Browsing by Subject "Waterflood"
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Item Application of dynamic optimization methods for foam floods in stratified reservoirs(2018-08-17) Tang, Brandon Chok-Yie; Nguyen, Quoc P.Efficient recovery of oil from heavily stratified carbonate reservoirs can be very technically challenging, even when applying waterflood, gasflood, or WAG (water-alternating gas) processes. To date, relatively few field or pilot applications of foam flooding have been conducted due to an incomplete understanding of how foam will behave in the field. The reservoir of interest studied in this work is oil-wet and consists of a stratified upper high-permeability zone overlaying a lower low-permeability zone. This study seeks to assess the performance of the foam flooding process in oil recovery and develop an optimum field injection strategy based upon various objective functions. In the process, the impact of initial waterflooding and varying foam strength on the optimum project termination time, as well as the sensitivity of foam parameters on the optimum field injection strategy is investigated. Two main optimization techniques are tested: static optimization, where the injection parameters are set once at the beginning of the simulation, and dynamic optimization, where injection parameters are optimized in five-year intervals over the life of the well. The dynamic optimization was performed in two ways: a local dynamic optimization and an early-time weighted optimization. In general, the dynamic optimization outperformed the static optimization with respect to all objective functions. Over the course of the study, a variety of objective functions were utilized. The objective functions began with maximizing cumulative oil recovery and evolved to maximizing oil recovery while minimizing gas utilization ratio, and finally maximizing net present value (NPV). From the results, it was ultimately shown that the global dynamic optimization of NPV was the most useful way of obtaining a field injection strategy. The optimal process design parameters indicated that high volumes of surfactant as well as gas in the lower zone needed to be injected early in the life of the project to best maximize NPV. From the optimal termination time study, it was found that the optimal termination time for the project was around ten years. Varying extents of initial waterflooding and alteration of foam strength did not have an impact on the suggested termination time. From the foam strength sensitivity, it was found that among the factors (water saturation, oil saturation, surfactant concentration) considered, the maximum dry-out water saturation had the most profound impact on the NPV. Ultimately, this work develops the framework necessary to create a field injection strategy for foam flooding in the stratified oil-wet reservoir used in this study, but can be extended to other types of reservoirs.Item Enhanced oil recovery of heavy oils by non-thermal chemical methods(2013-05) Kumar, Rahul, active 2013; Mohanty, Kishore KumarIt is estimated that the shallow reservoirs of Ugnu, West Sak and Shraeder Bluff in the North Slope of Alaska hold about 20 billion barrels of heavy oil. The proximity of these reservoirs to the permafrost makes the application of thermal methods for the oil recovery very unattractive. It is feared that the heat from the thermal methods may melt this permafrost leading to subsidence of the unconsolidated sand (Marques 2009; Peyton 1970; Wilson 1972). Thus it is necessary to consider the development of cheap non-thermal methods for the recovery of these heavy oils. This study investigates non-thermal techniques for the recovery of heavy oils. Chemicals such as alkali, surfactant and polymer are used to demonstrate improved recovery over waterflooding for two oils (A:10,000cp and B:330 cp). Chemical screening studies showed that appropriate concentrations of chemicals, such as alkali and surfactant, could generate emulsions with oil A. At low brine salinity oil-in-water (O/W) emulsions were generated whereas water-in-oil (W/O) emulsions were generated at higher salinities. 1D and 2D sand pack floods conducted with alkali surfactant (AS) at different salinities demonstrated an improvement of oil recovery over waterflooding. Low salinity AS flood generated lower pressure drop, but also resulted in lower oil recovery rates. High salinity AS flood generated higher pressure drop, high viscosity emulsions in the system, but resulted in a greater improvement in oil recovery over waterfloods. Polymers can also be used to improve the sweep efficiency over waterflooding. A 100 cp polymer flood improved the oil recovery over waterflood both in 1D and 2D geometry. In 1D geometry 1PV of polymer injection increased the oil recovery from 30% after waterflood to 50% OOIP. The tertiary polymer injection was found to be equally beneficial as the secondary polymer injection. It was also found that the combined application of AS and polymer did not give any major advantage over polymer flood or AS flood alone. Chemical EOR technique was considered for the 330cp oil B. Chemical screening studies showed that microemulsions could be generated in the system when appropriate concentrations of alkali and surfactant were added. Solubilization ratio measurement indicted that the interfacial tension in the system approached ultra-low values of about 10-3 dynes/cm. The selected alkali surfactant system was tested in a sand pack flood. Additionally a partially hydrolyzed polymer was used to provide mobility control to the process. The tertiary injection of ASP (Alkali-Surfactant-Polymer) was able to improve