Abstract Chevron (as operator for its partners, Phillips, Union Pacific Resources, and Impkemix) discovered the Point Arguello oil field in 1981. The discovery well, the Chevron et al. Ρ 0316 #1, was drilled in federal waters 8.5 mi (13.7 km) south of Point Arguello, California. Delineation drilling (by both Chevron and Texaco) has confirmed the discovery of a giant oil field with estimated recoverable reserves in excess of 300 million bbl of oil. The oil field is located within a small depocenter at the southern edge of the offshore Santa Maria basin. This local depocenter may contain over 15,000 ft (4600 m) of Neogene rocks. The Point Arguello accumulation is trapped in a large north-northwest-trending anticlinal complex and is part of an anticlinal trend of similar Monterey oil discoveries and producing fields within the offshore Santa Maria basin. The primary reservoir is the middle and upper Miocene Monterey Formation, composed of fractured cherts, porcelanites, siliceous mudstones, and dolostones. Calculated fracture permeabilities range up to 3 darcys. Crestal wells have productive capabilities, after acid, of approximately 6000 BOPD. Three production platforms have been installed, and connected by oil and gas pipelines to onshore treatment facilities capable of handling 100,000 BOPD and 60 MMCFGD. Thirty-nine development wells have been drilled. Initial production was scheduled for late 1987; however, permitting delays stalled production from this giant oil field until May 1991.

Abstract The fracture system in the Miocene Monterey section at Point Arguello Field, was studied to find the relationship between fracture intensity and local tectonic structure. The analysis included five studies: seismic structural mapping, seismic amplitude, outcrop, core, and surface curvature. The goal was to develop a predictive and quantifying methodology for the exploitation and exploration of fractured reservoirs of the type found in the Point Arguello field. A detailed structure map on the Monterey chert member was constructed from a 3D seismic survey on a Landmark workstation. The time structure map was depth converted with an accuracy of ±100 feet to the lithologic Monterey chert unit within existing well control. Seismic amplitude studies were performed to relate fracture intensity to a reduction in seismic amplitude across the field. An outcrop study was performed at Lion's Head fault to determine the relationship between the distance to a large fault and fracture density. A statistical evaluation of core analyses for 6 wells by Terra Tek (Salt Lake City) was performed to evaluate the variability of fracture intensity as a function of structure. The surface curvature analysis consisted of treating each fault block as a 2 dimensional curved space (closed-compact 2D manifold in R 3 ). At each point the distance to the boundary (faults) was determined as well as measures of the local curvature. The Gaussian curvature, ellipsoidal curvature and second derivative were used to characterize the curvature. The distances to faults and curvature measures were correlated to core analyses and to each other. Results are consistent with the outcrop and core studies, and indicate an ability to use the topology of a seismically derived structure map to predict fractured reservoir parameters.

Abstract The Point Arguello field is located in federal waters at the western end of the Santa Barbara Channel, offshore California. The reservoir consists of highly fractured fine-grained siliceous rocks of the Miocene Monterey Formation. Nine wells were examined, using cores and Formation MicroScanner (FMS) images, to determine the relationship of fractures to lithology and structure. The Point Arguello structure is a doubly plunging, slightly asymmetric anticline created by horizontal compressive stresses oriented N36°E. Monterey Formation rock types in the Point Arguello field consist of interbedded shale/mudstone, marl, porcelanite, chert, and dolostone. The siliceous rocks are in the quartz phase of diagenesis. Core and outcrop studies show that fracture development is highest in the more siliceous rocks (chert and porcelanite) and is lower in more argillaceous rocks. Fracture development is also higher in thin beds. The Monterey Formation is fractured into three distinct sets of joints oriented relative to the principal horizontal compressive stress direction: extensional, longitudinal, and shear. Extensional fractures have dips ranging from 70° to 90° and strike directions ranging + or -15° perpendicular to the fold axis. Longitudinal fractures have dips that are variable but are often normal to bedding and oriented subparallel (+ or - 15°) to the fold axis. Shear fractures cut the other fractures at an angle and occur as conjugate pairs, with the development of one half of the pair dominating over the other. The orientations of fracture sets are similar to those described in outcrop in the western Santa Ynez Mountains. Fractures are grouped according to their order of frequency for each well, with first order fractures having the highest frequency, and second, third, and fourth order fractures having lesser frequencies. All the wells have one dominant set of fractures (first order) with second and third order fractures occurring at comparative frequency ratios of 2:1 to 25:1. No one fracture type dominates in the order of development, and the development appears to be random across the structure. Extensional fractures are common to all the wells, whereas longitudinal and shear fractures are not. Extensional fractures probably provide a mechanism for connecting other fractures that have developed at all scales, from the microscopic to the megascopic. The result is that extensional fractures may be responsible for draining the reservoir. Fracture analyses were conducted on both core and Formation MicroScanner (FMS) images. Two wells had both types of data recorded from the same intervals. The fracture analyses and bed orientations derived from FMS images compare very well with cores and dipmeter data.

