved polymer flooding increased it to 63% with a SAS slug of 0.1 wt% for 0.5 PVI or 0.5 wt% for 0.1 PVI
The Application of Improved Numerical Techniques to 1-D Micellar/Polymer Flooding Simulation
(1981-08) Ohno, Takamasa; Pope, Gary A.
Three examples of three phase flow models which have been developed are compared under various conditions. Although the dif-ference in oil recovery and surfactant trapping among the models was rather large with constant. salinity, a salinity gradient produced high oil recovery and low surfactant trapping with all three models. Since surfactant trapping is important and it is highly uncertain, this is another reason for designing a micellar flood with a salinity gradient, or something equivalent to a salinity gradient. The semi-discrete method was applied to a 1-D micellar/polymer flooding simulator. By using a semi-discrete method, the time step size can be controlled and varied to be as large as pos-sible without sacrificing accuracy. The stability limit can also be detected with this method. The method is tested and compared with the fully discrete method in various conditions such as differ-ent phase behavior environments and with or without adsorption. In the application of the semi-discrete method, four different ODE in-tegrators were used. Two of them are explicit methods while the other two are implicit methods. Although the implicit methods did not work as well as the explicit methods, there may be some improve-ment possible. With respect to the computation time, one of the explicit methods which is based on the· Runge-Kutta approximation worked best. Although the method can save 20 to 30% computation time under some conditions, compared with the fully-discrete method, the results are highly problem-dependent. To improve the computation time, two methods are suggested. One is to check the error only in the oil or water component rather than all components or any other one component such as surfactant. The other is to check absolute error instead of relative error and multiply by a small conservative factor to the calculated time step size. The stability was analyzed for the oil bank, and for the surfactant front. The former imposes a rather constant limitation on the time step size continuously until the plateau of the oil bank is completely produced: Although approximate, the stability analysis for the surfactant front suggests an unconditional local instability, which is caused by the change in the fractional flow curve due to the surfactant.
Chemical enhanced oil recovery simulation in highly stratified heterogeneous reservoir : a field case study
(2020-03-27) Navas Guzman, Jorge Andres; Delshad, Mojdeh; Sepehrnoori, Kamy, 1951-
Oil and gas companies are looking for proven hydrocarbon reserves from their existent drained reservoirs with the objective to extend the production and economical life of their fields. The chemical enhanced oil recovery (CEOR) has raised with a myriad type of process that goes beyond the primary and secondary recovery. The polymer flooding (PF) is a widely applied process in reservoirs with low swept efficiency after the water flooding (WF) process. Colombian field has one of the first polymer pilots in the region with positive results of oil recovery in “A” sands. Thus, the operator is interested in the expansion of PF for the same reservoir and even in deeper reservoir sands. This thesis focuses in the evaluation of different scenarios of PF and surfactant polymer flooding (SPF) for the producer layers A and B with a mechanistic model, thus obtaining new recommendations for the recovery strategy in the field. Therefore, a sector model was constructed from a full field commercial simulator to the in-house simulator: UTCHEMRS. In addition, this sector model was migrated to a second commercial simulator allowing a performance comparison for three simulators. UTCHEMRS model was validated with the commercial simulators through the history matching (HM) phase. The primary and waterflood history match was in agreement with the field data. Simulation results suggested that PF for the base case in “A” sands presented an incremental oil recovery of up to 12% additional to water flooding. Additionally, PF was extended to the lower layer “B” sand to investigate the potential of polymer injection. The PF injection in both reservoirs simultaneously loses swept efficiency and decreases the oil recovery in 3%. However, a hypothetical case of new infill producer wells with the objective of testing the individual reservoir performance has revealed that PF is having important raises in oil recovery for B sands as well. Though, further research should be developed in order to strengthen this interpretation. Finally, the results of SPF case for A sands are inconclusive because a laboratory tests of surfactant phase behavior is needed to ensure the lowest IFT in reservoir conditions
Decision support for enhanced oil recovery projects
(2010-08) Andonyadis, Panos; Gilbert, Robert B. (Robert Bruce), 1965-; Lake, Larry W.
