The project goal is to resume marginal oil production operations in Red Mountain oilfield in the San Juan Basin in McKinley County, NM, by installing a cable-suspended electric submersible pumping system. The objective is to determine if the system could reduce lift costs, making it a more cost-effective production system for similar oilfields within the region, and if warranted, drill additional wells to improve the economics.
A joint venture between Enerdyne LLC, a small independent oil and gas producer, and Pumping Solutions Inc., developer of a low-volume electric submersible pump suspended from a cable-both based in Albuquerque, NM-sought to reestablish marginal oil production from Red Mountain oilfield by working over 17 existing wells, installing submersible pumps, and operating the field for approximately one year.
Enerdyne has reached the conclusion that the cable-suspended pumping system, when installed in a shallow reservoir such as Red Mountain oilfield, can be a more cost-effective artificial-lift method than the conventional rod pump method. It thus can provide an operator the opportunity to extend the life of a similar field by reducing the man-hours to maintain pumping wells and by lowering operating energy costs.
Since this diaphragm type, positive displacement hydraulic submersible pump system eliminates the need for expensive surface pumping equipment that requires constant maintenance, pumping labor costs can be reduced by 60%. This, coupled with the reduced operations electricity cost savings of about 45%, creates a significant comparative cost advantage that can extend the economic life of a marginal oil well.
However, at the end of about one year of operating the submersible pumps to produce Red Mountain oilfield, 3 of the 16 pumps installed had failed due to electrical complications.
In summary, in spite of the pump failures, the submersible pumping system was found to have several advantageous features:
Conversely, the system can cause a unique set of potential problems during operations:
There are a tremendous number of stripper oil and gas wells producing in the United States, many coalbed natural gas wells that require dewatering, deviated wells that are impossible to produce with conventional rod systems, and chemically challenged wells where the downhole environment can significantly reduce the life of conventional steel pumps, tubing, and rods. All of these wells are capital-intensive to equip. With a diaphragm type submersible pump system, costly surface equipment can be eliminated, and operating cost can be reduced. In doing so, that investment can be directed toward exploration rather than production, which adds reserves and creates jobs.
Where producing wells are located within urban areas that are sensitive to air and noise pollution, the submersible pumping system appears to be the solution to both the community and the producer in an aesthetically pleasing manner.
In April 2003 a cooperative 50% cost-share agreement between Enerdyne LLC and DOE was executed to investigate the feasibility of using cable-suspended electric submersible pumps to reduce lifting costs and increase ultimate oil recovery in Red Mountain oilfield, located on the Chaco Slope of the San Juan Basin. The field was discovered in 1934 and has produced 350,000 barrels of oil. Prior to April 2003, the field was producing only about 20-30 barrels per month; however, reservoir characteristics suggested that the field contains ample oil for production to be economically revived. The shallow nature of the water-drive reservoir, where oil occurs with fresh water at depths of 290-1,000 feet, served as a relatively good test area.
Seventeen well bores were selected by Enerdyne for workover. Wells were selected based on their completed depth and casing size (4-inch inside diameter) to accommodate the pump.
Using Enerdyne's rig, conventional methods were employed to clean out all wells of sediment. Each well then was treated for minor skin damage and circulated. No significant problems were incurred during these procedures. After each well was cleaned, the submersible pumping system was installed via a special coiled tubing trailer. With the exception of one installation, all pumps were eventually installed and tied into a temporary power supply and storage tank. The one installation that was not completed was the result of an unforeseen downhole condition that caused the pump to become stuck diagonally in the well and irretrievable. It was found that when using a cable to suspend the pump and flexible production tubing, the movement of the pump is extremely limited within the wellbore. Several other pumps had to be pulled and reinstalled because of electrical or chemical problems.
Following the temporary tie-in procedures, each well was pumped until it was determined that the well was stable and reservoir conditions were normalized. The well was then pumped for a period of time to gauge the produced fluid and determine the actual oil cut. It was concluded that, on average, a well would produce about 8 barrels per day of fluid with a 15% oil cut.
In summary, the project has:
Phase III of the project calls for additional drilling to improve field economics. Based on 3-D seismic, eight well locations have been staked and three permitted to drill by the State. All locations target fluvial sandstones in the Mesaverde Menefee formation, ranging from 1,050 feet to 1,750 feet in depth. Potential-reserve calculations estimated 2.5 million barrels of original-oil-in-place.
Phase III commenced in May 2005, with final approval from DOE in November 2005. Since commencement, several delays and drilling problems have occurred. The initial deep (1750 feet) well has been drilled and completed. Testing began with the well producing at a rate of 85 barrels of water per day. After a lengthy test with water persisting, the well may be recompleted in a shallower objective that appears to be hydrocarbon bearing.
$602,504 (50% of total)
These reports are available from NETL, 918-699-2000: Semi-Annual Technical Progress Report, dated October 16, 2003; Semi-Annual Technical Progress Report, dated April 15, 2004; the Phase II Technical Report, dated November 15, 2004, and the Phase III Technical Report dated November 15, 2006.