CO2 Injection in Depleted Reservoirs: Analysis, Modelling

Abstract

CO2 geological storage is key in the battle against global warming considering the amount of CO2 that can be removed from the atmosphere and stored underground. CO2 geological storage is targeting at least three different subsurface resources: depleted hydrocarbons reservoirs, deep saline aquifers or unconventional formations such as coal seams or basalts. Unlike the latter solution, interests have mostly been focused on deep saline aquifers and depleted oil & gas reservoirs. If deep saline aquifers are preferred in terms of storage resources as larger volumes can be handled, there are unknowns and the geological structures can be poorly defined. For depleted hydrocarbons reservoirs, knowledges are larger, but resources are less. CO2 geological storage in depleted reservoirs gives the possibility of reusing existing infrastructures and can lead to cost reductions. At date, there are six large scale operational CO2 Geological Storage projects: Sleipner (Norway), Snohvit (Norway), Quest (Canada), Gorgon (Australia), Decatur (USA) and Tomakomai (Japan, stopped); none of them injects into depleted reservoirs, but into saline aquifers. Operational projects targeting CO2 injection within depleted hydrocarbon reservoirs are very few and of a smaller scale. The most prominent projects are Rousse CO2 pilot in France (2009-2013) in which gaseous CO2 was injected at well head, and K12-B gas field in the Netherlands (2004-2017), in which supercritical CO2 was injected at well head. In the Oil & Gas industry, transport pipelines generally flow single-phase hydrocarbon fluid, and preferred phase is liquid to avoid cavitation effects and limit volumes to be transported. When it comes to CO2 geological storage, CO2 is transported in liquid phase by pipeline or by boat compressed at circa -51°C and 7 bars. To optimize the volume stored underground, injection of supercritical CO2 is recommended (dense phase). Potential detrimental side effects of injecting CO2 in depleted reservoirs are the Joule-Thomson effect, the risk of forming CO2 hydrate and creation of thermal induced fractures. To fight those adverse effects, most of the projects (such as those in Northern Sea offshore depleted reservoirs) consider heating the CO2 at the well head before injecting. Heating CO2 before injection could under certain conditions be a killing factor for the project; not only from a cost point of view, but also from a life cycle analysis point of view. Thus, injecting “cold CO2” within depleted reservoirs (compared to “hot CO2” injection) should also be considered. “Cold CO2 injection” (4°C or 10°C depending of seabed temperature) into a low pressure reservoir (circa 10-20 bar) leads to a phase transition from liquid to liquid/gas within the wellbore resulting in temperature profile that can reach negative values near the wellhead and/or at the perforation level. From a well integrity point of view, impacts must be assessed, completions and downhole safety valves materials must be carefully evaluated and qualified. From a well injectivity point of view, possible impairment due to hydrates formation within the near wellbore must be assessed in detail and operational procedures have to be defined accordingly. Based on these considerations, risk analysis is required to address well integrity and well injectivity stakes with appropriate tools. A review of current off-the-shelf commercial software and tools for near wellbore modelling has demonstrated that approaches for cold CO2 injection into depleted reservoir cases are not completely satisfactory. In order to be able to represent properly the CO2 thermodynamic specificities, simulators need to be coded using pressure and enthalpy (P H) primary variables, instead of pressure and temperature (P T), which is not the case for most of them. For the few of them coded in P-H mode, their internal limitations are incompatible with P T ranges of cold CO2 injection into depleted reservoirs (pressures range from 5 up to 300 bar, temperatures range from 50°C up to 150°C). A dedicated numerical tool has thus been developed by TOTAL. It consists of an analytical numerical approach enabling to model thermodynamically the phenomenon occurring during cold CO2 injection, within wellbore and reservoir.