Recently, oil prices and oil demand are rising and are projected to continue to rise over the long term. These trends create great potential for enhanced oil recovery methods that could improve the recovery efficiency of reservoirs all over the world. The greatest challenges for enhanced oil recovery involve the technical uncertainty with design and performance, and the high financial risk. Pilot tests can help mitigate the risk associated with such projects; however, there is a question about the value of information from the tests. Decision support can provide information about the value of an enhanced oil recovery project, which can assist with alleviating financial risk and create more potential opportunities for the technology. The first objective of this study is to create a new simplified method for modeling oil production histories of enhanced oil recovery methods. The method is designed to satisfy three criteria: 1) it allows for quick simulations based on only a few physically meaningful input parameters; 2) it can create almost any potential type of realistic production history that may be realized during a project; and 3) it applies to all nonthermal enhanced oil recovery methods, including surfactant-polymer, alkali-surfactant polymer, and CO₂ floods. The developed method is capable of creating realistic curves with only four unique parameters. The second objective is to evaluate the predictive method against data from pilot and field scale projects. The evaluations demonstrate that the method can fit most realistic production histories as well as provided ranges for the input parameters. A sensitivity analysis is also performed to assist with determining how all of the parameters involved with the predictive method and the economic model influence the forecasted value for a project. The analysis suggests that the price of oil, change in oil saturation, and the size of the reservoir are the most influential parameters. The final objective is to establish a method for a decision analysis that determines the value of information of a pilot for enhanced oil recovery. The analysis uses the predictive method and economic model for determining economic utilities for every potential outcome. It uses a decision-based method to ensure that the non-informative prior probability distributions have an unbiased, consistent, and rational starting point. A simple example demonstrating the process is discussed and it is used to show that a pilot test provides some valuable information when there is minimal prior information. For future work it is recommended that more evaluations are performed, the decision analysis is expanded to include more input parameters, and a rational and logical method is developed for determining likelihood functions from existing information.
Design and Scaleup of Micellar-Polymer Flooding in the Presence of Heterogeneity
(1988-12) Shook, George Michael; Pope, Gary; Sepehrnoori, Kamy
A three dimensional, multiphase, multicomponent micellar-polymer simulator has been used to identify the most important scaling groups and design parameters in heterogeneous permeable media. This was done in a series of sensitivity studies where a single process design parameter was varied, holding all others constant. In this way the influence of each variable has been well established. The studies were conducted on two different reservoir types, both of which are of particular interest in chemical flooding. The variables studied include, among others, mobility ratio, gravity, transverse and longitudinal dispersion, capillary trapping forces, and salinity gradient design. A modified cation exchange formulation has also been presented. In addition to correcting an inconsistency in the governing equations, the side benefit of removing an iteration loop from the simulator is described. Finally, several gravity formulations are compared under conditions of segregated flow.
Efficiency of low salinity polymer flooding in sandstone cores
(2012-05) Kozaki, Chie; Pope, Gary A.; Mohanty, Kishore Kumar
Waterflooding has been used for many decades as a way of recovering oil from petroleum reservoirs. Historically the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. In recent years, however, evidence of increased oil recovery by injection of low salinity water has been observed in laboratories and fields. The technique is getting wider attention in the oil industry because it is more cost-effective than other EOR techniques. The present work demonstrates the synergy of low salinity water flooding and polymer flooding in the laboratory scale. The use of low salinity polymer solution in polymer flooding has significant benefits because considerably lower amount of polymer is required to make the solution of a target viscosity. Low salinity polymer flooding can also increase oil recovery by lowering residual oil saturation and achieve faster oil recovery by improving sweep efficiency. Several coreflood experiments were conducted to study the efficiency of low salinity water flooding and low salinity polymer flooding in mixed-wet Berea sandstone cores. All the core samples were aged with a crude oil at 90oC for 30-60 days before the tests. All the polymer floods were conducted in the tertiary mode. A synthetic formation brine (33,800 ppm) was chosen for high salinity water and a NaCl brine (1,000 ppm) for low salinity water. Medium molecular weight HPAM polymer, FlopaamTM 3330S was used due to the low/moderate permeability of the Berea sandstone cores used in this study. Coreflood tests indicate that injection of low salinity polymer solution reduces residual oil saturation by 5-10% over that of the high salinity waterflood. A part of the residual saturation reduction is due to low salinity and this reduction is achieved in less pore volumes of injection in the presence of polymers. Effluent ion analysis from both low salinity water flooding and low salinity polymer flooding showed a slight increase in divalent cation concentrations after the polymer breakthrough. Cation bridging may play a role in oil wettability and low salinity injection desorbs some of these cations.
Experimental investigation of the effect of polymers on residual oil saturation
(2015-05) Koh, Hee Song; Pope, Gary A.; Chun, Huh; Mohanty, Kishore; Balhoff, Matthew; Johnston, Keith P.
