Browsing by Subject "EOR"
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Item Analysis of Field Development Strategies of CO2 EOR/Capture Projects Using a Reservoir Simulation Economic Model(2013-05-03) Saint-Felix, MartinA model for the evaluation of CO2-EOR projects has been developed. This model includes both reservoir simulation to handle reservoir properties, fluid flow and injection and production schedules, and a numerical economic model that generates a monthly cash flow stream from the outputs of the reservoir model. This model is general enough to be used with any project and provide a solid common basis to all of them. This model was used to evaluate CO2-EOR injection and production strategies and develop an optimization workflow. Producer constraints (maximum oil and gas production rates) should be optimized first to generate a reference case. Further improvements can then be obtained by optimizing the injection starting date and the injection plateau rate. Investigation of sensitivity of CO2-EOR to the presence of an aquifer showed that CO2 injection can limit water influx in the reservoir and is beneficial to recovery, even with a strong water drive. The influence of some key parameters was evaluated: the producer should be completed in the top part of the reservoir, while the injector should be completed over the entire thickness; it is recommended but not mandatory that the injection should start as early as possible to allow for lower water cut limit. Finally, the sensitivity of the economics of the projects to some key parameters was evaluated. The most influent parameter is by far the oil price, but other parameters such as the CO2 source to field distance, the pipeline cost scenario, the CO2 source type or the CO2 market price have roughly the same influence. It is therefore possible to offset an increase of one of them by reducing another.Item Application of Polymer Gels as Conformance Control Agents for Carbon Dioxide for Floods in Carbonate Reservoirs(2012-10-15) Al Ali, Ali 1986-With the production from mature oil fields declining, the increasing demand of oil urges towards more effective recovery of the available resources. Currently, the CO2 Floods are the second most applied EOR processes in the world behind steam injection. With more than 30 years of experience gained from CO2 flooding, successful projects have showed incremental oil recovery ranging from 7 to 15 % of the oil initially in place. Despite all of the anticipated success of CO2 floods, its viscosity nature is in heterogeneous and naturally fractured reservoirs is challenging; CO2 will flow preferentially through the easiest paths resulting in early breakthrough and extraction ineffectiveness leaving zones of oil intact. This research aims at investigating gel treatments and viscosified water-alternating-gas CO2 mobility control techniques. A set of experiments have been conducted to verify the effectiveness and practicality of the proposed mobility control approaches. Our research employed an imaging technique integrating an X-Ray CT scanner with a CT friendly aluminum coreflood cell. With the integrated systems, we were able to obtain real time images when processed provide qualitative and qualitative evaluations to the coreflood. The research studies included preliminary studies of CO2 and water injection performance in fractured and unfractured cores. These experiments provided a base performance to which the performances of the mobility control attempts were compared. We have applied the same methodology in evaluation of the experimental results to both conformance control gel treatments and viscosified water-alternating-gas CO2 mobility control. The gel conformance control studies showed encouraging results in minimizing the effect of heterogeneities directing the injected CO2 to extract more oil from the low permeability zones; the gel strength was evaluated in terms of breakdown and leakoff utilizing the production data aided with CT imaging analysis. The viscosified water coupled with CO2 investigations showed great promising results proving the superiority over neat CO2 injection. This research serves as a preliminary understanding to the applicability of tested mobility control approaches providing a base to future studies in this category of research.Item Application of X-ray CT for investigating fluid flow and conformance control during CO2 injection in highly heterogeneous media(Texas A&M University, 2005-08-29) Chakravarthy, DeepakFractured reservoirs have always been considered poor candidates for enhanced oil recovery. This can be attributed to the complexities involved in understanding and predicting performance in these reservoirs. In a fractured system, the high permeability fracture forms the preferred pathway for the injected fluids, and a large amount of oil that is stored in the matrix is bypassed. Hence, a good understanding of multiphase fluid flow in fractures is required to reduce oil bypass and increase recovery from these reservoirs. This research investigates the effect of heterogeneity and injection rates on oil bypass and also the various techniques used for the improvement of sweep efficiency in heterogeneous systems. Several coreflood experiments were performed using homogeneous and heterogeneous cores and a 4th generation X-Ray CT scanner was used to visualize heterogeneity and fluid flow in the core. Porosity and saturation measurements were made during the course of the experiment. The experimental results indicate that injection rates play a very important role in affecting the recovery process, more so in the presence of fractures. At high injection rates, faster breakthrough of CO2 and higher oil bypass were observed than at low injection rates. But very low injection rates are not attractive from an economic point of view. Hence water viscosified with a polymer was injected directly into the