BEST PRACTICES FOR IMPROVING ECONOMIC MARGINS

Based on crisis-oriented workshops developed by PTTC’s Midwest, North Midcontinent, and Rocky Mountain regions in March 1999 in Colorado, Illinois, and Kansas.

BOTTOM LINE

Practical survival tips, from both a technology and business perspective, can give operators the information they need to improve their economic margins, by reducing operating cost and/or increasing production.

PROBLEM ADDRESSED

Independent producers, particularly during periods of depressed oil prices, must use all available tools to improve economic margins. Several options have the potential to reduce electrical power costs, which is a major element of operating costs. In some cases, downhole water separation technologies may be applicable. Chemical treatments are available for protecting downhole equipment during shut-ins, and for removing wellbore damage and enhancing production. If wells are to be shut-in, operators must understand what is required to maintain the lease, including lease terms and regulatory requirements.

KEY WORDS:

Electrical Power Costs, Downhole Water Separation, Shut-in Practices, Chemical Treatments, Operating Costs

SPEAKERS

David Coston, Coston Energy, Inc.

George Fancher, Fancher Oil LLC

Lester Moore, Moore Engineering & Production Co., Inc.

Rocky Higgins, Baker Petrolite

Craig Hedin, John L. Richeson, Steven Richardson: attorneys

TECHNOLOGY OVERVIEW

Although no panaceas exist, the combined effect of many actions can improve profitability for independents. On the operating cost side of the margin equation, operators should know their direct lifting and total costs, with data broken down into meaningful categories. By analyzing the data, an operator can prioritize cost reduction efforts, which is particularly important when well shut-in is considered. Operators also should evaluate their pumper’s routines to determine if wells must be pumped every day and to optimize driving time. Pumpers may be able to perform additional duties (e. g., some roustabout and general maintenance work) or share their time with other operators.

Reducing Electrical Power Costs. Utility bills consist of a basic energy charge, a demand charge, and, at times, a power-factor charge. Savings are possible when demand charges are 50% or more of the total bill. Power factor, the ratio of the real power needed to get the job done to the total power supplied, is another consideration. Power factors that are less than 95% can be improved by adding line capacitors.

Equinox Oil Company used timers to reduce power costs in the South Albion Field in Illinois. Working with Coston Energy Inc., Equinox took advantage of off-peak (9: 00 p. m. through 9: 00 a. m. weekdays, plus all day Saturday, Sunday, and holidays) and seasonal discounts. Rates were discounted 30% during winter months, and 57% during summer months. Equinox put 20 wells on seven-day timers in 1998, pumping them during off-peak hours. While production did not appreciably change, electrical consumption dropped 25%, decreasing power costs by $2,000 per month.

Unless power costs are low (2 to 3 cents/kwh), selfgeneration of electricity is another option. Operating and maintenance costs for new high-efficiency gas turbine generators are $0.01 to $0.02/kwh. Self-generation is particularly attractive if flared or low-cost gas is available for fuel. Capital cost can vary significantly, but reliable generators can be purchased for $200 per kw of installed capacity. Operators also can contract with vendors for on-lease power generation.

Water Handling Costs. For some operations, downhole oil-water separation with subsurface injection in a disposal zone may be appropriate. The equipment, which can be used in either sandstone or carbonate zones, uses gravity or hydrocyclone separation technology. This can only be used where wells have a disposal zone with adequate injectivity. Even then, operators often encounter problems maintaining injectivity. Although this technology can be profitable in some applications, it is a high-risk, evolving technology.

In other reservoirs, downhole water sink (DWS) technology may be an option when a well is dually completed for both oil production and water drainage (water sink). The location of the oil leg (and coning) is controlled by varying the rates of the separate oil and water completions. The production of water-free oil can be prolonged, and the water may require less treating.

Protecting Equipment. Sulfate-reducing and acid-producing bacteria must be controlled in shut-in wells. Corrosion inhibitor and biocide treatments are both recommended. The primary strategy is to distribute the proper chemicals throughout the water phase where corrosion takes place. If tubing is in the hole, the chemically treated water must contact both internal and external surfaces. If a well is returned to production, it should be retreated.

Removing Damage to Increase Production. Baker Petrolite has tested an encouraging treatment program that reduces near well-bore organic damage (wax buildup). Wells are treated with solvent/dispersant combinations that penetrate 12 to 18 inches into the formation, followed by a 12-hr. shut-in period. In selecting candidates, operators must thoroughly analyze well history looking for wells that have experienced a production decline that cannot be explained by expected reservoir depletion or other mechanical problems.

Handling Lease and Legal Issues. Operators should maintain good relations with the lease owner and know the terms of their leases, as well as state regulations. Operators also should understand the legal concepts of the “reasonably prudent” operator and maintaining production “in paying quantities.” The latter does not mean that an operator has to show a profit every month, just over a reasonable period of time. To protect both sellers and buyers when leases are changing ownership, the details of plugging and environmental liability should clearly be outlined with other “due diligence” concerns in sales agreements.

CONNECTIONS:

David Coston, President
Coston Energy, Inc.
309 Daras Dr., Carmi, IL 652821
Phone 618-382-2280, Fax 618-382-2424, E-mail ueceil@midwest.net

George Fancher, President
Fancher Oil LLC
1801 Broadway, Suite 720, Denver, CO 80202
Phone 303-296-6600, Fax 303-296-2433, E-mail ghfancher@aol.com

Lester Moore, President
MEPCO, Inc.
2104 Lincoln Ave., Evansville, IN 47714
Phone 812-479-1051, Fax 812-476-2569, E-mail mepco21104@aol.com

Rocky Higgins
Baker Petrolite
1675 Broadway, Suite 1500, Denver, CO 80202
Phone 303-573-2772, Fax 303-615-9004, E-mail rocky.higgins@bhi.bhi-net.com

Craig Hedin, Attorney
Campell, Black, Carnine & Hedin, P. C.
PO Drawer C, 108 S. 9th St., Mt. Vernon, IL 62864
Phone 618-242-3310, Fax 618-242-3735

John L. Richeson, Attorney
Anderson, Byrd, Richeson, Flaherty & Henrichs LLP
216 S. Hickory, PO Box 17 Ottawa, KS 66067
Phone 785-242-1234, Fax 785-242-1279

Steven Richardson, Attorney
Holme, Roberts & Owen
1700 Lincoln St., Suite 4100, Denver, CO 80203
Phone 303-861-7000

For information on PTTC’s regional resource centers and activities contact:

Midwest: David G. Morse, Petroleum Geologist,
Oil and Gas Section, Illinois State Geological Survey,
Natural Resources, Bldg., 615 E. Peabody Dr., Champaign, IL 61820
Phone 217-244-5527, Fax 217-333-2830, E-mail morse@geoserv.isgs.uiuc.edu

North Midcontinent: Rodney Reynolds, Project Manager,
Energy Research Center, and Petroleum Engineer,
Tertiary Oil Recovery Project, University of Kansas,
1930 Constant Ave., Lawrence, KS 66047
Phone 785-864-7398, Fax 785-864-7399, E-mail reynolds@cpe.engr.ukans.edu

Rocky Mountain: Roger Slatt, Department Head,
Geology/ Geological Engineering, Colorado School of Mines,
Golden CO, 80401-1887
Phone 303-273-3822, Fax 303-273-3859, E-mail rslatt@mines.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org