Role of Small-Scale Variations in Water Saturation in Optimization of Steamflood Heavy-Oil Recovery in the Midway-Sunset Field, California
- Steven Schamel (GeoX Consulting Inc) | Milind D. Deo (U. of Utah)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2006
- Document Type
- Journal Paper
- 106 - 113
- 2006. Society of Petroleum Engineers
- 4.3.4 Scale, 1.6 Drilling Operations, 1.2.3 Rock properties, 5.1.1 Exploration, Development, Structural Geology, 5.4.6 Thermal Methods, 1.10 Drilling Equipment, 5.6.1 Open hole/cased hole log analysis, 5.2 Reservoir Fluid Dynamics, 5.1 Reservoir Characterisation, 2.2.2 Perforating, 5.1.2 Faults and Fracture Characterisation, 5.2.1 Phase Behavior and PVT Measurements, 5.1.5 Geologic Modeling, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 4.6 Natural Gas, 5.5.8 History Matching, 5.5 Reservoir Simulation
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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.
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.
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