Conformance control has long been a compelling subject in improving waterflood oil recovery. By blocking the areas previously swept by water, subsequently injected water is allowed to sweep the remaining unswept portions of the reservoir and thereby increase the ultimate oil recovery. One technique that has received a great deal of attention recently in achieving this in-depth water shut-off is crosslinked gel injection. However, processing and predicting the performance of these gels in complex petroleum reservoirs is known to be extremely challenging. A model that accurately represents the reservoir features, chemical properties, and displacement mechanisms is, therefore, required. In this study, we further developed the UT in-house numerical reservoir simulator, branded as UTGEL. Our first focus was to enable UTGEL to simulate a new type of temperature-resistant and salt-tolerant pre-crosslinked swellable particle gel, known as Preformed Particle Gel or PPG. A series of numerical simulations have been conducted to match with experimental data and generate parameters for full field scale simulation. Five laboratory experimental matching attempts were successfully performed using the UTGEL simulator in this study. The matched experiments included a fracture model, two sandpack models, a sandstone coreflood experiment, and a parallel sandpack model. The second focus of this study was to investigate the applications of PPG in blocking high-permeability layers, fractures, and conduits. A number of synthetic and actual field cases were generated to study the performance of PPG in (1) reservoirs with various layered permeability contrasts, from extremely low to extremely high permeability contrasts, (2) reservoirs containing extensive conduits or channels, and (3) real field cases where heterogeneity had been identified unfavorable to the waterflood efficiency. The simulation outcomes indicated significant incremental oil recovery from PPG treatment ranging from less than 5% to almost 30%. A number of sensitivity analyses were also conducted to provide some insights on the optimal PPG treatment design. Lastly, to enhance the capability of UTGEL in simulating gel transport in diverse scenarios, a novel Embedded Discrete Fracture Modeling (EDFM) concept was implemented into UTGEL in this study, allowing multiple sets of fracture planes and conduits with dip angles and orientations to be modeled and simulated with gel treatments for the first time with a rather computationally inexpensive method. Although the developed simulator requires further improvement and validation against wider reservoir and fluid conditions, the representative results from a number of generated models in this study have suggested another step forward towards achieving realistic reservoir modeling and advanced gel transport simulation. / text

Significant quantities of hydrocarbon are bypassed during conventional waterfloods. This is the direct result of fluid channeling through high permeability zones within the reservoir. Conformance control offers a mean of increasing vertical and areal sweep efficiency, thus decreasing the amount of hydrocarbon bypassed. This, in turn, results in increased hydrocarbon production, decreased water cut, and field life extension. This thesis focuses on the use of polymer microgels as a relatively novel conformance control agent. Polymer-microgel-enhanced waterflooding tackles fluid channeling by “plugging” high permeability channels, or thief zones, and diverting trailing flooding fluid to adjacent poorly swept areas of the reservoir. The first major objective of this thesis was to provide an extensive literature survey on polymer microgel technology, which can serve as the go-to reference on this topic. Colloidal Dispersion Gels (CDGs), Preformed Particle Gels (PPGs), temperature-sensitive polymer microgels (Bright Water), and pH-sensitive polymer microgels are all discussed in detail, and an attempt is made to highlight the potential mechanisms by which they plug thief zones and improve oil recovery. This thesis then outlines the results of simulating numerous polymer microgel floods, ranging from experimental cases to field cases. Specifically, Colloidal Dispersion Gels (CDGs) were chosen for the simulations undergone. All simulations were run using UTGEL, a newly developed in-house simulator designed exclusively for the simulation of polymer, gel, and microgel floods. The simulations performed provide insight on the polymer microgel flooding process, and also served as a means of validating UTGEL’s polymer microgel (CDG) models. The development of the UTGEL simulator was important as it enables the optimization of polymer microgel floods for maximized hydrocarbon recovery efficiency. The results of a simulation study, using a synthetic field case, are also outlined. This sensitivity study provides additional insight on optimal operational conditions for polymer microgel technology. More specifically, this study aimed to investigate the effectiveness of microgel flooding treatments in layered reservoirs of varying permeability contrasts, vertical-to-horizontal permeability ratios, and under a variety of different injection concentrations. / text