fracture to divert CO2 flow into the matrix and delay breakthrough, similar to the WAG process. Although the breakthrough time reduced considerably, water ??leak off?? into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome ??leak off?? problems and effectively divert CO2 flow into the matrix. This experimental research will serve to increase the understanding of fluid flow and conformance control methods in fractured reservoirs.Item Development of a four-phase flow simulator to model hybrid gas/chemical EOR processes(2015-05) Lotfollahi Sohi, Mohammad; Pope, Gary A.; Delshad, Mojdeh; Sepehrnoori, Kamy; Mohanty , Kishore K; Johnston, Keith PHybrid gas/chemical Enhanced Oil Recovery (EOR) methods are such novel techniques to increase oil production and oil recovery efficiency. Gas flooding using carbon dioxide, nitrogen, flue gas, and enriched natural gas produce more oil from the reservoirs by channeling gas into previously by-passed areas. Surfactant flooding can recover trapped oil by reducing the interfacial tension between oil and water phases. Hybrid gas/chemical EOR methods benefit from using both chemical and gas flooding. In hybrid gas/chemical EOR processes, surfactant solution is injected with gas during low-tension-gas or foam flooding. Polymer solution can also be injected alternatively with gas to improve the gas volumetric sweep efficiency. Most fundamentally, wide applications of hybrid gas/chemical processes are limited due to uncertainties in reservoir characterization and heterogeneity, due to the lack of understanding of the process and consequently lack of a predictive reservoir simulator to mechanistically model the process. Without a reliable simulator, built on mechanisms determined in the laboratory, promising field candidates cannot be identified in advance nor can process performance be optimized. In this research, UTCHEM was modified to model four-phase water, oil, microemulsion, and gas phases to simulate and interpret chemical EOR processes including free and/or solution gas. We coupled the black-oil model for water/oil/gas equilibrium with microemulsion phase behavior model through a new approach. Four-phase fluid properties, relative permeability, and capillary pressure were developed and implemented. The mass conservation equation was solved for total volumetric concentration of each component at standard conditions and pressure equation was derived for both saturated and undersaturated PVT conditions. To model foam flow in porous media, comprehensive research was performed comparing capabilities and limitations of implicit texture (IT) and population-balance (PB) foam models. Dimensionless foam bubble density was defined in IT models to derive explicitly the foam-coalescence-rate function in these models. Results showed that each of the IT models examined was equivalent to the LE formulation of a population-balance model with a lamella-destruction function that increased abruptly in the vicinity of the limiting capillary pressure, as in current population-balance models. Foam models were incorporated in UTCHEM to model low-tension-gas and foam flow processes in laboratory and field scales. The modified UTCEM reservoir simulator was used to history match published low-tension-gas and foam coreflood experiments. The simulations were also extended to model and evaluate hybrid gas/chemical EOR methods in field scales. Simulation results indicated a well-designed low-tension-gas flooding has the potential to recover the trapped oil where foam provides mobility control during surfactant and surfactant-alkaline flooding in reservoirs with very low permeability.Item Development of compositional three-phase relative permeability and hysteresis models and their application to EOR processes(2016-12) Mohammad Reza Beygi, Mohammad Reza; Delshad, Mojdeh; Wheeler, Mary F. (Mary Fanett); Pope, Gary A; Sepehrnoori, Kamy; Mohanty, Kishory K.; Arbogast, ToddEnhanced oil recovery (EOR) techniques have the potential to improve hydrocarbon recovery and project economics substantially. Characterizing fluid displacement and the relevant multiphase flow properties are essential to modeling EOR processes to reliably forecast the performance and economics. The spatial-temporal distribution of fluids spans a broad spectrum of composition and saturation spaces. In addition, a fundamental understanding of characteristic parameters of interphase mass-transfer in various EOR applications is crucial to capture and model fluid displacement. Relative permeability is a critical characteristic petrophysical property for modeling fluid displacement in porous media. Also, hysteresis phenomena govern physics of fluid flow in many subsurface applications such as multicyclic EOR processes, geological CO2 sequestration, and natural gas storage. Capillary trapping is the essence of hysteresis to trap fluids. In this research, we developed a high-fidelity computational tool for integrating compositional three-phase relative permeability and hysteresis to assist in accurate modeling of multicycle and compositional EOR methods. This viable tool can be implemented into general-purpose reservoir simulators to model field-scale projects. It consists of an integrated compositionally-consistent three-phase relative permeability and three-phase hysteresis models. The developed three-phase relative permeability model is valid on entire saturation and composition spaces, is simple with one free parameter for each phase, and is versatile for all phases and wettability states. The general model is saturation-path dependent and adopts a linear saturation-weighted interpolation scheme for calculation of relative permeability parameters. For the compositional relative permeability modeling, we developed a general framework applicable to hydrocarbon and non-hydrocarbon phases. The developed framework provides a pragmatic approach for adding the direct