Davy Jones: A new era for GoM shelf exploration?

Zoe Sutherland - Wood Mackenzie

Davy Jones is in shallow waters offshore Louisiana and is one of the deepest wells ever drilled below the mudline in the Gulf of Mexico. The discovery is famous for verifying the ultra-deep gas play by providing the most encouraging evidence to date that the prolific Wilcox sands, found onshore and in deepwater, are present also on the GoM shelf. The well’s operator, McMoRan, indicates recoverable reserves could exceed 1 tcf of gas, which would make this the biggest gas discovery on the shelf in decades. In a mature region with declining production, the prospect that vast reserves could be accessed by drilling deeper has caused a great deal of industry excitement.

Although the Davy Jones results appear promising, exploration of the ultra-deep play remains in its infancy. Only a handful of the many wells drilled on the shelf can be classed as true ultra-deep wells, which by definition must penetrate the salt weld at depths around 6,096 m (20,000 ft).

With so little information, estimates of reserve size and well productivity remain speculative. Ultra-deep reservoirs are characterized by extreme high pressures and temperatures, making the wells challenging and costly to drill. Assuming a base case reserve size of 1 tcf of gas, lowering the recovery per well from 100 bcf to 50 bcf results in an increase in the breakeven gas price from $4.20/mcf to $7.90/Mcf.

If ultimate recoverable reserves prove smaller or if initial production rates are less than the 100 MMcf/d proposed by the operator, the project becomes increasingly marginal under current North American gas prices. With ultra-deep drilling costs rivaling those in the deepwater, highly prolific wells and substantial recoverable reserves will be needed to justify the cost of an ultra-deep gas development.

Furthermore, the growth of unconventional gas plays onshore is creating an increasingly competitive North American gas market. A successful well test will be central to determining whether this new play can be developed economically, and whether the Davy Jones discovery signals a new era for exploration and production in the GoM.

Still in its infancy

The ultra-deep gas play refers to Lower Tertiary reservoirs below the salt weld on the GoM shelf. The handful of ultra-deep exploration wells that have been drilled to date all reached TVDs below 7,620 m (25,000 ft), with the deepest reaching 10,057 m (32,997 ft). Despite the long history of exploration and production in the region, the deeper plays on the GoM shelf remain largely unexplored. Between 1990 and 2007, only 10% of the some 10,000 wells that were spudded had “deep” targets, referring to depths below 4,572 m (15,000 ft). Of these deeper wells, only one drilled in the time frame reached below 7,620 m (25,000 ft).

Prior to 2004, most “ultra-deep” drilling on the shelf targeted relatively conventional Jurassic or Mid-Lower Miocene reservoirs. No wells penetrated the pre-Miocene section below the salt weld.

A turning point occurred in 2004 when Shell drilled Shark (ST 174 No. 2) to TVD of 7,850 m (25,756 ft). Although not a discovery, the well encountered positive evidence of hydrocarbon shows and reservoir quality at depth. It also led Shell to spud a follow-up well, Joseph (HI 10 No. 1), which reached a TVD of 7,788 m (25,552 ft) in June 2005. Again, the well did not find commercial hydrocarbons, but it did stand as an example of a well successfully drilled and evaluated, despite bottom hole temperatures in excess of 450 ºF (232 ºC) and pressure of 25,000 psi. Blackbeard West, spudded in February 2005, was one of the most closely watched wells that year. Drilled by a consortium made up of ExxonMobil, Petrobras, Dominion, BHP, and Newfield, it had a target TD of 9,754 m (32,000 ft). However, the extremely high temperatures and pressures proved too much, and the well was halted at 9,164 m (30,067 ft), just short of its primary target.

The disappointment cast a shadow of doubt over the feasibility of the ultra-deep play, and a lull in ultra-deep drilling followed, with many of the proponents choosing to focus exploration programs elsewhere.

McMoRan seized this opportunity to position itself as the new leader of ultra-deep gas exploration. In August 2007, it acquired Newfield’s shelf portfolio, which included interests in the Blackbeard West well and a number of other, ultra-deep prospects. It re-entered Blackbeard West in March 2008, with partners Energy XXI, Plains E&P, and Eni.

The well was deepened to 10,057 m (32,997 ft), encountering four potential hydrocarbon-bearing zones below 9,167 m (30,067 ft). Although the sands were thin, results were encouraging. In July 2009, McMoRan spudded another ultra-deep well, Davy Jones, again choosing to deepen an existing exploration well.

Davy Jones reached a measured depth of 8,615 m (28,263 ft) in January 2010 and provided the most promising results to date. Wireline logs indicated a total of 40 m (135 ft) of net hydrocarbon-bearing sands in four zones in the Wilcox section of the Eocene/Paleocene. A later announcement brought the total net pay encountered to 61 m (200 ft), heralding the discovery of a new and potentially significant play.

