Deep Shelf Drilling

GOM Deep Shelf activity drills to Miocene targets

Ultradeep Shelf estimates compare favorably with other world plays.

Ian Ashcroft, Wood Mackenzie; Victor Schmidt, Drilling Engineering Editor

The US Gulf of Mexico Continental Shelf (GOM) continues to be one of the most active and prolific oil patches available the oil and gas industry. It is a mature area with established oil and gas fields, the world’s most complete offshore infrastructure and a history of continuous exploration and development. It is where the oil and gas industry presses the envelope of possibilities and probes the limits of drilling technology.

That quest continues today to locate, drill and test the deeper reaches of the GOM. Bolstered by incentives from the US Department of Interior’s Minerals Management Service (MMS), well tests in the GOM Shelf below the 15,000 ft mark are increasing in number and have moved the technology boundary deeper. Now a new frontier is before the industry, a pre-Miocene rock sequence (Fig. 1) under the Shelf that is productive onshore and has tested oil and gas in the deep water, in the outer-most limits of the US Continental shelf. This Ultradeep Shelf drilling target is essentially untested below the regional decollement and salt weld that can vary from 18,000 ft to 28,000 ft below the mudline. According to Wood Mackenzie, the Ultradeep Shelf has the potential to be a new world-class play.

Fig. 1. The Ultradeep GOM Shelf lies below the regional decollement and salt weld 20-30,000 ft below the mudline.

POTENTIAL

Fig. 2. The Ultradeep Shelf is economically favorable when compared to other international areas.

Fig. 3. Only 6% of the ~13,000 Deep Shelf exploration wells penetrate below 15,000 ft.

Ultradeep prospect sizes range from 0.5 – 4.0 Tcfe in recoverable reserves with the average resource likely to be 1.0 Tcfe, Fig. 2. This can be up to an order of magnitude larger than traditional GOM Shelf plays and is comparable to the top international deepwater plays, Fig. 2. Due to the region’s established infrastructure, the economic threshold is lower than most international plays. Some mapped prospects have potential reserves of up to 8 Tcfe. Large potential reserves like this are material for the super-majors and can be “company makers” for the smaller independent companies that dominate the shelf.

ULTRADEEP DRILLING

The challenges of drilling into the higher pressures and temperatures below 18,000 ft have kept the Deep Shelf and Ultradeep Shelf from being widely drilled. Less than 6% (~780 wells) of the GOM wells have been drilled below 15,000 ft, Fig. 3.

Pressures for ultra-deep tests are expected to reach 30,000 psi with temperatures above 400°F. Drilling in theses conditions is at the edge of present technology. Evaluating reservoirs at those conditions is problematic because the sensors fail at the high temperatures. Producing from reservoirs with these conditions is not yet possible.

PLAYERS

Positioning for this new frontier began with the first MMS Royalty Relief program in 2001, which opened the Shelf to new exploration by encouraging the industry to accept the challenge of deeper shelf drilling. Now both primary and held-by-production (HBP) leases are open to the royalty relief incentive. This places Apache, Chevron, Forest and Devon in good position because of their existing leasehold. In addition, these companies have added to their holdings with new primary term leases.

The GOM Shelf is generally independent company territory since most of the majors, with the exception of Chevron’s properties, sold their shelf properties in the middle-late 1990s to enter the GOM Deepwater play. However, the major oil companies are not out of the running, but are taking-up the ultra-deep drilling challenge. BP, ExxonMobil, Shell and BHP Billiton have purchased primary term leases on the shelf and have initiated Ultradeep Shelf drilling programs. Since most of the shelf leasehold is controlled by the independents, the majors are working with the independents to test deeper targets. In particular, Newfield Exploration has been vary successful at promoting its “Treasure Island” and “Treasure Bay” ultra-deep shelf concept areas, as evidenced by the spud of the ExxonMobil-operated Blackbeard West wildcat earlier this year.

ACTIVITY

The majors and some independents are drilling deep wells, Fig. 4, and testing new concepts, but so far they have found little production. This is normal in any opening trend. The deeper rock formations must be cut and analyzed, drilling issues must be overcome, and play concepts must be proven to warrant full-scale investment in a new trend.

Fig. 4. Several new wells will test the Ultradeep Shelf this year.

Shell, in partnership with Nexen, drilled one of the first of the ultradeep wells last year. The Shark well in South Timbalier 174-2 penetrated to 25,756 ft, but failed to penetrate the pre-Miocene section. Shell and Nexen had earlier drilled the Fergana well in South Timbalier 239-1, but found no commercial reserves. However, the well did set a record for the tallest self-standing conductor.

Shell’s most recent attempt may have penetrated the pre-Miocene section. Partnered by Devon, Total and BHP Billiton, its Joseph well at High Island 10-1 was temporarily plugged and abandoned at the end of June this year. The results remain tight.

ExxonMobil’s Blackbeard West, South Timbalier block 160-1, began drilling in February and is still drilling ahead toward a target depth of 32,000 ft and possibly deeper. The well may take another six months to complete. ExxonMobil has plans for up to four more Ultradeep Shelf wells in the vicinity.

UNKNOWNS

The Ultradeep Shelf holds some critical unknowns. Reservoir quality, continuity and aquifer support are all unknown. If Deep Shelf reservoirs are used as analogs, individual well recoveries could range from 10 – 50 Bcfe. The maximum recovery to date is from Shell’s Alex Deep at around 150 Bcfe (100 MMcfd). Most Deep Shelf wells return 5 – 20 MMcfd.