impact of composition, pressure, and temperature and is independent of the conventional phase-labeling method. The proposed framework unifies thermodynamics, petrophysics, and geochemistry to enhanced relative permeability modeling. Relative permeability parameters are calculated based on a mapping scheme of current-state bulk and interphase Gibbs free energy onto corresponding initial-state values. We applied the developed framework to modeling lowsalinity waterflood and complex fluid displacement of near-critical fluids. The three-phase hysteresis model provides a general and straightforward approach for calculation of capillary trapping in multicyclic processes. The developed hysteresis model provides a set of cycle-dependent relative permeability curves and applies to any three-phase relative permeability model by incorporating the free-saturation concept. We implemented the developed toolbox into two in-house compositional reservoir simulators (i.e., IPARS and UT-DOECO2). Several synthetic field cases are discussed to validate the implemented models conceptually. Using the enhanced simulators, we demonstrated accurate modeling of multiphase fluid displacement and trapping in EOR processes such as water-alternate-gas injection scheme, low-tension gas flood (i.e., foam), and carbon capture, utilization, and storage (CCUS).Item Engineering and economics of enhanced oil recovery in the Canadian oil sands(2014-05) Hester, Stephen Albert, III; Fisher, W. L. (William Lawrence), 1932-Canada and Venezuela contain massive unconventional oil deposits accounting for over two thirds of newly discovered proven oil reserves since 2002. Canada, primarily in northern Alberta province, has between 1.75 and 1.84 trillion barrels of hydrocarbon resources that as of 2013 are obtained approximately equally through surface extraction or enhanced oil recovery (EOR) (World Energy Council, 2010). Due to their depth and viscosity, thermal based EOR will increasingly be responsible for producing the vast quantities of bitumen residing in Canada’s Athabasca, Cold Lake, and Peace River formations. Although the internationally accepted 174-180 billion barrels recoverable ranks Canada third globally in oil reserves, it represents only a 9-10% average recovery factor of its very high viscosity deposits (World Energy Council, 2010). As thermal techniques are refined and improved, in conjunction with methods under development and integrating elements of existing but currently separate processes, engineers and geoscientists aim to improve recovery rates and add tens of billions of barrels of oil to Canada’s reserves (Cenovus Energy, 2013). The Government of Canada estimates 315 billion barrels recoverable with the right combination of technological improvements and sustained high oil prices (Government of Canada, 2013). Much uncertainty and skepticism surrounds how this 75% increase is to be accomplished. This document entails a thorough analysis of standard and advanced EOR techniques and their potential incremental impact in Canada’s bitumen deposits. Due to the extraordinary volume of hydrocarbon resources in Canada, a small percentage growth in ultimate recovery satisfies years of increased petroleum demand from the developing world, affects the geopolitics within North America and between it and the rest of the world, and provides material benefits to project economics. This paper details the enhanced oil recovery methods used in the oil sands deposits while exploring new developments and their potential technical and economic effect. CMG Stars reservoir simulation is leveraged to test both the feasible recoveries of and validate the physics behind select advanced techniques. These technological and operational improvements are aggregated and an assessment produced on Canada’s total recoverable petroleum reserves. Canada has, by far, the largest bitumen recovery operation in the world (World Energy Council, 2010). Due to its resource base and political environment, the nation is likely to continue as the focus point for new developments in thermal EOR. Reservoir characteristics and project analysis are thus framed using Canada and its reserves.Item Enhanced oil recovery in fractured vuggy carbonates(2014-05) Chen, Peila; Mohanty, Kishore Kumar; Pope, Gary A.; Balhoff, Matthew T.; Delshad, Mojdeh; Arbogast, Todd J.Naturally fractured carbonates contribute substantially to global oil reserves. Waterflood and gas-oil gravity drainage (GOGD) recover oil from the fractured oil-wet carbonates, with limited success due to poor sweep and very low recovery factors. Surfactant flooding has shown a great potential to enhance oil recovery in the oil-wet carbonates by reducing interfacial tension and/or altering wettability. Carbonates are characterized by the wide pore-size distributions. Surfactant EOR cannot be successfully implemented in a fractured, oil-wet, carbonate reservoir unless the reservoir is fully characterized and all of the mechanisms involved in oil recovery are fully understood. NMR T₂ measurement, mercury injection capillary pressure test (MICP), thin-section imaging, and computerized tomography (CT) scanning were conducted in the characterization of vuggy dolomite cores from the field. Both thin section and CT images reveal that the touching vugs and separate vugs co-exist in the core samples. Although the vuggy porosity is estimated to be 85%, the matrix controls the permeability of the core because of poor vug connectivity. MICP and NMR T₂ measurements show multimodal pore-throat and pore-body size distributions. Reconstructed 3D CT porosity maps indicate that the vugs in the field dolomite are large and randomly distributed, while the vugs in the Silurian dolomite are small and densely populated. A single-phase tracer test performed under CT scanner reveals a large porosity variation and the preferential flow paths within the field dolomite