Will be challenging

The Davy Jones well has transformed our understanding of geology on the GoM shelf, but it is likely to be some time before commercial production from the play. The reservoirs are characterized by extremes of temperature and pressure (>450 ºF and >25 kpsi) and it is worth noting that the technology required to produce at these temperatures and pressures does not yet exist. The operator estimates a lead time of up to two years to acquire the necessary equipment, but it could take longer.

For comparison, the average lag between discovery and development consent of a Lower Tertiary field in the deepwater GoM is almost four years. In this environment, development takes another four years, bringing the total time from discovery to first production to eight years. As the ultra-deep shelf is an equally challenging frontier play, it seems reasonable to assume the time required for appraisal would be similar, lasting at least a number of years.

Development time could be shortened because the shelf is close to existing infrastructure. However, the cost of drilling deep, HT/HP wells means these projects will be capital intensive despite their proximity to shore. The interest holders in both Davy Jones and Blackbeard are predominantly smaller independents that will find it a challenge to maintain the cash flow required for these investments. Raising finance, particularly in the current economic climate, is a key risk that could delay both the appraisal and development stage of these ultra-deep projects.

High well cost

As investment in infrastructure will be minimal, development drilling is likely to account for the lion’s share of costs. The wells will be some of the deepest and most technically challenging in the Gulf, taking an average of eight months to drill and complete for production. Consequently, the number of wells required for an ultra-deep development, and the prevailing rig rates at the time of development, will be key factors to determine profitability.

With so few wells drilled, and no production from the play, much uncertainty surrounds how ultra-deep reservoirs will perform and, ultimately, how much gas will be recovered. Until a production test is conducted and further appraisal is carried out, estimates of reserves and reservoir performance are speculative.

In light of this uncertainty, Wood Mackenzie has modeled a number of scenarios for an ultra-deep shelf development. First is a base-case scenario, with recovery expectations in line with announcements made by the operator. We then looked at the effect of varying recoverable reserves, initial production (IP) rate, well recovery, and lead times on the remaining post-tax net present value (NPV), and the internal rate of return (IRR) of the project.

The base case is an ultra-deep discovery with 1 tcf of recoverable gas reserves and a start-up date in mid-2013. Wells are assumed to recover an average of 100 bcf each and initial production rates are assumed to be 100 MMcf/d.

Under these base-case well recovery and IP rate assumptions, an ultra-deep project will remain profitable, even with a 50% reduction in recoverable reserves. However, changes in well recovery had a more dramatic effect. A 25% drop in well recovery resulted in a 60% fall in the NPV at 10%, while a 50% drop gave a negative NPV, indicating a breakeven well recovery in the region of 60 to 75 bcf per well. Unsurprisingly, small changes in the IP rate of the wells had a dramatic effect on the IRR of the project, with a 50% reduction causing the IRR to drop from 37% to 23%. Lead time, however, had a minimal effect on the post tax NPV and the IRR.

North American gas prices

Our base-case scenario breaks even at $4.20/Mcf, suggesting favorable economics should the play deliver high-performance wells. Again, variations in well recovery had a dramatic effect, with a 50% drop pushing the breakeven price from $4.20/mcf to over $7.90/Mcf. Wood Mackenzie’s North American Gas team forecasts a permanent recovery in Henry Hub prices to above $6.00 per million British thermal units (MMbtu) real from 2012. Under this outlook, a recovery factor per well in excess of 75 bcf would deliver returns exceeding 10%. However, the project remains highly sensitive to gas prices, and any downturn could threaten project viability, particularly if the wells prove to be less prolific than initial estimates.

Ultra-deep drilling

Most operators on the shelf have been content to adopt a “wait and see” approach to ultra-deep exploration. At the time of writing, two new ultra-deep exploration wells were under way, both operated by the play’s main advocate, McMoRan. It remains to be seen whether the success at Davy Jones will encourage other players to target this frontier play. Rig availability could be a constraint to future exploration levels.

Only 5% of the worldwide jackup fleet can drill to 10,668 m (35,000 ft), and even fewer of these rigs have the mud pump and hook-load capacities to drill the deep and difficult wells required. However, newbuild trends are shifting toward more premium jackup rigs with higher design criteria.

Rowan Co.s, owner of the rigs used to drill both Blackbeard West and Davy Jones, has the lead position in supplying the premium jackup rigs needed to successfully operate in these HT/HP environments. During 2010 and 2011, Rowan will complete construction on theJoe Douglas and three Rowan EXL jackup rigs, all capable of ultra-deep drilling. It also recently announced plans to go ahead with the construction of a fourth EXL rig that was previously suspended.

These newbuilds are an encouraging sign for continued ultra-deep exploration. In addition, an increased supply of premium rigs available to GoM shelf operators should contribute to keeping rig rates reasonable, which is key to unlocking the potential in this new play.