New Technologies Recover More Oil From California Monterey

(Tech Connections Column, August 2002, American Oil and Gas Reporter)

Venoco Inc., operator of the South Ellwood Field offshore California, shared at a PTTC workshop how the Department of Energy’s support helped the company employ advanced technologies to significantly improve its management of reserves in the Monterey Formation.

Monterey geology is complex–fractures predominate, permeability barriers and compartmentalization exist, damage during drilling and completion is common, and coning from strong aquifer support and a secondary gas cap complicates production. Monterey wells start producing at very high rates, but well trajectory strongly influences productivity, and compartmentalization affects cumulative production. These restraints have historically limited recovery of oil in place. But Venoco has found a successful formula for revisiting mature Monterey (and other) fields that look promising to extract more of the remaining oil by evaluating them with developing technologies. Its formula may work for other operators in other formations.

Tackling these challenges in a project supported with DOE funding through its Reservoir Class Program, Venoco knew going in that three-dimensional reservoir modeling and characterization would be critical to getting more from the South Ellwood Field. Old 3-D seismic data were available. Venoco would have preferred shooting new data, but many regulatory restrictions made this option unattractive. Reprocessing the existing data would cost much less: $50,000-$100,000 versus millions for new data and, most importantly, could be accomplished in months versus the several years required for permitting a new survey. Reprocessing provided good definition of the crest and south flank, defined the north fault well, revealed smaller faults that explained reservoir variations, and identified a large untested fault block.

Creative reinterpretation of old data as well as new logging provided key data for 3-D modeling, and analyzing individual well recompletion and workover opportunities. Formation micro-imaging logs revealed that open fractures were predominantly oriented north-south, and they helped select perforated intervals for individual wells. Production logging, both the PSP-Floview (water/hydrocarbon holdup and bubble count) log and Schlumberger’s GHOST (gas/liquid holdup and bubble count) logs, helped identify where oil, water and gas were entering well bores. In these deviated wells, stratified flow, three-phase slugging, and unexpected flow profiles were identified. First (lowest) oil entry was clearly evident, illustrating water control opportunities.

Logging led to several successful water shut-off workovers using rigless through-tubing operations. The added bonus of increased oil production often comes with water control in the Monterey, as the full lift energy is applied to the oil-bearing fractures. On one of Venoco’s wells, oil production increased 1,000 barrels of oil a day with the water shut off.

In some wells, water shut-off is not an option. Venoco is considering applying downhole separators in conjunction with electric submersible pumps, thereby avoiding lifting excess water to the surface. In those instances, water separated downhole is injected into a deeper zone. With downhole separation, a well previously producing 1,500 barrels of fluid a day with 143 bbl oil may produce 290 bbl fluid at a 50 percent oil cut–a reduction of more than 1,000 bbl/d water.

The overriding influence of fractures complicates reservoir modeling. The University of Southern California–a partner in the project with Venoco–developed a Web-based interactive data repository, a fracture mapping process, and a conceptual modeling approach where fractures were represented in a pipeline network model. The data repository proved invaluable for subsequent modeling work. Fracture mapping was central to follow-up modeling work. In simulating reservoir performance, pipeline networks calibrated by a CMG simulator could be adjusted. This allowed staff, using reprocessed, reinterpreted 3-D seismic data and considering production logging and pressure test results, to match reservoir performance. With new confidence in the resulting 3-D model, Venoco is using the model to optimize location of wells and completions, and eventually will use simulation in reservoir management.

Total project scope was $9.2 million, with $3.3 million coming from DOE. Additional reserve potential in the South Ellwood Field is now estimated at 36 million-68 million barrels of oil-equivalent. Productivity and economic margins are improved, and environmental impacts have decreased with reduced water production and a decrease in natural gas seeps.

Why is this successful Monterey project important? First, Monterey wells exhibit much higher productivity than typical sandstone wells–i.e., it is possible to produce a lot of hydrocarbons from few wells. Second, there are other Monterey fields offshore California where the approach could be applied, and the potential target in the Pacific Coast is huge, because there are indications of many undiscovered basins with Monterey equivalents. Admittedly, widespread additional development off the West Coast seems unlikely at present. Third, there are other producing reservoirs in both offshore and onshore California. These reservoirs and others across the United States with similar fracture domination would benefit from applying technologies demonstrated in this project.