core. The mercury withdrawal test and NMR T₂ measurement have indicated that snap-off retains oil in the vugs due to the large aspect ratio pores and the large length-scale of the oil blobs. The imbibition oil recovery from the initially oil-wet field dolomite core is 20% lower (in OOIP) than that from the Silurian dolomite core, mainly because of an unfavorable pore structure in the field dolomite core. A few surfactants were selected as promising candidates for wettability alteration because they possess aqueous stability in hard brine at elevated temperatures and reduce contact angles. The divalent cations in the hard brine significantly suppress the anionic surfactant-mediated wettability alteration. The removal of Ca²⁺, and then Mg²⁺ from the hard brine progressively promotes anionic surfactant-assisted wettability alteration, evidenced by decreasing contact angles. The addition of sufficient amount of divalent ion scavengers, including chelating agents (e.g. EDTA.4Na) and scale inhibitors (e.g. Sodium Polyacrylate) in the hard brine, rescues the anionic surfactant-mediated wettability alteration. We propose that the scavenger reduces the concentration of free divalent cations, and promotes the release of the surfactant monomers, which favors wettability alteration through the surfactant adsorption mechanism. The scavenger- triggered mineral dissolution only weakly contributes to the imbibition oil recovery. Experiments and simulation studies consistently showed the synergy between wettability alteration and IFT reduction in a surfactant-assisted gravity-driven process. The residual oil saturation after gravity drainage is approximately 10~20% higher than that by gravity-driven imbibition if the two processes have the same trapping number N[subscript T], which implies that wettability alteration contributes to oil recovery from the oil-wet carbonates. A critical capillary number was found in the capillary desaturation curve plotted for the spontaneous imbibition tests, not for gravity drainage tests. In a UTCHEM model, wettability alteration is represented by the changes in P[subscript c], k[subscript r] and CDC. The simulation successfully history-matched and also predicted the incremental oil recovery by the surfactant formulations. The sensitivity study carried out in UTCHEM simulation shows the strong effects of fluid density, capillary pressure and vuggy pore structures on oil recovery. Three current available oil recovery prediction models (Hagoort, 1980; Aronofsky, 1958; Gupta and Civan, 1994) were tested against imbibition experiments. Two new analytical models were developed in this work, which significantly improved the quality of matching with experimental oil recovery. The matrix-fracture transfer functions, derived from the analytical oil recovery models, can be implemented in a dual-porosity simulator, providing more accurate numerical simulations of oil production in the fractured reservoirs. Lastly, we investigated the feasibility of using single well tracer test (SWTT) in the fractured reservoirs to determine the ROS or connate water saturation. The fractures studied are mainly small-scale fractures. The effects of fracture and its orientation on SWTTs were studied in four Berea cores with a single fracture in each core, orientated as 90°, 60°, 30°, and 0° against dominant flow direction. A simple Cartesian grid without dual porosity in UTCHEM simulator is adequate to interpret the experimental data. A synthetic field-scale SWTT is not sensitive to the presence of moderate degrees of small-scale fractures. The sensitivity study of fluid drift, representing flow irreversibility in a fractured reservoir, reveals the existence of a critical drift velocity, below which the tracer breakthrough curves (BTCs) are interpretable.Item Enhanced Oil Recovery in High Salinity High Temperature Reservoir by Chemical Flooding(2012-02-14) Bataweel, Mohammed AbdullahStudying chemical enhanced oil recovery (EOR) in a high-temperature/high-salinity (HT/HS) reservoir will help expand the application of chemical EOR to more challenging environments. Until recently, chemical EOR was not recommended at reservoirs that contain high concentrations of divalent cations without the need to recondition the reservoir by flooding it with less saline/ less hardness brines. This strategy was found ineffective in preparing the reservoir for chemical flooding. Surfactants used for chemical flooding operating in high temperatures tend to precipitate when exposed to high concentrations of divalent cations and will partition to the oil phase at high salinities. In this study amphoteric surfactant was used to replace the traditionally used anionic surfactants. Amphoteric surfactants show higher multivalent cations tolerance with better thermal stability. A modified amphoteric surfactant with lower adsorption properties was evaluated for oil recovery. Organic alkali was used to eliminate the water softening process when preparing the chemical solution and reduce potential scale problems caused by precipitation due to incompatibility between chemical slug containing alkali and formation brine. Using organic alkali helped in minimizing softening required when preparing an alkali-surfactant-polymer (ASP) solution using seawater. Solution prepared with organic alkali showed the least injectivity decline when compared to traditional alkalis (NaOH and Na2CO3) and sodium metaborate. Adding organic alkali helped further reduce IFT values when added to surfactant solution. Amphoteric surfactant was found to produce low IFT values at low concentrations and can operate at high salinity / high hardness conditions. When mixed with polymer it improved the viscosity of the surfactant-polymer (SP) solution when prepared in high salinity mixing water (6% NaCl). When prepared in seawater and tested in reservoir temperature (95?C) no reduction in viscosity was