Carbon dioxide (CO2) and other greenhouse gas (GHG) emissions have become a major challenge globally, and particularly for the oil and gas industry. Carbon capture, utilization and storage (CCUS) is one of the options to reduce the amount of anthropogenic CO2 entering the atmosphere. This option creates economic benefit from the waste CO2, vs. pure disposal for sequestration. Organic rich shale reservoirs are an attractive target for carbon storage, due to their adsorptive abilities and multiple mechanisms for gas storage. CO2 has been widely used in oilfield operations since the 1950's. The unique physical properties of CO2 allow for easy transport in pipelines as a gas, or by transport truck as a cold liquid. Oilfield uses include: a gaseous agent to assist in fluid recovery from the wellbore, a component in hydraulic fracture fluids, an enhanced oil recovery (EOR) agent, a fluid blockage removal agent, etc. CO2 is at least partially soluble in water and is a strong hydrocarbon solvent. This study investigates the amount of CO2 sequestered when utilized as a component in the hydraulic fracture fluid system used in multi-stage fractured horizontal wells in several different western Canadian formations. By careful analysis and accounting for the volumes of CO2 injected and returned during flowback, it will be shown that significant volumes of CO2 remain sequestered in the formation; in some cases up to 75% of the injected volume. With more stringent carbon regulations coming into effect in Alberta in 2017 (and Canada in 2020), this opens up a potential new avenue for emitters to utilize and store some of the CO2 they emit - into formations they are actively developing, while at the same time potentially monetizing carbon credits. This is believed to be the first definitive study proving that CO2 is sequestered during hydraulic fracturing operations in organic rich shales and tight sandstone reservoirs. The study will show that there is a net environmental benefit to hydraulic fracturing with anthropogenic CO2 from an overall perspective. It will be shown that this unique application of CCUS also has significant economic benefit to the producer.
A major issue with determining the effectiveness of different completion strategies is reservoir heterogeneitywhich is to be expected with most unconventional resource plays. Two horizontal wells separated by 400 m or less lateraly, completed and stimulated identically may result in one well peforming significantly better than the other, with significantly higher estimated ultimate recovery (EUR). Hence the statistical approach to the problemdeveloped and used in this case study. Rather than using 'closeology' with the assumption that the reservoir quality is the same in a confined areawe use a large number of wells across all geologies to 'normalize' the geological differences. For a large enough sample size statistical theory states that each different completion type to be compared is equally represented in permeability and net pay space (reservoir flow capacity). If this is true, then statistical variations in cumulative production from one group to another are more representative of completion and hydraulic fracture effectiveness. Therefore, the cumulative production metric may be used to compare directly different completion types, number of stages, fracture designs, fluid systems, etc.
In recent years, the tight Cardium sandstones of west central Alberta have seen significant new development with the application of multi-stage fractured horizontal wells. This case study reviews the completion costs, economics and production performance of 148 horizontal oil wells completed in the Pembina Field halo areas (west and east), central Pembina, Willesden Green and Garrington Fields. Production analysis was performed on all wells using the Duong decline curve analysis technique. This technique has been successfully used on tight multi-stage fractured wells in other areas, and has proven successful at predicting long-term well performance and recoveries. Wells were chosen for comparison that were in the same geological and pressure regions, had a minimum of 2 years of production information, and were stimulated with various fracture fluid systems. In one of the analyzed areas, a definite trend was identified; it was found that wells drilled in a certain orientation performed better than wells drilled with other orientations. Completions and hydraulic fracturing costs were gathered from public sources in order to understand the cost differences between areas and types of fracture fluid systems. Using decline curves and cost information, full cycle economics were run on the ‘average’ well for each area in order to determine the Net Present Value (NPV) of each area. This case study shows there is value in optimizing fracture designs through look-back studies, and there is a need to focus on more effective fracture treatment designs in unconventional oil development.
In recent years, the tight Cardium sandstones of west central Alberta have observed significant new development with the application of multistage-fractured horizontal wells (MFHWs). This case study reviews the completion costs, economics, and production performance of 148 horizontal oil wells completed in the Pembina field halo areas (west and east), central Pembina, Willesden Green, and Garrington fields.Production analysis was performed on all wells using the Duong decline-curve-analysis technique. This technique has been used successfully on tight multistage-fractured wells in other areas, and has proved successful at predicting long-term well performance and recoveries. Wells were chosen for comparison that were in the same geological and pressure regions, had a minimum of 2 years of production information, and were stimulated with various fracture-fluid systems.In one of the analyzed areas, a definite trend was identified; it was found that wells drilled in a certain orientation performed better than wells drilled with other orientations.Completions and hydraulic-fracturing costs were gathered from public sources in order to understand the cost differences between areas and types of fracture-fluid systems. Using decline curves and cost information, full-cycle economics were run on the "average" well for each area in order to determine the net present value (NPV) of each area.This case study shows there is value in optimizing fracture designs through look-back studies, and there is a need to focus on more-effective fracture-treatment designs in unconventional oil development. The overall results of the study showed: (1) the choice of fracture-fluid system is a key component in optimizing economics in the Cardium halo areas; and (2) the optimum fluid system varies in different areas of the Cardium.
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