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

Miscible CO2 injection is the second largest contributor to global enhanced oil recovery, as it has successfully undergone extensive laboratory tests and field applications for recovering residual oil left behind after waterflooding. Prolific incremental recoveries have been obtained for some fields. Although miscible CO2 injections generally have excellent microscopic displacement efficiency they often result in poor sweep efficiency. In order to address sweep problems and maximize recoveries, other schemes of gas injection have been developed. Two such processes are water-alternating-gas (WAG) and simultaneous water-and-gas (SWAG) injection. WAG and SWAG have been successfully used to minimize poor sweep. Improved gas utilization and oil recovery have been reported for SWAG injection at Joffre Viking, Kapurak River, and Rangley Weber fields. There are very little published data evaluating the performance of simultaneous water and gas injection under miscible conditions and very little published data exists that compares enhanced recovery processes conducted under consistent experimental conditions. This is especially true when the gas is CO2. In this work a sequence of experiments were conducted to evaluate core flood behavior of Continuous Gas Injection (CGI), 1:1 Water Alternating Gas (WAG) with a slug size of 0.25 pore volumes, and Simultaneous Water-and-Gas (SWAG) injection at four fg values. The experiments were conducted at rock wettability, flow rates and pressures that were as consistent as possible in order to make meaningful comparisons. After 2 PV of CO2 injection the SWAG flood with fg = 0.4 recovered about 0.9692 of waterflood residual oil. CGI had the second best recovery of about 0.8998 followed by WAG with 0.8602. The SWAG flood with fg = 0.6 recovered about 0.8300 of waterflood residual oil and SWAG with fg = 0.8 and fg = 0.2 recovered about 0.7507 and 0.7253 respectively. The gas utilization was the least for SWAG with fg = 0.4 at 15.54 Mscf/bbl followed by CGI with 16.13 Mscf/bbl. The remaining experiments utilized over 17.20 Mscf/bbl.

Enhanced oil recovery by CO2 injection is a common application used for light oil reservoirs since CO2 is relatively easily miscible with light oils. CO2 flooding in heavy oil reservoirs is often uneconomic due to unfavorable mobility ratios. Reservoir heterogeneity further complicates the process as CO2 channels through high permeability layers leading to premature breakthrough. However, this can be controlled by choosing a suitable modification to the CO2 injection process enabling better sweep efficiencies, and making the process economic. The current work focuses on two such methods; water-alternating-gas injection (WAG) and profile modification by blocking gas flow in the high permeability layer. These methods were studied for physical mechanisms of oil recovery, increasing sweep efficiency, and mitigating premature breakthrough. Reservoir simulation studies of these methods were conducted using an analog heavy oil (14° API) field with a high permeability streak which had 50 times greater permeability than the adjacent zones. A detailed fluid characterization was performed to accurately represent the reservoir fluid. Slim tube and core flood simulations were interpreted to understand the physical mechanisms of oil recovery for this crude. Profile modification using a blocking agent showed very encouraging results. Different WAG ratios were also evaluated, and a WAG ratio of 1:1 resulted in the highest oil recovery which was consistent between both core flood simulations and field simulations. This is different from WAG ratios for highest recovery in light oil reservoirs where values of 1:2 are typically seen. It is shown that with careful study of the reservoir geology and fluid properties, application of these methods can significantly improve sweep efficiency and oil recovery in heavy oil floods.

The objective of this study is to investigate the characteristics of foam flow behavior in pipes in a wide range of experimental conditions, including two pipe materials (stainless steel and nylon pipes with about 0.36 - 0.38 inch in inner diameter and 12 ft in length), three surfactant formulations (Cedepal FA-406, Stepanform-1050, and Aquet-944), and three surfactant concentrations (0.1, 0.5, and 5 wt%). The concept of two foam-flow regimes, consisting of high-quality regime and low-quality regime, is at the heart of interpreting the experimental data. The experimental results in horizontal pipes showed the presence of two distinct high-quality and low-quality foam-flow regimes which could be identified by both pressure responses and direct visual observations. The high-quality regime was characterized by unstable and oscillating pressure responses represented by slug flow, while the low-quality regime was characterized by stable pressure responses represented by either plug flow or segregated flow. These two distinct flow regimes, separated by a locus of fg* in the contour plot, were shown to have different sensitivities to the change in gas and liquid velocities: (1) foam rheology in the high-quality regime was sensitive to both gas and liquid velocities because of the resulting changes in lengths of foam-slug and free-gas sections adjusted to the new flow conditions, and (2) foam rheology in the low-quality regime was sensitive to gas velocity because of finer foam texture at higher shear rates, and was relatively insensitive to liquid velocity because of lubricating effect and drainage effect. The results at different inclination angles showed that foam rheology was not significantly altered by the inclination angle as long as the slug-flow or plug-flow pattern was formed because of a viscous-force dominant environment. However, if flow conditions fell within the segregated-flow pattern, foam rheology was governed by the gravitational force rather than the viscous force, and therefore the flow characteristics were sensitive to inclination angles. These findings were supported by visual observations as well as pressure responses. The implication of these experimental findings is discussed for applications such as foam-assisted underbalanced drilling processes and foam-fracturing treatments in the petroleum industry.