found. Unlike the anionic surfactant that causes reduction in viscosity of the SP solution at reservoir temperature. This will not require increasing the polymer concentration in the chemical slug. Unlike the case when anionic surfactant was used and more polymer need to be added to compensate the reduction in viscosity. Berea sandstone cores show lower recovery compared to dolomite cores. It was also found that Berea cores were more sensitive to polymer concentration and type and injectivity decline can be a serious issue during chemical and polymer injection. Dolomite did not show injectivity decline during chemical and polymer flooding and was not sensitive to the polymer concentration when a polymer with low molecular weight was used. CT scan was employed to study the displacement of oil during ASP, SP, polymer and surfactant flooding. The formation and propagation oil bank was observed during these core flood experiments. ASP and SP flooding showed the highest recovery, and formation and propagation of oil bank was clearer in these experiments compared to surfactant flooding. It was found that in Berea sandstone with a permeability range of 50 to 80 md that the recovery and fluid flow was through some dominating and some smaller channels. This explained the deviation from piston-like displacement, where a sharp change in saturation in part of the flood related to the dominated channels and tapered front with late arrival when oil is recovered from the smaller channels. It was concluded that the recovery in the case of sandstone was dominated by the fluid flow and chemical propagation in the porous media not by the effectiveness of the chemical slug to lower the IFT between the displacing fluid and oil.Item Enhanced Oil Recovery of Viscous Oil by Injection of Water-in-Oil Emulsion Made with Used Engine Oil(2012-08-20) Fu, XuebingSolids-stabilized water-in-oil emulsions have been suggested as a drive fluid to recover viscous oil through a piston-like displacement pattern. While crude heavy oil was initially suggested as the base oil, an alternative oil ? used engine oil was proposed for emulsion generation because of several key advantages: more favorable viscosity that results in better emulsion injectivity, soot particles within the oil that readily promote stable emulsions, almost no cost of the oil itself and relatively large supply, and potential solution of used engine oil disposal. In this research, different types of used engine oil (mineral based, synthetic) were tested to make W/O emulsions simply by blending in brine. A series of stable emulsions was prepared with varied water contents from 40~70%. Viscosities of these emulsions were measured, ranging from 102~104 cp at low shear rates and ambient temperature. Then an emulsion made of 40% used engine oil and 60% brine was chosen for a series of coreflood experiments, to test the stability of this emulsion while flowing through porous media. Limited breakdown of the effluent was observed at ambient injection rates, indicating a stability of the emulsion in porous media. Pressure drops leveled off and remained constant at constant rate of injection, indicating steady-state flows under the experimental conditions. No plug off effect was observed after a large volume of emulsion passed through the cores. Reservoir scale simulations were conducted for the emulsion flooding process based on the emulsion properties tested from the experiments. Results showed significant improvement in both displacement pattern and oil recovery especially compared to water flooding. Economics calculations of emulsion flooding were also performed, suggesting this process to be highly profitable.Item An experimental and simulation study of the effect of geochemical reactions on chemical flooding(2010-12) Chandrasekar, Vikram, 1984-; Delshad, Mojdeh; Pope, Gary A.The overall objective of this research was to gain an insight into the challenges encountered during chemical flooding under high hardness conditions. Different aspects of this problem were studied using a combination of laboratory experiments and simulation studies. Chemical Flooding is an important Enhanced Oil Recovery process. One of the major components of the operational expenses of any chemical flooding project, especially Alkali Surfactant Polymer (ASP) flooding is the cost of softening the injection brine to prevent the precipitation of the carbonates of the calcium and magnesium ions which are invariably present in the formation brine. Novel hardness tolerant alkalis like sodium metaborate have been shown to perform well with brines of high salinity and hardness, thereby eliminating the need to soften the injection brine. The first part of this research was aimed at designing an optimal chemical flooding formulation for a reservoir having hard formation brine. Sodium metaborate was used as the alkali in the formulation with the hard brine. Under the experimental conditions, sodium metaborate was found to be inadequate in preventing precipitation in the ASP slug. Factors affecting the ability of sodium metaborate to sequester divalent ions, including its potential limitations under the experimental conditions were studied. The second part of this research studied the factors affecting the ability of novel alkali and chelating agents like sodium metaborate and tetrasodium EDTA to sequester divalent ions. Recent studies have shown that both these chemicals showed good performance in sequestering divalent ions under high hardness conditions. A study of the geochemical species in solution under different conditions was done using the computer program PHREEQC. Sensitivity studies about the effect of the presence of different solution species on the performance of these alkalis were done. The third part of this research focused on field scale mechanistic simulation studies of geochemical scaling during ASP flooding. This is one of