Thesis (M. Sc.)--University of Alberta, 2010. / Title from pdf file main screen (viewed on Jan. 18, 2010). A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Master of Science in Chemical Engineering, Department of Chemical & Materials Engineering, University of Alberta. Includes bibliographical references.

Anthropogenic CO₂ captured from a coal-fired power plant can be used for an enhanced oil recovery (EOR) operation while mitigating the atmospheric impact of CO₂ emissions. Concern about climate change caused by CO₂ emissions has increased the motivation to develop carbon capture and sequestration (CCS) projects to reduce the atmospheric impact of coal and other fossil fuel combustion. Enhanced oil recovery operations are typically constrained by the supply of CO₂, so there is interest from oil producers to use large-volume anthropogenic (LVA) CO₂ for tertiary oil production. The intermittency of LVA CO2 emissions creates an area of concern for both oil producers and electric utilities that may enter into a CO₂ supply contract for EOR. An oil producer wants to know if intermittency from a non-standard source of CO₂ will impact oil production from the large volume being captured. Since the electric utility must supply electricity on an as-needed basis, the CO₂ emissions are inherently intermittent on a daily and seasonal basis. The electric utility needs to know if the intermittent supply of CO₂ would reduce its value compared to CO₂ delivered to the oil field at a constant rate. This research creates an experimental test scenario where one coal-fired power plant captures 90% of its CO₂ emissions which is then delivered through a pipeline to an EOR operation. Using real emissions data from a coal-fired power plant and simplified data from an actual EOR reservoir, a series of reservoir simulations were done to address and analyze potential operational interference for an EOR operator injecting large-volume, intermittent CO₂ characteristic of emissions from a coal-fired power plant. The test case simulations in this study show no significant impact to oil production from CO₂ intermittency. Oil recovery, in terms of CO₂ injection, is observed to be a function of the total pore volumes injected. The more CO₂ that is injected, the more oil that is produced and the frequency or rate at which a given volume is injected does not impact net oil production. Anthropogenic CO₂ sources can eliminate CO₂ supply issues that constrain an EOR operation. By implementing this nearly unlimited supply of CO₂, oil production should increase compared to smaller-volume or water-alternating-gas (WAG) injection strategies used today. Mobility ratio and reservoir heterogeneity have a considerable impact on oil recovery. Prediction of CO₂ breakthrough at the production wells seems to be more accurate when derived from the mobility ratio between CO₂ and reservoir oil. The degree of heterogeneity within the reservoir has a more direct impact on oil recovery and sweep efficiency over time. The volume of CO₂ being injected can eventually invade lower permeability regions, reducing the impact of reservoir heterogeneity on oil recovery. This concept should mobilize a larger volume of oil than a conventional volume-limited or WAG injection strategy that may bypass or block these lower permeability regions. Besides oil recovery, a reservoir's performance in this study is defined by its CO₂ injectivity over time. Elevated injection pressures associated with the large-volume CO₂ source can substantially impact the ability for an oil reservoir to store LVA CO₂. As CO₂, a less viscous fluid, replaces produced oil and water, the average reservoir pressure slowly declines which improves injectivity. This gradual improvement in injectivity is mostly occupied by the increasing volume of recycled CO₂. Sweep efficiency is critical towards minimizing the impact of CO₂ recycling on reservoir storage potential. Deep, large, and permeable oil reservoirs are more capable of accepting LVA CO₂, with less risk of fracturing the reservoir or overlying confining unit. The depth of the reservoir will directly dictate the injection pressure threshold in the oil reservoir as the fracture pressure increases with depth. If EOR operations are designed to sequester all the CO₂ delivered to the field, additional injection capacity and design strategies are needed. / text

