This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123788, ’CO2 Injection Into Depleted Gas Reservoirs,’ by Hrvoje Galic, SPE, Steve Cawley, SPE, and Simon Bishop, SPE, BP, and Steve Todman, SPE, and Frederic Gas, Petroleum Experts Ltd., prepared for the 2009 SPE Offshore Europe Oil and Gas Conference & Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed. Depleted gas fields represent an opportunity for CO2 storage. However, low reservoir pressure will present a significant challenge for CO2 injection because of phase-behavior issues. This behavior will constrain injection operating parameters significantly during the early stages of CO2 injection. An efficient way of understanding and possibly resolving flow-assurance problems is to adopt an integrated-asset-modeling (IAM) approach. The IAM recognizes the interaction between all system elements and enables observing the effects of many parameter changes within the whole system. Introduction The case study modeled a BP-operated asset offshore UK in the southern North Sea (UK SNS) for CO2 injection. The modeled CO2 supply would come from burning fossil fuels at a power plant. The resulting CO2 would be captured, dehydrated, compressed, and transported to an onshore pumping facility at approximately 70–80 bar and at ambient temperature (0 to 20°C). Under these conditions, CO2 is in dense liquid phase. An onshore pump then would move the CO2 through a subsea pipeline to an offshore injection facility. From there, it would be distributed to several injection wells (most likely converted from existing production service) and injected into a depleted gas reservoir, which had initial conditions of approximately 27 bar and 90°C. The model assumed an approximately constant CO2 delivery rate of 2×106 t/a for a nominal project life of 20 years, with injection beginning in 2013. Toolkit The injection-modeling toolkit comprised a full-field thermal reservoir model with wells and well-network descriptions, surface-network descriptions, dynamic connections between the reservoir and the well-/surface-net-work models (acting as a data-transfer system and master controller for the integrated full-field model at each forecast timestep), and a consistent set of fluid pressure/volume/temperature (PVT) descriptions between the different models. A major technical challenge was related to the phase behavior of CO2. As Fig. 1 shows, pure CO2 has a triple point of 5.18 bar at −56.6°C and a critical point of 73.8 bar at 31.1°C, enabling three different phase regions to be defined under real reservoir conditions: liquid, vapor, and supercritical fluid. Keeping the CO2 in a liquid or super-critical phase is essential to realize the benefits from the high density of the fluid in terms of bulk-transportation efficiency, injectivity potential, and stored-CO2 mass.
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Jun 1, 2011
Akihiko Yokoo + 6
Open Access