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In 2002, few believed that Lower Tertiary sands would be present, let alone productive. Today these defiant sands are reshaping the industry’s appraisal of plays in the Gulf of Mexico (GOM). Back in 2002, supermajor Chevron and independent Devon formed a joint venture to explore and exploit the deep Wilcox formation. According to both, new and emerging technology has been and continues to be the differentiator in both the exploration and exploitation efforts in these deep structural targets and has the potential to create a shock wave on financial portfolios.

The Jack-2 well test took place in the second quarter of 2006 at Walker Ridge Block 758 in 7,000 ft of water, and more than 20,000 ft under the seafloor, breaking Chevron’s 2004 Tahiti well-test record as the deepest successful well test in the GOM. Chevron, Devon, and Statoil announced that it was a record-setting production test, with the test representing approximately 40% of the total net pay measured in the Jack-2 well.

National Geographic recently gave an apt description of industry achievement in the Lower Tertiary trend: “…you’re looking at where in the GOM to drill an 80- to 100-million-dollar well that will ultimately be the size of a dinner plate [on the seafloor].” And, according to analysts, it equates to spending U.S. $100 million to drill and construct a well in mile-deep water to as deep as 5.3 miles below sea level beneath a salt canopy.

Fig. 1—Devon’s position in the GOM deepwater exploration trends.

The recent, well-publicized Jack-2 well test is actually the latest of several successes in the play. The Great White and Trident finds by Chevron, located in Alaminos Canyon, were the first, and it is speculated that this trend could extend into the Garden Banks and Green Canyon blocks. “This is truly frontier exploration … pushing boundaries,” said Gero Farrugio, Wood Mackenzie Upstream Research Manager for Latin America, the U.S. GOM, and Canada. Other prospects already on record in the GOM Lower Tertiary trend include Cascade in 2002, St. Malo in 2003, the first Jack find in 2004, and Kaskida in 2006. The Jack prospect is located far from any existing platform and pipeline infrastructure.

Farrugio points out that while “the Jack-2 test is the first indicator, it is far from proving commerciality of the play.” The technology that is being brought to bear to realize the potential of the Lower Tertiary trend is the ingredient that has the potential to bring understanding of this play needed for the creation of infrastructure and ultimately to prove commercial viability. Drilling commenced on the Jack-2 well under 7,000 ft of water and continued to a depth of 28,175 ft. At this depth, pressures can reach 20,000 psi and the temperature of the oil is approximately 200°C.

The testing performed on the Jack-2 garnered multiple headlines because it is the only extended well test to date in the Lower Tertiary trend. The other significant result of this test is that it establishes that commercial production is now possible from such a deep trend. During the test, the Jack-2 well posted a steady flow rate of 6,000 BOPD.

“Variable permeability of the play can have significant consequences,” said Farrugio. “Any attempt to put a figure on the production forecast at this point would be pure speculation.”

There is also an interesting dynamic at work in the trend; not only are major operators and independents aligned and seeing the trend from a dual perspective, but many of the leases housing the Lower Tertiary sands will soon expire and will be included in bidding rounds. Such a turnover will influence the level of exploration activity in the trend.

“Chevron continues to demonstrate its leading position employing deepwater exploration technology to develop new supplies of U.S. crude oil and natural gas with projects such as Jack,” said George Kirkland, Chevron Executive Vice President Upstream and Gas. “Our strategic position in the deepwater GOM will continue to be a platform for future growth for years to come.” The largest deepwater leaseholder in the GOM, Chevron’s proven track record includes the ultradeepwater Perdido fold belt in 2002; some of the deepwater finds include Great White, Silver Tip, Tabago, and Tahiti.

“We made a commitment to this play back in 2001,” said Tony Vaughn, Devon Vice President and General Manager–Gulf of Mexico. “Cascade, St. Malo, Jack, and Kaskida are all very material to Devon. We have the second largest exposure of any player in the GOM to the Lower Tertiary trend. High-impact plays such as these are a great balance for our portfolio, which includes North American repeatable projects such as the Barnett Shale, east Texas, and Rocky Mountains. The GOM, a politically friendly environment, offers deepwater projects as large as those existing in other parts of the world.… Success of the Lower Tertiary play will be material to the energy industry in the GOM.”

