This paper highlights an integrated scheme of engineering studies implemented in the Heyburn Field since January, 1970 to optimize injection and production operations. The field was discovered in 1955 and waterflood operations initiated in 1964. To minimize declining oil production which was first observed in 1966, increased water injection volumes were required. An average increase of 10 barrels of oil per 100 barrels of water injected as well as 9% decrease in the artificial lift operating costs were realized due to implementation of the various optimization programs.
Source water lifting costs were reduced by replacing existing gas engine driven pumps with high grade material electric submersible pumps. Existing water injection plant suction piping was redesigned to achieve greater injection capacity and reduce the adverse effects of vibration caused by lack of net positive suction head. The concept of peripheral injection stations using electric submersible pumps to achieve increased injection requirements are discussed. Injection Satellites were redesigned to mitigate corrosion-erosion and pollution of the environment as a result of system failures.
Implementation of a field-wide diagnostic method incorporating computer analysis of dynamometer cards and a new approach to sucker rod string make-up were the cause of reduced maintenance costs, failure frequencies and downtime. Installation of high slip motors resulted in decreased torque loading of pumping units. Excessive sucker rod loading and severe corrosion caused by viscous emulsions and corrosive fluids could be reduced by the use of a single chemical. Experience with chemicals to invert emulsions causing high flowline pressures are presented.
Future studies include surface facilities, automation and consolidation as well as a field-wide preventive maintenance program. It also includes methods to achieve a longer ground bed life of impressed current cathodic protection installations.
The Weyburn field, located in Southeastern Saskatchewan (Fig. 1), was discovered in January, 1955. The field was unitized in July 1963. It currently comprises 151 water injection and 516 producing wells. The daily average producing rate in July 1963 was 37,400 bbls. The maximum oil production rate of 44,500 bbls. per day due to waterflooding was achieved in 1965 and had declined to 28,500 BOPD at the end of 1971 (Fig. 2). This corresponds to an average of 8% decline.
Production to injection correlations lndicated that, conservatively, a 4 bbl. increase in oil production could be expected for each additional 100 bbls. of water injected.. In order to minimize production decline reservoir studies suggested that an increase of water injection from 110,000 BWPD to 160,000 BWPD is required.
This paper discuss techniques and presents policies which have achieved optimization of the waterflood operations by maximizing production and decreasing operating costs.
The water source is obtained from seven wells completed in the Blairmore formation at 3,400 feet K, B. The capabilities of each water well had been tested as high as 10,000 BWPD with 100 feet drawdown. The operating fluid levels is at 400 to 600 feet from surface at an operating average production of 9,400 BWPD per well.