Of all available EOR methods deployed in thin oil rims and gas/oil reservoirs
gas intervention techniques seem the most effective1,2,3,4,5. The study of
practicability of this method was carried out at one of West Siberia gas/oil
reservoirs. Natural pressure depletion is the chosen production method for the
reservoir in question. Almost 150 wells were drilled within the limits of the
reservoir. The dominant production mechanisms are free flow and gas-lift. By
the beginning of 2008 average reservoir pressure dropped to 13.0 MPa from the
original 28.0 MPa. Decline of formation pressure well below saturation pressure
(19.0 MPa) resulted in wells’ shutting-in and curtailment of producing well
stock. Prevailing causes of well problems are flooding and gas coning while in
service. Mean water cut is 10%, GOR is 1600 CUM/MT, while oil production rate
of available stock does not exceed 13 MT/D against start-up values of about 100
A well drilled next to one of the clusters of the reservoir in question exposed
overpressured B4 stratum. Gas flowrates in the well reach up to 106-166 MCUMD
with wellhead pressures of 25.0 to 30.0 MPa. This fact encouraged the studies
of possibility of gas/oil reservoir pressure maintenance by way of injection of
high-pressure natural gas.
The subjects of the present study are oil reservoir of A11(2) stratum located
close to the 3rd Pilot Block and gas/condensate accumulation within B4 of the
2nd Pilot Block.
3rd Pilot Block was brought on production in late December, 1990, oil recovery
reached its peak in 1992 making over 550 MMT. Subsequent development years saw
gradual decline of oil production.
The review of well data and operation behaviour in the 3rd Pilot Block
indicates that structural characteristics of the reservoir exert major
influence on well performance. Most wells here exposed pure oil-bearing
reservoir. This fact explains GOR values of the existing wells, in 26% of which
GOR does not exceed 1,000 CUM/MT, 58% of wells exhibit GOR of 1,000 to 5,000
CUM/MT and only 16% wells have GOR over- 5,000 CUM/MT.
In addition, in 80% of reviewed wells mean water cut is no more than 10%, and
only in 19% wells water cut tops 10%.
By the beginning of 2008 well stock made 104 units, of which 81 were operating,
while 23 wells were out of action. 38 wells are shut-in due to various reasons,
namely: no flow; low wellhead pressure; hydrate formation related to high GOR;
flooding during operation or annular flows; work-over (WO) requirements;
squeeze cementing jobs (SC) and switching to artificial lift.
In 1998 straight gas-lift system was introduced for oil wells. Gas after
processing at gas treatment plant is delivered to well pads via gas-lift
pipeline network 46 km long. Some oil wells deploy the gas from ‘donor’ wells.
To date the produce is collected from 30 well pads via double-pipe gathering
lines 57 to 426 mm in size. Wellhead pressures (in post-choke discharge-line
manifold) read 3.7 to 3.0 MPa for high-pressure gathering lines and 2.8 to 1.0
MPa for low-pressure ones.
Currently gas-lift operations are carried out at 64 wells, free piston pumping
is deployed at three wells, one well is ECP-operated, remaining 13 wells are in
flush production stage.
Processing of oil from the 3rd Pilot Block is done at the Central Gathering
Production testing of gas-condensate deposits of the 2nd Pilot Block is
designated to 20 wells to be drilled on 5 cluster pads (CP). Natural gas and
condensate processing will be done at gas treatment plant under design.