Carbon Dioxide Enhanced Oil Recovery and Storage: Experimental Investigation to Maximize Energy Resources while Reducing Carbon Footprint in Qatar
Authors: Al-Menhali Ali , Krevor Samuel 
Published: July 2019

Qatar is the biggest exporter of liquefied natural gas, LNG, in the world and is a main oil-producing member of The Organization of Petroleum Exporting Countries, OPEC. A fossil fuel-based industry emerged around the ports of Ras Laffan and Mesaieed, Qatar's industrial cities, perusing industrial diversity and maximising the huge fossil fuel reserves that serve as the primary feedstock for the industrial sector. LNG, crude oil, and petroleum products has given Qatar a per capita GDP that ranks among the highest in the world with the lowest unemployment. This also has given Qatar a per capita CO2 emissions among the highest in the world. A recent report from The World Health Organisation, stated that the capital of Qatar, Doha, is one of the world's most polluted cities and its air ranked the 12th highest average levels of small and fine particles which are particularly dangerous to health [1]. The people and wise leadership of Qatar recognizes the significance of the problem and made environmental development one of the four pillars of Qatar National Vision 2030. The vision places environmental preservation for Qatar's future generations at the forefront. Qatar Carbonates and Carbon Storage Research Centre is an example demonstrating Qatar's commitment to preserve the envioronment by investigating and implementing key technologies such as carbon capture and storage (CCS) to address the next step in climate change. CCS in deep saline aquifers is an important process for CO2 reduction on industrial scales. The aim of CCS is to safely sequester CO2 generated from stationary sources, such as power-plants, into aquifers and depleted oil reservoirs. It is considered a valuable option to reduce greenhouse gases and has been proposed as a practical technology to tackle climate change [2–4]. The importance of CCS as a key option to mitigate CO2 emissions and combat climate change has been highlighted also in a report by the International Energy Agency (IEA) and suggests that CCS could contribute to a 17% reduction in global CO2 emissions by 2035 [5]. Previously, carbon dioxide injection into the subsurface has mainly been used for enhanced oil recovery (EOR) purposes. That gave rise to Carbon capture, utilization and storage (CCUS) processes in mature oil reservoirs where CO2 is first used to enhance oil recovery and then ultimately stored in the reservoir. The incremental hydrocarbon recoveries associated with CCUS make it more attractive to implement compared to CCS. It have significant energy, economic and environmental benefits and is considered an important component in achieving the widespread commercial deployment of CCS technology. Residual trapping of CO2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. Observations and modelling have shown how capillary, or residual, trapping leads to the immobilisation of CO2 in saline aquifer reservoirs, limiting the extent of plume migration, enhancing the security and capacity of CO2 storage [6,7]. In contrast, carbonate hydrocarbon reservoirs are characterised by a mixed-wet state in which the capillary trapping of nonpolar fluids have been observed to be significantly reduced relative to trapping in rocks typical of saline aquifers unaltered by the presence of hydrocarbons [8,9]. There are, however, no observations characterising the extent of capillary trapping that will take place with CO2 in mixed-wet carbonate rocks, the same rock type found in Qatar's subsurface geological formations and many other giant oil reservoirs in the Middle East that hold most of the oil in the world [10, 11]. Experimental tests of CO2 and brine in carbonate rocks at reservoir conditions are very challenging due to the complex and reactive nature of carbonates when dealing with corrosive fluids pair of CO2 and brine. In this study, we compare residual trapping efficiency in water-wet and mixed-wet carbonates systems on the same rock sample before and after wettability alteration by aging with oil mixture of Arabian medium crude oil. The experimental work was conducted using a state of the art multi-scale imaging laboratory (core and pore scale) developed at Imperial College London designed to characterise reactive transport and multiphase flow, with and without chemical reaction for CO2-brine systems in both sandstone and carbonate rocks at reservoir conditions [12]. The flow loop included stir reactor to equilibrate rock with fluids, high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner and micro x-ray scanner for in situ saturation monitoring. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions with the ability to preserve the rock sample from reacting to carbonic acid. We report the initial-residual CO2 saturation curve and the resulting parameterisation of hysteresis models for both water-wet and mixed-wet systems. A novel core-flooding approach was used, making use of the capillary end effect to create a large range in initial CO2 saturation in a single core-flood. Upon subsequent flooding with CO2-equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial residual curve. Observations were made on a single Estaillades limestone core sample. It was made first on its original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly on both core and pore scales. A carefully designed wettability alteration programme was designed in this study to replicate a mixed-wet carbonate system similar to those found in Qatari oil reservoirs. At the pore level, oil can precipitate asphaltene and other heavy components after long exposure with the rock changing the wetting state of the surface to oil-wet. A mixture of the evacuated crude oil with an organic precipitant, n-heptane, was used to deposit a stable oil-wet film. The precipitant substituted some of the evaporated and oxidised light hydrocarbon originally existed in the crude and deposited asphaltene to generate a stable strongly oil-wet film layer. Filtration experiments were carried out to sensibly precipitate enough asphaltene for a stable and strong oil-wet film without over precipitating and causing fine migration that can damage the core sample. The weight fraction of asphaltene precipitated with different fractions of crude-precipitant mixtures were measured. The diluent consisted of toluene as the solvent and heptane as the precipitant. 40 ml of the diluent was thoroughly mixed with 1 ml of Arabian Medium crude oil at 11 different precipitant/solvent volume ratios ranging from 0–100% at 10% increments and then left in the dark for 48 hours to allow the system to come to equilibrium. The mass of precipitated asphaltenes was measured in each mixture by vacuum filtration using a 0.45 micron polytetrafluoroethylene hydrophobic filter paper (Millipore) and evaporation of any remaining liquid oil from the filter paper. No asphaltene was precipitated at low precipitant volume fraction and only above the onset of precipitation, a linear relationship was seen between the wt% precipitated asphaltenes and the volume % of the precipitant in the mixture. The onset for asphaltene precipitation for an oil mixture of Arabian Medium crude oil and heptane alone without solvent was calculated at the onset using the volume fractions of the components with the mixing rule. The sample's wettability was altered to a mixed-wet using the appropriate oil mixture as measured using the filtration test and the oil was then removed from the sample by CO2 enhanced oil recovery injected above the minimum miscibility pressure. This allowed for producing unique dataset and a great complement to the more theoretical analysis. That is if we make a surface oil-wet (to water), how does it behave in the presence of a gas. Here we show that residual CO2 trapping in mixed-wet carbonate rocks characteristic of hydrocarbon reservoirs is significantly less than trapping in water-wet systems characteristic of saline aquifers. We found that in the native water-wet state of the carbonate sample, the extent of trapping of CO2 and N2 were indistinguishable, consistent with past studies of trapping and multiphase flow properties in water-wet sandstones [13, 14]. After alteration of the wetting state of the same rock sample with oil, the residual trapping of N2 was reduced compared to the amount in the pre-altered rock. Surprisingly, the trapping of CO2 was reduced even further. The unique results were complemented with pore scale observations to investigate the balance of interfacial tensions and contact angles in three-phase flow. Our results show that one of the key processes for maximising CO2 storage capacity and security is significantly weakened in hydrocarbon reservoirs relative to saline aquifers. We anticipate this work to highlight a key issue for the early deployment of carbon storage – that those sites which are economically most appealing as initial project opportunities are the very locations in which the contribution of capillary trapping to storage security will be minimised. This should serve as a starting point for modelling studies to incorporate the reduced impact of capillary trapping on CO2 injection projects using hydrocarbon reservoirs.

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