The current screening criteria excluded shallow formations (depth < 800 m) from the desirable CO2 geological storage sites. However, in the Athabasca oil sands area of northeast Alberta, shallow gas reservoirs have at least 500 Mt storage potential and are close to many large emitters in Alberta. This study uses Kirby gas fields as an example and examines the suitability of shallow gas reservoirs as CO2 storage sites from leaking risks associated with engineering aspects. First, the storage systems characterized by five parameters were built based on a statistical analysis of 210 gas pools in the Kirby field. Second, to capture uncertainties, 270 cases were simulated to represent the sealing-layer performances. The results were then analyzed statistically, where an information-entropy-based regression tree was generated to rank the relative importance of the parameters and leaking risk level. Third, the storage systems with multi-sealing layers were modeled to examine the effective drainage area, injectivity, and storage capacity under different drilling and injection schemes. Finally, the potential issues of carbon storage in depleted shallow gas fields were addressed. Our study suggests that the CO2 storage potential and carbon-neutral benefits of the shallow gas reservoir in the Athabasca oil sands area are underestimated for the low-carbon energy transition. The results found that the regression tree allows for screening parameters effectively for selecting storage sites from the shallow gas pools and revealed that the permeability of the sealing layers is more important than the seal thickness. For CO2 storage in shallow formations, the minimum requirements of the seal (especially for the caprock) under the safe injection pressure range are a permeability of less than 0.001 mD and a thickness higher than 35 m. Due to key characteristics of shallow gas reservoirs (high permeability and thin reservoir layers), the CO2 plume behaviors are significantly different from reported CO2 storages in desirable deep formations. The CO2 plume will spread rapidly in all directions of the reservoirs and reaches the maximum capacity quickly. A low well density of the CO2 injection network (< 0.39 wells/km2) is sufficient for CO2 storage in shallow depleted gas reservoirs. Compared to the single-layer injection scheme, the multi-layer injection can relieve the early leaking risks of the mid-sealing layers and increase the injection rate to nearly 1 Mt CO2 per year. The short project life resulting from the high injection rate and small storage capacity in each gas pool makes the CCS projects of shallow reservoirs in NE Alberta more suitable for transporting CO2 using tankers or repurposing the old pipelines nearby. It also makes the small (~64.7 E4m2) to medium gas reservoirs (259 E4m2) with excellent top seals the desirable candidates of CO2 storage for small companies when the carbon tax reaches $170/ton in 2030. A novel workflow with an effective assessment methodology for selecting CO2 storage sites from shallow gas pools has been proposed. The results can assist geoscientists in reducing uncertainty on the estimate of CO2 capacity storage and provide practical guidance on site selection for the pre-feasibility study of CO2 storage in shallow formations.
In this paper, an innovative multi-phase strategy is developed and numerically tested to optimize CO2 utilization and storage in an oil reservoir to support low carbon transition. In the first phase, the water-alternating-gas (WAG) injection is conducted to simultaneously store CO2 and produce crude oil in the reservoir from the respective injection and production wells. In the second phase, the injection and production wells are both shut in for some time to allow CO2 and water to be stratigraphically separated. In the third phase, CO2 is injected from the upper part of the reservoir above the separated water layer to displace water downwards, while fluids continue to be produced in the water-dominated zone from the lower part of the production well. Lastly, the production well is finally shut in when the produced gas–water ratio (GWR) reaches 95%, but CO2 injection is kept until the reservoir pressure is close to the fracture pressure of its caprocks. The numerical simulations show that implementing the proposed multi-phase strategy doubles CO2 storage in comparison to applying the WAG injection alone. In particular, 80% of the increased CO2 is stored in the third phase due to the optimized perforation. In addition, the CO2 injection rate in the last phase does not appear to affect the amount of CO2 storage, while a higher CO2 injection rate can reduce the CO2 injection time and accelerate the CO2 storage process. In the proposed strategy, we assume that the geothermal energy resources from the produced fluids can be utilized to offset some energy needs for the operation. The analysis of energy gain and consumption from the simulation found that at the early stage of the CO2-WAG phase, the energy gain mostly comes from the produced oil. At the late stage of the CO2-WAG phase and the subsequent phases, there is very little or even no energy gain from the produced oil. However, the geothermal energy of the produced water and CO2 substantially compensate for the energy loss due to decreasing oil production. As a result, a net energy gain can be achieved from the proposed multi-phase strategy when geothermal energy extraction is incorporated. The new multi-phase strategy and numerical simulation provide insights for practical energy transition and CO2 storage by converting a “to be depleted” oil reservoir to a CO2 storage site and a geothermal energy producer while enhancing oil recovery.
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