The Sword field is located in the western Santa Barbara Channel approximately ten miles (16 km) west of Point Conception and five miles (8 km) south of the Point Arguello field (Fig. 1). Conoco, Inc. and its partners acquired the Sword leases in 1979 in POCS Sale #48. The water depths range from 1000 ft (300 m) at the north end of the field to 1800 ft (549 m) in the southern portion. Two wells have been drilled on the Unit and one other to north of the Unit boundary in Lease P-0320. The OCS P-0322 #1, drilled in 1982, was the discovery well for the field. The OCS P-0320 #2, drilled in 1985, was a successful delineation well. The OCS P-0320 #1 was drilled in 1983, off the Sword structure, on the south limb of the Point Arguello structure. Although hydrocarbons were tested from

ABSTRACT Federal OCS tracts in the offshore Point Arena and Eel River basins, presently scheduled for leasing in early 1989, offer excellent potential for the discovery of significant new oil and gas reserves. Environmental challenges to the upcoming lease sale can be expected; however, Hodel’s newly-proposed 5 year lease plan has taken much of the steam out of the opposition by excluding a large number of chiefly low interest and deep water tracts. The offshore Point Arena basin, which extends northwestward for over 100 miles from south of Point Arena to Cape Mendocino, is underlain by thick sections of strongly folded Cretaceous through Neogene sedimentary strata that bear strong similarities to productive sections in the offshore Santa Maria basin and Santa Barbara Channel. Both Monterey (Point Arena Formation) and Rincon (Gallaway Formation) equivalents were penetrated in the three offshore wells drilled by Shell Oil Co. in the mid-1960’s. Numerous oil shows were reported from fractured, cherty Monterey sections, as well as from sands in the underlying lower Miocene Gallaway section. A wireline test of one fractured chert interval in the P-030 well, located at the southeastern end of the basin, yielded a small amount of 29 degree gravity oil, which could indicate that intermediate to relatively high-gravity Monterey oil may be trapped in some structures within the basin. Certainly, the possibility of another giant Monterey field discovery, on the order of the Point Arguello field, cannot be ruled out for the offshore Point Arena basin. The offshore Eel River basin, which lies north and inboard of the Mendocino triple junction, is presently undergoing a tectonic transition from a forearc to a strike-slip basin. Because of a paucity of offshore well information, the Neogene sedimentary section underlying the offshore, which exceeds 10,000 feet locally, is only indirectly known via seismic-reflection data and extrapolation of the geology from onshore. Thus, structures in the offshore Eel River basin should more appropriately be considered as frontier targets in terms of their exploration potential. Importantly, the offshore Eel River basin extends onshore where more than 85 Bcf of gas has been produced from Pliocene Rio Dell sands underlying the Tompkins Hill gas field. The structural trend of the Tompkins Hill gas field can be followed into the immediate offshore where very large on-trend structures are present in water depths of less than 600 feet. Questions as to the oil-generating potential of the offshore Eel River basin are more difficult to answer. However, clues from offshore seismic-reflection data, onshore and offshore hydrocarbon seeps, and more deeply buried potential source rocks suggest that oil production in the offshore cannot be ruled out.