Carbon Capture and Sequestration in the Monterey Stevens Sandstone, San Joaquin Valley, California
Goodell, Jonathan A. and Gillespie, Janice
The Stevens Sandstone at the North Coles Levee (NCL) oil field in the petroliferous Southern San Joaquin Basin (SSJB) has been identified as a prime candidate for Carbon Capture and Sequestration (CCS). The Stevens reservoir at NCL is hypothesized to satisfy the criteria for injection of CO2 set forth by the USGS because a. it exceeds the minimum storage capacity of 12.5 million barrels and b. it’s depth is sufficient to maintain injected CO2 in a supercritical phase. Additionally reservoirs at NCL have trapped buoyant fluids for millions of years providing evidence of their sealing characteristics. Tectonic subsidence of the San Joaquin Basin, growth of the NCL anticline, and eustatic sea level changes influenced the distribution of the sandstone reservoirs deposited in a series of turbidite complexes at NCL during late Miocene time. The modern reservoir architecture is hypothesized to be a series of stacked turbidite sand channels and lobes encased in shale. Despite the above assurances the potential for local aquifer CO2 contamination is still a possibility. Regional pressure studies of the SSJB reservoirs show that at least some reservoirs have a water drive and are in hydraulic communication with potential aquifers. Initial observation of the reservoir at NCL indicates that a water drive is not present there. Throughout the life of the NCL reservoir, produced water from the Stevens and shallow reservoirs was injected back into the formation in order to keep reservoir pressure above the bubble point. Despite the large volume of fluid injection over time, the overall reservoir pressure today is significantly lower than its initial value indicating that there is no water drive and therefore the reservoir sands are compartmentalized and safe for CO2 storage. Research Plan: 2011-2012; a. Gather porosity and electric log data from well logs and fluid production and pressure data from well records and idle well fluid levels. b. Produce a GIS database including annual production and injection values. c. Account for all fluids produced and volume changes that occur when fluids are pumped to the surface d. Utilize pressure measurements from idle wells and production tests as a reverse analog to determine how the formation will react to injection of CO2. 2012-2013; a. Utilize geologic interpretation software (e.g., Petra, and Petrel) to build a 3D geologic model in order to access net sand, reservoir geometry, cross sections, and total reservoir volume. b. Produce a plot of pressure vs. net fluid production to determine the effect of water drive on the reservoir. This is an ongoing study and is on schedule. We expect to have most if not all of our results and a thesis rough draft by April 2013.
AAPG Search and Discovery Article #90162©2013 Pacific Section AAPG, SPE and SEPM Joint Technical Conference, Monterey, California, April 19-25, 2013