대염수층 내 CO2 저장을 위한 주입성 분석 시뮬레이션 연구

Abstract

CCS (Carbon Capture & Storage)는 지구온난화의 주요 요인인 CO2를 화력발전소 등의 CO2 대량배출원에서 화학적인 기술을 이용하여 분리한 CO2를 파이프라인으로 수송하여 대염수층 등의 검증된 저장소에 저장하는 기술이며, 이를 통해 방대한 양의 CO2를 안정적으로 격리하는 것을 목표로 한다. 지중격리의 대상에는 고갈 유가스전, 심부 대염수층, 석탄층 등이 있으며, 이 중 심부 대염수층은 전 세계적으로 널리 분포되어 있고, 가장 많은 양의 CO2를 격리할 수 있다는 장점을 가지고 있다. 뿐만 아니라, CO2 배출원으로부터 가까이 위치하는 경우가 많으므로 수송비용을 절감할 수 있으므로 이에 대한 활발한 연구가 진행되고 있다. 본 연구에서는 지하 심부 대염수층에의 CO2 주입가능성 및 유동 특성에 대한 평가를 위한 시뮬레이션 연구를 수행하였다. 대수층에 주입된 CO2의 지층내 유동 및 격리메커니즘 양상을 파악하기 위해 대수층 특성에 대한 민감도 분석을 실시하였고, 한국석유공사에서 캐나다 PTRC (Petroleum Technology Research Center)와 국제공동연구로 수행 중인 캐나다의 Aquistore CO2 지중저장 프로젝트의 대상 대염수층에 대한 CO2 격리 타당성을 조사하였다. 이들 작업을 수행하기 위해 CO2 격리용 상용전산시뮬레이터인 「GEM」모델을 활용하여 대염수층 내 주입된 CO2의 격리양상을 분석하였다. 대염수층의 평균투과도, 수직-수평 투과도비나 잔류가스 포화율 등과 같은 지층 특성은 CO2의 유동양상에 영향을 미쳐서 격리메커니즘에도 차이가 발생할 수 있으므로 이에 대한 사전분석을 수행하였다. 대염수층의 평균투과도가 커지면서 가장 먼저 목격할 수 있는 것은 주입효율 향상으로 인한 CO2 주입량 증대이며, 그와 더불어 주입된 CO2의 지층 내 이동이 원활하여 CO2 plume의 크기가 커지는 것을 볼 수 있다. CO2의 원활한 이동으로 인해 대염수층 내에서 CO2의 다양한 격리메커니즘도 활발히 일어나며, 잔류트랩, 용해트랩과 광화트랩 모두 평균투과도 증가에 따라 그 양이 증가하는 것을 확인하였다. 수직-수평 투과도비의 경우, 대염수층 내 CO2의 상부이동에 가장 큰 영향을 미치는 요인이므로 이에 대한 분석을 실시하였으며, 그 결과, 수직-수평 투과도비가 큰 대수층의 경우, CO2는 보다 빠르게 상승하여 덮개암에 다다르지만, 상승하면서 지층수와의 접촉 면적이 넓어져서 용해트랩 및 잔류트랩으로 격리되는 양도 커지게 된다. 이로 인해 상승하는 CO2의 양도 그 만큼 줄어들게 되어 일정 깊이까지 상승한 후부터는 더 이상 상승하지 못하고 안정적으로 격리되는 것으로 나타났다. 또한 공극성 대수층의 특성인 잔류가스 포화율에 대한 결과에서는 잔류가스 포화율이 큰 대수층일수록 공극 내 잔류량이 늘어나면서 상부로의 이동량이 적게 되고 따라서 덮개암 하부에 집적되는 CO2의 양이 적어져 누출가능성이 감소되는 것을 알 수 있다. 마지막으로, 지층수의 염도에 따른 대염수층의 CO2 저장양상 변화를 관찰하였다. 그 결과, 지층수의 염도가 증가할수록 용해트랩에 의해 격리되는 CO2 양이 감소하는 것을 볼 수 있었고, 그에 따라 잔류트랩량이 늘어났으나, 구조트랩 및 광화트랩에 미치는 영향은 거의 없는 것을 알 수 있었다. 캐나다 Aquistore 프로젝트의 CO2 주입 대상 대염수층에서 CO2의 유동양상을 파악하기 위한 CO2 거동예측 시뮬레이션을 수행하였다. 먼저, 지층의 주입성 평가에서는 낮은 대염수층 투과도의 영향으로, 주입 가능한 최대속도는 약 760 CO2ton/day로 나타났으며, 여기에 최대 암석파쇄압력인 33.63 MPa를 최대 공저압력으로 제한하여 수행한 결과에 따르면, 최대 주입속도 78 CO2ton/day, 20년간 주입 시 최대 주입량은 약 50만톤 정도로 산출되었다. 동일한 공저압력 제한 조건으로 20년간 CO2를 주입한 후 500년까지 주입된 CO2를 모니터링 하였다. 그 결과, 마찬가지로 낮은 대염수층 투과도의 영향을 받아, 500년이 지난 시점에서도 CO2가 덮개암에 미치지 못했으며, 수평방향으로의 최대 영향반경은 1.6 km에 머무르는 것을 알 수 있었다. CO2의 이동이 제한적이므로 잔류트랩보다는 용해트랩에 의해 격리되는 양이 많았으며, 시간이 지날수록 그 양은 더 커질 것으로 예상된다.