the oil recovery from 60% OOIP after the waterflood to almost 98% OOIP. A simple mathematical model was built around viscous fingering phenomenon to match the experimental oil recoveries and pressure drops during the waterflood. Pseudo oil and water relative permeabilities were calculated from the model, which were then used directly in a reservoir simulator in place of the intrinsic oil-water relative permeabilities. Good agreement with the experimental values was obtained. For history matching the polymer flood of heavy oil, intrinsic oil-water relative permeabilities were found to be adequate. Laboratory data showed that polymer viscosity is dependent on the polymer concentration and the effective brine salinity. Both these effects were taken into account when simulating the polymer flood or the ASP flood. The filtration theory developed by Soo and Radke (1984) was used to simulate the dilute oil-in-water emulsion flow in the porous media when alkali-surfactant flood of the heavy oil was conducted. The generation of emulsion in the porous media is simulated via a reaction between alkali, surfactant, water and heavy oil. The theory developed by Soo and Radke (1984) states that the flowing emulsified oil droplets clog in pore constrictions and on the pore walls, thereby restricting flow. Once captured, there is a negligible particle re-entrainment. The simulator modeled the capture of the emulsion droplets via chemical reaction. Next, the local water relative permeability was reduced as the trapping of the oil droplets will reduce the mobility of the water phase. This entrapment mechanism is responsible for the increase in the pressure drop and improvement in oil recovery. The model is very sensitive to the reaction rate constants and the oil-water relative permeabilities. ASP process for lower viscosity 330 cp oil was modeled using the UTCHEM multiphase-multicomponent simulator developed at the University of Texas at Austin. The simulator can handle the flow of three liquid phases; oil, water and microemulsion. The generation of microemulsion is modeled by the reaction of the crude oil with the chemical species present in the aqueous phase. The experimental phase behavior of alkali and surfactant with the crude oil was modeled using the phase behavior mixing model of the simulator. Oil and water relative permeabilities were enhanced where microemulsion is generated and interfacial tension gets reduced. Experimental oil recovery and pressure drop data were successfully history matched using UTCHEM simulator.Item Forecasting of isothermal enhanced oil recovery (EOR) and waterflood processes(2011-12) Mollaei, Alireza; Delshad, Mojdeh; Lake, Larry W.; Patzek, Tadeusz W.; Edgar, Thomas F.; Lasdon, Leon S.Oil production from EOR and waterflood processes supplies a considerable amount of the world's oil production. Therefore, the screening and selection of the best EOR process becomes important. Numerous steps are involved in evaluating EOR methods for field applications. Binary screening guides in which reservoirs are selected on the basis of reservoir average rock and fluid properties are consulted for initial determination of applicability. However, quick quantitative comparisons and performance predictions of EOR processes are more complicated and important than binary screening that are the objectives of EOR forecasting. Forecasting (predicting) the performance of EOR processes plays an important role in the study, design and selection of the best method for a particular reservoir or a collection of reservoirs. In EOR forecasting, we look for finding ways to get quick quantitative results of the performance of different EOR processes using analytical model/s before detailed numerical simulations of the reservoirs under study. Although numerical simulation of the reservoirs is widely used, there are significant obstacles that restrict its applicability. Lack of necessary reservoir data and time consuming computations and analyses can be barriers even for history matching and/or predicting EOR/waterflood performance of one reservoir. There are different forecasting (predictive) models for evaluation of different secondary/tertiary recovery methods. However, lack of a general purpose EOR/waterflood forecasting model is unsatisfactory because any differences in results can be caused by differences in the model rather than differences in the processes. As the main objective of this study, we address this deficiency by presenting a novel and robust analytical-base general EOR and waterflood forecasting model/tool (UTF) that does not rely on conventional numerical simulation. The UTF conceptual model is based on the fundamental law of material balance, segregated flow and fractional flux theories and is applied for both history matching and forecasting the EOR/waterflood processes. The forecasting model generates the key results of isothermal EOR and waterflooding processes including variations of average oil saturation, recovery efficiency, volumetric sweep efficiency, oil cut and oil rate with real or dimensionless time. The forecasting model was validated against field data and numerical simulation results for isothermal EOR and waterflooding processes. The forecasting model reproduced well (R2> 0.8) all of the field data and reproduced the simulated data even better. To develop the UTF for forecasting when there is no injection/production history data, we used experimental design and numerical simulation and successfully generated the in-situ correlations (response surfaces) of the forecasting model variables. The forecasting model variables were proven to be well correlated to reservoir/recovery