The use of foam for mobility control is a promising means to improve sweep efficiency in subsurface applications such as improved/enhanced oil recovery and aquifer remediation. Foam can be introduced into geological formations by injecting gas and surfactant solutions simultaneously or alternatively. Alternating gas and surfactant solutions, which is often referred to as surfactant-alternating-gas (SAG) process, is known to effectively create fine-textured strong foams due to fluctuation in capillary pressure. Recent studies show that foam rheology in porous media can be characterized by foam-catastrophe theory which exhibits three foam states (weak-foam, strong-foam, and intermediate states) and two strong-foam regimes (high-quality and low-quality regimes). Using both mechanistic foam simulation technique and fractional flow analysis which are consistent with foam catastrophe theory, this study aims to understand the fundamentals of dynamic foam displacement during gas injection in SAG processes. The results revealed some important findings: (1) The complicated mechanistic foam fractional flow curves (fw vs. Sw) with both positive and negative slopes require a novel approach to solve the problem analytically rather than the typical method of constructing a tangent line from the initial condition; (2) None of the conventional mechanistic foam simulation and fractional flow analysis can fully capture sharply-changing dynamic foam behavior at the leading edge of gas bank, which can be overcome by the pressure-modification algorithm suggested in this study; (3) Four foam model parameters (¤Po, n, Cg/Cc, and Cf) can be determined systematically by using an S-shaped foam catastrophe curve, a two flow regime map, and a coreflood experiment showing the onset of foam generation; and (4) At given input data set of foam simulation parameters, the inlet effect (i.e., a delay in strong-foam propagation near the core face) is scaled by the system length, and therefore the change in system length at fixed inlet-effect length requires the change in individual values Cg and Cc at the same Cg / Cc. This study improves our understanding of foam field applications, especially for gas injection during SAG processes by capturing realistic pressure responses. This study also suggests new fractional flow solutions which do not follow conventional fractional flow analysis.

The understanding of geological characteristics and heterogeneity of a reservoir enables better decisions for reservoir development. Statistical methods use universally available injection and production rate data to help evaluate reservoir characteristics and behavior.In this research project, statistical methods typically used to infer communication between injector-producer well pairs in a waterflood reservoir using only production and injection rate data are applied to a CO2 flood. The multivariate linear regression (MLR) technique computes weighting coefficients possibly related to the fraction of the flow in a producer that comes from each of the injectors (Albertoni and Lake, 2002). MLR was applied to the Phase 2 portion of the Little Creek field, Mississippi CO2 flood. Albertoni and Lake use diffusivity filters to model the time lag and attenuation between the stimulus (injection) and the response (production), and further modify the model by successive elimination of negative weighting coefficients (SEN) and successive elimination of positive coefficients larger than 1 (SEP). Diffusivity filters do not improve the results for the Little Creek Field. The statistical implications of the SEN and SEP procedures were compared with a less complex simple linear model (SLM) which eliminates the need to make ad hoc assumptions. A statistical hypothesis test (P-Value test) was carried out to determine the significance of each injector-producer well pair relationship. Well pairs with non-significant relationships are then eliminated from the model. This avoids making statistically questionable assumptions to eliminate injector-producer well pairs with connection strengths (i.e., connections not in the range [0,1]). Recommendations to improve sweep were made using results from the Simple Linear Model with the application of the statistical significance test. Suggestions for future work are also presented.