Few heavy oil reservoirs with strong bottom water drives have been developed successfully because of severe water coning. Water coning tends to cause low ultimate recovery, low well productivity, and high water production. Although thermal and gravity-assisted methods might improve recovery in oil reservoirs, such methods are widely perceived as either economically unfavorable or technologically infeasible. This study proposes a new, cold production technique, called Bilateral Water Sink (BWS), to meet those challenges. The BWS method suppresses water cresting by producing oil and water simultaneously from separate, horizontal wells completed in the oil and water zones; the oil and water completions are parallel, with the oil well directly above the water well. In conventional horizontal well production, water cresting causes water to bypass oil, making the water drive mechanism ineffective. BWS controls water invasion by altering the pressure distribution in the near-well area. With cresting suppressed, the oil completion remains water-free, allowing water to displace oil from the edges of the well drainage area to the oil completion, increasing ultimate recovery. Unlike existing heavy oil recovery methods, BWS exploits the natural reservoir energy in the bottom water drive. This makes BWS economically, technically, and environmentally appealing especially for offshore applications, where cold production is currently the only option and oil-water separation is a problem. In this study, BWS oil recovery is investigated analytically and numerically. A new mathematical model identifies controlling variables and project design parameters, and describes the relationships among them. The design model is used to select rates of water and oil in BWS wells for best performance. The analytical model is verified by a comparison to numerical simulations. These two approaches together provide the quantitative account of the BWSs effect on avoiding water cresting and improving oil recovery. The results show that BWS can increase oil recovery from 10 percent to over 40 percent in a conventional case, while avoiding the problem of oil-contaminated water production. As a result, the mathematical model of BWS well behavior is shown to be a practical reservoir management tool to guide development of heavy oil reservoirs with bottom water drives.

Geopressured geothermal brines are a vast geothermal resource in the US Gulf of Mexico region. In particular, geopressured sandstones near salt domes are potential sources of geothermal energy because salt diapirs with high thermal conductivities may pierce younger, cooler strata. These characteristics enhance transfer heat from older, hotter strata at the base of the diapir into shallower strata. Moreover, widespread geopressure in the Gulf region tends to preserve permeability, enhancing productivity. As an example, the Camerina A sand of South Louisiana was chosen as a geomodel for a numerical simulation study of effects of CO2 injection and coupled convection as a method of geothermal development. This study presents scenarios for heat harvesting from typical Gulf of Mexico aquifers including Camerina A that take advantage of coupled convection and simultaneous CO2 sequestration. Suites of TOUGH2 numerical simulations demonstrate benefits of introducing CO2 injection wells, varying locations of injection/production wells, and exploiting gravity segregation of the fluids.

Sustained casing pressure (SCP) is considered a well integrity problem. The approach of this study is to look at SCP as environmental risk due hydrocarbon release. Currently, the risk is qualified by the value of surface pressure (Pcsg) that may cause failure of casing head. However, the resulting rate of gas emission to the atmosphere is not considered. Also not considered is a possibility of breaching the casing shoe due transmission of Pcsg downhole. The objective of this study is to develop methods for maximum possible air emission rates (MER) and risk of subsurface well integrity failure due SCP. Mathematical models and software are developed for computing MER, casing shoe strength (CSS) determined by leak-off test (LOT), and casing shoe pressure load resulting from SCP (SCPd). The models are used to find controlling parameters, identify the best and least-desirable scenarios, and assess environmental risk. It is concluded that emission potential of SCP wells with high wellhead pressure (Pcsg) can be quite small. The CSS model study reveals the importance of data recorded from LOT; particularly the time after circulation was stopped the non-circulation time (∆ts). Ignoring ∆ts would result in underestimation of the ultimate CSS. The error is caused by the cumulative effect of thermally induced rock stresses, which strongly depend on ∆ts. The study displayed SCPd being controlled by the annular fluid properties which are subject to change in long time through mud aging; and mostly being overestimated. Comparison of surface versus subsurface failure scenarios yielded cases where the casing shoe demonstrates more restrictive failure criterion (CSS) than the burst rating of wellhead (MAWOP). Risk of casing shoe breaching (RK) is quantified using the CSS and SCPd models and application of risk analysis technique (QRA). The CSS distribution followed log-normal trend due the effect of ∆ts, while the SCPd distribution maybe of various shapes dependent on the annular fluid size and properties that are not well known. Possible scenarios of casing shoe breaching are statistically tested as a hypothesis of two means. The study produced engrossingly variant outcomes, RK changing from 1 to 80 percent.