Carbon dioxide (CO₂) flooding is the second most common tertiary recovery technique implemented in the United States. Yet, there is huge potential to advance the process by improving the volumetric sweep efficiency of injected CO₂. Delivering CO₂ into the reservoir as a foam is one way to do this. Surfactants have traditionally been used to generate CO₂ foams for mobility control; however, the use of nanoparticles as a foam stabilizing agent provides several advantages. Surfactant-stabilized foams require constant regeneration to be effective, and the surfactant is adsorbed onto reservoir rocks and is prone to chemical degradation at harsh reservoir conditions. Nanoparticle-stabilized foams have been found to be tolerant of high temperature and high salinity environments. Their nano size also allows them to be transported through reservoir rocks without blocking pore throats. Stable CO₂-in-water foams were generated using 5 nm silica nanoparticles with a short chain polyethylene glycol surface coating. These foams were generated by the co-injection of CO₂ and a nanoparticle dispersion through both rock matrix and fractures. A threshold shear rate was found to exist for foam generation in both fractured and non-fractured Boise sandstone cores. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous; in field applications, high shear rates are associated with high permeability zones, where the presence of foam is desired. Reducing CO₂ mobility in these high permeability zones diverts CO₂ into lower permeability regions containing not yet swept oil. Nanoparticles were also found to be able to stabilize CO₂ foams by co-injection through rough-walled fractures in cement cores, demonstrating their ability to stabilize foams without matrix flow. Experiments were conducted on the ability of fly ash, a waste product from burning coal in power plants, to stabilize oil-in-water emulsions and CO₂ foams. The use of fly ash particles as a foam stabilizing agent would significantly reduce material costs for potential tertiary oil recovery and CO₂ sequestration applications. Nano-milled fly ash particles without surface treatment were able to generate stable oil-in-water emulsions when high frequency, high energy vibrations were applied to a mixture of fly ash dispersion and dodecane. Oil-in-water emulsions were also generated by co-injecting fly ash and dodecane, a low pressure analog to CO₂, through a beadpack. Emulsions generated by co-injection, however, were unstable and coalesced within an hour. A threshold shear rate was required for the emulsion generation. Fly ash particles were found to be able to stabilize CO₂ foam in a high pressure batch mixing cell, but not by co-injection through a beadpack. Dispersions of fly ash particles were found to be stable only at low salinities (<1 wt% NaCl). / text

Fractured viscous oil resources hold great potential for continued oil production growth globally. However, many of these resources are not accessible with current commercial technologies using steam injection which limits operations to high temperatures. Several steam-solvent processes have been proposed to decrease steam usage, but they still require operating temperatures too high for many projects. There is a need for a low temperature injection strategy alternative for viscous oil production. This dissertation discusses scoping experimental work for a low temperature solvent injection strategy targeting fractured systems. The strategy combines three production mechanisms – gas-oil gravity drainage, liquid extraction, and film gravity drainage. During the initial heating period when the injected solvent is in the liquid phase, liquid extraction occurs. When the solvent is in the vapor phase, solvent-enhanced film gravity drainage occurs. A preliminary simulation of the experiments was developed to study the impact of parameter uncertainty on the model performance. Additional work on reducing uncertainty for key parameters controlling the two solvent production mechanisms will be necessary. In a natural fracture network, the solvent would not be injected uniformly throughout the reservoir. Preferential injection into the higher conductivity fracture areas would result in early breakthrough leaving unswept areas of high oil saturation. Conformance control would be necessary to divert subsequent solvent injection into the unswept zones. A variety of techniques, including polymer and silica gel treatments, have been designed to block flow through the swept zones, but all involve initiating gelation prior to injection. This dissertation also looks at a strategy that uses the salinity gradient between the injected silica nanoparticle dispersion and the in-situ formation water to trigger gelation. First, the equilibrium phase behavior of silica dispersions as a function of sodium chloride and nanoparticle concentration and temperature was determined. The dispersions exhibited three phases – a clear, stable dispersion; gel; and a viscous, unstable dispersion. The gelation time was found to decrease exponentially as a function of silica concentration, salinity, and temperature. During core flood tests under matrix and fracture injection, the in-situ formed gels were shown to provide sufficient conductivity reduction even at low nanoparticle concentration. / text

