George P. Stoeppelwerth
Consultant
Wichita, Kan.
Injected exhaust gas from a natural gas or propane engine enhanced oil recovery from several Nebraska and Kansas wells. The gas, containing nitrogen and carbon dioxide, is processed through a catalytic converter and neutralized as necessary before being injected in a cyclic (huff and puff operation.
The process equipment is skid or trailer mounted (Fig. 1). The engine in these units drives the gas-injection compressor.
Maximum unit size depends on transportable weight limits and economics for an alternative nitrogen fixation plant or CO2 pipeline.
The gas after passing through the converter and neutralizers is approximately 13% CO2 and 87% N2. The pH is above 6.0 and dew point is near 0 F. at atmospheric pressure. Water content is 0.0078 gal/Mscf. This composition is less corrosive than pure CO2 and reduces oil viscosity by 30% at 1,500 psi.
The nitrogen supplies reservoir energy and occupies pore space.
GAS PERMEABILITY
Relative permeability to gas (krg) depends on gas saturation history, and in some rocks the krg is zero at a much higher gas saturation during a period of decreasing gas saturation than during the period of increasing gas saturation. In other words, during primary production from an undersaturated reservoir, gas will begin to flow at a lower gas saturation.
If gas is injected and later produced, the gas will stop flowing at a higher gas saturation than the saturation at which gas flowed during primary production. Retained, trapped, gas saturation as high as 60% of pore space has been reported.
Changes in relative permeability caused by the introduction of a third phase may reduce water cuts.
APPLICATIONS
In using exhaust gas, an important consideration is the volume of fuel gas. One ton of propane fuel yields 3 tons of CO2 in over 15 tons of total injected gas. One mole of methane (359 scf) results in 1 mole of CO2 in 7.7 moles (2,762 scf) of injected gas.
Construction costs are about $60,000 for a 140 Mscfd unit and $40,000 for a 40 Mscfd unit. Both sizes are capable of compressing gas to 1,200 psi. Injection costs vary from $2.00 to 3.50/Mscf.
These costs compare favorably with hauled-in CO2 costs of $7.66-9.19/Mscf, reported by a Kansas operator.
Besides cost, another disadvantage for the hauled-in CO2 is that operators often base injection rates on minimizing pumping charges rather than obtaining an efficient injection rate for the reservoir.
Exhaust gas injection is applicable for the following:
- Single well reservoirs producing at low rates, or wells with shut-in offsets.
- Waterfloods with poor performance or mature floods that need a source of foam or water-alternating-gas (WAG).
- Determination of directional permeability or other reservoir characteristics prior to a waterflood.
- Replacement of flood water if the water is unavailable or too expensive or if the formation is sensitive to the available water.
- Clean up of well bore.
- Fluid depression during mechanical integrety tests.
The economics for several of these applications depend on the unit's portability and the fact that no capital investment is required on the lease.
FIELD EXAMPLES
In one case, cyclic gas injection recovered over 1,000 bbl of oil above the extrapolated decline curve from a Lansing-Kansas City formation well scheduled for abandonment. The operator was CO2 Operations Co., McCook, Neb.
The cost of recovering the oil was less than $5.00/bbl. The incremental volume recovered was significant because the prior production from this single-well reservoir was less than 7,000 bbl.
In a multiple-well Lansing reservoir project, CO2 Operations Co. recovered only an incremental 158 bbl. Prior cumulative oil production was 5,800 bbl and, after injection, the total oil produced was 347 bbl. But nearby wells, probably because of the injected gas, recovered over 2,000 bbl of incremental oil.
Both CO2 Operations Co.'s projects were in Southwest Nebraska.
In another project in Nebraska, M&C Oil Inc. set up a combination cyclic injection and flooding project. The two wells in the Lansing formation were producing about 24 bo/d with a decline of over 4%/month.
The wells were on diagonal 10 acre locations and had a cumulative oil production of 47,000 bbl. Estimated remaining oil from primary was 2,500 bbl.
M&C's plan was to initially inject in one well and produce from the other well. Later, production would also be from the injected well.
Gas was not used efficiently during the first and early part of the second injection. Incremental oil produced during these cycles was over 5,000 bbl. Approximately 17.6 MMscf (12 MMscf in the first cycle and 5.6 MMscf during the second cycle) were injected, which resulted in an efficiency of about 1/3 bbl/Mcf (3,521 scf/bbl).
To improve efficiency, production near the end of the second injection phase was restricted to 15 bo/d. The last information available indicates a production of 15 bo/d after producing more than 1,000 bbl of incremental oil since imposing the rate restraint. The project's projected decline curve anticipated only a 5 bo/d rate.
For these two injection periods, total propane cost was $13,880 during the recovery of 6,000 bbl of incremental oil.
Production history for this lease is plotted as Fig. 2. Note that during the second cycle more oil was recovered with less gas.
Range Oil, Wichita, used exhaust gas on one project with no economic and only limited technical success. The cyclic injection in four wells in tight Mississippian reservoirs nearly doubled production from two wells, but the improvement lasted for only a few months.
In one well the water production decreased almost in half while in the other it nearly doubled. The other two wells had a very limited or negative response.
One of the unsuccessful wells did provide reservoir data that indicated the profitability of infill drilling. Information from another treatment helped Range Oil in deciding to start water injection.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