the major challenges faced by the oil and gas industry and has been found to occur when sodium carbonate is used as the alkali and the formation brine present in situ has a sufficiently high hardness content. The multicomponent and multiphase compositional chemical flooding simulator, UTCHEM was used to determine the quantity and composition of the scales formed in the reservoir as well as the injection and production wells. Reactions occurring between the injected fluids, in situ fluids and the reservoir rocks were taken into consideration for this study. Sensitivity studies of the effect of key reservoir and process parameters like the physical dispersion and the alkali concentration on the extent of scaling were also done as a part of this study.Item Experimental demonstration and improvement of chemical EOR techniques in heavy oils(2013-05) Fortenberry, Robert Patton; Pope, G.A.Heavy oil resources are huge and are currently produced largely with steam-driven technology. The purpose of this research was to evaluate an alternative to steam flooding in heavy oils: chemical EOR. Acidic components abundant in heavy crude oils can be converted to soaps at high pH with alkali, reducing the interfacial tension (IFT) between oil and water to ultra-low levels. In an attempt to harness this property, engineers developed alkaline and alkaline-polymer (AP) flooding EOR processes, which met limited success. The primary problem with AP flooding was the soap is usually too hydrophobic, its optimum salinity is low and the ultra-low IFT salinity range narrow (Nelson 1983). Adding a hydrophilic co-surfactant to the process solved the problem, and is known as ASP flooding. AP floods also form persistent, unpredictable and often highly viscous emulsions, which result in high pressure drops and low injection rates. Addition of co-solvents such as a light alcohol (typically 1 wt %) improves the performance of AP floods; researchers at the University of Texas at Austin have coined the term ACP (Alkaline Co-solvent Polymer) for this new process. ACP has significant advantages relative to other chemical flooding modes to recover heavy oils. It is less costly than using surfactant, and has none of the design challenges associated with surfactant. It shows the benefit of nearly 100% displacement sweep efficiency in core floods when properly implemented, as heavy oils tend to produce significant IFT reducing soaps. The use of polymer for mobility control ensures good sweep efficiency is also achieved. Since heavy oils can be extremely viscous at reservoir temperature, moderate reservoir heating to reduce oil viscosity is beneficial. In a series of core flood experiments, moderately elevated temperatures (25-75°C) were used in evaluating ACP flooding in heavy oils. The experiments used only small amounts of inexpensive co-solvents while recovering >90% of remaining heavy oil in a core, without need for any surfactant. The most successful experiments showed that a small increase in temperature (25°) can have very positive impacts on core flood performance. These results are very encouraging for heavy oil recovery with chemical EOR.Item Experimental development of a chemical flood and the geochemistry of novel alkalis(2012-08) Winters, Matthew Howard; Pope, Gary A.; Weerasoriya, UpaliSurfactant-Polymer (SP) and Alkaline-Surfactant-Polymer (ASP) floods are tertiary oil recovery processes that mobilize residual oil to waterflood. These Chemical EOR processes are most valuable when the residual oil saturation of a target reservoir to waterflood is high. The first steps of designing a SP or ASP flood are performed in a laboratory by developing a surfactant formulation and by performing core flood experiments to assess the performance of the flood to recovery residual oil to waterflood. The two criteria for a technically successful laboratory SP or ASP core flood are recovering greater than 90% of residual oil to waterflood leaving behind less than 5% of residual oil and accomplishing this at a field scalable pressure gradient across the porous medium of approximately 1 psi per foot. This thesis documents the laboratory development of SP and ASP core floods for a continental Unites States oil reservoir reported to contain the minerals anhydrite and gypsum. The significance of these minerals is that they provide an infinite acting source of calcium within the reservoir that makes using the traditional alkali sodium carbonate unfeasible using conventional Chemical EOR methods. This is because sodium carbonate will precipitate as calcite in the presence of free calcium ions. Secondly, this thesis investigates two novel alkalis that are compatible with free calcium ions, sodium acetate and tetrasodium EDTA, for their viability for use in ASP floods for reservoirs containing anhydrite or gypsum.Item Experimental investigation of the effect of increasing the temperature on ASP flooding(2011-12) Walker, Dustin Luke; Pope, Gary A.; Weerasooriya, UpaliChemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent.Item Experimental Investigation on the Use of Water Soluble Polyacrylamides as Thickeners During CO_(2) WAG EOR(2014-07-24) Tovar, FranciscoCO_(2) flooding often results in poor sweep efficiency due to the high mobility ratio caused by its low viscosity. To mitigate this problem, alternate injection of water and CO_(2) slugs (WAG) is widely applied. Recently, numerical simulation and core flood experiments in heavy oil indicate that the use of chemicals in the water slug may improve mobility control during WAG. Therefore, stability studies of common polymers used for EOR applications in CO_(2) saturated environments becomes necessary. Also, the possibility to extrapolate the benefits observed in heavy oil to light and medium oil reservoirs needs to be assessed as they gather the majority of the existing CO_(2) applications. This thesis presents an evaluation of