Managing Adequate Gas EOR for Unstable Asphaltene Stability Field?Asphaltene Flow Assurance Pre-Risk Assessment Case Study for CO2, Enriched Gas, and Lean Gas Options

Abstract

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.