Abstract The phase of CO 2 present in a saline reservoir influences the change of the pore geometry properties of reservoir rocks and consequently the transport and storage integrity of the reservoir. In this study, digital rock physics was used to evaluate pore geometry properties of rocks saturated with the different phaseCO 2 -brine under reservoir conditions. The changes in the pore geometry properties due to the different phaseCO 2 -brine-rock interaction were quantified. In addition to compression, CO 2 -brine-rock interaction caused a further reduction in porosity by precipitation. Compared to the dry sample, the porosity of the gaseous CO 2 -br sample was reduced the most, and was lower by 15% after saturation and compression. There was reduction in the pre-compression porosity after compression for all the samples, however, the reduction was highest in the gaseous CO 2 -br-saturated sample (13%). The flatness of pore surfaces was reduced, and pores became less rounded after compression, especially in supercritical CO 2 -br-saturated rock. The results from this research provide a valuable input to guide a robust simulation of CO 2 storage in reservoir rocks where different phases of CO 2 could be present.
Emerging Technologies in Hydraulic Fracturing and Gas Flow Modelling features the latest strategies for exploiting depleted and unconventional petroleum rock formations as well as simulating associated gas flow mechanisms. The book covers a broad range of multivarious stimulation methods currently applied in practice. It introduces new stimulation techniques including a comprehensive description of interactions between formation/hydraulic fracturing fluids and the host rock material. It provides further insight into practices aimed at advancing the operation of hydrocarbon reservoirs and can be used either as a standalone resource or in combination with other related literature. The book can serve as a propaedeutic resource and is appropriate for those seeking rudimentary information on the exploitation of ultra-impermeable oil and gas reservoirs. Professionals and researchers in the field of petroleum, civil, oil and gas, geotechnical and geological engineering who are interested in the production of unconventional petroleum resources as well as students undertaking studies in similar subject areas will find this to be an instructional reference.
An overview of the different categories of unconventional oil and gas reservoirs, and corresponding stimulation techniques appropriate for them is examined. Three main groups of unconventional oil and gas formations are appraised: heavy oil, oil shale and tight reservoirs. The scope of stimulation methods applicable to heavy oil reservoirs is limited. This kind of formation contains characteristic high-viscous hydrocarbons and are produced majorly by cold production and thermal stimulation. On the other hand, a wider range of stimulation methods are successfully used to produce tight and oil shales formations. For oil shales, these include drilling horizontal wells as substitutes to vertical wells, hydraulic fracturing, surfactant treatment, water imbibition, thermal treatment and acidisation; whilst for tight formations, these include hydraulic fracturing, surfactant treatment, water imbibition, acidisation and the application of electro-kinetics. Fracturing fluid systems are integral to the implementation of most stimulation operations and are evaluated herein under the following groups: water-based, oil-based, foam-based and acid-based. The most commonly used fracturing fluids are water based, albeit there are several instances where other types of fluids or combination of fluids are more suitable based on factors such as formation sensitivity, costs, wettability, rock solubility, surface tension, capillarity, viscosity, density, rheology and reactivity.
There have been several incidences of flood recently, which are believed to be aggravated by increased climatic variables as a result of perceived changes in climatic conditions (due to climate change) in the Cross River Basin. The basin is the most extensively developed and used river basin in the management of the water resources of the Cross River and Akwa Ibom States in Nigeria. In this paper, 30 years (from 1992 to 2021) of hydro-meteorological data (annual average rainfall, maximum and minimum temperatures, hu midity, duration of sunlight (sunshine hours), evaporation, wind speed, soil temperature, cloud cover, solar radiation, and atmospheric pressure) from four stations in the Cross River Basin were obtained from the Nigerian Meteorological Agency (NIMET), Abuja and subjected to trend detection analysis using the Mann–Kendall test to determine the trend in climatic parameters. The results indicate that there is a significant upward trend in annual rainfall in Ogoja but a downward trend in Calabar. The evaporation trend is significantly downward in Eket, whereas in Calabar, there is an upward trend in solar radiation. Generally, there is a significant rise in annual maximum temperature across the basin. Serial correlation and segmented regression analyses were performed to measure the impact of fluctuations in monthly and long-term Tahiti and Darwin’s Sea level pressures on the climatic variables at the Cross River Basin catchment. These analyses were necessary to determine the extent of the influence of the El Nino Southern Oscillation climatic cycle. The analyses show no significant association between the El Niño Southern Oscillation (ENSO) and rainfall or between the ENSO and runoff in the catchment. This implies that the impact of the ENSO on rainfall and runoff in the Cross River Basin catchment is not considerable. The intercepts derived from the segmented regression in Eket and Ogoja show significant positive trends in both areas for rainfall and runoff. The trends in intercepts suggest that there are external factors influencing rainfall and runoff other than ENSO events, thus strengthening the assertion of climate change. Results from this study will facilitate the understanding of the variability in climatic parameters by stakeholders in the basin, researchers, policymakers, and water resource managers.
