The objective of this Joint Industry Project is to identify technically feasible processes for preparing and transporting heavy oil from a well lease to a battery that are cost competitive with the conventional means of transferring the oil, namely by tanker truck. The first step was identifying potentially viable concepts and processes, and developing appropriate economic and technical screening criteria to use in establishing the most viable options for further investigation.

The study consisted of a comprehensive sucker rod/tubing wear assessment and a statistical production performance assessment of approximately 160 vertical, directional and slant heavy oil wells on primary production. The influence of well offset, local curvature variation and equipment type on well productivity and servicing costs were quantified to provide economic information for use by operators in improving the performance of existing wells and in optimizing the future design and completion of directional wells.

The Problem:

Produced water contributes to high operating expenses for oil producers. Excessive water production also results in many wells and fields being suspended and abandoned, despite the fact that significant volumes of oil are still being produced. The Canadian oil industry produces, on average, almost six cubic meters of water for every cubic meter of oil.

Field experience has shown that conventional ESP completions can be successfully used in directional wellbores, provided the ESP assembly does not have to pass through regions of high wellbore curvature during installation, and is landed and operated in a relatively straight section of the wellbore. A common "rule-of-thumb" in the industry is that standard ESP assemblies can tolerate up to 3°/100 ft of well curvature during installation without suffering permanent damage.

Operators have long identified that having a failure tracking system in place is key to obtaining longer average service life in fields with Electrical Submergible Pump (ESP) operated wells. Problems with system design, equipment specification, manufacturing or installation, and day-to-day operation can be identified and corrected, contributing to run life improvement with time and resulting in increased profits.

In 1999, C-FER completed a project, on behalf of Chevron, that showed that a GL-JP system can achieve measurable increases in production rates, compared to conventional continuous gas lift, when conditions are favorable. The Inflow/Outflow Performance Relationship (IPR/OPR) curves show how this is possible. The top OPR curve indicates the tubing pressure, at the gas injection location, for a continuous gas lift (GL) system. It also indicates the discharge pressure (Pd) for the jet pump in a GL-JP system operating with the same gas injection rate.

The principles associated with the Gas-Purge Production System (GPPS) were identified by C-FER in recognition of the need for new recovery techniques to improve both production rates and reserves recovery from heavy oil formations.

This $1,700,000 joint industry study resulted in an improved understanding of solids production mechanisms which led to the implementation of drilling, completion and operating strategies that reduced the costs and risks for oil and gas production from sanding-prone reservoirs.

A full-scale experimental study was conducted to evaluate the ability of a modified jet pump to produce heavy oil under primary production conditions. One of C-FER's Special Environments Chambers was equipped with a flow loop and caisson to simulate the bottomhole pressure and temperature conditions typical of the target field. The test arrangement facilitated the monitoring and control of the various test parameters enabling performance characteristics to be established for several different nozzel/throat combinations under a range of operating conditions.

Field experience has shown that the run lives of progressing cavity pumps (PCP) vary considerably in heavy oil applications but, overall, they remain unacceptably short. In wells which produce sand, run lives may range from only a few weeks up to eighteen months with a typical average of six to twelve months depending on the field. The resultant equipment replacement and servicing costs contribute significantly to the high operating costs of heavy oil developments.