Drilling advances

	Vol. 224 No. 5
ROBERT E. SNYDER, EXECUTIVE ENGINEERING EDITOR

Deep gas drilling in shallow water. On March 26, the US Minerals Management Service published a proposed rule in the Federal Register which would provide for suspension of royalties for leases issued before January 1, 2001, in shallow water, on deep gas production on the Outer Continental Shelf. The proposal provides a royalty suspension volume for a lease on the first 15 Bcf of gas production for new wells drilled and completed from 15,000 to 18,000 ft subsurface, and on the first 25 Bcf for a new well drilled to 18,000 ft or deeper. 

MMS hopes the incentives will encourage production of deep gas resources. Operators hold about 2,400 existing leases in the area targeted for relief in the proposed rule. OCS gas provides about 25% of domestic production, but the shallow water area has been declining sharply over the last few years. 

An analysis by Friedman, Billings, Ramsey & Co., Inc. (FBR), notes that the industry has drilled some 35,000 wells in the Gulf, but only about 5% were drilled below 15,000 ft. Over the past three years, the industry has drilled about 87 deep-shelf wells per year, defined as below 15,000 ft TVD. FBR believes that higher commodity prices and the royalty relief stimulus will cause E&P companies to drill roughly 10 to 15 more wells per year, adding about 200 MMcfd to present base production of 47 Bcfd. 

There is an increase in exploration risk with deep gas due to several causes. Besides the obvious higher temperature and pressure, there is an increase in mechanical drilling risk: as the well gets deeper, especially in uncharted areas, more things tend to go wrong, such as stuck pipe and lost circulation. The risk of encountering unwanted and dangerous gases, such as CO₂ and H₂S, also increases. 

Regarding drilling contractors, FBR says Rowan and Ensco are the primary beneficiaries of increased deep-shelf drilling. These two companies own most of the 30-some rigs capable of efficiently drilling deep gas wells. Rowan is particularly focused on deep-shelf drilling and has undertaken a newbuild program for high-spec, Tarzan-class jackups, with the first expected in 2004. Ensco is also well positioned after its recent acquisition in Chile, and is planning several rig upgrades in the Gulf by 2005. 

Many rigs in the GOM are capable of drilling deep gas wells; however, to efficiently drill these wells, the rig must meet high specs. It would require a newer-generation top drive with enough hp to run long strings of drill pipe and casing, three or more mud pumps capable of handling large fluid volumes, and high-end, 15,000-psi BOPs. FBR estimates that there are roughly 30 rigs that meet or approach these specs in the GOM. 

These high-spec rigs are now being utilized at about 90%, in contrast to the overall Gulf rig market at 67%. However, this figure can be misleading because some of these rigs are drilling less-challenging wells. As demand for high-spec rigs increases, those rigs will begin to drill more-challenging wells, and some contractors may upgrade, or move, premium jackups into the Gulf. However, FBR notes, the current number of high-spec rigs in the Gulf is sufficient to handle near-term demand; therefore, it does not expect more than a few upgrades or rig moves in the next 12 months. 

The analyst does believe that Deep Shelf activity will increase in 2003, based on lease sale activity and the potential for royalty relief. But even a substantial 15% to 20% increase would lead to only 10 – 15 additional wells. With average drilling times of three to four months, 15 additional wells would only put an extra four rigs to work each year. 

The rule provides for a 60-day comment period. For further information, contact Marshall Rose, Chief, Economics Division, MMS, at (703) 787-1536, or visit: www.gomr.mms.gov/homepg/offshore/deepgas.html.

Innovative Arctic Platform. The first attempt in the US to tap methane hydrates, a potentially immense source of future energy, is using what could be the forerunner of a new type of onshore drilling platform that dramatically reduces environmental impact.

The “Arctic Platform” is a lightweight, 100 x 100-ft aluminum drilling platform elevated 12 ft above the frozen tundra on specially designed steel legs. The platform is compact and modular, allowing it to be safely transported by air or with ultra-low-impact vehicles called rolligons. It was developed by Anadarko Petroleum. It could allow extension of the operating season above the Arctic Circle, when the tundra has thawed.

Anadarko’s Arctic Platform, a new drilling platform concept.

Although the prototype platform is a scaled-down version of what would be deployed in future operations, the concept could one day eliminate the need for gravel pads, temporary ice roads and ice pads on the North Slope. The platform could be the next major step toward the day when exploration and drilling would leave virtually no lasting surface trace.

The platform has been installed south of Kuparuk River field, Alaska. The methane hydrates project is part of a two-year cost-shared partnership between DOE, Anadarko, Maurer Technology Inc., and Noble Engineering and Development. DOE is providing $6 million of the $10.5-million total estimated cost. Deployment and testing of the Arctic Platform is expected to cost another $2 million, with DOE planning to contribute half.

Drilling of hydrate well Hot Ice-1 began on March 31, using a slim-hole rig. The well was over 800 ft deep at mid-April, and has a planned 3,000-ft TD. A production test of the hydrate formation is scheduled when the well is complete the first ever such test in the US).

A specially designed “Drill Smart” system developed by Noble allows project participants to view continuous live data and images from the platform. Maurer Technology Inc., the “principal investigator” for the DOE-funded project, maintains a website with daily updates at: http://www.maurertechnology.com/JIP/GasHydrates/NGHhome.asp.