Technology issues will delay and constrain Ultradeep Shelf development by 2 – 4 years. This pushes the first production estimates out to 2008. Drilling will take 6 – 12 months with 2 – 4 months needed for completions.

Production from such depths will likely have high proportions of CO₂ and H₂S as well as other gases. Dealing with these gases will drive up the facilities’ cost and may require new safety measures because of the higher pressures and temperatures.

All of these unknowns will affect project economics and could lead to significant cost overruns.

PROFITABILITY

Even with all the unknowns Wood Mackenzie estimates that the Ultradeep Shelf could become a new profitable region. Using a base case of a 1 Tcf discovery, The analysis yields a profit to investment ratio of 3.2, a rate of return of 44%, and a net present value of $860 million, discounted at 10%. Payout would occur in five and a half months with at breakeven gas price of $1.40/Mcf, Fig. 5.

Fig. 5. The Ultradeep Shelf has a profitable future using modest economic assumptions.

Present prices are three or more times the breakeven gas price, making the economics attractive on an unrisked basis. The overriding issue for the play is the probability of success in terms of geology and the technical challenges of drilling such wells. On a fully risked basis, Wood Mackenzie’s analysis suggests that the play requires a probability of success of 9% or greater to provide an adequate return.

LEASES

Interior Secretary Gale Norton announced new incentives for natural gas development in hard-to-reach areas of the Gulf of Mexico earlier this year. The royalty relief incentives encourage industry to explore and develop deep gas accumulations in water depths less than 656 ft, and 15,000 ft below the shelf and provide:

• A royalty suspension on the first 15 Bcf produced from depths greater than 15,000 ft and less than 18,000 ft or on the first 25 Bcf produced from 18,000 ft or deeper. A royalty suspension volume of 15 Bcf can be increased to 25 Bcf from a second successful well to 18,000 ft or deeper. Gas production from all qualified wells on a lease participates in the full royalty suspension volume earned by the lease.
• A royalty suspension supplement of 5 Bcf (equivalent), applied to future lease production of gas and oil from any depth, for drilling a qualifying dry hole (unsuccessful well) at 18,000 ft or deeper. Two royalty suspension supplements are available per lease prior to production from a deep well. The maximum relief the lease can earn from drilling unsuccessful and successful deep wells is 35 Bcf.
• Eligibility of sidetrack wells to earn royalty suspensions in amounts based on drilling depth and sidetrack length.
• Price threshold provisions that discontinue royalty relief if gas prices rise too high. An option for qualifying lessees to replace existing deep gas royalty relief lease provisions with the deep gas royalty incentive terms in this final rule.
• Drilling of qualified wells must have started on or after March 26, 2003, and production must begin within 5 years of the effective date of the final rule. However, any royalty suspension volume or supplement earned must be applied only to production occurring after the effective date of the final rule, even if this production actually started between the proposed and final rule.

“With demand for natural gas climbing as more American families and businesses choose this clean-burning fuel, we must provide incentives for development of known resources that are harder to reach,” said Norton. “These incentives will help ensure we have a reliable domestic supply of natural gas in the future.”

Americans use 22 Tcf/y. Farmers are paying more to run irrigation pumps, heat greenhouses and to buy fertilizer made with natural gas. Forty percent of American industry currently depends on natural gas, and about 90% of new electricity plants coming online in the next decade will be natural gas fueled. Some businesses are moving manufacturing overseas, where gas is a fraction of the US price.

The recent GOM Western Area Lease Sale 196 included 3,762 unleased blocks covering almost 20.3 million acres of federal land offshore Texas and in deeper waters offshore Louisiana. The blocks are 5 – 357 km offshore in 8 – 3,100 m water depths.

MMS received 422 bids from 56 companies on 346 tracts. The sale attracted $285,192,865 in high bids totaling $335,628,130.

“We saw the highest dollar amount of high bids for a Western Gulf Sale in seven years,” said Chris Oynes, MMS Gulf of Mexico regional director. “We continued to see strong bidding activity in the Deepwater Gulf particularly in the Alaminos Canyon and Keathley Canyon Areas. This activity is due largely to the encouraging results of rank wildcat drilling activity in the Lower Tertiary Wilcox Trend. It was also noteworthy that there was strong bidding interest in the shallow water area for potential deep gas prospects.”

Oil companies bid on 224 deepwater tracts: 37 are in 400 – 799 m water depths and 101 are in 800 1,599 m water depths. In the two new ultra-deepwater royalty relief categories, 26 tracts in 1,600 – 1,999 m water depths received bids and 60 tracts in than 2,000 m water depths or greater received bids. This new 2,000 meter category was established as a provision of the 2005 Energy Policy Act, signed into law on August 8, 2005.

In ultra-deep water beyond 1,600 meters, about 25 percent of the tracts received bids. Sigsbee Escarpment 288 in 3,278 m water depth was the deepest tract bid upon. LLOG Exploration Offshore, Inc. made the highest bid with $26,500,000 exposed for High Island 156.

The MMS estimates that undiscovered gas resources of up to 55 Tcf may exist in this “frontier” area. The Energy Information Administration forecasts that demand for natural gas will increase by 42% in the United States over the next 20 years. 

This article is derived in part from a Wood Mackenzie presentation given at the 2005 World Oil HPHT/ DeepDrill Conference in Houston, Texas, April 7, 2005.

THE AUTHOR
	Ian L. Ashcroft, principal research consultant-North America has almost 20 years’ industry experience, joining Wood Mackenzie in July 1987 with an MEng in Petroleum Engineering. Over the past six years Ian has been focused solely on the North America upstream, particularly the US Gulf of Mexico.