process variables and can be reliably used for forecasting. As an extension to the abilities of the forecasting model, these correlations were used for prediction of volumetric sweep efficiency and missing/dynamic pore volume of EOR and waterflooding processes.Item Investigation of the correlation between waterflood maturity and appropriate optimum salinity(2020-06-30) Wagner, Ryan James; Nguyen, Quoc P.This work sets out to establish a correlation between waterflood maturity and the appropriate optimum salinity of a surfactant formulation. This is done by introduction of the novel concept of a critical waterflood “pre-flush,” specifically its presence and effect on Low-Tension-Gas (LTG) injection. The conditions of this work are for an offshore process with high salinity, moderate permeability, and only seawater available for use during enhanced oil recovery (EOR). LTG is a process that involves the co-injection of a surfactant solution and gas in order to achieve ultra-low interfacial tension from Type III microemulsion and mobility control due to generation of foam in the porous media. This technology has been used in various severe reservoir conditions such as high salinity, high temperature, and low permeability. Furthermore, field studies with similar injection strategy and use of foam have been conducted. Phase behavior testing was first conducted to create and identify two surfactant formulations. These formulations would allow for the testing of different scenarios along the research methodology outlined for this offshore project. Five coreflood experiments were then conducted to test these various scenarios. The pertinent data gained from the coreflood experiments were pressure drop during LTG, and oil cut, oil recovery, and effluent salinity of the LTG process. The presence of a critical pre-flush and its effects on LTG were shown from the dataset gathered. It was determined that the salinity maturity of a waterflood and the resulting salinity environment for LTG was heavily impacted by the waterflood pre-flush. The impact of the pre-flush on the presence of foam and effectiveness of each coreflood is also analyzed. The existence of a correlation between the waterflood maturity and appropriate optimum salinity for EOR is shown in this workItem Modeling of recovery process characterization using magnetic nanoparticles(2013-12) Rahmani, Amir Reza; Bryant, Steven L.; Huh, ChunStable dispersions of magnetic nanoparticles that are already in use in biomedicine as image-enhancing agents, also have potential use in subsurface applications. Surface-coated nanoparticles are capable of flowing through micron-size pores across long distances in a reservoir with modest retention in rock. Tracing these contrast agents using the current electromagnetic tomography technology could potentially help track the flood-front in waterflood and EOR processes and characterize the reservoir. The electromagnetic (EM) tomography used in the petroleum industry today is based on the difference between the electrical conductivity of reservoir fluids as well as other subsurface entities. The magnetic nanoparticles that are considered in this study, however, change the magnetic permeability of the flooded region, which is a novel application of the existing EM tomography technology. As the first fundamental step, the magnetic permeability change in rock due to injecting magnetic nanoparticles is quantified as a function of particle and reservoir properties. Subsequently, a new formulation is devised to compute the sensitivity of magnetic measurements to magnetic permeability perturbations. The results are then compared with the sensitivity to conductivity perturbations to identify the application space of magnetic contrast agents. Using numerical simulations, the progress of magnetic nanoparticle bank is monitored in the reservoir through time-lapse magnetic tomography measurements that are expected. Initially, simple models for displacement of injection banks are assumed and the level of complexity is gradually increased to incorporate the realities of fluid flow in the reservoir. The fluid-flow behavior of the nanoparticles is dynamically integrated with time-lapse magnetic response. Since the nanoparticles could help illuminate the flow paths, they could be used to indirectly measure reservoir heterogeneities. Therefore, numerous case studies are demonstrated where reservoir heterogeneity could potentially be inferred. Finally, fundamental pore-scale models are developed as a first step towards the multiple fluid phases extension of the EM tomography application. Using magnetic nanoparticles to improve electromagnetic tomography provides several strategic advantages. One key advantage is that the magnetic nanoparticles provide high resolution measurements at very low frequencies where the conductivity contrast is hardly detectable and casing effect is manageable. In addition, the sensitivity of magnetic measurements at the early stages of the flood is significantly improved with magnetic nanoparticles. Moreover, the vertical resolution of magnetic measurements is significantly enhanced with magnetic nanoparticles present in the vicinity of source or receiver. The fact that the progress of the magnetic slug can be detected at very early stages of the flood, that the traveling slug’s vertical boundaries can be identified at low frequencies, that the reservoir heterogeneities could potentially be characterized, and that the magnetic nanoparticles can be sensed much before the actual arrival of the slug at the observer well, provides significant value of using magnetic contrast agents for reservoir illumination.Item A