Deepwater Gulf Decommissioning—1: Aging platforms, ownership changes pose special risks

March 3, 2014
This is the first of four articles that forecast deepwater decommissioning schedules in the US Gulf of Mexico (GOM). No estimates for the timing of deepwater decommissioning activity have previously been reported.

Mark J. Kaiser
Louisiana State University
Baton Rouge

Mingming Liu
China University of Petroleum
Beijing

This is the first of four articles that forecast deepwater decommissioning schedules in the US Gulf of Mexico (GOM). No estimates for the timing of deepwater decommissioning activity have previously been reported.

Part 1 reviews the life-cycle stages of offshore production and the role of decommissioning within the development cycle. It summarizes historical installation and removal trends and economic-limit statistics for deepwater structures.

The remaining parts of the series summarize the deepwater GOM well and structure inventory, expected short-term removal trends, and a decline-curve forecast to predict long-term activity.

In GOM water deeper than 400 ft, 110 fixed, tensioned, and moored structures have been installed. Through 2012, a total of 15 deepwater structures have been decommissioned, 8 over the past 3 years, according to data from the US Bureau of Ocean Energy Management (BOEM).1-3

The aging deepwater fixed platform inventory and continuing change in ownership present special risk to operators and the US government.

Largest province

The deepwater GOM is the largest and most prolific oil province in the US, producing in 2012 more than 80% of the oil produced in the entire GOM and about 25% of all US production. The notion of deep water has evolved over time with the technical capabilities of the industry and today generally refers to water deeper than 1,000 ft.

This article uses a 400-ft water depth threshold to designate deep water because the focus of our analysis is on decommissioning, and to date most decommissioning activities and experience in the GOM are limited to waters shallower than 400 ft.

Over several hundred million years, rivers draining the North American continent provided vast quantities of sand, silt, and mud to the GOM through major deltas similar to the present Mississippi and Rio Grande deltas. Sandstone reservoirs in two main geological formations, the Miocene and Lower Tertiary horizons, were transported into minibasins and hydrocarbon seals were provided by salts and the muds integral to the depositional system.

The shallow water GOM (<400 ft) has offered abundant opportunities since the late 1940s for companies able to master the complex subsurface geology while managing the catastrophic risk of hurricanes. For the past 15 years, however, GOM Outer Continental Shelf production has been declining (Fig. 1) and reserves are not being replenished.

Companies whose business strategy is to acquire and exploit mature assets have helped to slow the decline, but most analysts do not anticipate growth in the region unless large new resource plays are discovered. Some industry observers believe the shallow-water GOM is fished out.

By contrast, the deepwater GOM (>400 ft) now contributes most US offshore oil production, and major developments continue. Salt is one of the most important factors of the deepwater GOM and is key to both the region's complexity and longevity as an exploration province. The upward movement of salt through the surrounding rock formed most of the geologic features in the deepwater GOM and partitioned the hydrocarbons into numerous accumulations rather than only a few supergiant fields. There are about a dozen or so deepwater GOM fields with reserves greater than 250 MMboe, but more than 150 fields with reserves less than 50 MMboe.

The deepwater GOM is a high risk, high-cost environment, but the allure of large reserves and strong returns makes the region attractive for those companies with deep pockets and the ability to manage complex projects. Majors have been the traditional players in deepwater regions around the world, but independents have established a footprint in the deepwater GOM on a number of smaller fields.

Life-cycle stages

All oil and gas properties pass through the same life-cycle stages from discovery to depletion (Fig. 2). The capital expenditures associated with drilling wells, fabricating and installing infrastructure, and producing during the early years are gradually replaced by a decreasing revenue stream, higher operating costs, fewer promising opportunities, and, eventually, production that is worth less than the cost to operate and maintain the asset.

The duration of each period depends on the size and type of the accumulation and the design capacity. Projects with lower annual depletion support a relatively longer plateau period followed by a longer decline period, and vice versa.

Development selection, concepts

The number and type of wells and structures required to produce offshore vary with the spatial distribution of reserves and reserves size, reservoir complexity, fluid characteristics, water depth and time of development, production rate, flow assurance, and related operating, economic, and strategic considerations.

In field development, decision makers' attempts to maximize asset value and minimize costs without compromising safety or reliability.

