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Collaborating Authors
Jones, Adrian
An Improved Understanding About CO2 EOR and CO2 Storage in Liquid-Rich Shale Reservoirs
Mahzari, Pedram (Department of Earth Sciences, University College London) | Oelkers, Eric (Department of Earth Sciences, University College London) | Mitchell, Thomas (Department of Earth Sciences, University College London) | Jones, Adrian (Department of Earth Sciences, University College London)
Abstract During the past decade, enhanced oil recovery (EOR) by CO2 in shale oils has received substantial attention. In shale oil reservoirs, CO2 diffusion into the resident oil has been considered as the dominant interaction between the CO2 in fractures and the oil in the matrices. CO2 diffusion will lead to oil swelling and improvement in oil viscosity. However, despite two-way mass transfer during CO2 EOR in conventional oil reservoirs, one-way mass transfer into shale oils saturated with live oils is controlled by an additional transport mechanism, which is the liberation of light oil components in the form of a gaseous new-phase. This in-situ gas formation could generate considerable swelling, which could improve the oil recovery significantly. This mechanism has been largely overlooked in the past. This study is aimed to better understand the role of this evolving gas phase in improving hydrocarbon recovery. Taking account of Bakken shale oil reservoir data, numerical simulations were performed to identify efficiencies of EOR by CO2 at the laboratory and field scales. Equation of state parameters between CO2 and oil components were adjusted to optimize the calculations and a sensitivity analysis was performed to identify the role of gas formation and consequent EOR efficiencies. At the laboratory scale, in-situ gas formation can increase oil recovery by 20% depending on the amount of gas saturation. Also, the CO2 storage capacity of the shale matrix can be enhanced by 25%, due to CO2 trapping in the gas phase. At the field scale, an additional oil recovery of 9.1% could be attained, which is notably higher than previous studies where this gas evolution mechanism was ignored. Furthermore, the results suggest that a six-weeks huff period would be sufficient to achieve substantial EOR if this new mechanism is incorporated. On the other hand, the produced fluid in the early period was primarily composed of CO2, which would make it available for subsequent cycles. The produced gas of the well under CO2 EOR was used in an adjacent well, which resulted in similar additional oil recovery and hence, impurities in CO2 injection stream would not undermine efficiency of this EOR method. The results of this study, therefore, could potentially be used to substantially improve the evaluations of CO2 EOR in liquid-rich shale reservoirs.
- North America > United States > North Dakota (0.34)
- North America > United States > South Dakota (0.25)
- North America > United States > Montana (0.25)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.98)
Abstract Traditionally, completion equipment has been run in clear fluids, brines, or base oils, to minimize the potential for solids to plug equipment, preventing tools from being set correctly or setting prematurely. However, both brines and base oils have limitations. Base oils typically have densities around 0.8 sg which has well control implications and brines can become prohibitively expensive where high densities are required. In the North Sea, many wells are either highly deviated or require extended reach to access compartmentalised reservoirs. Consequently, the reservoir often comprises a significant proportion of shales. The use of brine as a completion fluid can therefore lead to significant wellbore instability and reservoir impairment issues. A novel approach has been employed by a UK operator to address these problems by compromising between the shale stability provided by oil and the density achievable with brine. The fluid employed is a low-solids, invert emulsion formulated with a high-density internal phase brine. Due to the density limit of the base solids-free brine, additional density is achieved through the use of manganese tetraoxide (Mn3O4). Manganese tetraoxide has a very small, sub-micron, particle size which allows a degree of self suspension thus allowing a fluid with low viscosities to be utilized. The use of this type of formulation provides a fluid which gives good wellbore stability while running completions screens but allows the completion fluid to be produced back in the testing phase of the well without plugging the screens due to the extremely fine particle size of the manganese tetraoxide. This fluid was designed to exhibit excellent sag performance while minimizing the gellation potential of the fluid. The physical characteristics of manganese tetraoxide (small spherical particles) were an important factor in the design of the fluid due to the very tight clearances expected when setting downhole tools. This paper presents laboratory design data and case histories from the UK sector of the North Sea and in Kazakhstan where this type of high-density fluid has been used to run the lower completions while successfully maintaining wellbore stability. Introduction Once the drilling phase of a well is complete, most operators will opt to clean up the well before running the completion string. With non-aqueous fluids (NAF), the cleanup can be quite complicated, requiring a sequence of surfactant pills to be pumped to remove mud residue from the welbore and casing. The ultimate objective is to leave the well with a clean fluid which contains very little solids (typically < 0.05%) or meets a clarity specification. This process can result in large volumes of fluid being generated which is deemed to be contaminated to the point of requiring disposal. Where a water-based drilling fluid has been used, this might simply involve the fluid being discharged (eg. seawater in an offshore environment), but where a NAF has been used, environmental limitations will usually require the contaminated fluid to be contained for further disposal. Part of the reason that large quantities of fluid can be generated is to achieve the required solids specification to ensure that the completion fluid is as clean as possible and prevent solids accumulating and impacting the completion of the well. Manganese tetraoxide has been used as an alternative weighting agent in both water-based and non-aqueous drilling fluids where equivalent circulating density (ECD) and sag performance has precluded the use of barite weighted fluids. The combination of small particle size, spherical shape (Fig. 1) and high specific gravity (4.8 g/cm) make it an ideal weighting agent for fluids where a low viscosity profile and gel strength are required. These same properties make the material suitable for use in completion fluids.
- North America > United States (0.94)
- Europe > Norway > North Sea (0.55)
- Europe > United Kingdom > North Sea (0.45)
- (2 more...)
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (6 more...)