Summary
In recovery of heavy oil by steamflood, efficiencies can be realized by
limiting the placement of steam to the portions of the reservoir with highest
oil saturations, thus reducing the disproportionate loss of heat to connate
water. This optimization strategy requires knowledge of water-saturation (Sw)
distributions within the heavy-oil reservoir at the scale of operations.
Application of this strategy has contributed to the successful reactivation of
the shut-in Pru Fee property in the Midway-Sunset field 1 mile west of Taft, a
U.S. Dept. of Energy (DOE) Class 3 oil-technology demonstration project.
The 40 new wells drilled and logged within the 40-acre Pru Fee property,
together with a single continuous core, have permitted 3D mapping of Sw within
the 250- to 350-ft-thick pay zone in the Monarch sand reservoir. Water
saturations are observed to vary at three different scales:
• A systematic vertical reduction in Sw through a 100- to 150-ft interval
above the oil/water contact (OWC) caused by dominant capillary influence where
the buoyancy effects are diminished by the low-density contrast of the 13°API
oil and formation water.
• Lateral variations in Sw on the scale of 10 to 100 ft caused principally
by prior oil production from the reservoir, but modified by its internal
stratigraphic architecture.
• Bed-to-bed variations in Sw on the order of a few feet or less constrained
by grain-size-controlled differences in porosity/permeability in these crudely
graded sands.
Overall production efficiency in the steamflood has been improved by
limiting steam injection to the upper one-half to two-thirds of the pay zone,
where Sw is lowest. Knowledge of the lateral variations in Sw has permitted
more accurate appraisal of the effectiveness of individual producers and
nine-spot injector/producer arrays. The recognition of the bed-to-bed
variations has permitted a better petrophysical model for calibrating Sw
calculated from logs.
Introduction
In recovery of heavy oil by steamflood, efficiencies can be realized by
limiting the placement of steam to the portions of the reservoir with lowest
water saturations (Sw), thus reducing the disproportionate loss of heat to
connate water. The specific heat of heavy oil is less than half that of water,
approximately 0.44 Btu lb–1F–1 (1.83 kJkg–1K–1) vs. 1.0 Btu lb–1F–1 (4.18
kJkg–1K–1), respectively (Burger et al. 1985). Effective execution of this
optimization strategy requires knowledge of Sw distributions within the
heavy-oil reservoir at the scale of operations. Application of this strategy
has contributed to the successful reactivation of the shut-in Pru Fee property
(Fig. 1) in the supergiant Midway-Sunset field 1 mile west of Taft, California,
a DOE Class 3 oil-technology demonstration project.
The Midway-Sunset field (Lennon 1990; Gregory 1996a) lies along the upturned
western margin of the southern San Joaquin basin. Here, uppermost Miocene
basin-center sands encased in organic-rich diatomite of the Monterey formation
are close to the surface overlain unconformably by a thin cover of Pliocene and
Pleistocene fluvial-lacustrine mudstones and sands (Nilsen 1996). The upper
Miocene sands were emplaced into the basin from the granitic Salina Block
situated immediately west of the San Andreas strike/slip fault, probably
through point-source fan delta systems (Ryder and Thomson 1989; Hall and Link
1990). In the Midway-Sunset field, the uppermost Miocene sand reservoirs are
debris flows and proximal turbidites of considerable thickness but irregular
lateral continuity (Webb 1978). Transpressional growth folds forming adjacent
to the tectonically active San Andreas fault system guided the debris flows
into the synclines on the basin flanks (Webb 1978), thus creating thickened
sand-reservoir “sweet spots.” The Pru Fee property is located immediately south
of the Spellacy anticline (Gregory 1996a) in a probable paleosynclinal
trough.
Although true anticlinal traps are common through most of the southern San
Joaquin basin (Nilsen 1996), the oil pools in the Midway-Sunset field generally
are related to unconformity or combination traps (Gregory 1996a). These are
controlled by nested unconformities on the east-dipping Temblor range, with the
top seal being Pleistocene Tulare shales, Pliocene Etchegoin shales, or
diatomite mudstone within the upper Monterey formation itself. The diatomite
mudstone encasing the sand bodies serves as both the lateral seal and the
source rock. The trap at the Pru Fee property is an unconformity at the base of
Etchegoin shales.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
21 August 2003
- Revised manuscript received:
28 July 2005
- Manuscript approved:
16 January 2006
- Version of record:
20 April 2006
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