Abstract
In this study, oil production and retention were observed and compared in 72 reservoir simulation cases, after which an economic analysis for various CO2 and oil prices was performed. Reservoir simulation cases comprise different combinations of water alternating gas (WAG) ratios, permeabilities, and well distances. These models were set at three different depths; thus different pressure and temperature conditions, to see the impact of miscibility on oil production and CO2 sequestration. Those reservoir conditions affect oil production and CO2 retention differently. The retention trend dependence on depth was not monotonic—optimal retention relative to the amount of injected CO2 could be achieved at middle depths and mediocre permeability as well. Results reflecting different reservoir conditions and injection strategies are shown, and analysis including the utilization factor and the net present value was conducted to examine the feasibility of different scenarios. The analysis presented in this paper can serve as a guideline for multiparameter analysis and optimization of CO2-enhanced oil recovery (EOR) with a WAG injection strategy.
Highlights
Optimization of the CO2 injection in CO2-enhanced oil recovery (EOR) projects can be evaluated through CO2 utilization factors (UF) since that factor is the ratio of utilized CO2 and produced oil, i.e., in this paper, CO2 UF was used and is previously defined by some authors ([67,68,69]) as qCO2inj − qCO2prod [Msc f ] qo prod[stb]
The FreigsuuFrilgetsu4rs.ehR4o.eRtweentetthniotainotnvifveerarsdsuudssiaatdioddniittiaioolnnraael lrceroceovcveoervryye.rwy as observed in relation to the injected pore volumes (PVs) of CO2 after 15 years of CO2 enhanced oil recovery (CO2-EOR), it was obvious that more PV could be injTechteeTdrehisenurceltassuselsthss owshwiotwhthatahstamtifiafaladldedrdiidttiiioosnntaaanllrcreeeccobovevetrweyreyweanwspaosrbosoedbruvsceetdrivoinendraeinlnadtiroiennlajtetociotthinoentionwjetehctleelsdi,nwjehcitcehd fpinoarellpbyveo,orialenuljvlemoocwtleeudsm(mienPsVoc(aPrsseV)essCo)wfOoCif2thCOtoOa2 2bsamfaetfaetrelrelret1ra155idniyyseeetdaaanrriscnseoofabfCertCOewsO2ee-eE2rn-vOEpoROri,orRidt(,uFwicitagtiwsuoonrabesavn5oiod)b.uivsnijtoehcuatitsomtnhowaretelmPlsV,owcroehuiPcldhV could be infijencatlelyd, ainllocwassems owreitChOa2stmo baellreertadinisetdanincea rbeestewrveoeirn(Fpirgoudreu5c)t.ion and injection wells, which allows more CO2 to be retained in a reservoir (Figure 5)
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Summary
Enhanced oil recovery (EOR) with CO2 injection might be attractive because of the carbon dioxide retention in the reservoir [1], which provides a positive effect on the feasibility of CO2 storage and storage capacity obligations regarding the European Union international agreements within the climate change domain (Kyoto protocol from the year 1997 and the Paris climate agreement from the year 2015). The increasing number of published works have been focused on more complex CO2-EOR issues, such as injection rates of water and CO2 (water alternating gas (WAG) ratios), permeability anisotropy, the effect of different simulation cell size, etc. Injection cost, and the amount of carbon dioxide permanently stored can be optimized by the application of methods, which include water alternating gas (WAG) injection. Simulation of the WAG process can help establish optimal relation between the stated parameters
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