Optimizing Spraberry operating practices in West Texas

World Oil, July, 2001 by Eric Brown, James Franklin, Paul Porter, Perry Stegall

BP Permian personnel coordinated a major program to improve pump performance, reduce chemical-related problems and apply automation benefits, boosting production and cutting operating costs in this 400-well area

BP Permian's Spraberry production in West Texas comprises 400 rod-pumped wells, located primarily in Midland, Martin and Glasscock Counties. Of these, the Spraberry Core Production Area, located in Glasscock County, includes 80 wells which have been producing for 30 years. Development of the Wildfire Production Area in Midland and Martin Counties began in 1996. Wells in both areas are typically completed to about 9,500 ft through Spraberry, Dean and Wolfcamp formations. Pump depths vary from 7,600 ft to 9,700 ft through the field. A variety of operating challenges have been encountered and worked through in recent years to optimize profitability.

This article discusses the teamwork and technology utilized in resolving these challenges. Discussions cover: 1) program strategy; 2) rod-pump failure reduction; 3) application of chemicals; and 4) benefits of automation implementation.

Results of the overall program were positive. System efficiency was increased through a series of incremental steps. Automation identified opportunities and provided real-time results of each process implemented. Failure reduction was achieved through competition and a new approach to the operator's standard practices. And competing chemical companies generated improved products and better customer service by setting clear expectations and providing regular feedback.

Implementing internally plastic coated and polylined tubing, identifying and repairing casing leaks, and removing paraffin through backside treatments of condensate were new approaches taken to achieve significant step changes in combating failures. Pumping unit speed was reduced in several instances, with an increase in system efficiency; the changes also resulted in economic benefit from less electrical use and increased production.

PROGRAM STRATEGY

It was recognized that the Spraberry operation's profitability could be improved by focusing on key issues, specifically, reducing cost and increasing production. To this end, the team identified the following opportunities:

* Reduce rod-pump system failures

* Reduce downtime

* Remediate casing leaks

* Improve pump efficiencies

* Optimize organization staffing.

After the key issues were identified, teams were organized to implement the strategy and improve performance. Teams typically consisted of engineering, operations and contract personnel.

ROD-PUMP FAILURE REDUCTION

Rod-pump system failures are economically detrimental, especially in mature fields. On average, a workover to repair tubing, rods or rod pumps on wells of Spraberry depth range from $3,500 to $6,000/well. In addition, downtime resulting from the failure delays production from the well. Typically, the most common downhole failure in mature Spraberry operations is that of tubing and rod wear. Several methods to reduce wear have been applied over the years, typically in sequential applications. These include:

* Anchor tubing in tension

* Reduce polished rod velocity

* Reduce friction in pump (control sand)

* Increase weight at bottom of rod string

* Control paraffin and scale deposition, and

* Install completions that reduce friction.

Although all of these methods have been found to improve run times between failures on specific wells, cost and individual-well characteristics should be considered to determine the best method for each well. One method to reduce friction in downhole assemblies is to install either polyethylene lined (polylined) or internally plastic coated (IPC) tubing with guided rods. The polyline substantially eliminates abrasion, but the tradeoff is a considerable reduction in tubing ID. Liner thickness ranges from 120-200 mil. IPC, with amodel-guided rods, provide two smooth surfaces and minimal reduction in tubing ID. Utilizing well histories, candidates were chosen by identifying wells with frequent wear failures. Candidates also comprise wells with repeated localized tubing wear failures.

Initial results from the two designs have successfully extended well runtime and decreased wear failures. The Lane 37-7, polylined-tubing well, increased its runtime from about five months between failures to over a year. After modifying the polyline design, runtime between failures increased to over two years. Similar results have been found with the IPC tubing and guided rods design. The Driver 14-9 was experiencing failures on 120-day intervals, due to wear. Refinement of the IPC tubing with guided rods has increased runtime between failures to over two and one-half years.

Casing, tubing and pump sizes are essential factors that must be evaluated before utilizing IPC tubing. While 2 7/8-in. tubing with polylining does not require a pump change, turned-down collars will be required in wells with 41/2-in. casing. Wells with 2 7/8-in. tubing are generally considered better IPC candidates, because running polylining in 2 3/8-in. tubing would require running a slimhole pump.