CO2–brine–rock interaction impacts the behavior and efficiency of CO2 geological storage; a thorough understanding of these impacts is important. A lot of research in the past has considered the nature and impact of CO2–brine–rock interaction and much has been learned. Given that the solubility and rate of mineralization of CO2 in brine under reservoir conditions is slow, free and mobile, CO2 will be contained in the reservoir for a long time until the phase of CO2 evolves. A review of independent research indicates that the phase of CO2 affects the nature of CO2–brine–rock interaction. It is important to understand how different phases of CO2 that can be present in a reservoir affects CO2–brine–rock interaction. However, the impact of the phase of CO2 in a CO2–brine–rock interaction has not been given proper attention. This paper is a systematic review of relevant research on the impact of the phase of CO2 on the behavior and efficiency of CO2 geological storage, extending to long-term changes in CO2, brine, and rock properties; it articulates new knowledge on the effect of the phase of CO2 on CO2–brine–rock behavior in geosequestration sites and highlights areas for further development.
The stimulation of unconventional hydrocarbon reservoirs is proven to improve their productivity to an extent that has rendered them economically viable. Generally, the stimulation design is a complex process dependent on intertwining factors such as the history of the formation, rock and reservoir fluid type, lithology and structural layout of the formation, cost, time, etc. A holistic grasp of these can be daunting, especially for people without sufficient experience and/or expertise in the exploitation of unconventional hydrocarbon reserves. This book presents the key facets integral to producing unconventional resources, and how the different components, if pieced together, can be used to create an integrated stimulation design. Areas covered are as follows: • stimulation methods, • fracturing fluids, • mixing and behavior of reservoir fluids, • assessment of reservoir performance, • integration of surface drilling data, • estimation of geomechanical properties and hydrocarbon saturation, and • health and safety. Exploitation of Unconventional Oil and Gas Resources: Hydraulic Fracturing and Other Recovery and Assessment Techniques is an excellent introduction to the subject area of unconventional oil and gas reservoirs, but it also complements existing information in the same discipline. It is an essential text for higher education students and professionals in academia, research, and the industry.
A numerical model is developed to simulate fluid flow conditions around a wellbore and to evaluate mechanisms governing fluid flow, pressure gradients, rock failure and the ensuing sand production. The rock material behaviour matches sandstone described by the Drucker–Prager material failure model. Conditions for erosion are governed through two criteria: a material failure criterion described by the Drucker–Prager model and a sanding criterion expressed by an eroded solid mass generation model. The interplay between controlling operating and reservoir conditions is assessed. In addition, contributions of the following key factors to interstitial fluid velocity, plastic strain, pore pressure variation and sand production are appraised: drawdown, wellbore perforation depth, mud pressure and erosion criteria. Despite a decrease in pore fluid velocity at the vicinity of the wellbore at increasing depth, sand production increases with wellbore/perforation depth. Likewise, at constant drawdown, sand production is aggravated as wellbore/perforation depth increases. The rate of increase in the plastic zone following the onset of sand production is inconstant. Furthermore, mud pressure is demonstrated as an effective tool for attenuating sand production. An understanding of interactions between key parameters governing reservoir responses and the effect on sanding during oil/gas production is imperative if extraction operations are to be optimised.
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