Assessment of chemo-mechanical impacts of CO2 sequestration on the caprock formation in Farnsworth oil field, Texas

Abstract

This study evaluates the chemo-mechanical influence of injected CO2 on the Morrow B sandstone reservoir and the upper Morrow shale caprock utilizing data from the inverted 5-spot pattern centered on Well 13-10A within the Farnsworth unit (FWU). This study also seeks to evaluate the integrity of the caprock and the long-term CO2 storage capability of the FWU. The inverted 5-spot pattern was extracted from the field-scale model and tuned with the available field observed data before the modeling work. Two coupled numerical simulation models were utilized to continue the study. First, a coupled hydro-geochemical model was constructed to simulate the dissolution and precipitation of formation minerals by modeling three intra-aqueous and six mineral reactions. In addition, a coupled hydro-geomechanical model was constructed and employed to study the effects of stress changes on the caprock’s porosity, permeability, and ground displacement. The Mohr–Coulomb circle and failure envelope were used to determine caprock failure. In this work, the CO2-WAG injection is followed by the historical field-observed strategy. During the forecasting period, a Water Alternating Gas (WAG) injection ratio of 1:3 was utilized with a baseline bottom-hole pressure constraint of 5500 psi for 20 years. A post-injection period of 1000 years was simulated to monitor the CO2 plume and its effects on the CO2 storage reservoir and caprock integrity. The simulation results indicated that the impacts of the geochemical reactions on the porosity of the caprock were insignificant as it experienced a decrease of about 0.0003% at the end of the 1000-year post-injection monitoring. On the other hand, the maximum stress-induced porosity change was about a 1.4% increase, resulting in about 4% in permeability change. It was estimated that about 3.3% of the sequestered CO2 in the formation interacted with the caprock. Despite these petrophysical property alterations and CO2 interactions in the caprock, the caprock still maintained its elastic properties and was determined to be far from its failure.

Time‐lapse VSP integration and calibration of subsurface stress field utilizing machine learning approaches: A case study of the morrow B formation, FWU

“…The Southwest Regional Partnership on Carbon Sequestration (SWP) has conducted several studies on FWU in the context of CO 2 -EOR operations, as evidenced by the works of Rasmussen et al 43 , Acheampong 44 , Will et al 45 , Adu-Gyamfi et al 46 , Ampomah et al 47 and Acheampong et al 4,5 The SWP is a constituent member of a larger network of seven partnerships that are engaged in a nationwide endeavor to investigate the sequestration and permanent containment of carbon dioxide as a means of mitigating the effects of global warming. SWP studies are geared towards assuring CO 2 containment within the FWU storage compartment.…”

Field‐scale reactive transport assessment of CO2 storage in the Farnsworth unit through enhanced oil recovery practices

“…The injected CO 2 was originally derived from two major point source emitters, the Agrium fertilizer plant in northern Texas and the Arkalon ethanol plant in southwestern Kansas, 20 though since 2018 the CO 2 has only come from the Arkalon ethanol plant 21,22 . The southwest regional partnership on carbon sequestration (SWP), sponsored by the US Department of Energy (DOE), began a study on the FWU in 2012 involving laboratory experiments of CO 2 injection and transport, 23,24 characterization of the FWU pore fluids and geology, 25–29 numerical modeling of reservoir evolution resulting from CO 2 injection, 23,26,30–50 tracer studies, 41,51,52 and risk assessment and site monitoring 40,41,52–59 . Despite the extensive previous study, important knowledge gaps remain, especially with respect to larger‐scale chemical effects of the CO 2 injection beyond the vicinity of the injection and production wells.…”

“…30,46,50 These studies were focused on physical processes and mainly tracked changes in fluid pressure, velocity, and saturation to achieve part of the DOE's objectives, which include (1) determining whether CO 2 injection from the industrial processes is an economically advantageous way of producing more oil from the FWU, and (2) effectively storing anthropogenic CO 2 . Subsequent numerical modeling studies attempted to include chemical processes to quantify changes to the mineral and pore fluid composition of the reservoir and to assess the importance of mineral trapping for CO 2 [35][36][37][38][39]43,48,49 . Limitations to the studies were as follows: (1) the model did not treat petroleum, 35,48,58 (2) the size of the model domains was very small, 37,39,42,43,49 (3) the reactive surface areas applied for the mineral reactions were not field-specific, [36][37][38][39]43,48,49 (4) the water alternating gas (WAG) schemes used did not represent well those used in the field, 35,48,49 (5) the model did not implement the actual regional pressure gradient occurring in the field, 48 (6) the injection temperature at the wells was not the same as the temperature in the field, [37][38][39]42,43,48,49…”

“…Subsequent numerical modeling studies attempted to include chemical processes to quantify changes to the mineral and pore fluid composition of the reservoir and to assess the importance of mineral trapping for CO 2 [35][36][37][38][39]43,48,49 . Limitations to the studies were as follows: (1) the model did not treat petroleum, 35,48,58 (2) the size of the model domains was very small, 37,39,42,43,49 (3) the reactive surface areas applied for the mineral reactions were not field-specific, [36][37][38][39]43,48,49 (4) the water alternating gas (WAG) schemes used did not represent well those used in the field, 35,48,49 (5) the model did not implement the actual regional pressure gradient occurring in the field, 48 (6) the injection temperature at the wells was not the same as the temperature in the field, [37][38][39]42,43,48,49 and (7) parts of the history matched model did not fit the production data well (i.e., less than 10% error). 37,39,43 In addition to these limitations, none of the studies accounted for capillary effects or fully quantified the field-scale response to the injected CO 2 by incorporating all four storage mechanisms.…”

“…Limitations to the studies were as follows: (1) the model did not treat petroleum, 35,48,58 (2) the size of the model domains was very small, 37,39,42,43,49 (3) the reactive surface areas applied for the mineral reactions were not field-specific, [36][37][38][39]43,48,49 (4) the water alternating gas (WAG) schemes used did not represent well those used in the field, 35,48,49 (5) the model did not implement the actual regional pressure gradient occurring in the field, 48 (6) the injection temperature at the wells was not the same as the temperature in the field, [37][38][39]42,43,48,49 and (7) parts of the history matched model did not fit the production data well (i.e., less than 10% error). 37,39,43 In addition to these limitations, none of the studies accounted for capillary effects or fully quantified the field-scale response to the injected CO 2 by incorporating all four storage mechanisms. In this study, we address these limitations and knowledge gaps, fulfilling the project objective, tracking changes in reservoir mineralogy and formation water chemistry as a result of chemical reaction with CO 2 using a history matched numerical model that employs the operating conditions used in the field.…”