Geothermal Supercritical Carbon Dioxide (CO2) Enhanced Oil Recovery© for Offshore and On-shore Applications by George E. Lockett—28th December 2012.
Carbon dioxide has long been known to help with the extraction of light oils; by using a geothermal reservoir below the oilfield we intend to extend its use to Heavy Oils and Tars.
Oilfields only have up to about 20% of their oil in liquid flowing form. To extract the remaining 80% it is normal to employ some form of Enhanced or Secondary Oil Recovery - EOR or SOR, either as water flooding, thermal – injecting steam, CO2, chemical or solvent injection or a combination of two or more methods.
Geothermal supercritical CO2 enhanced oil recovery uses Carbon Capture and Storage (CCS) CO2 and heat naturally occurring beneath the oilfield to turn the CO2 into supercritical CO2, which is at much higher temperatures and pressures after passing through the geothermal reservoir beneath the oilfield.
A typical offshore platform/flow configuration would have a production well drilled, say, to 3,000m and have an oil flow temperature of say 70 degC at wellhead. Two additional wells would be drilled down to between 6,000m—where temperatures would be about 170 degC—and 10,000m, where temperatures may rise to as much as 350 degC, depending on the geothermal gradient.
Typical Offshore Geothermal Gradients may be in the region of 25 to 35 degC per kilometre of depth depending on location. A higher temperature at the geothermal field would increase the supercritical effect of the CO2 when it reaches the heavy oil in the oilfield.
At the bottom of the two geothermal wells, high pressure fracturing would be done from each well to create a connecting reservoir (1/2 cubic kilometre or more) of geothermally heated hot fractured rocks, say in this example at 250 degC. One of the wells would become the CCS injection well, where in an offshore situation CCS CO2 would arrive in storage barges and be connected to high pressure pumps, to pump the CO2 down the injection well and across the geothermal field.
The second well would then have been perforated at the oilfield level and fractured, then had a plug put in the well bore above these perforations, to allow the rising supercritical CO2 to reach up into the heavy oilfield at a point opposite the production well to allow as much of the field as possible to be swept by the SCCO2.
The high temperature high pressure CO2 can flood the oilfield over quite a large area, reducing the viscosity of the heavy oil by around 80% and raising its temperature to improve its laminar flow rate.
Five types of forces control the displacement of heavy oil by CO2: viscous, capillary, gravitational, diffusive, and inertial forces.i Depending on the rock and reservoir-fluid properties, a few of these forces may be neglected. CO2 at 2,600 psi (17.9MPa) is nearly four times as dense at 75 degC as at 350degC.ii This reduction in density of the SCCO2 at a higher temperature will help to make the CO2 miscible with the heavy oils and tars in the heavy oilfield.
Geothermal Supercritical CO2 Enhanced Oil Recovery is a continuous process; it has many advantages over other forms of enhanced or secondary oil recovery that work on a batch process, using the same well as production. This system has a long field life of up to 30 years and has many advantages over using water as the working fluid.
Raising the temperature of the CO2 through the Geothermal Hot Rock Reservoir should help achieve the necessary miscibility with the heaver oils at higher temperatures—immiscibility being a known issue with heaver oils that have not been heated with high temperature high pressure SCCO2 in this geothermal EOR system above, as in this extract:
“Oil displacement by CO2 injection relies on the behaviour between CO2 and crude. This interaction depends on the oil's weight, and the reservoir characteristics. In high pressure applications with lighter oils, CO2 is miscible with the oil (in all proportions forms a single phase liquid), with resultant swelling of the oil, and reduction in viscosity, and possibly also with a reduction in the surface tension with the reservoir rock. All these effects serve to improve the flow of oil to the production wells.
“In the case of low pressure reservoirs or heavy oils, CO2 (potentially along with alternating water injection) will form an immiscible fluid, or will only partially mix with the oil. Some oil swelling may occur, and oil viscosity can still be significantly reduced. However, in immiscible CO2 flooding the main function of the CO2 is to raise and maintain reservoir pressure. CO2 immiscible flooding is considered where the reservoir permeability is too low for water flooding, or where the geochemistry or other geological conditions are unfavourable for water flooding.
“During these CO2-EOR applications, more than 50 per cent and up to 67 per cent of injected CO2 will return to the surface with the extracted oil, requiring separation and reinjection into the well to prevent release into the atmosphere and to reduce operating cost of obtaining additional CO2.
“The effectiveness of CO2-EOR is dictated by reservoir characteristics, such as temperature, pressure, height, angle and permeability. For example, injection depth must be generally greater than 600m and well pressure over 10MPa into light weight oil to achieve the desirable miscible flood, described above. These factors along with the well’s stage of production must be considered when selecting a reservoir for CO2-EOR.”v
By combining the Geothermal SCC2 System below the oilfield with the SCC2 Enhanced Oil Recovery System we created a combined cycle, which is able to raise the temperature of the heavy oil in the oilfield and make it miscible with the low density SCC2 that is being injected at high pressure due to the high geothermal preheating which it has passed through before reaching the oilfield.
To find out more about Geothermal Supercritical CO2 Enhanced Oil Recovery©, or look at the feasibility of a specific application, please contact the author George E. Lockett at: email@example.com
i Rojas, G.A. (February 1988) Dynamics of Subcritical CO2/Brine Floods for Heavy-Oil Recovery http://www.onepetro.org/mslib/servlet/onepetropreview?id=00013598
ii Alan D. Eastman and Mark P. Muir (February 2012)UPDATE OF A TRIAL OF CO2-BASED GEOTHERMAL AT THE ST. JOHNS DOME https://pangea.stanford.edu/ERE/pdf/IGAstandard/SGW/2012/Eastman.pdf
iii See ii above
iv Donald W. Brown (January 2000) A HOT DRY ROCK GEOTHERMAL ENERGY CONCEPT UTILIZING SUPERCRITICAL CO2 INSTEAD OF WATER http://www.geothermal-energy.org/pdf/IGAstandard/SGW/2000/Brown.pdf
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