Chemical flooding is one of the most difficult enhanced oil recovery methods and was considered a high-risk process in the past. Some reasons are low and uncertain oil price, high chemical prices, lack of confidence in performance of the chemical flooding process, long project life, and reservoir and process uncertainties. However, with significant improvement in simulation and optimization tools and high oil price, chemical flooding is feasible in terms of economical and carefully implemented design. Optimization of chemical floods requires complex integration of reservoir, chemical, economics properties and also drilling and production strategies. Many of these variables are uncertain parameters and many simulations are required to capture the effect of the uncertain and decision variables. These simulations could become very expensive and may not be feasible to consider all of the required simulation models. The goal of this research is the development of a methodology for optimization and design of chemical flooding of candidate oil reservoirs. We performed a comprehensive sensitivity study of reservoir and fluid properties that have significant influence on the oil production during the chemical flooding by performing a series of reservoir simulation runs. For performing the reservoir simulation runs, this study used the UT_IRSP platform and the multiphase, multicomponent, chemical flooding simulator called UTCHEM. During the study, UT_IRSP and UTCHEM have been modified by adding new modules, functions and variables. For example, a deviated well module was implemented in UTCHEM to study deviated wells. Deviated well module allows the users to introduce deviated wells in reservoir and import the well locations similar to Eclipse or CMG simulators. A time-dependent well schedule module was implemented in the UT_IRSP framework. This enhancement allows the well placement optimization studies to find the best time to add new wells, and change the status of the well for example from a producer to an injector in order to have an optimum development plan. An advanced post processing module was added to UT_IRSP in order to design, screen, and optimize complex cases for chemical enhanced oil recovery processes such as investigating the well patterns, well spacing, and type of the well (horizontal vs. vertical wells). An experimental design and response surface methodology with integrated economic model were utilized in this study to obtain the optimum design under uncertainties and have an optimal combination of the decision variables. This methodology is based on applying multi-regression analysis and ANOVA (analysis of variance) between the objective function (i.e. dependent variable, which is net present value (NPV) in chemical flooding) and other uncertain and process variables (independent variables). The economic analysis model used the discounted cash flow method to calculate net present value at the economic life of process, internal rate of return, and growth rate of return for each simulation case. Also the optimizer, OptQuest, is launched with a goal of maximizing the mean NPV. The range and the risk associated with the optimum design was studied using Monte Carlo simulation of objective function of the response variable and other independent variables. This methodology was applied for complex chemical flood cases such as well placement, change of status of wells as a function of time or well pattern and well spacing to investigate the best well scenario from recovery and economics point of view. / text

Chemical Enhanced Oil Recovery methods have been growing in popularity as a result of the depletion of conventional oil reservoirs and high oil prices. These processes are significantly more complex when compared to waterflooding and require detailed engineering design before field-scale implementation. Coreflood experiments that have been performed on reservoir rock are invaluable for obtaining parameters that can be used for field-scale flooding simulations. However, the design used in these floods may not always scale to the field due to heterogeneities, chemical retention, mixing and dispersion effects. Reservoir simulators can be used to identify an optimum design that accounts for these effects but uncertainties in reservoir properties can still cause poor project results if it not properly accounted for. Different reservoirs will be investigated in this study, including more unconventional applications of chemical flooding such as a 3md high-temperature, carbonate reservoir and a heterogeneous sandstone reservoir with very high initial oil saturation. The goal of the research presented here is to investigate the impact that select reservoir uncertainties can have on the success of the pilot and to propose methods to reduce the sensitivity to these parameters. This research highlights the importance of good mobility control in all the case studies, which is shown to have a significant impact on the economics of the project. It was also demonstrated that a slug design with good mobility control is less sensitive to uncertainties in the relative permeability parameters. The research also demonstrates that for a low-permeability reservoir, surfactant propagation can have a significant impact on the economics of a Surfactant-Polymer Flood. In addition to mobilizing residual oil and increasing oil recovery, the surfactant enhances the relative permeability and this has a significant impact on increasing the injectivity and reducing the project life. Injecting a high concentration of surfactant also makes the design less sensitive to uncertainties in adsorption. Finally, it was demonstrated that for a heterogeneous reservoir with high initial oil saturation, optimizing the salinity gradient will significantly increase the oil recovery and will also make the process less sensitive to uncertainties in the cation exchange capacity. / text

The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg[superscript 2+] and SO4[superscript 2-] and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca[superscript 2+], but without Mg[superscript 2+] or SO₄[superscript 2-] was unsuccessful in changing calcite wettability. Modified seawater containing Mg[superscript 2+] and SO₄[superscript 2-], and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO₄[superscript 2-] and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs. / text

