PLUGGING: THE LAST RESORT

Based on a workshop sponsored by PTTC’s South Midcontinent Region and the Oklahoma Commission on Marginally Producing Wells on April 7, 1999, in Broken Arrow, OK.

BOTTOM LINE

Well plugging operations go smoother and cost less when operators know regulatory requirements, understand the basic steps of the plugging process, and apply regional insights.

PROBLEM ADDRESSED

While not a pleasant option, well plugging is a reality, and operators should know how to cost-effectively plug wells. Costs savings can be realized by wisely purchasing plugging services. When plugging wells, operators must comply with appropriate regulations and properly protect the environment.

KEY WORDS:

Well Plugging, Regulatory, Environmental

SPEAKERS

Michael Stovall, Genie Well Services, Inc.

TECHNOLOGY OVERVIEW

Before plugging a well, an operator should look hard for remaining potential, whether in the current formation, uphole, through a waterflood, or in improved oil recovery. If there is even a remote possibility of future potential, an operator may want to use a shut-in or temporary abandonment period that is allowed by regulations (being mindful of lease terms) to further evaluate resource potential. If one must plug a well, it is good practice, although not required in Oklahoma, to notify other operators.

The plugging process has several phases. First, operators must obtain consent from other working interest owners (WIOs). Then, the plug and abandonment (P& A) operation itself must be performed. Third, the surface equipment and tubular goods must be removed. The final, but often neglected, step is to restore the wellsite and location.

 In obtaining consent from other WIOs, an operator should review the lease, land files, and the joint operating agreement (JOA). Typically, all WIOs must consent within 30 days, or elect to take over the well. It should be noted that salvage value provisions typically overvalue equipment. To avoid such overvaluing, an operator needs to provide a written estimate of salvage value, less P& A and reclaim costs, and tailor the consent ballot to reflect “in lieu of amounts to which undersigned may be entitled by JOA.” Pumping units may only be worth 10 to 15% of original cost. Surface equipment and tubular goods are typically sold to local dealers or specialized buyers; rods are usually sold to another operator or well service contractor.

There are four approaches to the plugging process: Operators may choose to do it themselves, hire a plugger to do it for them, request a turn-key bid from a plugger, or sell the well to the plugger who assumes full responsibility. The last two options will cost more, since the plugger assumes more risk. If actually selling the well, a change of operator notification should be filed, and a written agreement should spell out terms and time limits.

Multiple agencies may have jurisdiction, including: the state regulatory agency, municipalities, Bureau of Land Management, Bureau of Indian Affairs, and US Environmental Protection Agency. Operators should research and discover what requirements the plugging operations must meet, and realize that notifications and paperwork may be required for multiple agencies.

From the regulatory perspective, recurring problems include: a failure to provide advance notice to field inspectors, not checking the depth of treatable water, delays or failing to file a final plugging report, not having a responsible person on location to make decisions, and not properly restoring the location. The operator, not the field inspector, must make decisions about the plugging procedure, or problems encountered, once operations are begun. Good communication is central to resolving many problems.

Rules may vary by state, but typically plugs must be set to isolate any formation that bears hydrogen sulfide, oil or gas, or treatable water. Care should be taken to isolate injection zone( s) that may be subject to secondary or enhanced recovery in the future. Also, low-pressure zones should be isolated from high-pressure zones.

In plugging the perforated interval in cased-hole completions, the operator can use a wireline-set Cast Iron Bridge Plug (CIBP) with a dump bailor of cement on top, or a cement plug. The wireline-set CIBP typically is used for deeper wells when there are many open perforations, for low-pressure or depleted zones, or when there are multiple zones to be shut off. Cement plugs are more applicable to shallower 3,000 to 4,000ft. wells.

The stump (stub plug), which is the cement plug at the casing cut, is best made by spotting cement through the tubing. Open-hole plugs may be required at intervals of every 2,500 to 3,000 ft. as the casing is pulled. Other critical plugs are the one at the surface casing (in/out plug, top plug) and the surface plug.

Mud used during plugging operations prevents blowouts and helps prevent cement plugs from falling. In Oklahoma, muds must weigh at least 9 pounds per gallon and have a 36 viscosity (funnel). The hole should be kept full of mud at all times; the best way to load the hole with mud is to set CIBPs, then trip in hole with tubing to the top of the plug and circulate the hole until loaded. Blowout preventers may not be required, but are recommended. Blowout preventers should be used that will accommodate both the tubing ram and casing ram blocks.

If 800 to 1,000 ft. can be salvaged, it is recommended that the casing be pulled. To estimate the amount of casing that can be recovered, the size, weight per foot, grade, run time, depth to top of cement (TOC), and history of squeeze jobs should be known. It also is helpful to know how much has been recovered from area wells.

The casing freepoint can be determined by performing stretch tests on the casing. Even with good planning, it’s rare when casing is recovered down to the TOC or the calculated freepoint. Rigs are faster and can be used for weights up to 200,000 lbs. Casing jacks are for deeper wells with more weight.

Location restoration, a task often overlooked by operators, is important to both regulatory agencies and surface owners. Restoration involves not just the wellhead but any pads, dikes, roads, etc. Hydrocarboncontaminated soils may need reclamation or disposal. All equipment and debris must be removed. By making deals, documented in writing, with surface owners about leavings things like roads, etc., operators can avoid removal costs.

CONNECTIONS:

Michael Stovall
Genie Well Services, Inc.
2815 E. Skelly Dr. #816, Tulsa, OK 74105
Phone 918-747-3695, E-mail geniewells@aol.com

For information on PTTC’s South Midcontinent Region and its activities contact:
Charles Mankin, Director, Oklahoma Geological Survey
100 E. Boyd St., Room N131, Norman, OK 73019-0628 
Phone 405-325-3031, Fax 405-325-7069, E-mail cjmankin@ou.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