Energy Policy Act of 2005 (Ultra-deepwater and Unconventional Resources Program)
Near Miscible CO2 Application to Improve Oil Recovery for Small Producers
This project seeks to demonstrate that “near miscible” carbon dioxide (CO2) flooding, where CO2 is injected at pressures below the minimum miscibility pressure (MMP), can result in incremental oil production. The application of CO2 injection at near miscible conditions may lead to development of CO2 projects by small producers in reservoirs where the MMP is not attainable at current operating reservoir pressures, in particular, the Arbuckle Formation of Kansas.
University of Kansas Center for Research, Lawrence, KS 66045
Carmen Schmitt, Inc., Great Bend, KS 67530
Injection of CO2 for enhanced oil recovery (EOR) is a proven technology and is also being considered as one of a number of promising methods for carbon sequestration in geologic formations. CO2 injection for enhanced oil recovery is normally carried out at a pressure above the MMP, which is determined by crude oil composition and reservoir conditions. This is the lowest pressure at which the injected carbon dioxide is miscible with the oil remaining in the reservoir; the interface between the two fluids disappears. Miscibility means that the carbon dioxide can act like a solvent, more effectively displacing the oil from the rock.
However, many mature reservoirs in the United States with residual oil saturations exist at depths or under geologic conditions such that they must operate at pressures below the MMP. Near miscible displacement generally refers to the process that occurs at pressures below the MMP, but the actual pressure range has never been clearly defined. At displacement pressures near to yet below the MMP, significant oil recovery has been observed in laboratory slim-tube experiments and to a lesser extent in core tests.
This high recovery has been attributed to possible improvement of the mobility ratio during displacement and an extraction process, both of which are closely related to operating pressure. To increase the resource base for CO2 flooding and substantially increase the potential for EOR from reservoirs operated by small producers, it is proposed to investigate the feasibility of applying CO2 displacement at near miscible pressures by conducting appropriate experimental work and reservoir simulation.
This project was the first study of applying CO2 displacement at near miscible pressure conditions for small producers active in Arbuckle fields in Kansas. Three oil fields (Chase-Silica, Trapp and Bemis-Shutts) in Arbuckle reservoir are estimated to have original oil in place of 2.7 billion barrels of which 900 million barrels have been produced by a bottom water drive through an underlying aquifer.
Previous assessments of CO2 miscible flooding in these Arbuckle reservoirs indicates that miscibility is not achievable at current reservoir operating pressures. Near miscible CO2 application could revive many of these fields in central Kansas which will otherwise be abandoned with substantial remaining oil left in place. Depending on the extent of recovery resulting from CO2 near-miscible flooding, the incremental oil produced from this formation could vary from 80 to 135 million barrels, assuming a 3 to 5% recovery improvement.
Research was performed by the University of Kansas Center for Research’s Tertiary Oil Recovery Project (TORP). The producing field is to be provided by Carmen Schmitt, Inc., an independent oil and gas producer in Kansas. Carmen Schmitt, Inc., owns the Ogallah Unit, which produces from the Arbuckle reservoir. Currently there are 18 wells in production on this 1600 acre site, with a daily production of 40 bbl/oil and 98% water cut. Carmen Schmitt, Inc. provided representative core samples, crude oil samples, well logging and 3-D seismic data for identifying resources. They also provided well performance data and reservoir production history for computer modeling.
Deliverables for this project included a series of reports on the tasks as they were completed and a final report integrating the results of the project.
The potential benefit of a successful laboratory modeling and testing effort is that it could lead to a pilot scale CO2 injection demonstration in the Arbuckle which could in turn lead to a commercial-scale near-miscible CO2 flood. Successful near-miscible CO2 flooding of the Arbuckle over a widespread area could result in a maximum potential of 180 to 300 million barrels of incremental oil production. Accordingly, the actual benefits accruing from this project could range anywhere from 0 to 300 million barrels of oil, depending on the success of the research, if it subsequently leads to a demonstration project, and if that in turn results in some degree of widespread near-miscible flooding of the Arbuckle. Research will need to proceed to pilot test level before more precise estimates of potential impacts can be made.
Work on this project began on June 2, 2008. In a number of experimental studies, phase behavior tests between CO2 and Arbuckle crude oil were carried out to define near miscible condition at reservoir temperature. The results of swelling/extraction tests combined with slim-tube experiments were interpreted to identify the mass transfer mechanisms at near miscible condition. A phase behavior model was developed to match PVT data and MMP in the slim-tube experiment. Good agreement was obtained between simulated and observed data from the slim-tube experiments. Core flooding tests were conducted to evaluate oil recovery at near miscible conditions where pressure varies from 1350 psi (MMP) to 1150 psi. Recovery of over 50% of the waterflood residual oil saturation was observed when CO2 was used to displace Arbuckle oil from Berea, Baker dolomite and Arbuckle dolomite cores.
At near miscible conditions, extraction appears to be the primary mechanism for mass transfer between hydrocarbon components and CO2. However, a reduction in oil viscosity by a factor of five occurred when CO2 dissolved in the oil. This suggests that some of the additional oil recovery may be attributed to improved mobility ratio.
In a number of computational studies, a 47 acre lease containing four wells was extensively examined for the effect of CO2 injection pressure, rate and pattern on the oil recovery efficiency. The average reservoir pressure was maintained at the near miscible condition during the CO2 injection as the pressure was supported by the underling aquifer. In general, the simulation results show that improvement of oil recovery at near miscible condition is achievable under current reservoir operating pressure. The incremental oil recovery increased with injection pressure. The oil recovery efficiency was increased by 1.3 to 4.8% as a result of the injection of CO2. This improved recovery efficiency is likely resulting from the improvement of relative mobility ratio of the CO2 and oil and the efficacy of CO2 extraction. However, recovery efficiency is affected by reservoir heterogeneity. It was shown in the pattern design that recovery results depend on the placement of the injectors. The theoretical storage capacity of CO2 in this 47 acre lease was estimated to be 1.58 BSCF. With 1.45 BSCF of CO2 injected in 10 years, the effective storage capacity of CO2 varied from 39 to 63%.
Current Status (January 2011)
This project has been completed. The final report is listed below under "Additional Information".
Project Start: June 2, 2008
Project End: May 20, 2010
DOE Contribution: $274,171
Performer Contribution: $68,543
RPSEA – Kent Perry (email@example.com or 847-768-0961)
NETL – Chandra Nautiyal (Chandra.Nautiyal@netl.doe.gov or 281-494-2488)
University of Kansas – Jyun Syung Tsau (firstname.lastname@example.org or 785-864-3441
Final Project Report [PDF-5.45MB]
Tecnical Report 1 [PDF-2.00MB]
Tecnical Report 2 [PDF-4.48MB]
Article in Spring 2009 E&P Focus [PDF]