Polymer flooding is a commercial enhanced oil recovery (EOR) method used to increase the sweep efficiency of water floods. Hydrolyzed polyacrylamide (HPAM), a synthetic commercial polymer, is widely used in commercial polymer floods and it is also used for mobility control of chemical floods using surfactants such as surfactant-polymer flooding and alkaline-surfactant-polymer flooding. The increase in the degree of hydrolysis of HPAM at elevated temperature or pH with time affects the polymer solution viscosity and its adsorption on rock surfaces. A polymer hydrolysis model based on published laboratory data was implemented in UTCHEM, a chemical EOR simulator, in order to assess the effect of hydrolysis on reservoir performance. Both 1D and 3D simulations were performed to validate the implementation of the model. The simulation results are consistent with the laboratory observations that show an increase in polymer solution viscosity as hydrolysis progresses. The numerical results indicate that hydrolysis occurs very rapidly and impacts the near wellbore region polymer injectivity. / text

Chemical flooding has been studied for 50 years. However, never have the conditions encouraging its growth been as good as right now. Those conditions being new, improved technology and oil prices high enough to make implementation economical. The objective of this work was to develop economical, robust chemical formulations and processes that recover oil in field pilots when properly implemented. This experimental study goes through the process of testing surfactants to achieve optimal phase behavior, coreflooding with the best chemical formulations, improving the formulation and testing it in more corefloods, and then finally recommending the formulation to be tested in a field pilot. The target reservoir contains a light (34° API, 10 cP), non-reactive oil at about 22° C. The formation is a moderate permeability (50 - 300 mD) sandstone with a high clay content (up to 13%). Different surfactants and surfactant mixtures were tested with the oil including alkyl benzene sulfonates (ABS), Guerbet alcohol sulfates (GAS), alkyl propoxy sulfates, and internal olefin sulfonates (IOS). The best formulation contained 0.75% TDA -13PO-SO₄, 0.25% C₂₀₋₂₄ IOS, 0.75% isobutanol (IBA), 1% Na₂CO₃, all which are mixed in a softened fresh water from a supply well. Corefloods recovered 93% of residual oil from reservoir cores. Core flood experiments were also done with the alkali sodium carbonate to measure the effluent pH in a Bentheimer sandstone core with a cation exchange capacity (CEC) of 2 meq/100g. Floods at frontal velocities of 100, 10, and 0.33 ft/D were performed with 0.3 pore volume slugs of 0.7% Na₂CO₃ at 86° C. The effluent was analyzed for ions and pH breakthrough. It was found that the pH breakthrough occurred before surfactant breakthrough would be expected as desired although the pH was lower at a frontal velocity of 0.33 ft/D than at the higher velocities. The Na₂CO₃ consumption was 0.244, 0.238, and 0.207 meq/100 g rock at velocities of 100, 10, and 0.33 ft/D, respectively. In addition, a no-alkaline formulation consisting of a new large hydrophobe ether carboxylate surfactant mixed with an internal olefin sulfonate was tested on an active oil and it successfully recovered 99% of the waterflood remaining oil from an Ottawa sand pack with no salinity gradient and no alkali. The final residual oil saturation after the chemical flood (S[subscript orc]) was only 0.005 / text

In this study, the co-optimization of carbon dioxide sequestration and enhanced oil recovery and the co-optimization of carbon dioxide sequestration and methane recovery studies were discussed. Carbon dioxide emissions in the atmosphere are one of the reasons of global warming and can be decreased by capturing and storing carbon dioxide. Our aim in this study is to maximize the amount of carbon dioxide sequestered to decrease carbon dioxide emissions in the atmosphere and maximize the oil or methane recovery to increase profit or to make a project profitable. Experimental design and response surface methodology are used to co-optimize the carbon dioxide sequestration and enhanced oil recovery and carbon dioxide sequestration and methane recovery. At the end of this study, under which circumstances these projects are profitable and under which circumstances carbon dioxide sequestration can be maximized, are given. / text

