Abstract The Long Beach Unit comprises part of the giant Wilmington Oil Field, Los Angeles Basin. Total original oil in place for the Long Beach Unit has been estimated at 3.8 billion barrels of oil, of which 645 million barrels have been produced to date. Petroleum reservoirs occur within seven zones called the Tar, Ranger, Upper Terminal, Lower Terminal, Union Pacific, Ford, and 237 (top to bottom). The Ranger zone, which is the largest reservoir, is >1000 ft (305 m) thick in the Long Beach Unit. Six cores through the Ranger, totalling about 5000 ft (1524 m), have been examined to evaluate depositional environments, reservoir quality, and geologic controls on reservoir properties. Foraminiferal analyses indicate the Ranger zone comprises the Puente and Pico Formations of late Miocene to early Pliocene age. Water depths at the time of deposition ranged from lower middle to upper middle bathyal (1640-6560 ft; 500-2000 m) with a slight deepening-upward trend. Sedimentary features indicate the Ranger sediments were deposited by a variety of mass-gravity flow processes in a submarine fan setting. The three major lithologies are massive sand, graded sand, and shale. These are arranged into three facies, Thin-Bedded Sand, Thick-Bedded Sand, and Shale. Owing to the tremendous size of the M 10 -Pliocene submarine fan system in the Wilmington Field area relative to the size of the Long Beach Unit study area, it is not currently possible to interpret depositional subenvironments. The sands are first cycle arkoses to feldspathic litharenites, subjected to limited chemical weathering in the source terrain as well as limited transport to the depositional site, and derived mainly from plutonic rocks to the north and/or east. Ranger zone sands exhibit good reservoir porosities and permeabilities. Permeability appears to vary with facies, suggesting a lithologic control on reservoir quality. The Spontaneous Potential, Gamma Ray, and Compensated Neutron log are all sensitive to lithologic variability. The Compensated Neutron log can resolve beds down to 2 ft (0.6 m) thick. All three logs are useful for distinguishing thin-bedded and thick-bedded sands, and for estimating shaliness.

Abstract The Staffa Field occurs at the crest of an intermediate tilted fault block that is located between the Ninian and Alwyn fields in the northern North Sea. The partnership BP, Lasmo and Ranger discovered the field with well 3/8b-10 in 1985. By 1990, BP had left the partnership while Lasmo and Ranger had received Annex B approval for development. First production from this small field reservoired in sandstones belonging to the Middle Jurassic, Brent Group was obtained in 1992. At sanction, reserves were estimated to be about 5.5 MMBBL together with 26.8 BCF corresponding to a recovery factor of 18%. Field life was expected to be about 7.5 years (to 2000) and the plateau length six months. Although initial production exceeded the planned plateau rate of 8000 BOPD, production ceased in June 1993 when the pipeline to Ninian became blocked with wax or wax hydrates. Remedial solvent treatment failed to remove the blockage and replacement of the blocked section was undertaken. This too became blocked soon after resumption of production and the field was shut-in in November 1994. It was then abandoned, since further replacement of the line was not justified economically. At abandonment the field had produced 3.9 MMBBL of oil, 0.296 MMBBL of NGL and 6.457 BCF of gas (just 13% of its original STOIIP).