The main objective of this research was to better understand the effect of polymer flooding on the remaining oil saturation by conducting experiments and interpreting these experimental data in terms of measured polymer and rock characteristics. This is because one of the most important factors in chemical enhanced oil recovery (EOR) is mobility control, for which partially hydrolyzed polyacrylamide (HPAM) and other polymers are extensively used. Rheological properties of the EOR polymer solutions depend on the various factors such as a polymer’s molecular properties and concentration, salinity, hardness, shear rate and temperature. Therefore, rheological measurements with commonly employed EOR polymers under various conditions were made and the effect of these factors on the polymer’s viscosity and mobility was quantified. In addition to the steady shear viscosities, the oscillatory rheological properties were measured to better define the polymer's viscoelastic behavior during flow in porous media. Commonly used partially hydrolyzed polyacrylamides (HPAM) have been successfully used in the field for decades, but they hydrolyze at high temperature and eventually precipitate in the presence of high concentrations of divalent cations. New polymers that are stable in harsh environments (high salinity/hardness and high temperature) are in high demand because of the need for chemical EOR in oil reservoirs with these conditions. Both scleroglucan and NVP co- or ter-polymers show good filterability and transport properties in sandstone and carbonate cores at high temperature and in brine with high salinity and hardness. Therefore, both polymers are promising candidates for polymer flooding, surfactant-polymer flooding and alkali-surfactant-polymer flooding in hard brine at high temperature, and their rheological properties were also evaluated for some representative reservoir conditions. Several polymer coreflood experiments have been carried out using both sandpacks and reservoir cores, starting at different water cuts to measure the effect of polymer on the remaining oil saturation. In order to interpret the polymer corefloods, fractional flow theory that incorporated non-Newtonian rheology was developed and applied. The much higher oil recovery from polymer flooding compared to water flooding observed in numerous coreflood experiments is deemed to be mainly due to the improved microscopic or displacement sweep efficiency of the polymer. There is no clear evidence from these experiments that polymer floods reduce the residual oil saturation substantially when the experiments are done with low pressure gradients typical of the pressure gradients that are feasible under field conditions.
Feedback control of polymer flooding process considering geologic uncertainty
(2010-12) Mantilla, Cesar A., 1976-; Srinivasan, Sanjay; Pope, Gary A.; Nguyen, Quoc P.; Huh, Chun; Kamath, Jairam
Polymer flooding is economically successful in reservoirs where the water flood mobility ratio is high, and/or the reservoir heterogeneity is adverse, because of the improved sweep resulting from the mobility-controlled oil displacement. The performance of a polymer flood can be further improved if the process is dynamically controlled using updated reservoir models and a closed-loop production optimization scheme is implemented. However, the formulation of an optimal production strategy is based on uncertain production forecasts resulting from uncertainty in spatial representation of reservoir heterogeneity, geologic scenarios, inaccurate modeling, scaling, just to cite a few factors. Assessing the uncertainty in reservoir modeling and transferring it to uncertainty in production forecasts is crucial for efficiently controlling the process. This dissertation presents a feedback control framework that (1) assesses uncertainty in reservoir modeling and production forecasts, (2) updates the prior uncertainty in reservoir models by integrating continuously monitored production data, and (3) formulates optimal injection/production rates for the updated reservoir models. This approach focuses on assessing uncertainty in reservoir modeling and production forecasts originated mainly by uncertain geologic scenarios and spatial variations of reservoir properties (heterogeneity). This uncertainty is mapped in a metric space created by comparing multiple reservoir models and measuring differences in effective heterogeneity related to well connectivity and well responses characteristic of polymer flooding. Continuously monitored production data is used to refine the uncertainty map using a Bayesian inversion algorithm. In contrast to classical approach of history matching by model perturbation, a model selection problem is implemented where highly probable reservoir models are selected to represent the posterior uncertainty in production forecasts. The model selection procedure yields the posterior uncertainty associated with the reservoir model. The production optimization problem is solved using the posterior models and a proxy model of polymer flooding to rapidly evaluate the objective function and response surfaces to represent the relationship between well controls and an economic objective function. The value of the feedback control framework is demonstrated with two examples of polymer flooding where the economic performance was maximized.
Modeling and simulation of polymer flooding including the effects of fracturing
(2015-12) Li, Zhitao; Delshad, Mojdeh; Wheeler, Mary F.; Pope, Gary A.; Sepehrnoori, Kamy; Huh, Chun
Chemical enhanced oil recovery (EOR) technology has attracted increasing interest in recent years with declining oil production from conventional oil reserves. Water flooding of heterogeneous reservoirs with viscous oil leaves considerable amount of remaining oil even at high producing water cuts. Polymer flooding is a mature EOR technology for augmenting recovery of moderately viscous oil. Water soluble polymers are used to reduce water mobility and improve sweep efficiency. For very viscous oil, polymer flooding is a potential non-thermal approach for minimizing viscous fingering and improving both displacement sweep efficiency and volumetric sweep efficiency. Polymer manufacturing techniques has been significantly advanced since 1980’s, which provides improved polymer quality and keeps polymer price relatively low. Compared with unconventional oil recovery techniques such as hydraulic fracturing, well planned and optimized polymer flooding can be profitable even at pessimistic oil price. It is thus crucial to have a reservoir simulator that is able to accurately model polymer properties and simulate polymer flooding in complex reservoir systems. Polymer rheological behavior is dependent on polymer molecular structure, concentration, Darcy velocity, brine salinity, hardness, permeability, porosity, etc. We improved polymer rheology modeling for heterogeneous reservoirs where permeability varies for orders of magnitude. For an injection well, a large portion of pressure drop is lost near wellbore where apparent polymer viscosity as a function of Darcy velocity varies drastically. Conventional analytical well models fail to capture the non-Newtonian effect of apparent polymer viscosity and make injectivity predictions widely deviated from true solutions especially for coarse-grid simulations. We developed a semi-analytical polymer injectivity model and implemented it into UTCHEM. This model is able to handle both shear-thinning and shear-thickening polymer rheology. It successfully avoids the grid effect and matches fine-grid simulation results and analytical solutions. Another challenge is to model polymer injectivity under fracturing conditions. To maintain an economic polymer injection rate, wellbore pressure may exceed the fracture initiation pressure. We developed a framework to couple a fracture model with UTCHEM. This coupled simulator is able to model fracture propagation during polymer injection. Finally several simulation studies were conducted to show the impacts of polymer rheological behavior, loss of polymer into aquifer, near wellbore effect and fracture propagation.