Despite bold steps taken worldwide for the replacement or the reduction of the world’s dependence on fossil fuels, economic and societal realities suggest that a transition to alternative energy forms will be, at best, gradual. It also appears that exploration for new reserves is becoming increasingly more difficult both from a technical and an economic point of view, despite the advent of new technologies. These trends place renewed emphasis on maximizing oil recovery from known fields. In this sense, low-cost and reliable enhanced oil recovery (EOR) methods have a strong role to play. The goal of this dissertation is to explore, using computational simulations, the feasibility of the, so-called, seismic or elastic-wave EOR method, and to provide the mathematical/computational framework under which the method can be systematically assessed, and its feasibility evaluated, on a reservoir-specific basis. A central question is whether elastic waves can generate sufficient motion to increase oil mobility in previously bypassed reservoir zones, and thus lead to increased production rates, and to the recovery of otherwise unexploited oil. To address the many questions surrounding the feasibility of the elastic-wave EOR method, we formulate an inverse source problem, whereby we seek to determine the excitations (wave sources) one needs to prescribe in order to induce an a priori selected maximization mobility outcome to a previously well-characterized reservoir. In the industry’s parlance, we attempt to address questions of the form: how does one shake a reservoir?, or what is the “resonance” frequency of a reservoir?. We discuss first the case of wellbore wave sources, but conclude that surface sources have a better chance of focusing energy to a given reservoir. We, then, discuss a partial-differential-equation-constrained optimization approach for resolving the inverse source problem associated with surface sources, and present a numerical algorithm that robustly provides the necessary excitations that maximize a mobility metric in the reservoir. To this end, we form a Lagrangian encompassing the maximization goal and the underlying physics of the problem, expressed through the side imposition of the governing partial differential equations. We seek to satisfy the first-order optimality conditions, whose vanishing gives rise to a systematic process that, in turn, leads to the prescription of the wave source signals. We explore different (indirect) mobility metrics (kinetic energy or acceleration field maximization), and report numerical experiments under three different settings: (a) targeted formations within one-dimensional multi-layered elastic solids system of semi-infinite extent; (b) targeted formations embedded in a two-dimensional semi-infinite heterogeneous elastic solid medium; and (c) targeted poroelastic formations embedded within elastic heterogeneous surroundings in one dimension. The numerical experiments, employing hypothetical subsurface formation models subjected to, initially unknown, ground surface wave sources, demonstrate that the numerical optimizer leads robustly to optimal loading signals and the illumination of the target formations. Thus, we demonstrate that the theoretical framework for the elastic wave EOR method developed in this dissertation can systematically address the application of the method on a reservoir-specific basis. From an application point of view and based on the numerical experiments reported herein, for shallow reservoirs there is strong promise for increased production. The case of deeper reservoirs can only be addressed with further research that builds on the findings of this work, as we report in the last chapter. / text

Macroscopic properties of rocks are functions of pore-scale geometry and can be determined from laboratory experiments using rock samples. Macroscopic properties can also be determined from computer simulations using 3D pore geometries derived from various imaging techniques. Using 3D imagery and computer simulations, we can calculate the porosity, permeability, formation resistivity factor and cementation exponent in reservoir drill cores. The objective of this thesis was to develop a workflow using Synchrotron X-ray Computed Microtomography (CMT) images and commercially available software in order to determine the macroscopic properties in reservoir drill cores for Midale Marly (M0) and Vuggy Shoal (V6) rocks. The workflow started by using CMT data that provided three-dimensional images of the reservoir rocks taken from drill cores in the Weyburn oil field. The resulting CMT grey scale images were used to isolate the pore space in the rock image. A three-dimensional mesh, representing the pore space, was then used to obtain the solution of the Navier-Stokes equations for an incompressible fluid and Laplace's equation for electrical current flow. Solutions of the Navier-Stokes equations were computed with different inlet pressures for the same pore geometry in order to confirm a direct proportionality between the mass fluid flux and pressure gradient as Darcy’s Law specifies. Previously measured laboratory transport properties were compared with my calculated transport properties on a smaller sub-volume of the same rock core imaged using 0.78 µm resolution CMT images. For the Midale Marly rock, the calculated permeability ranged from 0.01 to 3.53 mD. The formation resistivity factor ranged from 29.3 to 309.43 and the cementation exponent ranged from 1.99 to 2.10. The sample was verified to be nearly isotropic as the permeability was similar for three orthogonal fluid flow directions. Even though the sub-volume analyzed was smaller than a Representative Elementary Volume (REV), the results are within an order of magnitude of the previously calculated laboratory results as completed by Glemser (2007) and fall on the same power law trend. A Vuggy (V6) sample was investigated after the sample had been exposed to CO2, and dissolution within the rock matrix resulted in large visible pore spaces. Using 7.45 µm resolution CMT images, the permeability for a large isolated pore could not be calculated using the previous workflow due to computer memory limitations. Resampling enabled the data to fit into the available computer memory. The permeability values ranged from 2.66x10^5 to 8.59x10^5 mD for resampling the CMT images from 2x to 10x.