Fig. 2—The overall thickness of Lower Tertiary subsalt plays can be as much as 10,000 ft. These drawings are representative of how hydrocarbons can become trapped beneath salt structures and are not to scale.

Complexity of the Play

The Tertiary trend in the GOM was formed in the early part of the Tertiary Period from 66 million years ago to 38 million years ago. The two oldest epochs are the Eocene (54 to 38 million years ago) and the Paleocene (66 to 54 million years ago). The Lower Tertiary trend, located 175 miles offshore, is approximately 80 miles wide and 300 miles long. Trend water depths range from 5,000 to 10,000 ft. Target formation depths range from 10,000 to 30,000 ft subsea. The target Lower Wilcox section comprises sheet to amalgamated-sheet sands and has been interpreted to be a regionally extensive basin-floor fan system.

According to the Minerals Management Service, 12 discoveries have been made in the Lower Tertiary since 2001.

Imaging, drilling, completion, and test success on the Jack-2 well illuminates technologies being brought to bear with a successful result. Operator Chevron (with a 50% working interest), Devon, and Statoil (each with a 25% working interest) are putting a lot on the line. Chevron is the largest lease holder in the deepwater GOM and currently is developing the Tahiti project located in Green Canyon. Devon has taken a high-stakes-position in the deepwater GOM with about 500 blocks under lease and about 35 exploratory prospects already identified. And they are not alone; Shell and BP also are actively exploring in the deepwater GOM.

“No doubt the Jack well will be a billion-dollar-plus project,” said Chevron spokesman Mickey Driver. More than half a dozen records for test-equipment pressure, depth, and duration in deep water were set during the Jack-2 well test, including perforating guns being fired at world-record depths and pressures (proprietary information for Chevron). Jack-2 was the deepest extended drillstem test in deepwater-GOM history. Modeling has begun for the production facility.

According to Driver, technology to be used in the Lower Tertiary is similar to the type of technology the industry has been using for exploration and completion, but with extended capability. “The technology is like comparing a Cessna 152 (minimalist) to a 747 jet (more robust). While there are commonalities, one can fly higher and further using extended capabilities…. The basics are the same, but we have to do it deeper and at higher pressure. This is the first use of equipment in this type of environment…. The increase in our abilities and robustness of seismic have made a significant difference. Today seismic-data systems are so powerful, data and advances in interpretation are at the forefront of successes in this trend.”

The challenges to seismic depth migration, such as the distortion and dispersion of seismic energy, caused by the presence of complex salt bodies are not new. But new acquisition techniques, processing algorithms, and the use of 3D volume interpretation for a rapid assessment of prospectivity have facilitated clearer imaging from seismic depth migration.

Fig. 3—A number of the GOM Lower Tertiary deepwater plays are subsalt. Illuminating this shallow salt cover through seismic data and depth migration is challenging because the seismic energy becomes distorted and disperses around complex salt bodies. The challenges extend to imaging, planning, and drilling.

Illuminating Subsalt Structures

While not used on the Jack prospect, wide-azimuth towed-streamer data is one technology that is enabling high-impact plays in the Lower Tertiary to be realized. Salt has long been the nemesis of geologists because its presence distorts and disperses seismic energy, creating a challenge to depth migration as a result of increasing seismic multiples. “New seismic techniques have allowed large structures under the salt canopy to be better imaged; we are now able to use more data in a more efficient and commercial manner than in the past,” said Vaughn. “Improved imaging is one of the best risk-reducers we have moving into this type of play. There is a need to better define the geometry, size, and depth of the structures being explored.”

Wide-azimuth towed-streamer-type data is one of the newer developments in seismic acquisition and represents a step increase in the data needed to eliminate noise from the salt and other events and to ultimately better define subsalt structures through accurate velocities. Having an understanding of the geometry, size, and shape of the salt is critical to understand what the rock velocities are subsalt. Wide-azimuth data acquisition consists of several narrow-azimuth surveys acquired over the same prospect and requires one or more streamer vessels and two or more source vessels.