Typical factors in the screening process include profitability, development cost, cycle time, operability, operating cost, hub or expansion capabilities, well access, and risk. The number of configurations and alternatives considered depend upon the complexity and size of the field and experience of the operator.

The goal is to select a development plan that manages downside reservoir risk (compartmentalization, bypassing, sand control, for example) while having the flexibility to capture its upside production capacity and reserves growth.

Cost is the primary design factor, and each system has advantages as well as technical and economic limitations. For high well counts or deep, compartmentalized reservoirs, structures with dry trees and drilling capability reduce drilling costs by avoiding the need for high-cost mobile offshore drilling units. For lower well counts and isolated reservoirs, pre-drilling and subsea (wet tree) completions are often employed.

Early discoveries in offshore basins usually involve large fields that allow for a standalone surface development, while subsequent discoveries are often smaller and not large enough to justify the expense of surface facilities. Once infrastructure is installed, however, it can be used to develop smaller and more isolated reservoirs with subsea systems.

As water depth increases, fixed platforms become prohibitively expensive and new designs are required. Various deepwater concepts have been employed worldwide, including compliant towers, floating production storage and offloading vessels, semisubmersibles, spars, tension leg platforms, and various hybrid structures; all of these systems have been deployed in the Gulf of Mexico.

Production systems

Integrated companies tend to take a strategic view of development relative to expansion capacity and hub infrastructure and often employ process-driven stage gates in decision making that increase the time from discovery to first oil. Phased development (early production, pilot production, full field development) is commonly employed for high-risk fields and by government-sponsored enterprises, in particular Petrobras and Statoil, that are focused on basin development rather than block development.

The purpose of early production is to gain cash flow along with increased knowledge of reservoir performance and to match capital expenditures with production revenue.

When the decision is made to stop drilling new wells, the focus changes to running the asset at minimum cost commensurate with safe and efficient operations. Redevelopment opportunities may exist via sidetracking, and additional pockets of reserves will prolong field life.

As production capacity at the facility becomes available, satellite fields may be economic. During this stage, production is enhanced by optimizing gas-lift systems and application of chemical treatment and wireline operations.

Mid-life, beyond

After mid-life, the asset makes the transition to a mature property, and structures are frequently sold during this time to companies seeking low-risk opportunities to grow reserves or wishing to economize on their regional operations. As long as the value of reserves exceeds the expected cost of decommissioning, reliable buyers can usually be found.

When the discounted value of reserves is less than the cost of abandonment or when the value is less than 1 year's cash flow, the pool of quality buyers shrinks considerably, and it is unlikely that the structure can be divested on a standalone basis. There is, however, a market niche for companies to handle closure planning and decommissioning, possibly including being paid to take on liability.

When production revenue is less than the cost to operate the structure, the economic limit has been reached, and the operator begins to plan for decommissioning or to recertify the structure as a hub platform or pipeline junction.

Deepwater fixed platforms sit near the edge of the continental shelf and frequently serve as hub platforms and pipeline junctions for off-lease production and piping and compression stations. Hub platforms may be designed to serve multiple off-lease fields from start-up or may be converted into a hub structure after production capacity becomes available.

Pipeline junction platforms are usually previously producing structures that were reconfigured when production stopped and subsea tiebacks did not materialize.

Decommissioning is the final stage of an asset's life cycle in which all wells are plugged and abandoned, the platform and associated facilities are removed, and the seafloor cleared of all obstructions created by the operations. In the US, the general requirements of decommissioning are specified through the US Code of Federal Regulations and are enforced by the US Department of Interior through the Bureau of Safety and Environment Enforcement (BSEE).

Decommissioning risk

Offshore decommissioning costs are considerably higher than for work on land and require greater planning and preparation due to the logistical issues associated with working in waters in various depths and weather. In deep water, decommissioning operations are subject to increased regulatory scrutiny and are considerably more expensive to perform than in shallow water because of the specialized heavy-lift requirements and the complexity of the operations.

From the operator's point of view, decommissioning represents a cost to be incurred in the future, while from government's perspective, decommissioning represents a risk of noncompliance and potential liability.

Failure to complete abandonment responsibilities causes a default of the lease and, in the worst-case scenario, forces the federal government to assume the responsibility of abandonment operations. To mitigate this risk, the federal government requires the lessee to make financial guarantees, such as bonds or an independent escrow account, to cover the expected cost of abandonment.