New discovery to reduce residual oil saturation by polymer flooding
(2017-05) Erincik, Mehmet Zeki; Pope, G. A.; Balhoff, Matthew T.
Eight coreflood experiments were conducted to investigate the effect of aqueous hydrolyzed polyacrylamide (HPAM) polymer solutions on residual oil saturation in sandstone cores. Seven of the experiments were conducted in high-permeability (~1500 mD) Bentheimer sandstones, six of the cores were saturated with a viscous oil (~120 cp), and one core was saturated with a light (10 cp) oil. The eighth experiment was performed in a Berea sandstone core using the light oil. Experiments #6 to 8 were done by Pengpeng Qi. These experiments are included in this thesis to provide more complete and convincing results. All experiments were first saturated with brine, flooded with oil to reach initial oil saturation, and then waterflooded with brine to zero oil cut. For experiments with viscous oil, a viscous glycerin solution was injected after the waterflood until the oil cut was zero. FP 3630S polymer was used in the seven Bentheimer coreflood experiments and FP 3330S polymer was used in the Berea coreflood experiment. The polymer solutions in low salinity brine had a high relaxation time. Additional hydrolysis of the polymers was done to further increase the relaxation time. The coreflood experiments were designed to maximize the effect of viscoelasticity on the residual oil saturation by flooding the cores at a high Deborah number, N [subscript De], which ranged from 30-300. The low-salinity polymer floods were followed by a second polymer flood with a similar viscosity, but higher salinity (viscosity was controlled by increasing polymer concentration). The higher salinity resulted in a much lower polymer relaxation time than the first polymer in low salinity brine, and therefore a lower N [subscript De] for the coreflood. Two of the experiments included additional polymer floods by alternating between the low and high salinity polymer solutions. The original objective of this work was to investigate the effect of polymer elasticity (measured by the dimensionless Deborah number, N [subscript De]) on residual oil saturation. The polymer flooding experiments were designed to keep the capillary number less than the capillary number of the preceding glycerin floods as well as less than the critical capillary number to avoid a reduction in the residual oil saturation caused by a high capillary number. Early in this experimental study, a surprising and remarkable discovery was made that completely changed the direction of the research. The residual oil saturation following the high-salinity polymer floods was reduced to remarkably low values. All eight experiments showed that the low-salinity polymer floods with high Deborah numbers resulted in additional oil recovery. The average reduction in oil saturation was ~10% for the seven Bentheimer corefloods, including the one with light oil (4%). There was a (weak) correlation indicating lower residual oil saturations with increasing N [subscript De] consistent with the observations by Qi et al. (2017). The most surprising observation and discovery was that the residual oil saturation decreased between 4 and 21% with an average reduction of 11% when high-salinity polymer solution was injected following the low-salinity polymer flood with the same viscosity and at the same or similar flow rates. The total reduction in residual oil saturation from both polymer floods was 21% below the residual oil saturation of the glycerin floods with the same viscosity. The lowest residual oil saturation in these experiments was only 7%. This is a truly remarkable result considering the interfacial tension between the polymer solution and oil is about the same as between water and oil. Additional measurements are needed to understand the mechanisms e.g. wettability measurements before and after the polymer floods in low and high salinity brines.
New polymer rheology models based on machine learning
(2019-09-17) Alqahtani, Abdulwahab Saeed; Balhoff, Matthew T.
