The goal of this project was to develop technologies that will improve the production performance of stripper gas wells. This goal was accomplished by developing a methodology, including a procedure guide, data collection forms and decision trees that will enable operators to economically identify the source of production problems and suggest cost effective corrective measures.
James Engineering, Inc. – Project management and all research products
Marietta, OH 45750
The low profitability of stripper gas wells limits the amount of time and money operators are willing to invest to optimize production. Production managers must work to minimize the number of “problem” wells exhibiting less-than-expected production, and at the same time minimize the amount of time spent assembling data and analyzing the causes of abnormal well declines. In this project, a study group of 270 Clinton Sand wells in Ohio provided the data to determine the historic frequency of abnormal production declines in stripper gas wells and the causes of those abnormal production declines. The researchers utilized database management software to graphically analyze abnormal production declines for the study wells. Production history gaps were filled in as necessary with data from two state maintained databases and a forty-year semi-log plot of monthly oil and gas production was prepared for each well.
Stripper gas-well operators frequently find it difficult to identify marginal or under-performing wells within producing areas. The primary challenge is the magnitude of the data that must be reviewed and the limited resources for doing so. These operators need an easier and faster way to screen stripper wells and identify those which are underperforming. The procedure guide developed in this project will provide the operator with tool to quickly analyze and correct problems within stripper gas wells experiencing abnormal production declines. This in turn will help to keep low producing wells operating and maximize the overall production from those wells.
A forty-year production decline type curve was prepared for the Clinton Sand formation based upon extensive experience in the Appalachian Basin. The type curve was overlaid on each well’s production plot and abnormal production declines were identified as those with a consecutive three-month period where production fell below the type curve by 50 percent. Over 70 percent of the study wells had experienced abnormal production decline in the five years preceding the study.
Eight categories of well problems were identified as potential causes for the declines: reservoir damage, reservoir depletion, fluid accumulation problems, precipitate plugging, mechanical failure, gathering system restrictions, metering inaccuracies, or “unknown.” Analysis showed that over 90 percent of the declines were due to just three of causes: fluid accumulation (46 percent), gas gathering restrictions (24 percent), and mechanical failures (23 percent).
A three-phase process to aid in identifying the most common production problems causing abnormal production decline was developed. The Decision Tree Triage Form provides a step-by-step methodology for identifying the cause of abnormal production declines in stripper gas wells by identifying factors that affect the flowing bottom hole pressure. The process (and form) is divided into three Phases: Identify, Measure, and Solve. The overall philosophy is to begin by eliminating the possibility of the most common causes and only expanding the analysis as the problem requires.
The steps in Phase 1 include verification of the production decline and forecast to ensure that they are appropriate and complete. Reviewing a complete monthly production history of all fluid production volumes is important. Verifying the situation with the pumper, and verifying metering accuracy and the gas gathering system integrity through pressure testing are also important.
Phase 2 (Measure) involves using the appropriate Data Collection Form to complete the problem analysis. Forms were developed for tubing plunger wells, casing plunger wells, pumping wells, and swab or flow wells, with specific data applicable to each production method identified. These forms require well information, fluid production volumes, pressure data, and well analysis for specific production methods, with particular attention focused on those factors that could adversely affect the flowing bottom hole pressure. Phase 3 (Solve) involves completing the Decision Tree Section of the Triage Form, and should result in a solution to the cause of the abnormal production decline. Completion of an Alternative Production Method Decision Form, provides a methodology to evaluate the costs and benefits of various production methods.
Twenty-four wells were identified with abnormal production decline from decline curve analysis and Artex Oil Company’s monthly production monitoring reports. The wells were reviewed utilizing the Decision Tree Triage Forms and the Data Collection Forms developed as a part of this project. Of the group, 15 wells were determined to have fluid accumulation problems, 8 wells to have mechanical failures, and 1 well to have gas system restrictions.
The C. Williams #1 and the Richey Lucille #1 were selected as the two wells with the greatest potential for production increase as well as the most frequently occurring problem, fluid accumulation. The C. Williams #1 was shown to be producing at 55 percent of its maximum rate because optimal pressure drop was not being achieved with the current tubing plunger operation. A bottom hole pump, rods, and pumping unit were recommended as the best solution, with payout of the estimated $10,000 cost in approximately 20 months. Installation of the pumping unit was completed on June 8, 2001. The well is pumped four times per week at four hours per cycle. The point of connection to the gas gathering system was moved eliminating 2000 feet of pipeline with a separate sales meter installed. Preliminary production results indicate the well produces 38 mcfd and 2 barrels of fluid per day, almost four times greater than predicted. The actual cost for the remediation was $10,954 with an associated payout in 4 months based upon an average 30 mcfd increase at $3.00/mcf.
The Richey Lucille #1 was produced through 4 ½-inch casing as a swab well at the time of analysis. A Swab Well Data Collection Form showed the well was produced twenty-four hours a day, seven days a week, with the average flowing casing pressure and gas sales line pressure equal at 40 psi. Gas production subsequent to swabbing increased production but the increase could not be sustained. The installation of a bottom hole pump, rods, and pumping unit was recommended, with a payout of the $18,000 cost estimated at approximately 10 months. Installation of the pumping unit was completed on April 26, 2001. The well is pumped two times per week at four hours per cycle and preliminary production results indicate the well is producing 26 mcfd and 3/4 barrels of fluid per day, similar to that predicted by decline curve analysis. Actual cost for the remediation was $17,576 with an associated payout in 11 months based upon an average 18 mcfd increase at $3.00/mcf.
Based upon the successful results of the two wells remediated as part of the project, the additional wells in the 24-well group were reviewed. Results for the 10 wells remediated showed production increases that ranged from 3 to 40 mcfd, and payouts from two to 34 months on remediation costs that ranged from $550 to $19,500.
A procedure guide was prepared that details the utilization of the Decision Tree Triage Form, the Alternate Production Decision Form, and the Data Collection Forms. A presentation of the summary technical report was presented at the National Energy Technology Laboratory in Morgantown West Virginia on September 13, 2001. These materials were also presented at the 2001 Eastern Regional Society of Petroleum Engineer’s Meeting (SPE 72359) October 18, 2001 in Canton, Ohio. For a copy of the guide and forms, please contact DOE.
This project is completed.