Summary
Gas cyclic-pressure pulsing is an effective improved-oil-recovery (IOR)
method in naturally fractured reservoirs. A limited number of studies
concerning this method in the literature focus on specific reservoirs, yet the
optimum operating conditions have not been broadly investigated. In this study,
we present a detailed parametric study of the process from both operational and
reservoir perspectives. Incremental oil production, discounted incremental oil
production, and net present value (NPV) are considered as the important markers
for the performance criteria. The necessary analyses are performed using a
single-well, dual-porosity, compositional reservoir model. In the first part of
the study, parametric studies are conducted to develop a better understanding
of the operational parameters affecting the process performance in the shallow,
naturally fractured, and depleted reservoir of Big Andy field in eastern
Kentucky, USA. These include analyses of various design parameters (e.g.,
soaking period, cycle rate limit, number of cycles, cycle, and cumulative
injected-gas volumes). In the second part of the study, reservoir
characteristics are investigated. Comparative discussions are presented between
cases with CO2 and N2 as the injected gas on reservoir
fluids of different compositions (heavy, black, and volatile oils). Influences
of area, thickness, fracture/matrix permeabilities, initial reservoir pressure,
and temperature on the process are studied. It is observed that N2,
as a lower-cost gas, would be a better choice than CO2 in the Big
Andy field. With the oil price used in this study, the cost of injected gas
becomes relatively insignificant in economic considerations. Increased income
from increased oil production overcomes the increased costs with higher volumes
of gas. The way reservoir characteristics affect the process performance is
similar in cases with CO2 and N2, but differs
significantly with different reservoir fluids. Thicknesses ranging between 20
and 50 ft produced more favourable results than thicker reservoirs. A higher
efficiency was observed with smaller drainage areas (5 to 8 acres) in the
presence of heavy oil. For the cases with volatile and black oil, it is
observed that the process efficiency is not altered significantly by the area.
The phase behaviour of the reservoir fluid is important for the performance of
the process. Initial pressure/temperature of the reservoir and, therefore, the
initial fractions of gas/liquid phases affect the process efficiency in a more
pronounced manner.
© 2011. Society of Petroleum Engineers
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History
- Original manuscript received:
20 February 2010
- Meeting paper published:
12 April 2010
- Revised manuscript received:
27 May 2011
- Manuscript approved:
16 June 2011
- Version of record:
13 September 2011
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