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Abstract In 1991, two horizontal wells were drilled in the Pittsburg "C" sandstone reservoir of the New Hope Shallow Unit (NHSU) in East Texas. The first well was a 457 m (1,500 ft) horizontal oil well and the second was a 457 m (1,500 ft) water injection well. The NHSU Pittsburg formation is a relatively tight sandstone reservoir undergoing a waterflood project expansion. It has a 45-year production history and is located at a depth of about 2,438 m (8,000 ft.). Different scenarios were examined by a simulation study to determine the optimum development program. The horizontal wells were drilled in the last quarter of 1991. This paper summarizes the engineering evaluation as well as the planning, drilling and completion of these wells. Production histories, as well as problems and their solutions to date, are also discussed. The project was a success in terms of the horizontal producer which tracks slightly below anticipated production. The horizontal injector was drilled in a tight zone which prevented water from being injected continuously into the formation. However, due to the success of the producer, it is shown that horizontal wells in sandstone reservoirs have potential of breathing new life into a tight waterflooded reservoir. Introduction Initially the horizontal well gained its fame in the mid-1980's for its application in the Austin Chalk formation for penetrating naturally fractured carbonate formations. As the industry is discovering, the horizontal well has many more applications, such as for thin formations, water or gas coning, viscous oil and EOR, low permeability gas reservoirs, and unusual gas sources such as coalbed methane or Devonian shale. The advance in horizontal well drilling techniques in recent years has allowed the horizontal well to become a less risky proposition. Its application in improving oil field recovery efficiency has just begun. The New Hope Shallow Unit is located in the New Hope Field, Franklin County, Texas. It is in the north central part of the East Texas Basin, some 32 km (20 miles) south of the Sulphur BluffTalco fault zone. Figure 1 is the location map of the New Hope Shallow Unit with the west side of the unit circled. Total area of the NHSU is approximately 2,065 ha (5,113 acres). The field was discovered in 1943 and a line drive waterflood was developed from east to west after the reservoir pressure was depleted. While the east side was nearly 100% waterflooded after 45 years of production, the waterflood on the west side was not fully developed. Before the horizontal wells were drilled, the west end Pittsburg reservoir was under a waterflood expansion with two water injectors and six oil wells which produced approximately 40 M3/day (250 BOPD). The average thickness of this reservoir is about 6.1 m (20 ft.) and it is a relatively tight (low permeability) formation. A long horizontal producing wellbore can greatly improve the productivity in tight, thin reservoirs and also reduce the cost of drilling many more vertical wells for achieving the same production rate.

Summary Steamflood operations commonly encounter steam override problems. Close well spacing is one method used to reduce this effect. Blind spot areas still exist in the pattern, however, and leave substantial amounts of unrecovered oil after project termination. This study examines the effect of horizontal wells on improving steamflood conformance. A three-dimensional (3D) numerical steamflood simulator was used. The study involves the use of horizontal wells for mature steamfloods to reduce steam override that has already occurred and for prevention of steam override if used at the start of steamflood operations. The data used are from a typical California heavy-oil reservoir. Simulation indicates that horizontal wells can be effective for reducing or preventing steam override. For a mature 18.5-acre [7.5-ha] pattern, simulated horizontal wells increased ultimate recovery at the end of 11 years from 63.2 to 74.7% of original oil in place (OOIP). When used at the start of steamflood, a pattern of vertical and horizontal wells had a predicted recovery of 72.2% OOIP after only 7 years.