A successful polymer-type EOR project relies upon many factors, including an adequate characterization, description, and prediction of the polymer’s rheology. A high polymer viscosity can improve the mobility and sweep efficiency, but can also lead to poor injectivity. Polymers are generally non-Newtonian and the rheology is a function of in-situ shear rate, polymer concentration, salinity, temperature, molecular weight, and molecular structure. A priori estimation of polymer rheology using models is important for design of polymer floods and prediction using numerical reservoir simulators. Existing models require many fitting parameters, are purely empirical, and can rarely be used for a priori estimation. The objective of this work was to develop new models to predict the viscosity of HPAM polymers used in enhanced oil recovery (EOR) and implement them into a chemical flooding numerical reservoir simulator. The study uses a combination of fundamental, physical models and machine learning methods to develop new predictive models. The data used in the study includes the measured polymer rheology at various polymer concentrations, molecular weights and types, temperatures, and brine salinity and hardness. Data are first fit to the 4-parameter Carreau’s model and then advanced machine learning techniques are used to develop the models of the Carreau parameters with the aforementioned solution properties. The models are then used to predict the rheology of new samples which are validated against data measured on an ARES G2 rheometer. All data fit the 4-parameter Carreau model well. The new models for the zero-shear viscosity, shear thinning index, and time constant are a function of temperature, polymer concentration, salinity, hardness, and molecular weight using less than ten parameters
Optimum Design of Field-Scale Chemical Flooding Using Reservoir Simulation
(1996-08) Wu, Wei-Jr; Pope, Gary A.; Sepehrnoori, Kamy
Chemical flooding techniques for improved oil recovery are not widely applied in large-scale projects due to the high cost of chemical and uncertainty of oil price. An optimum design was constructed with new techniques and innovations such as high-efficiency chemicals, horizontal well technique, and advantage from the chemical reactions and interactions that is necessary to improve the cost-effectiveness of chemical floodings. A series of systematic sensitivity simulations with a realistic fluids and reservoir properties was adopted as the optimization process. The sensitivity factors included reservoir properties, injection fluid physical properties, the chemical reactions, and fluid/rock interactions. The simulations were perfo1med by a three-dimensional, multiphase, multicomponent chemical flooding simulator, UTCHEM, developed in the center for Petroleum and Geosystems Engineeling at The University of Texas at Austin. In the course of the optimum design construction, the competitive adsorption and dynamic adsorption model and the modifications of geochemical model for UTCHEM was made and validated. The optimization process was applied to three reservoirs each representative of low, moderate, and high heterogeneous permeability distributions for surfactant/polymer flooding. Several factors such as amount of chemicals, chemical adsorption, cation exchange, salinity gradient design, temperature effect on surfactant phase behavior, and low tension polymer injection scheme were studied in detail. A complete economic analysis was done on the typical on-shore U.S. oil reservoir case. We also investigated the alkaline/surfactant/polymer (ASP) flooding for a pilot with an inverted five-spot pattern and a total of 13 vertical wells and history matched three core flood results. This is the first time field-scale alkaline/surfactant/polymer flooding simulations with detailed reaction chemistry have been done. A tracer test simulation to obtain the pattern balance and optimum production rate for each producer was performed. A comparison of different improved oil recovery processes such as water, polymer, alkaline/polymer, surfactant/polymer, and alkaline/surfactant/polymer flooding was made. Finally, a series of sensitivity simulations was performed to approach the optimum design for the pilot. From these results, injection of high-efficiency surfactant and utilization of polymer for mobility control along with benefit of competitive adsorption and alkaline/surfactant/polymer process has high potential to improve the cost-effectiveness of chemical flooding.
A Predictive Model for Water and Polymer Flooding
(1984-04) Jones, Ralph Steven Jr; Lake, Larry W.; Pope, Gary A.
A "predictive evaluation model" (PEM) has been developed for feasibility analysis of water and polymer flooding. It is designed to produce a reservoir performance prediction suitable for economic analysis, with small computing time and input data requirements. The tools previously available for this purpose range from "binary" screening guides to sophisticated reservoir simulators. Binary screening guides do not consider the composite effect of reservoir parameters, and offer little information about economic feasibility. Many simplified prediction methods are available for waterflooding, and some for special cases of polymer flooding; however, the assumptions inherent in these methods limit applicability. Mathematical reservoir simulators are excellent prediction tools, but operational costs are often prohibitive when screening prospective reservoirs. The PEM was developed to fill the gap between simplified methods and reservoir simulators. The PEM uses "vertical equilibrium" methods to generate pseudorelative permeability curves, which are then used in a one-dimensional finite-difference model; this accounts for vertical heterogeneity and crossflow between communicating layers. Areal sweep correlations for pattern floods are then applied, followed by injection rate calculations. The PEM is based on the assumption of incompressible oil-water flow, but includes a correction for initial gas saturation. The resulting output consists of cumulative produced volumes and producing rates as a function of time for oil, water, and gas, as well as injection rates and volumes. The PEM considers many important flow properties which usually are accounted for only in reservoir simulators and requires a small fraction of the computing time. Polymer solution flow properties accounted for in the PEM include permeability reduction, adsorption, viscous fingering of drive water into polymer slug, and viscosity, all as functions of polymer concentration; the 11 inaccessible pore volume11 effect is also included. Predictions can also be made for tertiary polymer floods initiated after waterflooding. Injection rate calculations account for variations with time due to reservoir flow characteristics; the nonNewtonian behavior of polymer solutions is also considered. Because the PEM is designed for preliminary analysis, where extensive reservoir and fluid data may not be available, it includes routines for estimating relative permeability and capillary pressure curves. Although it is based on a stratified model, it can generate layers of different permeability given the Dykstra-Parsons permeability variation. These features reduce data requirements to a minimum when necessary, but the PEH also accepts more extensive data if it is available. Sensitivity studies were conducted to show the effects of various reservoir and fluid parameters on oil recovery and injection rates, for both water and polymer flooding. The PEM was validated by matches with a cross-sectional polymer flood simulator and other published simulation results; good agreement was observed. History matching of actual field data was successfully performed for a pilot waterflood and a field-scale polymer flood.