The much greater understanding gained from 3D volume visualization and interpretation techniques—shape and structures of the salt and whether or not it is trapping—is crucial to success in the Lower Tertiary, where it can take 3 to 4 months to drill each well at long-term rates already approaching $500,000 per day. The strength of volume-interpretation software in this application is the ability to animate and manipulate data in such a way as to distinguish noise from signal and artifacts from geologic events, and to identify residual multiples.

Better imaging leads to better well planning and cost control. Knowledge of where to set casing, which results in getting wells to total depth trouble-free, is at a premium. According to Vaughn, the ability to image the salt and subsalt strata is of great interest to the industry.

Fig. 4—The Cajun Express rig used for the Jack-2 well production test. (Photo courtesy of Chevron.)

Drilling Beneath Salt

Just beneath the Lower Tertiary salt canopy is a high-pressure zone. Drilling in this environment holds another set of challenges. Traditional rigs are prevented from operating in this environment, where equipment must withstand 20-ft waves and strong currents. Bottomhole pressures encountered thus far have been in the 20,000-psi range, and the oil to be recovered from these zones is high-temperature. Fifth-generation semisubmersible technology, with faster penetration rates, streamlined logistics, extensive mechanization, and parallel tubular-handling operations, is among the technological advances enabling the proliferation of industry activity in the trend. Devon has contracted two such rig builds, the Ocean Endeavor and West Sirius. These rigs are qualified for water depths of 10,000 ft and for drilling depths of 35,000 ft and 37,500 ft, respectively. Multidisciplinary well planning is proving advantageous.

Fig. 5—The second semisubmersible rig, the West Sirius, contracted by Devon for work in the GOM Lower Tertiary trend.

Chevron has awarded drilling contracts to TransOcean to construct two new drillships to be dedicated exclusively to Chevron for 5 years. “The design of the new drillships will include the most advanced drilling capabilities in the offshore drilling industry,” said Kirkland. The Discoverer Clear Leader and another Enterprise-class dynamically-positioned, double-hull drillship will feature a patented dual-activity drilling technology process that uses two drilling systems in a single derrick, allowing for parallel drilling operations designed to save time and money in deepwater well construction. Dual-activity drilling technology has the unique capability to conduct drilling operations simultaneously, rather than sequentially in series. Two full-capability, full-capacity drilling stations (two separate drilling rigs) carry out parallel operations under a single, massive derrick. Two full-sized rotary tables are designed into a drill floor more than twice as large as a conventional one. In addition, the top drive (hoisting structure) will be larger, stronger, and more efficient than existing top drives; there also will be an expanded high-pressure mud-pump system, expanded completions capabilities to handle wells up to 40,000-ft total depth and water depths to 12,000 ft.

The next 5 years, according to Vaughn, will bring subsea technologies to the industry specific to high-pressure environments—subsea pumps, separators, and artificial lift to enhance flow capability and infrastructure development. Advancing technologies will continue to improve the efficiency and profitability of the play.

The Jack test provided valuable information, with the actual test results being a good match to pretest expectations. This well test provided critical information to understanding the production capacity of typical Lower Tertiary rock, and the results gave Devon confidence in the commerciality of the play. “Finding large amounts of oil in place doesn’t add value unless you can produce it in a timely way and in commercial quantities,” said Vaughn. “We are aggressively pushing the Cascade prospect to production in 2009.” It is anticipated that typical Lower Tertiary Trend projects will come on production in 5 to 7 years.

Fig. 6—New seismic techniques are enabling clearer imaging of subsalt structures, a crucial step toward solving E&P challenges in the Lower Tertiary trend.

“With two deepwater rigs now under contract, we now have the ability to execute a delineation/development program in addition to our exploration program and aggressively move projects to first production,” said Vaughn. “Typical developments may take up to 10 to 25 wells and may have total development costs in the $2 to 4 billion range. A multidisciplinary team from the companies participating in the discoveries are jointly modeling each of the projects to determine the optimum development plan unique to each discovery.”

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