Enhanced Recovery in Unconventional Liquid Reservoirs by Use of CO2

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169022, ’Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs by Use of CO2: A Look Ahead to the Future of Unconventional EOR,’ by Francisco D. Tovar, SPE, Texas A&M University; Oyvind Eide, SPE, and Arne Graue, SPE, University of Bergen; and David S. Schechter, SPE, Texas A&M University, prepared for the 2014 SPE Unconventional Resources Conference, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed. Technological advances in multiple-stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil-shale plays by enhancing matrix/wellbore connectivity. However, as the reservoir matures, primary-production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix/wellbore connectivity insufficient to provide economically attractive production rates. This study presents experimental results on the use of carbon dioxide (CO2) as an enhanced-oil- recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. Introduction CO2 is a powerful agent for EOR. It reaches miscibility at lower reservoir pressure compared with nitrogen and hydrocarbon gases, swells the oil, reduces oil viscosity, and reaches supercritical state at the pressure and temperature of most oil reservoirs, resulting in oil-like density that reduces override effects. Moreover, CO2 has been reported to be successful during field applications under unfavorable conditions such as those found with heavy-oil reservoirs and oil-wet naturally fractured reservoirs, where waterflooding is largely unsuccessful. The purpose of this investigation is to evaluate CO2 EOR in unconventional liquid reservoirs with lower permeability than that reported previously. We used preserved sidewall shale cores saturated with oil and with permeability in the nanodarcy range, preventing us from performing CO2 flooding as conventionally conceived because CO2 could not be injected directly into the matrix. We developed a technique to pack the sidewall core samples into the core holder, using glass beads to simulate the presence of a hydraulic fracture. With this approach, we did not have to cut the cores and we did not alter the rock properties and the original fluid saturation. The core was soaked in CO2 for several days, and production was allowed in intervals. Changes in saturations were tracked with X-ray computed tomography (CT). Analysis of the images revealed that CO2 was able to penetrate the cores, resulting in an oil recovery estimated in the range of 18 to 55% of original oil in place (OOIP). This paper discusses the results on the basis of viscous-displacement, diffusion, and solubilization mechanisms. Additionally, the paper draws a research path using numerical simulation and laboratory experiments to evaluate the potential of these mechanisms to determine if they can support an economical continuous- CO2-injection process in reservoirs where conventional flooding cannot be performed because of adverse rock properties, and it compares that scenario on the basis of recovery and economics with a huff ’n’ puff CO2 injection.