Proposal of a rapid model updating and feedback control scheme for polymer flooding processes
(2010-05) Mantilla, Cesar A., 1976-; Srinivasan, Sanjay; Sepehrnoori, Kamy
The performance of Enhanced Oil Recovery (EOR) processes is adversely affected by the heterogeneous distribution of flow properties of the rock. The effects of heterogeneity are further highlighted when the mobility ratio between the displacing and the displaced fluids is unfavorable. Polymer flooding aims to mitigate this by controlling the mobility ratio resulting in an increase in the volumetric swept efficiency. However, the design of the polymer injection process has to take into account the uncertainty due to a limited knowledge of the heterogeneous properties of the reservoir. Numerical reservoir models equipped with the most updated, yet uncertain information about the reservoir should be employed to optimize the operational settings. Consequently, the optimal settings are uncertain and should be revised as the model is updated. In this report, a feedback-control scheme is proposed with a model updating step that conditions prior reservoir models to newly obtained dynamic data, and this followed by an optimization step that adjusts well control settings to maximize (or minimize) an objective function. An illustration of the implementation of the proposed closed-loop scheme is presented through an example where the rate settings of a well affected by water coning are adjusted as the reservoir models are updated. The revised control settings yield an increase in the final value of the objective function. Finally, a fast analog of a polymer flooding displacement that traces the movement of random particles from injectors to producers following probability rules that reflect the physics of the actual displacement is presented. The algorithm was calibrated against the full-physics simulation results from UTCHEM, the compositional chemical flow simulator developed at The University of Texas at Austin. This algorithm can be used for a rapid estimation of basic responses such as breakthrough time or recovery factor and to provide a simplified characterization the reservoir heterogeneity. This report is presented to fulfill the requirements to obtain the degree of Master of Science in Engineering under fast track option. It summarizes the research proposal presented for my doctorate studies that are currently ongoing.
A Simulation Study of Polymer Flooding and Surfactant Flooding Using Horizontal Wells
(1995-08) Dakhlia, Hichem; Pope, Gary A.; Sepehrnoori, Kamy
The apparent economic attractiveness of polymer flooding and surfactant flooding has always been lessened by the fact that expensive polymer or surfactant is injected and then many years are required to produce the incremental oil. This is especially true in shallow, low-permeability oil reservoirs with low injectivity, but is also a factor even for reservoirs with high injectivity in expensive environments such as off shore. The potential for horizontal wells to accelerate oil production and thus improve the discounted cash flow may seem obvious, but the precise improvement depends on many complex factors such as vertical permeability and horizontal well location and can only be assessed using realistic simulations. In this study, the potential of improving polymer flooding and surfactant flooding by using horizontal wells has been systematically investigated with a compositional chemical flooding simulator (UTCHEM) that can model both three-dimensional heterogeneous reservoirs and realistic process behavior. For the purpose of this study, the capability of modeling horizontal wells was added to the simulator and the code modifications were successfully validated through a comparison of the numerical results to published analytical solutions. The reservoir description played a central role in this study. Stochastic reservoir descriptions were generated and multiple realizations of these were made to see the impact of heterogeneity on polymer flooding and surfactant flooding with both vertical and horizontal wells. While horizontal wells were found to improve injectivity, especially of the high-viscosity polymer, the sweep efficiency of the floods sometimes increased and sometimes decreased when horizontal wells were substituted for vertical wells. The location of the horizontal well was very important with respect to both the sweep efficiency and the injectivity and needed to be in a relatively high-permeability location to accelerate oil production. Oil recovery was found to be very sensitive to the correlation length, indicating that the stochastic approach for reservoir description has advantages over the layered approach that has traditionally been used in this type of study. The vertical permeability was the most sensitive parameter for horizontal wells and needed to be moderate to high (on the order of 0.1) to give adequate injectivity, although using vertical drainholes off the horizontal injector was found to shorten the project life in cases of low vertical permeability. Surfactant flooding was found to be more sensitive to these factors than waterflooding and even polymer flooding. Many other factors were investigated to evaluate the potential of improving the cost effectiveness of polymer flooding and surfactant flooding and these results are reported in this study. Under some circumstances, the use of horizontal injectors with vertical producers appeared to have economic merit, but these circumstances are clear only after a careful study with realistic reservoir and process descriptions and detailed economic analysis.
