Forecast of Economic Tight Oil and Gas Production in Permian Basin

We adopt a physics-guided, data-driven method to predict the most likely future production from the largest tight oil and gas deposits in North America, the Permian Basin. We first divide the existing 53,708 horizontal hydrofractured wells into 36 spatiotemporal well cohorts based on different reservoir qualities and completion date intervals. For each cohort, we fit the Generalized Extreme Value (GEV) statistics to the annual production and calculate the means to construct historical well prototypes. Using the physical scaling method, we extrapolate these well prototypes for several more decades. Our hybrid, physico-statistical prototypes are robust enough to history-match the entire production of the Permian mudstone formations. Next, we calculate the infill potential of each sub-region of the Permian and schedule the likely future drilling programs. To evaluate the profitability of each infill scenario, we conduct a robust economic analysis. We estimate that the Permian tight reservoirs contain 54–62 billion bbl of oil and 246–285 trillion scf of natural gas. With time, Permian is poised to be not only the most important tight oil producer in the U.S., but also the most important tight gas producer, surpassing the giant Marcellus shale play.

Study on Fracture Conductivity of Mahu Sandy Conglomerate Tight Oil Reservoir

Objectives/Scope: Effective development of tight oil and gas depends on the generation of artificial fractures, and continuous and efficient development of tight oil and gas requires the use of proppants to maintain the diversion effect of artificial fractures. At present, the microscopic mechanism of damage to fracture conductivity of sand conglomerate reservoir is not clear. Methods, Procedures, Process: Taking the sandstone conglomerate in Mahu sag as the research object, the experimental study on the fracture conductivity of the sandstone conglomerate in Mahu sag is carried out. First, the stress sensitivity analysis of the sandstone conglomerate is performed on a pore scale using a self-made permeability measurement method, then, the fracture width, pressure and flow rate are measured under the condition of fracture scale to analyze the change law of conductivity during fracturing fluid injection. Results, Observations, Conclusions: The results show that the permeability of gravel decreases with the increase of confining pressure, and the stress sensitive damage is strong. After a cyclic loading condition, permeability will not recover to the initial value, causing irreversible damage to the pore and roar. As the fracturing fluid continues to be injected, a large amount of proppant becomes embedded in the fracture and leads to a decrease in conductivity. The whole diversion curve can be divided into two stages. In the first stage, the diversion damage is great, and in the second stage, the diversion damage decreases somewhat. The damage of conductivity is closely related to the content of clay minerals.With the increase of clay mineral content, the conductivity damage rate increases rapidly, especially the existence of illite and Aimonite mixed beds can significantly improve the conductivity damage rate. Novel/Additive Information:The results provide a solution for the optimization of proppant concentration, the improvement of tight oil production and the study of gravel diversion damage mechanism in the Mahu area.

Correction to: Influence of CO2 retention mechanism storage in Alberta tight oil and gas reservoirs at Western Canadian Sedimentary Basin, Canada: hysteresis modeling and appraisal

A correction to this paper has been published: https://doi.org/10.1007/s13202-020-01070-5

Influence of CO2 retention mechanism storage in Alberta tight oil and gas reservoirs at Western Canadian Sedimentary Basin, Canada: hysteresis modeling and appraisal

Rapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.