The advent of the digital oil eld and rapidly decreasing cost of computing creates opportunities as well as challenges in simulation based reservoir studies, in particular, real-time reservoir characterization and optimization. One challenge our eorts are directed toward is the use of real-time production data to perform live reservoir characterization using high throughput, high performance computing environments. To that end we developed the required tools of parallel reservoir simulator, parallel ensemble Kalman lter and a scalable work ow manager. When using this collection of tools, a reservoir modeler is able to perform large scale reservoir management studies in short periods of time. This includes studies with thousands of models that are individually complex and large, involving millions of degrees of freedom. Using parallel processing, we are able to solve these models much faster than we otherwise would on a single, serial machine. This motivated the development of a fast parallel reservoir simulator. Furthermore, distributing those simulations across resources leads to a smaller total time to completion by making use of distributed processing. This allows the development of a scalable high throughput work ow manager. Finally, with thousands of models, each with millions of degrees of freedom, we end up with a super uity of model parameters. This translates directly to billions of degrees of freedom in the reservoir study. To be able to use the ensemble Kalman lter on these models, we needed to develop a parallel implementation of the ensemble Kalman lter. This thesis discusses the enabling tools and technologies developed to address a speci c problem: how to accurately characterize reservoirs, using large numbers of complex detailed models. For these characterization studies to be helpful in making production decisions, the time to solution must be feasible. To that end, our work is focused on developing and extending these tools, and optimizing their performance.

Managed Pressure Drilling (MPD) is an emerging drilling technology that utilizes mud weight, surface backpressure and annular frictional pressure loss (AFP) to precisely control the wellbore pressure. The goal of this project is to identify the most appropriate initial response and kick circulation method for the kicks that result from complications specific to MPD. These complications that can cause a reduction in bottomhole pressure were classified as surface equipment failures and unintended equivalent circulating density (ECD) reductions. Rotating control device (RCD) and pump failures are the examples of surface equipment failures. Pump efficiency loss and BHA position change represent the unintended ECD reductions. Shut-in (SI), MPD pump shut down, increasing surface backpressure, increasing pump rate, starting a new pump with surface backpressure and increasing pump rate with surface backpressure responses were simulated on a transient drilling simulator for kicks taken due to the pump efficiency loss, and the simulation results were evaluated. Shut-in and starting a new pump with a surface backpressure were simulated for a pump failure, which led to a loss of total AFP, and the simulation results were evaluated. A shut-in response was simulated for surface pressure loss (RCD failure), and its results were evaluated. Shut-in, MPD pump shut down, increasing surface backpressure pressure, increasing pump rate and increasing pump rate with surface backpressure responses were simulated, and the simulation results were evaluated for the kick taken due to BHA position change. Kick circulation was also simulated after the influx was stopped by the initial responses. The kicks were circulated using drillers method at normal, half, and increased circulating rates depending on the initial response. The results of circulating simulations were also evaluated. SI was concluded to be applicable for all kicks caused by bottomhole pressure fluctuations. However, increasing casing pressure is the most effective response if it is practical given the surface equipment and its condition. Normal rate circulation following these responses is generally better than using an increased or slow pump rate for these kinds of kicks. It reduces the surface backpressure and non productive time (NPT) required versus slower pump rates.

The Thesis is an analytical and numerical analysis of a new method for completing and producing oil wells affected by water coning. The method enables producing oil with no or minimal water cut while keeping the water subsurface with downhole water loop (DWL) installation. Typically, a DWL well is triple-completed in the oil and water zones with the three completions separated by parkers. The top completion produces oil to the surface while the middle and bottom completions drain from and inject into the bottom water zone, respectively. Segregated-inflow operation of DWL well requires keeping the production and drainage-injection rates below their critical values. Therefore, the theory of water coning is re-visited and examined using analytical modeling of critical height and dynamic stability of water cone. The analytical model employs transformation from anisotropic to equivalent isotropic radial flow system. Also, considered are the effects of partial penetration and capillary-pressure transition zone. The analytical model is used to determine operational domain of DWL for different well-reservoir systems. The results are then compared with data from commercial simulator and real field showing good match. Also investigated is the effect of the distance between water drainage and injection completions (D/I spacing), which is the most important design parameter for DWL wells. The results show that DWL wells could successfully work in reservoirs with relatively small aquifer as the DWL operational domain is only sensitive to small values of D/I spacing. A commercial simulator is employed to build a numerical model of DWL operations outside the segregated-inflow domain where the top completion produces oil with water. The steady demonstrates the flexibility of DWL in controlling water cut. Then, the model is used to study DWL performance with controlled water production using a modified nodal analysis approach that includes the D/I spacing constraint. The results show that DWL could improve critical oil rate and reduce water cut before and after water breakthrough, respectively. Nodal analysis is used to seek the possible production operations of DWL which would help to design the D/I spacing and decide if one or two downhole pumps were needed for the system.