the use of polymers as water thickeners during CO_(2). The work has been divided into three stages: An investigation on the stability of acrylamide based polymers exposed to CO_(2) for 328 days at 122 ?F. The determination of the MMP for the system crude oil ? CO_(2) using the slim tubing technique in a fast approach that employs a short column of 20 ft in length. And the execution of 12 core flooding experiments under miscible and immiscible conditions, in homogeneous and heterogeneous rock. We conclude that polyacrylamide based polymers can resist the presence of CO_(2). HPAM was able to retain 54% of its original viscosity after 215 days at 122 ?F. PAM - ATBS increased its viscosity to 104% of its original viscosity after 328 days. A MMP of 1563 psia was calculated, which has a good correlation to previous laboratory measurements and EOS predictions for live oil. The core flooding experiments gave insights regarding the role of miscibility, frontal advance rate, heterogeneity and water viscosity on the viscous fingering of CO_(2) into the oil and suggested that thickening the water during WAG could be beneficial in highly heterogeneous formations. The limitations to scale reservoir heterogeneity prevented us to reach a fully understanding of the process. An approach combining numerical simulation with experimental work is recommended.Item Experimental Study of In Situ Combustion with Decalin and Metallic Catalyst(2011-02-22) Mateshov, DaurenUsing a hydrogen donor and a catalyst for upgrading and increasing oil recovery during in situ combustion is a known and proven technique. Based on research conducted on this process, it is clear that widespread practice in industry is the usage of tetralin as a hydrogen donor. The objective of the study is to find a cheaper hydrogen donor with better or the same upgrading performance. Decalin (C10H18) is used in this research as a hydrogen donor. The experiments have been carried out using field oil and water saturations, field porosity and crushed core for porous medium. Four in situ combustion runs were performed with Gulf of Mexico heavy oil, and three of them were successful. The first run was a control run without any additives to create a base for comparison. The next two runs were made with premixed decalin (5 percent by oil weight) and organometallic catalyst (750 ppm). The following conditions were kept constant during all experimental runs: air injection rate at 3.1 L/min and combustion tube outlet pressure at 300 psig. Analysis of the performance of decalin as a hydrogen donor in in-situ combustion included comparison of results with an experiment where tetralin was used. Data from experiments of Palmer (Palmer-Ikuku, 2009) was used for this purpose, where the same oil, catalyst and conditions were used. Results of experiments using decalin showed better quality of produced oil, higher recovery factor, faster combustion front movement and higher temperatures of oxidation. API gravity of oil in a run with decalin is higher by 4 points compared to a base run and increased 5 points compared to original oil. Oil production increased by 7 percent of OOIP in comparison with base run and was 2 percent higher than the experiment with tetralin. The time required for the combustion front to reach bottom flange decreased 1.6 times compared to the base run. The experiments showed that decalin and organometallic catalysts perform successfully in in situ combustion, and decalin is a worthy replacement for tetralin.Item Experimental Study of Solvent Based Emulsion Injection to Enhance Heavy Oil Recovery(2011-08-08) Qiu, FangdaThis study presents the results of nano-particle and surfactant-stabilized solvent-based emulsion core flooding studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion. Specifically, nano-emulsion systems with high viscosity have been injected into sandstone cores containing Alaska North Slope West Sak heavy oil with 16 API, which was dewatered in the laboratory condition. The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR (enhanced oil recovery) process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems. Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nano-emulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation. In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat. In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.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 Impact of viscoelastic polymer flooding on residual oil saturation in sandstones(2013-12) Ehrenfried, Daniel Howard; Balhoff, Matthew T.The objective of this research was to determine whether the use of polymer compounds with elastic properties can reduce residual oil saturation in porous media below that of brine or inelastic polymerized solutions. One hypothesis is that long-chain polymer molecules experience stress and a resulting strain when they flow through pore throat constrictions. If the fluid residence time in larger pore spaces is insufficient to allow full relaxation, then strain can accumulate. Sufficient strain results in normal forces which can impinge on oil interfaces and potentially mobilize them. A second hypothesis suggests that polymerized solutions can temporarily protect flowing oil filaments from snap off, allowing them to flow longer and de-saturate further than they would otherwise. The approach taken in this thesis was to conduct a series of core floods in several different sandstones using displacement fluids with elasticity ranging from none to those with extremely high relaxation times. Accelerated flow rate was also employed to reduce residence time and maximize the accumulation of elastic strain and normal force potential. Experiments were designed to provide direct comparisons between both non-elastic and elastic floods but also multiple floods with increasing elasticity. The results were inconclusive with some experiments showing