The distal fan margin in the northeast portion of the Yowlumne field contains significant reserves but is not economic to develop using vertical wells. Numerous interbedded shales and deteriorating rock properties limit producibility. In addition, extreme depths (13,000 ft) present a challenging environment for hydraulic fracturing and artificial lift. Lastly, a mature waterflood increases risk because of the uncertainty with size and location of flood fronts. This project attempts to demonstrate the effectiveness of exploiting the distal fan margin of this slope-basin clastic reservoir through the use of a high-angle well completed with multiple hydraulic-fracture treatments. The combination of a high-angle (or horizontal) well and hydraulic fracturing will allow greater pay exposure than can be achieved with conventional vertical wells while maintaining vertical communication between thin interbedded layers and the wellbore. The equivalent production rate and reserves of three vertical wells are anticipated at one-half to two-thirds the cost. An analogous well was hydraulically fractured to obtain fracture-treatment design parameters for the proposed high-angle well. This well was the first frac in the northwest fan margin, and it treated with a higher frac gradient (1.06 psilft) than the 0.91 psilft gradient observed in the northeast fan margin (where the high-angle well is proposed to be drilled). Microseismic events were passively monitored during the frac from an offset well to determine fracture geometry and azimuth. A NW -SE azimuth was detected, compared to the expected NNE-SSW azimuth. Knowledge of fracture azimuth was useful for determining location and azimuth of the high-angle well. The reservoir geology of the northeast fan margin was re-evaluated. Petrophysical properties were derived from core, log, and RFT data. In general, only slight modifications of previous interpretations were necessary. As expected, rock properties were shown to deteriorate in a easterly direction, towards the distal margin. The five major flow ,units were subdivided into ten layers. Rock properties were calculated and mapped for each layer. The detailed reservoir geology was then inserted in a fine-grid, partial-field reservoir simulation model. The model was history matched, with some layers appearing to be more swept than expected. Upon completion of history matching, the model was used to test a variety of development alternatives aimed at optimizing project economics. Model forecasts compared slant well performance to more conventional development options and quantified rate impacts from changes in well location, orientation, and completion technique. An east-to west slant well with multiple hydraulic fractures proved to be the optimal alternative to develop the fan-margin region. Model results indicated the well could initially produce 2180 BOPD and recover 724 MBO of reserves (net of interference).