Managed pressure drilling (MPD) is an adaptation of conventional drilling that has been developed to manage and control subsurface pressures in the well in order to minimize specific drilling problems. The constant bottom hole pressure approach (CBHP) is a versatile method of MPD, where a closed annulus allows initial responses to kicks other than simply shutting in the well. The objective of this research was to identify and evaluate the best initial response to gas kicks taken during drilling as a basis for developing reliable well control procedures for CBHP operations. Nine non-circulating and circulating responses (NCRs and CRs) were defined, and their application to kicks in two different wellbore geometries was studied through the use of computer simulations. Two different kick sizes, two different formation permeabilities, and three different kick intensities were considered. NCRs included a rapid shut in (SI) and four different MPD pump shut down schedules ending in SI. CRs included stepwise and rapidly increasing the casing pressure until the mud flow out equaled mud flow in, increasing casing pressure to a pre-defined limit and increasing the ECD by increasing mud pump rates. The initial responses were compared, based on the ability to stop an influx, determine whether the influx was stopped assuming intact wellbore, minimize risk of lost returns, minimize additional kick influx, and minimize excessive pressure at the surface and casing shoe. The results of over 150 simulations revealed that no single best initial response to all kicks could be identified. Three initial responses showing broad applicability include a rapid increase of casing pressure until flow rates are equal, shutting the well in and an adaptation of the MPD pump shut down schedule that allowed confirmation of a low rate kick. Increasing mud pump rate also showed advantages, but has limited application. Potential advantages and limitations of each were also explained. A method to confirm that the influx stopped during the application of CRs was also proposed. The best initial response was dependent on well conditions and the equipment used. Therefore, a simple decision tree was developed to plan an appropriate response.

Natural gas, which accounts for a quarter of worlds energy, has been a major energy source because of its abundance and less impact on environment. With explorations at higher depth, pressure and temperature, the share of gas condensate reservoirs to global gas production is increasing. A unique production challenge associated with these reservoirs is the condensate blockage problem, which is the buildup of condensate liquid saturation around wellbore as a result of drawdown below dew point pressure. Mitigation of this problem requires in depth understanding of the multiphase flow of liquid and gas. Surfactants are well known in the literature for affecting such multiphase flow characteristics in reservoirs. They affect the flow behavior primarily by wettability alteration as well as spreading coefficient modification. In this study, multiphase flow characteristics of gas condensates, with and without surfactants were observed by running corefloods representing actual reservoir retrograde condensation phenomena. A commercial anionic surfactant, Alfoterra® 123-4S, was successfully shown to facilitate condensate removal with relative permeability enhancement of over 17 percent at a surfactant concentration of 2000 ppm, which was also the optimum concentration under the flowing conditions. The efficacy of surfactant was observed to be a non-linear function of its concentration and this is attributed mainly to the pleateauing effect above the critical micellar concentration (CMC) values.

Carbon capture and storage is one of the technologies that could help reduce CO2 concentration in the atmosphere while contributing to cutback of Greenhouse Gas emissions. Depleted oil and gas fields are favorable targets for CO2 storage because existing wells can be readily used as injection wells. However, a number of abandoned wells also serve as gateway to the reservoir which should be considered in the context of effective Carbon capture and storage. Wellbore cement is a very essential element in wellbore systems that serve as a barrier between different zones in the subsurface. The fractures inside wellbore cement sheath, one of the possible pathways for CO2 leakage to surface and/or fresh water aquifers, impair the effective sealing of the wellbore cement. Hence, the existence of microfractures poses a risk for Carbon capture and storage. The purpose of this experimental study is to gain understanding about the effect of acidic brine on the behavior of cement fracture and porosity. Two experiments were conducted, one under atmospheric and one under high pressure conditions, using CO2 saturated brine. Fracture widening was observed in CT images of the low pressure experiment and was verified with pressure drop calculations. The low pressure experiment resulted in the reduction of porosity whereas the high pressure experiment resulted in a slight increase in porosity. The porosity reduction was caused by calcite deposition which was confirmed by mineralogical analysis, ESEM images and effluent brine analysis. There were 2 mechanisms working simultaneously: leaching and precipitation (carbonation). It appeared that leaching took place first and drove the carbonation process. Leaching resulted in an increase in porosity whereas carbonation resulted in a reduction of porosity. In a possible leakage scenario, acidic brine exposure may result in a reduced fracture aperture due to carbonation coupled with confining stress around cement sheath.

