Analysis examines more than 500 platform wells
Mark J. Kaiser
Center for Energy Studies
Louisiana State University
In recent years, operators have been paying more attention to offshore decommissioning in the Gulf of Mexico because of greater regulatory oversight and more restrictive regulations, increased cost of operations, including insurance coverage and the increasing volume and associated cost to maintain aging infrastructure.
No empirical studies have attempted to quantify the reliability of well abandonment despite its obvious importance for decision makers and regulators. The purpose of this three-part series is to estimate the probability that a dry tree well abandoned using rigless technologies requires remediation.
A random sample of 502 platform wells abandoned in 2010 in water depths less than 400 ft (122 m) were tracked from 2010-2015 to identify leaking/bubbling events. Nine wells were identified that required remediation leading to a remediation probability of 1.8% and a 95% confidence interval ranges between 0.6% and 3.0%. The results of this analysis demonstrate that rigless abandonment procedures are robust and have a low probability of failure.
Part one describes the three methods used for well abandonment - rig, coil tubing unit, and rigless technologies - and summarizes federal regulations. Parts two and three will describe methodology, results, and limitations.
P&A activity, 2004-2015
The Gulf of Mexico is the largest and most active decommissioning market in the world, and also the most transparent in terms of publicly accessible data. From 2004-2015, about 3,000 wells were temporarily abandoned and 8,000 wells were permanently abandoned, and from 2009-2014, more than 1,000 wells were plugged annually. Activity in 2015 and 2016 was significantly reduced. In recent years, operators have begun to pay more attention to abandonment because of several factors:
- Greater regulatory oversight and more restrictive regulations such as NTL 2010-G05 and NTL 2016-N01
- Fewer entrants into the GoM shelf provide fewer opportunities to “kick the decommissioning can down the road” to the next lease operator
- The increased cost of decommissioning storm toppled wells and structures compared to standing wells and structures, and the increased cost to insure against storm damage repairs or replacement
- The increasing volume and associated cost to maintain the aging infrastructure that is no longer useful for producing smaller quantities of oil and gas.
Well abandonment classification
The following terms need to be defined in this process.
Rig. A rig must have the rated capacity to pull tubing and the downhole equipment out of the well, and may be used to cut and pull casing, set packers or retainers, and to drill out retainers. Before working on the well, weighted fluid is either pumped or circulated to eliminate any pressures that might be present, and usually valves are installed in the well and the tree or wellhead is removed, after which the BOP is installed. After testing the BOP, the tubing is pulled and abandonment procedures are followed. Rig-based operations give the operator the most flexibility but at a high cost due to the high equipment day rates.
Coil tubing unit. Coil tubing units (CTU) are units that carry tubing coiled around a large drum, and are much like rigs in that they have pumps to circulate fluid and test BOPs but on a more limited scale. CTUs have been successfully used to abandon wells throughout the world, but are usually applied in specialized or complex situations, such as high casing pressure since these wells have to be remediated before proceeding with abandonment.
Rigless. In the 1980s, contractors developed “rigless” methods to reduce cost and improve the efficiency of operations. Rigless well abandonment is commonplace throughout the GoM and substitute smaller equipment spreads such as pumping skids and jacking units in lieu of a workover or drilling rig to deliver cement and pull pipe from shallow depth. The primary distinguishing feature of a rigless abandonment is the use of the tubing already in the wellbore to place cement plugs, rather than pulling the tubing and running a work string with a rig or using coiled tubing to pump the cement through.
Rig vs. rigless abandonment
The basic differences between a rig and a rigless abandonment are depicted in a typical wellbore schematic with gas-lift mandrels. Wells with gas-lift mandrels inject natural gas into the production tubing to reduce the hydrostatic head of the crude oil and enhance production rate. Not all oil wells apply gas-lift, but on the GoM shelf, where gas supplies are readily available, gas-lift wells are common.
|Step 1: Bottom plugs set with tubing pulled out of hole in the rig method.|
Step one shows the wells after the bottom plugs have been set and the tubing pulled out using the rig method. Note that the production tubing remains in place in the rigless method.
|Step 2: Balanced plug on rigless and stopped plug with the rig.|
Step two shows the balanced plug with the rigless method and the spotted cement plug with the rig method.
|Step 3: Rigless with cut casing and cast iron bridge plug.|
In step three, the rigless method cuts the production tubing and a cast iron bridge plug is set with 200 ft (61 m) of cement on top, whereas the rig method shows the same with more casing cut out of the hole.
The outcome in both methods are similar, namely, a plugged well intended to maintain its abandonment integrity until the natural pressures within the borehole and formation return. The risk associated with rigless abandonment is that the procedures may not be as durable or reliable as a rig-based approach. When tubulars remain in the wellbore, they may limit access, provide less competent seals, and/or create additional leak pathways which may lead to environmental leaks. When correct procedures are followed, the risks of failure are designed to be small, but procedures may not be followed correctly or be unable to be followed.
All operations in federal waters must be conducted in accordance with the OCS Lands Act, the lease terms and stipulations, the regulations of 30 CFR Part 250, notices to lessees and operators (NTLs), the approved application for permit to modify (APM), and any written instructions or orders from the district supervisor.
Temporary abandonment procedures require operators to provide (a) at least two independent tested barriers as per 30 CFR 250.1712(g) including one mechanical barrier, and (b) an independent third-party review to ensure compliance with 30 CFR 250.1715 for abandonment activities and BOEM’s drilling safety rules. In some cases, a well can be classified as temporarily abandoned with only one plug isolating open perforations.
For permanent abandonments, requirements are specified for: (a) isolation of zones in open hole, (b) isolation of open hole, (c) plugging or isolating perforated intervals, (d) plugging of casing stubs, (e) plugging of annular space, (f) surface plugs, and (g) testing of plugs.
The request for approval of an APM contains the reason for abandonment and a description and schematic of the proposed work, including depths, type, location, length of plugs, cementing, casing removal, and other pertinent information. The report of abandonment includes a description of the manner in which the abandonment or plugging work was accomplished, and a revised schematic. Wellbore schematics show the status and condition of the well after proposed operations are finished, including the location of all casings, cemented intervals (including top of cement), perforated zones, completion equipment, isolation packers, tubing, landing nipples, and subsurface safety devices.
Operators submit APMs for proposed activities, and are required to obtain verbal/written approval from BSEE district supervisors for any deviations from these procedures. Any changes to steps outlined require permission from the BSEE, and failure to comply with the requirements may result in the issuance of an incident of noncompliance. All tubing and casing strings are checked for pressure and pressure tested as per regulatory requirement. If casing annuli does not test or cement plugs cannot be set at levels specified in the APM, contingency plans are followed subject to BSEE District Supervisor approval. Every significant departure is outlined in APMs and provide a documented record when activities are changed or do not proceed according to plan (e.g., unable to establish circulation during abandonment at a specific depth).
This study was performed on behalf of the Oil & Gas UK and has not been technically reviewed. The opinions, findings, conclusions, or recommendations expressed in this article are those of the author, and do not necessarily reflect the views of the U.K. Oil & Gas Association. Funding for this research was provided through the Oil & Gas UK.