Abstract
Natural gas from the Zalecze gas field located in the Fore-Sudetic Monocline of the Southern Permian Basin has been produced since November 1973, and continuous gas production led to a decrease in the initial reservoir pressure from 151 bar to about 22 bar until 2010. We investigated a prospective enhanced gas recovery operation at the Zalecze gas field by coupled numerical hydro-mechanical simulations to account for the CO 2 storage capacity, trapping efficiency and mechanical integrity of the reservoir, caprock and regional faults. Dynamic flow simulations carried out indicate a CO 2 storage capacity of 106.6 Mt with a trapping efficiency of about 43% (45.8 Mt CO 2 ) established after 500 years of simulation. Two independent strategies on the assessment of mechanical integrity were followed by two different modeling groups resulting in the implementation of field-to regional-scale hydro-mechanical simulation models. The simulation results based on application of different constitutive laws for the lithological units show deviations of 31% to 93% for the calculated maximum vertical displacements at the reservoir top. Nevertheless, results of both simulation strategies indicate that fault reactivation generating potential leakage pathways from the reservoir to shallower units is very unlikely due to the low fault slip tendency (close to zero) in the Zechstein caprocks. Consequently, our simulation results also emphasise that the supra-and subsaliniferous fault systems at the Zalecze gas field are independent and very likely not hydraulically connected. Based on our simulation results derived from two independent modeling strategies with similar simulation results on fault and caprock integrity, we conclude that the investigated enhanced gas recovery scheme is feasible, with a negligibly low risk of relevant fault reactivation or formation fluid leakage through the Zechstein caprocks. © Ł. Klimkowski et al.
Highlights
Enhanced Gas Recovery (EGR) from depleted natural gas fields by CO2 injection is considered as an economic option for greenhouse gas emission mitigation and as an efficient way to maintain gas production from low-pressure gas reservoirs (Kühn et al, 2012, 2013; Hussen et al, 2012; Polak and Grimstad, 2009; Oldenburg et al, 2004)
Thereafter, the effect of pore pressure increase by CO2 injection overcomes the pore pressure decrease induced by natural gas production from 19 wells, and the induced subsidence is decreased by the competing ground uplift
We investigated a prospective EGR operation by a hypothetical CO2 injection below the gas-water contact by application of coupled numerical simulations
Summary
Enhanced Gas Recovery (EGR) from depleted natural gas fields by CO2 injection is considered as an economic option for greenhouse gas emission mitigation and as an efficient way to maintain gas production from low-pressure gas reservoirs (Kühn et al, 2012, 2013; Hussen et al, 2012; Polak and Grimstad, 2009; Oldenburg et al, 2004). Production from the Załęcze natural gas field located in the Fore-Sudetic Monocline of the Southern Permian Basin has been undertaken since November 1973. In this context, the initial reservoir pressure of 151 bar was decreased by about 130 bar until 2011, indicating significant CO2 storage capacity that may be derived from the natural gas volume of 19.25 billion sm produced from the reservoir until the end of 2010. An assessment of hydro-mechanical effects allows defining the constraints required for a safe EGR operation not posing a risk to the mechanical integrity of the reservoir, its caprocks and adjacent geological faults (Rutqvist, 2012; Hawkes et al, 2004). The hydro-mechanical simulation results can be employed for quantification of potential CO2 and/or formation fluid leakage via faults, as recently discussed by Jamaloei (2013), Tillner et al (2013), Pruess (2011), Cappa and Rutqvist (2011)
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