주요어: CO2 지중격리, 심부 대염수층, 용해트랩, 잔류트랩, 광화트랩, 평균투과도, 수직-수평 투과도비, 잔류가스 포화율, 염도, CO2 누출성| CCS (Carbon Capture & Storage) is the technology to capture CO2 from the large CO2 sources such as thermoelectric power plants and transfer it to the site to store and finally inject into the geological structure that can guarantee the permanently stable sequestration of large amount of CO2 which is the main cause of the global warming. The main targets for the CO2 injection are depleted oil/gas reservoirs, deep saline aquifers and coal seams, and among these, saline aquifers can store the most amount of CO2 and are distributed widely. There are more possibility for aquifers to be located near the CO2 sources, and it can reduce the CO2 transfer cost. In this study, numerical simulation works were made to assess the CO2 injectivity and flow characteristics in a deep saline aquifer. Sensitivity analysis was made to identify the flow aspect and trapping mechanisms of CO2, and validity analysis for CO2 sequestration was made with the simulation model of Aquistore CO2 injection project which PTRC (Petroleum Technology Research Center) is operating near Estevan, Saskatchewan, Canada. KNOC is participating as a co-researching partner of the project. Compositional simulator, CMG�s GEM was used for the simulation. The properties of aquifer, average permeability, vertical-horizontal permeability ratio, residual gas saturation by hysteresis and salinity, affect the CO2 flow and the trapping mechanisms in the formation. We can observe the injected CO2 amount and the CO2 plume size increase as the average permeability increases. From the easy flow of CO2 in the aquifer, the trapping mechanisms - residual trapping, solubility trapping, and mineralization trapping mechanisms � occur more actively as the average permeability increases. The vertical-horizontal permeability ratio is the most important factor for the upward migration of CO2, as the vertical-horizontal permeability ratio increases, CO2 rises to the sealing structure relatively faster, also it causes more amount of CO2 trapped by residual trapping and solubility trapping due to the increase of contact area with formation water. The risk for CO2 leakage can be releaved from this phenomena as the amount of free CO2 to move upward was decreased, and less CO2 were accumulated under the sealing structure. I also observed as the value of residual gas saturation by hysteresis increases the more CO2 remains in the pore space, and the less CO2 reaches to the sealing structure, which can assure the safe storage. Lastly, as the salinity of formation water increases, the amount of CO2 trapped by solubility decreases and it accompanies the increase of CO2 trapped by residual trapping, but it seems that there is not much relation with the structural and mineralization trapping mechanisms. Simulation for estimating the CO2 migration in the saline aquifer of the Canadian Aquistore Project. Firstly, injectivity test was made and it showed that the maximum injection rate was 760 CO2ton/day with the restriction of the maximum bottomhole pressure, 80 MPa, and it decreased to 78 CO2ton/day with the restriction of the maximum bottomhole pressure, 33.63 MPa, which is the average breaking pressure of sandstone. With the same restriction, CO2 injection for 20 years, and monitoring for 480 years after injection end were made. The total injected CO2 amount was about 500 thousand ton, and the CO2 couldn�t reach to the sealing structure, and the maximum horizontal effective radius stayed at 1.6 km. More CO2 was trapped by solubility trapping than residual trapping, and it seems that the more CO2 will be trapped by solubility trapping as the time goes.