Successful field waterflood is a crucial prerequisite for improving the performance before EOR methods, such as ASP, SP, and P flooding, are applied in the field. Excess water production is a major problem in mature waterflooded oil fields that leads to early well abandonment and unrecoverable hydrocarbon. Gel treatments at the injection and production wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. There are extensive experimental studies performed by some researchers in the past to investigate the performance of gels in conformance control and decreasing water production in mature waterflooded reservoirs, but no substantial modeling work has been done to simulate these experiments and predict the results for large field cases. We developed a novel, 3-dimensional chemical compositional and robust general reservoir simulator (UTGEL) to model gel treatment processes. The simulator has the capability to model different types of microgels, such as preformed particle gels (PPG), thermally active polymers (TAP), pH-sensitive microgels, and colloidal dispersion gels (CDG). The simulator has been validated for gel flooding using laboratory and field scale data. The simulator helps to design and optimize the flowing gel injection for conformance control processes in larger field cases. The gel rheology, adsorption, resistance factor and residual resistance factor with salinity effect, gel viscosity, gel kinetics, and swelling ratio were implemented in UTGEL. Several simulation case studies in fractured and heterogeneous reservoirs were performed to illustrate the effect of gel on production behavior and water control. Laboratory results of homogeneous and heterogeneous sandpacks, and Berea sandstone corefloods were used to validate the PPG transport models. Simulations of different heterogeneous field cases were performed and the results showed that PPG can improve the oil recovery by 5-10% OOIP compared to waterflood. For recovery from fractured reservoirs by waterflooding, injected water will flow easily through fractures and most part of reservoir oil will remain in matrix blocks unrecovered. Recovery from these reservoirs depends on matrix permeability, wettability, fracture intensity, temperature, pressure, and fluid properties. Chemical processes such as polymer flooding (P), surfactant/polymer (SP) flooding and alkali/surfactant/polymer (ASP) flooding are being used to enhance reservoir energy and increase the recovery. Chemical flooding has much broader range of applicability than in the past. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils. The recovery from fractured carbonate reservoirs is frequently considered to be dominated by spontaneous imbibition. Therefore, any chemical process which can enhance the rate of imbibition has to be studied carefully. Wettability alteration using chemicals such as surfactant and alkali has been studied by many researchers in the past years and is recognized as one of the most effective recovery methods in fractured carbonate reservoirs. Injected surfactant will alter the wettability of matrix blocks from oil-wet to water-wet and also reduce the interfacial tension to ultra-low values and consequently more oil will be recovered by spontaneous co-current or counter-current imbibition depending on the dominant recovery mechanism. Accurate and reliable up-scaling of chemical enhanced oil recovery processes (CEOR) are among the most important issues in reservoir simulation. The important challenges in up-scaling CEOR processes are predictability of developed dimensionless numbers and also considering all the required mechanisms including wettability alteration and interfacial tension reduction. Thus, developing new dimensionless numbers with improved predictability at larger scales is of utmost importance in CEOR processes. There are some scaling groups developed in the past for either imbibition or coreflood experiments but none of them were predictive because all the physics related to chemical EOR processes (interfacial tension reduction and wettability alteration) were not included. Furthermore, most of commercial reservoir simulators do not have the capability to model imbibition tests due to lack of some physics, such as surfactant molecular diffusion. The modeling of imbibition cell tests can aid to understand the mechanisms behind wettability alteration and consequently aid in up-scaling the process. Also, modeling coreflood experiments for fractured vuggy carbonates is challenging. Different approaches of random permeability distribution and explicit fractures were used to model the experiments which demonstrate the validity and ranges of applicability of upscaled procedures, and also indicate the importance of viscous and capillary forces in larger scales. The simulation models were then used to predict the recovery response times for larger cores.