Carbon dioxide capture, utilization and storage (CCUS) has been recognized as a key technology to reduce CO2 emission. Among various CCUS technologies, CO2 enhanced oil recovery (EOR) has been widely implemented at an industrial scale in the E&P sector. However, it is well-known that CO2-mixed oil would cause asphaltene precipitation resulting in flow assurance troubles. Therefore, more advanced asphaltene-risk-managing technology can be an enabler to improve robustness of CCUS projects. This paper presents a case study for a comprehensive series of asphaltene flow assurance pre-risk evaluation in Arabian Gulf Carbonate Oil Field at where the CO2 EOR is recognized as one of the highest potential technologies for full-field implementation. At first, sampling location was carefully selected considering the target reservoir's feature because the reliability of asphaltene study highly depends on sample representativeness. After the QA/QC of collected sample, asphaltene onset pressures (AOP) were measured at multiple temperatures under the CO2 mixing conditions in a straightforward experimental-design optimizing manner so that not only the evaluation accuracy could be improved but also the experimental cost could be minimized. The AOP measurements showed clear potential risks associated with CO2 injection. Subsequently, the numerical model analysis was conducted with Cubic-Plus-Association (CPA) EoS model to identify the risk area during CO2 injection. The analysis suggested that a risk would be caused at not only near-wellbore region at the sampling location but also tubing section / surface facility, furthermore, more seriously at the deeper location of target reservoir. Finally, CO2-induced asphaltene formation damage risk was investigated from the viewpoints of precipitated asphaltene particle size and pore throat size in the porous media. As a result, the clogging risks by CO2-induced asphaltene were estimated high in the target reservoir. By virtue of the above comprehensive series of pre-risk evaluation, the asphaltene flow assurance risk associated with CO2 injection was identified field-widely. The evaluation findings suggested moving on to future actions such as more detailed formation damage risk evaluation and mitigation plan development. The phased approach for evaluating asphaltene flow assurance risk and the reverse engineering of sampling operational design from the experimental design made a worthy demonstration to reduce unnecessary cost and time while obtaining the key information to drive the project. The procedure in this work can contribute to establish a subsurface part of guideline for CCUS from viewpoints of asphaltene flow assurance risk evaluation.

To enhance oil production (EOR) in tight carbonate oil reservoirs, gas EOR can be a promising option from injectivity viewpoints compared with water-basis chemical EOR. CO2 is the most attractive injectant with higher recovery factor expectation while responding to the recent decarbonization demands; however, CO2 is also known to accelerate asphaltene flow assurance risks. In actual fact, the previous work revealed a high asphaltene flow assurance potential risk for CO2 injection. Therefore, a further pre-risk evaluation case study was conducted to extract adequate type of potential injection gas among CO2, enriched gas, and lean gas. This study focused on subsurface gas-induced asphaltene risks in an offshore heterogeneous oil field showing unstable asphaltene colloidal instability index (CII=2.2), where a crestal lean gas injection has been applied without any asphaltene issues. A single phase bottomhole sample was taken from appropriate candidate well keeping representative reservoir fluid in a clear asphaltene-gradient field: i.e., lesser asphaltenes in shallow depth but more in deeper section. As a result of this study, no asphaltene onset was detected from original reservoir fluid while asphaltene onset pressures (AOPs) were detected from mixture of reservoir fluid and CO2 or enriched gas or lean gas at two temperatures representing reservoir and wellhead conditions. Experimental gas mixing ratios were carefully designed to distribute the AOPs broadly in operating pressure range: from in-situ reservoir and near wellbore to bottomhole, for securing higher numerical model accuracy by avoiding data extrapolation. A numerical model, calibrated with experimental outputs, predicted risk magnitude by reservoir depth. A comparative analysis revealed higher asphaltene precipitation risks in CO2 injectant than enriched gas and lean gas. Finally, asphaltene particle/aggregate size were discussed for formation damage risks. The visually measured asphaltene solid particle size varied from 1-10 μm for CO2 injection and 1-4 μm for enriched gas injection while no visible for lean gas. From the past injection water quality analysis, the reservoir has threshold particle size between 0.5-1.0 μm to cause plugging. Therefore, it was concluded that risk of asphaltene-induced formation damage is lower in enriched gas injection compared with CO2 injection. In general, higher oil recovery is expected by order of CO2, enriched, and lean gases. In conclusion, even CO2 EOR is being attractive rapidly from decarbonization viewpoints, the study highlights an importance of balancing business case opportunity and risk from the aspect of injection gas-induced asphaltene flow assurance potential risks.

This paper presents the evaluation results of water shut-off (WSO) agent based on emulsion type chemical material with nanoparticles. The WSO agent called Emulsion System with Nanoparticles (ESN), it has several unique advantages to existing polymer and gel materials; high thermal stability, low sensitivity to mineralization, thixotropic characteristic, selectivity of blocking effects for oil and water, and reversibility of blocking effect. In WSO application, these properties of ESN could be a good match for the tasks of improved oil recovery. Also, the surface modified silica (SiO2) nanoparticles have an important role to drastically enhance stability of the emulsion system. The ESN can be prepared easily by mixing emulsifier and silica nanoparticles with the on-site oilfield materials such as crude oil and brine. The refined diesel oil can be used for ESN preparation instead of crude oil, so it will be an option depending on the situation of target oil field infrastructure and operator's policy. To evaluate the performance of ESN as WSO agent for UAE's carbonate reservoirs, core flooding tests using low permeability carbonate cores with different water saturation were performed at high temperature condition. The ESN, which is confirmed to be stable at 120 °C and 240,000 ppm TDS, achieved 85 % permeablity reductions for intermeaiete and high Swi cases of the core flood tests. The relative permeability analysis confirmed unblocking by oil inflow for intermediate and low Swi cases. Through comparative analysis and discussing these test results, the laboratory study investigated technological potentials of ESN to block water zones and control water cut of oil wells. This paper introduces the detailed evaluation results of ESN and possibility to successfully apply it for UAE's oil fields in the future.

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