additional oil recovery that could be attributed to elastic mechanisms. Most experiments, however, showed no significant difference between elastic and non-elastic floods when experimental parameters were controlled within narrow limits. This research did refine the experimental context in which elastic effects are most likely to be observed. As such, it can serve as a precursor to additional core flooding in oil-wet systems, experiments conducted at reservoir temperature, and those where the pressure gradient of the flood is held constant and the flow rate allowed to vary. Computer aided tomography could also be employed to visualize the mobilization of oil with different displacement fluids, identify where bypassed oil occurs with unstable floods, and determine how oil is subsequently mobilized with better conformance and or elasticity.Item Improved Steam Assisted Gravity Drainage (SAGD) Performance with Solvent as Steam Additive(2011-02-22) Li, WeiqiangSteam Assisted Gravity Drainage (SAGD) is used widely as a thermal recovery technique in Canada to produce a very viscous bitumen formation. The main research objectives of this simulation and experimental study are to investigate oil recovery mechanisms under SAGD process with different injection fluids, including steam, solvent or steam with solvent. 2D simulation studies based on typical Athabasca reservoir properties have been performed. Results show that a successful solvent co-injection design can utilize the advantages of solvent and steam. There is an optimal solvent type and concentration ratio range for a particular reservoir and operating condition. Long, continuous shale barriers located vertically above or near the wellbore delay production performance significantly. Co-injecting a multi-component solvent can flush out the oil in different areas with different drainage mechanisms from vaporized and liquid components. Placing an additional injector at the top of the reservoir results only in marginal improvement. The pure high-temperature diluent injection appears feasible, although further technical and economic evaluation of the process is required. A 2D scaled physical model was fabricated that represented in cross-section a half symmetry element of a typical SAGD drainage volume in Athabasca. The experimental results show co-injecting a solvent mixture of C7 and xylene with steam gives better production performance than the injection of pure steam or steam with C7 at the study condition. Compared to pure steam injection runs ( Run 0 and 1), coinjecting C7 (Run 2) with steam increases the ultimate recovery factor of oil inside the cell from 25 percent to 29 percent and decreases the ultimate CSOR from 2.2 to 1.9 and the ultimate CEOR from 4892 J/cm 3 to 4326 J/cm 3 ; coinjecting C7 and Xylene (Run 3) increases the ultimate recovery factor of oil from 25 percent to 34 percent, and decreases the ultimate CSOR 2.2 to 1.6 and the ultimate CEOR from 4892 J/cm 3 to 3629 J/cm 3 . Analyses of the experimental results indicate that partial pressure and the near wellbore flow play important roles in production performance. In conclusion, a successful solvent injection design can effectively improve the production performance of SAGD. Further research on evaluating the performance of various hydrocarbon types as steam additives is desirable and recommended.Item Improved upscaling scheme for steam assisted gravity drainage (SAGD) and semi-analytical modeling of the SAGD rising phase(2015-05) Murugesu, Mayuri; Srinivasan, Sanjay; Lake, Larry W.Steam assisted gravity drainage (SAGD) process commonly applied for heavy oil and bitumen recovery consists of two production phases: a steam rising phase and a spreading phase. Extensive research has been done on modeling the SAGD spreading phase, but fewer analytical/semi-analytical models exist for the unstable rising phase. This thesis presents a semi-analytical method, MS-SAGD, to model the SAGD rising phase. In addition, an improved upscaling technique that takes into account the unique flow geometry observed during SAGD is presented that enables more accurate predictions of oil recovery rates in heterogeneous reservoirs during both phases. The MS-SAGD semi analytical method, based on the Myhill and Stegemeier frontal advance model for steam drive processes, tracks the growth of the steam chamber as a function of time. Two different oil production rate models are proposed and the comparison of results from flow and transport simulations is presented. Model 1 is similar to Butler’s approach using the rising steam finger theory. Model 2 is obtained by modifying Butler's spreading phase model and applying it to the rising phase. Both models use the outputs of the MS-SAGD model to estimate the oil production rates during the SAGD rising phase. The application of the MS-SAGD model is extended to heterogeneous reservoirs by treating the heated volume estimated by the original MS-SAGD model as an effective heated volume. In addition, the homogeneous permeability in the proposed oil production rate model is replaced with an upscaled effective permeability that is a function of time. The improved upscaling technique is based on a global approach that minimizes the differences between the fine scale and upscaled model pressure solutions. Sources and sinks by means of wells are used in the upscaling to simulate the convergent flow pattern observed during the SAGD process. The proposed models outperform existing analytical/semi-analytical methods and are in good agreement with the results obtained from CMG-STARS reservoir simulation. Both oil production rate models perform comparatively well, producing similar results in terms of cumulative oil production. However, Model 2 performs better than Model 1 in describing the overall behavior of the oil production observed in the reservoir simulation and is thus a better model for the SAGD rising phase.