Surfactants have a variety of applications in the petroleum industry due to their remarkable ability to lower the oil-water interfacial tension and alter wettability. However, surfactant adsorption on rock surfaces has severely crippled this means of improving oil recovery due to the high cost associated with the large quantities of surfactant needed. A previous experimental study by Ayirala (2002) reported the development of mixed wettability using a nonionic surfactant. At this mixed-wet state he was able to recover about 94% of the original oil in place. The underlying motivation of this study was to achieve such high recoveries without using large quantities of surfactants. A new surfactant enhanced waterflood method is proposed as the means to accomplish this task. This improved waterflood method consists of soaking the area around the production or injection well with an optimally concentrated surfactant slug prior to conducting a waterflood. Four variations of this novel process were investigated. The first two variations examined two surfactant slug sizes (0.2PV and 0.3PV) soaked around the production well prior to conducting a waterflood. The third variation explored the idea of soaking the area around the injection well instead of the production well prior to a waterflood. After soaking the area around the production well with a surfactant slug, the fourth variation used a low concentration (LC) surfactant solution to flood the reservoir instead of water. The main objective of this study was to evaluate whether these proposed improved waterflood methods are technically feasible, and also determine their effectiveness when compared to a conventional waterflood. In addition, simple cost analysis calculations were carried out to show the economic feasibility of the proposed improved waterflood variations, especially when compared to a conventional waterflood. All the experiments utilized the same rock and fluid properties, as those used by Ayirala in his coreflood experiments. A surfactant (Tomadol 91-8) with similar properties and recovery to that used by Ayirala was used in this project. This project was divided in four sets of experiments. This study found that all four improved waterflooding variations were technically feasible, and were more effective in improving oil recovery than a conventional waterflood. In addition, the proposed improved waterflood variations accomplished the task of significantly improving oil recovery with small quantities of surfactant.

With recent advances in the capabilities of high performance computing (HPC) platforms and the relatively simple representation of complex geometries of porous media, lattice Boltzmann method (LBM) has gained popularity as a means of solving fluid flow and transport problems. In this work, LBM was used to obtain flow parameters of porous media, study the behavior of these parameters at varying flow conditions and quantify the effect of roughness on the parameters by relating the volume averaged flow simulation results to Darcy and Forchheimer equations respectively. To validate the method, flow was simulated on regular and random sphere arrays in cubic domains, for which a number of analytical solutions are available. Permeability and non-Darcy coefficients obtained from the simulation compared well with Kozeny and Ergun estimates while deviation from the observed constant permeability and tortuosity values occurred aroundRe≈1-10. By defining roughness as hemispherical protrusions on the smooth spheres in the regular array, it was observed from flow streamlines obtained at different roughness heights that the average length of the flow paths increased with increasing roughness height. As such, the medium tortuosity and non-Darcy coefficient increased while the permeability decreased as height of the roughness increased. Applying the method to a 3D computed tomography image of Castlegate sandstone, the calculated macroscopic permeability and beta factor components were in good agreement with reported experimental values. In addition, LBM beta factors were compared with a number of empirical models for non-Darcy coefficient estimation and were found to be of the same order of magnitude as most of the correlations, although estimates of the models showed wide variation in values. Resolution of the original sample was increased by infilling with more voxels and simulation in the new domain showed better flow field resolution and higher simulated flow regimes compared to those of the original sample, without significant change in the flow parameters obtained. Using the Reynolds number based on the Forchheimer coefficient, the range of transition from Darcy to non-Darcy regime was within the values reported by Ruth and Ma (1993) and Zeng and Grigg (2006). 1