Key Word: CO2 sequestration, deep saline aquifer, sealing structure, structural trapping, solubility trapping, residual trapping, mineralization trapping, average permeability, vertical-horizontal permeability ratio, residual gas saturation by hysteresis, salinity, CO2 injectivity, Aquistore Project; CCS (Carbon Capture & Storage) is the technology to capture CO2 from the large CO2 sources such as thermoelectric power plants and transfer it to the site to store and finally inject into the geological structure that can guarantee the permanently stable sequestration of large amount of CO2 which is the main cause of the global warming. The main targets for the CO2 injection are depleted oil/gas reservoirs, deep saline aquifers and coal seams, and among these, saline aquifers can store the most amount of CO2 and are distributed widely. There are more possibility for aquifers to be located near the CO2 sources, and it can reduce the CO2 transfer cost. In this study, numerical simulation works were made to assess the CO2 injectivity and flow characteristics in a deep saline aquifer. Sensitivity analysis was made to identify the flow aspect and trapping mechanisms of CO2, and validity analysis for CO2 sequestration was made with the simulation model of Aquistore CO2 injection project which PTRC (Petroleum Technology Research Center) is operating near Estevan, Saskatchewan, Canada. KNOC is participating as a co-researching partner of the project. Compositional simulator, CMG�s GEM was used for the simulation. The properties of aquifer, average permeability, vertical-horizontal permeability ratio, residual gas saturation by hysteresis and salinity, affect the CO2 flow and the trapping mechanisms in the formation. We can observe the injected CO2 amount and the CO2 plume size increase as the average permeability increases. From the easy flow of CO2 in the aquifer, the trapping mechanisms - residual trapping, solubility trapping, and mineralization trapping mechanisms � occur more actively as the average permeability increases. The vertical-horizontal permeability ratio is the most important factor for the upward migration of CO2, as the vertical-horizontal permeability ratio increases, CO2 rises to the sealing structure relatively faster, also it causes more amount of CO2 trapped by residual trapping and solubility trapping due to the increase of contact area with formation water. The risk for CO2 leakage can be releaved from this phenomena as the amount of free CO2 to move upward was decreased, and less CO2 were accumulated under the sealing structure. I also observed as the value of residual gas saturation by hysteresis increases the more CO2 remains in the pore space, and the less CO2 reaches to the sealing structure, which can assure the safe storage. Lastly, as the salinity of formation water increases, the amount of CO2 trapped by solubility decreases and it accompanies the increase of CO2 trapped by residual trapping, but it seems that there is not much relation with the structural and mineralization trapping mechanisms. Simulation for estimating the CO2 migration in the saline aquifer of the Canadian Aquistore Project. Firstly, injectivity test was made and it showed that the maximum injection rate was 760 CO2ton/day with the restriction of the maximum bottomhole pressure, 80 MPa, and it decreased to 78 CO2ton/day with the restriction of the maximum bottomhole pressure, 33.63 MPa, which is the average breaking pressure of sandstone. With the same restriction, CO2 injection for 20 years, and monitoring for 480 years after injection end were made. The total injected CO2 amount was about 500 thousand ton, and the CO2 couldn�t reach to the sealing structure, and the maximum horizontal effective radius stayed at 1.6 km. More CO2 was trapped by solubility trapping than residual trapping, and it seems that the more CO2 will be trapped by solubility trapping as the time goes.

Key Word: CO2 sequestration, deep saline aquifer, sealing structure, structural trapping, solubility trapping, residual trapping, mineralization trapping, average permeability, vertical-horizontal permeability ratio, residual gas saturation by hysteresis, salinity, CO2 injectivity, Aquistore Project