Simulations of subsurface multiphase flow including polymer flooding in oil reservoirs and infiltration in vadose zone
(2009-12) Yuan, Changli; Delshad, Mojdeh; Wheeler, Mary F. (Mary Fanett)
With the depletion of oil reserves and increase in oil price, the enhanced oil recovery methods such as polymer flooding to increase oil production from water flooded fields are becoming more attractive. Effective design of these processes is challenging because the polymer chemistry has a strong effect on reaction and fluid rheology, which in turn has a strong effect on fluid transport. We have implemented a well-established polymer model within the Implicit Parallel Accurate Reservoir Simulator (IPARS), which enables parallel simulation of non-Newtonian fluid flow through porous media. The following properties of polymer solution are modeled in this work: 1) polymer adsorption; 2) polymer viscosity as a function of salinity, hardness, polymer concentration, and shear rate; 3) permeability reduction; 4) inaccessible pore volume. IPARS enables field-scale polymer flooding simulation with its parallel computation capability. In this thesis, several numerical examples are presented. The result of polymer module is verified by UTCHEM, a three-dimensional chemical flood simulator developed at the University of Texas at Austin. The parallel capability is also tested. The influence of different shear rate calculations is investigated in homogeneous and heterogeneous reservoirs. We observed that the wellbore velocity calculation instead of Darcy velocity reduces the grid effect for coarse mesh. We noted that the injection bottom hole pressure is very sensitive to the shear rate calculation. However, cumulative oil recovery and overall oil saturation appear to not be sensitive to grid and shear rate calculation for same reservoir. There are two models to model the ground water infiltration in vadose zone. One is Richard’s Equation (RE) model. And the other is two-phase flow model. In this work, we compare the two-phase model with an RE model to ascertain, under common scenarios such as infiltration or injection of water into initially dry soils, the similarities and differences in solutions behaviors, the ability of each model to simulate such infiltration processes under realistic scenarios, and to investigate the numerical efficiencies and difficulties which arise in these models. Six different data sets were assembled as benchmark infiltration problems in the unsaturated zone. The comparison shows that two-phase model holds for general porous media and is not limited by several assumptions that must be made for the RE formulation, while RE is applicable only for shallow regions (vadose) that are only several meters in depth and a fully saturated bottom boundary condition must be assumed.
A Study of Polymer/Surfactant Interactions for Micellar/Polymer Flooding Applications
(1978-12) Tsaur, Kerming; Pope, Gary A.
Static measurements of the phase volumes of mixtures of surfactant, polymer, alcohol, water, n-octane, sodium chloride, and in some cases polymer additives were made. A limited number of viscosity, phase concentration, and IFT measurements were also made. The purpose was to systematically determine the affect of various polymers on the phase behavior of various surfactant formula-tions. Measurements with and without oil (n-octane) were made across a range of salinity appropriate to the particular surfactant at temperatures between 24 and 75° C. The polymers used were xanthan gum, hydrolyzed polyacrylamide, polyacrylamide, hydroxyethylcellulose, and polyethyleneoxide of three different molecular weights. The surfactants used were Exxon's C 12 MEAOXS, Witco's TRS 10-80, Stepan's Petrostep 465, Alcolac's Siponate DS-10, GAF's Igepal C0-530 and C0-610, and Witco's ethoxylated alcohol TDA-100. The alcohols were isobutyl, secondary butyl, isopentanol, and isopropanol. The oil free (i.e. no added oil) solutions showed a characteristic phase seperation into an aqueous surfactant rich phase and an aqueous polymer rich phase, at some sufficiently high salinity (NaCl concentration), which we call the CEC. The CEC was found to be a characteristic 6f a given surfactant/alcohol combination, which shifts with the solubility of the surfactant, qualitatively the ., same way as the optimal salinity does. But the CEC was found to be independent of the polymer type, polymer concentration (between the 100 and 1000 ppm limits investigated), and surfactant concentration. The CEC increases with temperature for the anionic surfactants and decreases with temperature for the nonionic surfactants. When oil was added to the above mixtures an entirely different pattern of phase behavior was observed. The particular formulations form the typical sequence of lower phase microemulsion and excess oil; middle phase microemulsion, excess oil, and excess brine; and upper phase microemulsions and excess brine; as salinity increases. The sequence with polymer was precisely the same over most of the salinity range but deviated over a limited range of salinity: the three phase region simply shifts a small distance to the left on the salinity scale. Also, and probably more significantly, some of the "aqueous" phases in the critical region of the shift (which is also just above oil-free CEC salinity) were found to be gel-like in nature. These apparently occur under conditions such that the polymer concentration in the excess brine of the three phase systems becomes very high, due to the fact that almost all the polymer is always in the brine phase, even when the brine phase is very small. Thus an overall 1000 ppm of polymer can easily be concentrated to 10000 ppm or more. One of the most remarkable aspects of the phase behavior of the surfactant/polymer systems is that the same patterns are observed for all combinations of anionic and nonionic surfactants and polymers. Also, little difference was observed in the IFT values with and without polymer. The three phase systems still exhibited ultra-low IFT values. Obviously, significant differences did occur in the brine viscosities when polymer was added. The polymer free mixtures were themselves quite viscous, however; and the viscosity of the oil free surfactant rich phases (above the CEC) were significantly higher when in equilibrium with a polymer rich aqueous phase, even though apparently containing almost no polymer. The polymer rich phases had normal viscosities as judged by the same polymer in the same brine at the expected concentration assuming all of the polymer was in the polymer rich phase. The affect of polymer on the systems with oil was to increase the viscosity of the water rich phase only, with little effect on the microemulsion phase unless it was the water rich phase.