Large firms are assumed to be financially secure and abandonment obligations are implicitly guaranteed through self-insurance. Firms that do not meet the test of financial strength are required to post supplemental bonds in case of default.

The federal government's concern is similar to a bondholder that is focused on the ability of the payer to meet a certain obligation in the future. The federal government reviews the financial strength of the working interest owners in terms of debt/equity ratio, return on assets, historical net income, interest coverage, and current ratios. The review also compares the size of the dismantling obligation with the firm's total net income to determine if additional risk mitigation is warranted.

Activity trends

To date, 62 fixed platforms, 3 compliant towers, and 45 floating structures have been installed in the deepwater GOM (Fig. 3). In 2012, there were 1,803 dry tree and 404 subsea wells producing.1 3

During 1978-2000, 69 deepwater structures were installed in waters up to 4,825 ft deep: 53 fixed platforms, 3 compliant towers, and 13 floaters. A total of 1,724 deepwater wells were drilled and completed during this time, including 143 subsea completions.

During 2001-12, 41 deepwater structures were installed in waters up to 8,300 ft deep: 9 fixed platforms and 32 floaters. A total of 714 dry tree wells were drilled and completed during this time along with 290 subsea completions.

Fifteen structures in waters deeper than 400 ft have been removed through 2012: 12 fixed platforms, 2 semisubmersibles, and 1 mini tension leg platform (table). Half of all deepwater removals have occurred in the last 3 years. The first two semisubmersibles installed were decommissioned early due to poor reservoir performance:

Placid Oil installed the first semisubmersible in the GOM in 1988 at Green Canyon Block 29 in 1,534 ft water depth with a converted Penrod 72 semisubmersible drilling rig, but after a satellite well was lost due to downhole equipment failure and producing wells developed problems from a gravel pack failure, operations ceased 1 year after production (OGJ, Apr. 23, 1990, p. 30).

In 1995, Enserch Exploration Partners installed a converted semisubmersible at Garden Banks Block 388 in 2,190 ft water depth. After producing 5.1 million bbl oil and 8.7 bcf natural gas from Cooper and Llano fields, the structure was decommissioned in 1999.

In September 2005, Hurricane Rita destroyed Chevron's Typhoon mini tension leg platform, which was subsequently converted into a deepwater artificial reef (OGJ Online, May 9, 2006). Chevron and partner BHP Billiton sold the field and adjacent acreage to Helix Energy Resource Technology, which subsequently redeveloped the field (now named Phoenix) with a mobile offshore production unit which re-started production in 2010.

Active structure inventories closely follow installation trends because deepwater removal activity is still in its infancy (Fig. 4). In January 2013, the active deepwater inventory consisted of 50 fixed platforms, 3 complaint towers, and 42 floating structures (Fig. 5).

Economic limit

Gross revenue near the end of production provides insight into the economic limit of production, since presumably a structure will stop producing when its gross revenue falls below its operating cost.

Every structure has a different operating cost profile, depending on the number and type of producing wells, product type and quality, distance to shore, water production, age, workover requirements, and related factors.

The average gross revenue the last year of production for the 15 deepwater structures decommissioned in the GOM, excluding the Typhoon mini-tension leg platform which was taken out prematurely by a hurricane, is $22.3 million for oil structures and $10.5 million for gas structures (Fig. 6).2 3 The median gross revenue the last year of production for all structures excluding Typhoon is $3.6 million.

References

1. Platform Master Database, 2013, US Bureau of Ocean Energy Management; www.data.boem.gov/homepg/data_center/platform/platform/master.asp.

2. Structure Database, 2013, US Bureau of Ocean Energy Management; www.data.boem.gov /homepg/pubinfo/freeasci/platform/PlatformStructuresFixeddfn.asp.

3. Wellbore Database, 2013, US Bureau of Ocean Energy Management; www.data.boem.gov/homepg/data_center/well/well.asp.

The authors

Mark J. Kaiser ([email protected]) is professor and director, research and development, at the Center for Energy Studies at Louisiana State University. His primary research interests are related to policy issues, modeling, and econometric studies in the energy industry. Kaiser holds BS, MS, and PhD degrees in engineering from Purdue University.

Mingming Liu ([email protected]) is a PhD candidate in petroleum engineering management at the school of business management, China University of Petroleum, Beijing, from which he also holds a BS in business management. His research interests include deepwater cost studies and fiscal system analysis.