GULF OF MEXICO

Jennifer E. Smith
Houston

• The downward trend in the price of the benchmark WTI crude oil over the last year is reflected, albeit imperfectly, in the percentage of rig utilization in the US Gulf of Mexico. Utilization has not fallen as sharply as might be expected because of the drop in dayrates, among factors. Several companies increased drilling plans to take advantage of low rig rates. Also, long-term contracts have contributed to stability. Despite this, however, overall utilization in the US Gulf has fallen from 94% to 73% in the past 12 months. Source: Oceandril Data Services, Houston. [11,033 bytes]

2nd royalty-in-kind gas pilot underway

The US Minerals Management Service (MMS) and the State of Texas General Land Office announced a joint royalty-in-kind (RIK) pilot project for natural gas in the Gulf of Mexico. The project is one of three RIK pilots the MMS is pursuing to test the effectiveness of taking royalty-in-kind as an alternative to cash payments. The other two are an onshore project in Wyoming and an offshore Gulf of Mexico project.

MMS and the General Land Office will jointly take and sell gas taken from federal leases in the 8(g) zone. Texas' jurisdiction extends out into the Gulf of Mexico 10.35 miles. A three-mile-wide band extending from Texas' jurisdiction in the Gulf is known as the 8(g) zone. In this pilot, Texas will continue to receive 27% of the revenues.

The purpose of the project is to test whether taking gas in-kind will increase the royalty revenues of the Federal Government and the State of Texas. A primary focus of the joint project will be to supply natural gas to Federal and State governmental facilities while providing utility savings for government agencies. The General Land Office has successfully managed such a program for some time on behalf of Texas agencies.

Power for deepwater: multiply by two

Speaking at the Electrical Power for Drilling industry gathering, Jon C. Coles, Senior Vice-President of Transocean Offshore, said that although in general offshore development costs have been dramatically reduced by replacing traditional platforms with minimal or subsea facilities, the beckoning deepwater market will require ever more power.

Despite short-term bobbles, demand for oil will very likely continue increasing regularly, and deepwater probably contains most of what oil remains. But drilling equipment for deep water uses more electricity, requiring larger drawworks, more powerful top drives, powered mouseholes, automated pipe handling, and larger capacity riser tensioners, for instance.

And on rigs like the Discoverer Seven Seas, dual-activity drilling capability requires power for everything above multiplied by two. That doesn't even count the increased electrical requirements for drilling fluids systems, subsea systems, or vessel systems like mooring or dynamic positioning. These electrical requirements will demand more installed generating capacity, more generators and transformers, and more cable and cable trays, fittings, etc.

Coles concluded by saying that the aging drilling fleet will need upgrading and replacement over the next decade, and these upgraded or new rigs will require significantly more electrical/electronic gear than their predecessors. However, the increased efficiency of these new rigs may require fewer rigs overall, he said.

E & P BRIEFS:

• Seneca Energy said the Vermilion 309 No. A-4 well logged 145 net ft of gas in one sand and the No. A-6 well logged 179 net ft of gas in six zones. This brings the total number of wells completed on the block to six. Production is expected to begin this month at a total rate of 60 MMcf/d. Also, the Eugene Island 47 No. 15 well was drilled to MD of 9,384 ft and encountered 40 ft of pay in two zones. Seneca holds 100% in both these prospects. It also said it participated with 41.25% working interest in the Titan Offshore-operated Vermilion 252 No. F-4 well, which was drilled to MD of 9,975 ft and logged net pay of 28 ft in two sands. Seneca also participated with 25% in the Walter Oil & Gas-operated Galveston 239 No. 4 well, which was drilled to MD of 9,942 ft and logged 80 net ft of gas in four sands.
• The subsalt Hickory No. 1 well, located on Grand Isle South Addition 116 in 320 ft of water, found some 300 ft of hydrocarbon pay in multiple sands. A 7-3/4-in. production liner is being run to the total depth of 21,600 ft. Partners in the Hickory prospect have contracted the Baltic I jackup to immediately begin drilling a field delineation well from the same surface location to develop proved reserves and explore for other pay options. Anadarko is beginning design work on a production platform; first production is expected in 2000. The well penetrated a salt section of approximately 8,000 ft, which Anadarko says it believes is the thickest section of salt ever drilled in the Gulf of Mexico. Anadarko operates Grand Isle 110, 111, and 116 with 50% working interest; Shell Oil holds 37.5%; and Ocean Energy holds 12.5%.
• Chieftain said a platform will be installed on East Cameron 34 in the fourth quarter to commence production. Also, two production platforms will be installed on South Marsh Island 39, where production from two wells should begin around year's end and a multi-well drilling program should follow. Follow-up drilling is also planned for Eugene Island 189 this quarter.
• Murphy Oil said wells are drilling at East Cameron 38, Vermilion 335, Viosca Knoll 827, and Matagorda Island 565, and upcoming wells scheduled for this month include Habanero on Garden Banks 341 and Wadden Zee on Garden Banks 168. Drilling on the Sidewinder prospect on Ewing Bank 995 should begin in first quarter 1999.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.