Abstract This case study describes a project applying a new technology—genetic algorithms—to the problem of scheduling oil production by cyclic steaming at an oil field in the San Joaquin Valley.The paper has seven parts.
In the first part, we discuss the nature of the problem, the importance of solving it well, and the nature of the work process as it occurred before the project began.In the second part, we discuss genetic algorithms and the way that the project adapted them to solve the problem of scheduling cyclical steam injections. In the third section, we describe a pilot project that demonstrated the potential of the approach.In the fourth, we describe the full project that created an optimization tool that has been working daily with oil field personnel to schedule production for the entire field for more than a year.In the fifth, we discuss two types of results of the project—an increase in production and changes to the work process on the part of the oil field personnel owing to their enthusiastic adoption of the optimizer.In the sixth, we discuss some project management factors that led to the success of the project.Finally, we discuss ways in which the success of this project may be relevant to a variety of other types of scheduling and resource allocation problems in the field of oil production.
The paper will center on three themes:the successful solution of a hard production problem with a new technology; the impact of that technology on the oil field personnel; and the potential of that technology to support other types of projects with similar levels of return.
1. Introduction The Cyclic Steam Process
The Antelope reservoir, located in the Cymric Field, in the San Joaquin Valley, is a siliceous shale reservoir containing heavy oil (12° to 13° API gravity). The reservoir consists primarily of diatomite, characterized by its high porosity (60%), high oil saturation (50–60%) and very low permeability (2 md).Approximately 430 wells are producing from this reservoir with an average daily production of 23,000 BOEG.The oil from the field is recovered using a Chevron-patented cyclic steam process. A fixed amount of saturated steam is injected during a three-to-four day period into the reservoir. The steam's high pressure fractures the rock and the heat from steam reduces oil viscosity. The well is shut in during the next couple of days known as the soak period. Condensed steam is absorbed by the diatomite and oil is displaced into the fractures and well bore. After the soak period the well is returned to production. The flashing of hot water into steam at the prevailing pressure provides the energy to lift the fluids to the surface. The well flows for approximately 20 to 25 days.After the well dies, the same cycle - cycle length of 26–30 days - is repeated.
Scheduling Problem for Cyclic Steam Process Since there is no oil production during the steaming and soaking period, there is an incentive to minimize the frequency of steaming and increase the length of the cycle. On the other hand, since the well production is the highest immediately after returning to production and declines quickly thereafter, a case can be made for increasing the steaming frequency and reducing the length of the cycle. This suggests there is an optimum cycle length for every well that results in maximum productivity during the cycle. Extend this dilemma for more than 400 wells in the field, combine that with the constraints of steam availability and balancing of the steam distribution system, factor in additional facility constraints, and the result is a formidable scheduling optimization problem.