numerical study of the impact of waterflood pattern size on ultimate recovery in undersaturated oil reservoirs(2014-08) Altubayyeb, Abdulaziz Samir; Lake, Larry W.The reserve growth potential of existing conventional oil reservoirs is huge. This research, through numerical simulation, aims to evaluate pattern size reduction as a strategy for improving waterflood recovery in undersaturated oil reservoirs. A plethora of studies have reported improvements in waterflood recovery resulting from pattern size reduction in heterogeneous reservoirs. The dependence of waterflood recovery on pattern size was attributed to factors such as areal reservoir discontinuity, preferential flooding directions, “wedge-edge” oil recovery, irregular pattern geometry, communication with water-bearing zones, vertical reservoir discontinuity, and project economics (Driscoll, 1974). Though many of these publications relied on decline curve analysis in estimating ultimate oil recovery, simulations completed in this thesis support their findings, specifically for compartmentalized reservoirs, fractured reservoirs, and layered reservoirs. Geostatistically-generated permeability fields were employed in the creation of various types of reservoir models. These models were populated with vertical production and injection wells. Sensitivity analysis was then performed on three development scenarios: 160, 40, and 10 acre five-spots. Based on assigned production and injection constraints, the quantity of oil recovered at simulation termination was used to calculate ultimate recovery efficiency. In homogeneous reservoir models, simulation results suggest that waterflood recovery was independent of pattern size. Similar results were also obtained from models with highly-variable non-zero permeabilities. On the other hand, pattern size reduction was found to enhance oil recovery from reservoir models with a high degree of permeability anisotropy. In such reservoirs, recovery was found to be highly dependent on bottom-hole injection pressures. The higher the injection pressure the larger the quantity of oil bypassed by widely spaced patterns. Likewise, high infill potential exists for reservoir models exhibiting areal discontinuity. In these types of models, the improvement in waterflood recovery resulting from pattern size reduction was directly related to the percentage of imbedded zero-permeability grid blocks. Ultimate oil recovery depended on the percolation of permeable grid blocks between production and injection wells. Increasing well density also enhanced waterflood recovery in vertically discontinuous reservoir models. In such layered reservoirs, the amount oil unswept with large patterns was considerably diminished because of the improved injection profiles associated with tighter patterns.Item 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.Item Proved Recovery From the Seventy-Six West Field by Geologically Targeted Infill Drilling and Waterflood Optimization(1993-05) Sen, Naresh D.; Miller, Mark A.; Reis, John C.The Seventy-Six West field, Duval County, Texas, has produced 4.6 MMstb of oil from the Cole "B" and "C" sands of the Jackson Group of Eocene age. Due to the complex reservoir geometry, mobile oil has been trapped in the reservoir in compartments poorly contacted by the current well spacing or in zones poorly swept by waterflood. If operated in its current mode, the field is projected to produce an additional 347 Mstb, for a total of 4.9 MMstb. This represents approximately 20% of the OOIP, indicating that there is much potential for development This study evaluated the current status of the northeastern part of the field, and examined schemes for efficient recovery of the remaining oil by geologically targeted infill drilling and waterflood optimization. Waterflooding has the potential for improving recovery by repressurizing the reservoir. Infill drilling should provide access to inefficiently drained areas and possibly untapped compartments. Simulation results indicate that waterflooding can significantly improve oil recovery. Recovery can further be improved by combining infill drilling with a waterflood. The waterflood can be optimized by an appropriate injection scheme to reduce the amount of water injected without significantly reducing the amount of oil recovered.Item A Theoretical Analysis of Viscous Crossflow(1981-08) Zapata, Vito J.; Lake, Larry W.In order to account for vertical heterogeneities in a petroleum reservoir, discrete layers with varying rock and/or fluid properties are introduced as a modeling tool. The addition of layers into an otherwise one-dimensional flow problem requires that consideration be given to the vertical flow of fluids in the event communication between any adjacent layers exists. This transverse flow of reservoir fluids is termed crossflow and in this work only crossflow induced from viscous forces will be studied. This research treats viscous crossflow only on a theoretical basis seeking to describe the mechanism in terms of reservoir and fluid properties. Emphasis is placed on understanding the physics controlling fluid movement rather than recording the results of viscous crossflow on a reservoir's performance by varying the reservoir's parameters. Through the assumption of vertical equilibrium, solutions to the stratified waterflood process including fractional flow behavior are derived, as well as simplified solutions to enhanced oil recovery processes for reservoirs modeled with layers. These solutions to the vertical equilibrium viscous crossflow phenomenon provide insight for making sound engineering decisions regarding implementation of displacement processes.