A Technical Survey of Polymer Flooding Projects
(1983-05) Manning, Robert Kenneth; Lake, Larry W.
A comprehensive survey of polymer flooding projects is essential to a thorough evaluation of enhanced oil recovery methods. This work seeks to statistically analyze the actual and projected performance of these projects. The report establishes a large data base of oil recovery, reservoir, and fluid identifiers for abandoned, current, and contemplated proj~cts. This data base was divided into subsets of field-wide and pilot projects. Statistics for each subset were determined separatel~ from both an analytical and a graphical perspective, and then were subsequently compared. One of the most important results found in these statistics is that the actual oil recovery of field-wide projects shows a close agreement with the I majority of previous surveys in the literature, except with respect to the identifier, actual oil recovery I (STB per lb polymer injected). This close agreement is demonstrated by similar, and in some cases, more favorable results than in previous surveys, with mean values of 3.85% OOIP, 4.22% Remaining OIP, 34.40 STB per Ac-Ft, and 3.74 STB oil recovered per lb polymer injected. Another significant result is that projects injecting polyacrylamide solutions into sandstone reservoirs accounted for the largest percentage contributions to the total actual oil recovery. The statistical computations include regression analyses of oil recovery as a function of selected fluid and reservoir identifiers. These analyses yielded statistically significant regression coefficients for ten oil recovery functions with the fallowing reservoir and fluid identifiers as independent variables: porosity, permeability, water-to-oil mobility ratio, polymer solution-to-oil mobility ratio, polymer solution pore volume, oil viscosity, water-to-oil ratio at start, average polymer concentration, mobile oil saturation, and net pay-to-gross pay ratio. No statistically significant regression coefficients were obtained for permeability variation, and, therefore, this result means that this reservoir identifier should be excluded as a screening factor for prospective polymer flooding projects.
The application of microfluidics in the study of multiphase flow and transport in porous media of improved hydrocarbon recovery methods
(2021-07-11) Du, Yujing; Balhoff, Matthew T.; Pope, Gary A; Mohanty, Kishore K; Prodanovic, Masa; Werth, Charles J
Fundamental investigation of the underlying physics in multiphase flow and transport phenomena in porous media is crucial for many engineering processes, including environmental remediation, geological sequestration, and improved hydrocarbon recovery. Microfluidics are widely used to provide direct, in-time visualization of multiphase flow behavior at the pore-scale and sometimes extend to the representative elementary volumes (REV) scale. Qualitative and quantitative analysis are obtained from microfluidic experiments and are used for mechanisms interpretations. In this work, microfluidics and micromodels are designed to explore fundamental mechanisms in several enhanced/improved oil recovery processes by performing systematic experiments. First, a study of the low salinity effects in improved oil recovery by microfluidics experiments is presented which explains a type of low-salinity effect with delayed oil recovery and without the presence of clay. Experiments were performed from single-pore microfluidics to a REV scale reservoir-on-a-chip model. A time-dependent, oil-water interaction controlled by diffusion was proposed based on the pore-scale observations. Second, the time-dependent behaviors and the role of surfactant during the low salinity waterflood is further investigated by systematic experiments in a 2.5D, inch-long micromodel using mineral oils with different surfactant concentrations and water with different salinities. It is found that the low salinity effects are significant when the surfactant concentration is sufficiently high. The surfactant also dominates the time-dependent behaviors, where higher surfactant concentration leads to shorter delay time. Third, three inch-long “reservoir-on-a-chip” micromodels were utilized to probe the impacts of the microfracture connectivity on the displacement efficiency and sweep patterns when the mobility ratio is unfavorable and the displacement is unstable. It was observed the presence of microfractures do not necessarily improve the displacement efficiency, but the microfracture connectivity, capillary number and wettability altogether impact on the displacement patterns and the ultimate recovery. Last, the role of viscoelasticity’s effects in reducing residual oil saturation is investigated by performing microfluidic experiments in foot-long (30 cm), heterogeneous glass micromodels (“coreflood-on-a-chip”). Significant redistribution and reconnection of residual ganglia occur due to viscoelasticity induced instabilities during high-viscoelasticity polymer floods, which results in residual ganglia remobilization that ultimately reduces residual saturation