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.

The events surrounding the Deepwater Horizon disaster have changed the face of deepwater operations. In order to continue drilling in the Gulf of Mexico, the regulatory body, the Bureau of Safety and Environmental Enforcement (BSEE), has required that applications to conduct work in the Gulf of Mexico (GOM) include a plan to stop, capture, or contain any uncontrolled release of fluids. The capping and containment systems built and implemented by BP during the event are an excellent starting point for minimizing pollution from deepwater subsea blowouts, but the system has limitations. The industry recognizes these limits but is currently focused on meeting the regulatory requirements. This project will analyze events reported to the BSEE in the past 15 years to define the basis for potential capabilities that a capping and containment system should have to minimize the volume of fluid released as well as minimize the time needed to regain control of the well. The analysis will take a detailed look at 90 events over the past 15 years to determine critical factors in the design of a generally applicable capping stack. The research will also look at specific barriers that were used to regain control of the well. Finally, any factors which contributed to the severity of the event or contributed to the success of the blowout response are identified. Based on this detailed review, a list of design considerations for a generally applicable capping stack was created.

The events of the Deepwater Horizon oil spill in the Gulf of Mexico were associated with great water depths that made it difficult to understand the behavior of the spilled oil as it came in contact with the seawater. The remedial subsea application of chemical dispersants draws interest to evaluate the interfacial interactions between the oil and water at such great water depths. Most importantly, a quantification of the interfacial tension (IFT) between the spilled oil and seawater at deepwater conditions can provide insight into the effectiveness of the chemical dispersion of spilled oil. In this study, Macondo crude oil and synthetic seawater samples were used to measure the oil/water IFT by the Pendant Drop method at deepwater conditions of pressure and temperature. A laboratory apparatus capable of representing such conditions was designed and established to enable IFT and density measurements. Reagent grade n-octane was also used to compare its behavior to that of crude oil. The effectiveness of a commercial dispersant, Corexit® 9500, was assessed through the evaluation of the magnitude of the reduction in the hydrocarbon/water IFT. The influence of pressure, temperature, water salinity and dispersant concentration on the IFT was each studied independently as well. The measured oil/water IFT decreased from 25.69 to 22.55 mN/m as both pressure and temperature were changed from water surface to seafloor conditions. The dispersant was capable of reducing the IFT by 70 % from its original value at the water surface while only a 50 % reduction was observed at seafloor conditions. The low temperature associated with the seafloor was determined as the main factor responsible for deteriorating the dispersant effectiveness as pressure had a relatively smaller effect on the IFT. The dispersant was also observed to perform better when dissolved in the crude oil as compared to the time it was dissolved in the water. However, at 10,000 ppm dispersant-in-oil concentration, the oil adopted the shape of a continuous stream instead of breaking up into small droplets. Accordingly, ultra-low oil/water IFT was not achieved, despite such a high dispersant concentration, indicating ineffective chemical dispersion at seafloor conditions.

Effective zonal isolation during primary cementing is only possible when drilling mud in the annulus is completely displaced with cement, while the spacers aid in this process. During the displacement process the rheological properties of fluids used and the operating conditions control the motion of different fluids interfaces; desired stable interfacial displacement leads to piston like motion. Computational Fluid Dynamics (CFD) tool with the Volume-of-Fluid (VOF) has been validated against experimental and used to conduct numerical experiments in a virtual well model consisting of 50 ft vertical section of 8.765" x 12.5" annulus having initially mud and this mud is swept by one annular volume of spacer followed by one annular volume of cement. The 50 ft section was further divided into five subsections each of length 10 ft and average values of quantities for these sections were used for further analysis. The mud and cement properties were kept constant and the spacer density, viscosity and displacement rate were the only controlling parameters to achieve the piston like displacement. The spacer density and viscosity were varied between water and cement with cement being the heaviest and most viscous fluid. Three Reynolds numbers of 100, 167 and 400 were simulated. Temporal variation of the mud volume fraction was used as an indication for the piston like interfacial displacement. For an ideal piston like interfacial displacement the mud fraction reduces sharply with minimum residual mud volume after the spacer sweeps through. A gradual mud reduction represents fluid fingering and the fluctuations in the mud fraction represent fluid mixing. The best displacement was observed when the spacer had the same density as mud while it has the viscosity similar to water. The displacement process was least effective when the spacer had the density equal to cement for all viscosity ranges. Based on the simulation results, a correlation was developed to find the final placed cement volume fraction in the annulus under similar fluid conditions, the utility of CFD based correlation is also presented. Further development of the correlation for varying spacer volume at other operating conditions may be needed to extend its applicability.

Thesis--PlanB (M.S.)--University of Wisconsin--Stout, 2004. / Includes bibliographical references.