Vol. 59 No. 6

June 2007

Gulf of Mexico

Technology Drives Deepwater GOM Winning Streak

Joel Parshall, JPT Features Editor

The oil and gas industry appears to be on a winning streak in the deepwater Gulf of Mexico. When major newspapers in New York, Washington, Los Angeles, and other cities run lengthy articles focusing on an extended well test 175 miles offshore Louisiana, as they did last September about Chevron’s Jack-2 well (Walker Ridge Block 758), then something is up. Likewise, something is up when BP discovers, as it did last August, 800 net ft of pay in 5,860 ft of water at Kaskida (Keathley Canyon Block 292). That opened an important new lane in the Lower Tertiary play. As industry consulting firm Wood MacKenzie later reported, 2006 was “an exceptional year for exploration in the deepwater Gulf of Mexico,” with discoveries such as Pony (Green Canyon Block 468) by Hess and Great White West (Alaminos Canyon Block 856) by Total adding to the buzz.

The discovery rate per well drilled in 2006 climbed to more than 40 million barrels of oil equivalent, the consulting firm noted, making it the most successful year since 1999 when BP discovered Thunder Horse. Discussing U.S. production, Cambridge Energy Research Associates labeled the Lower Tertiary play “the most significant oil trend since the discovery of the Prudhoe Bay field in 1968” and said that as much as 800,000 barrels per day—11% of U.S. production—could be flowing from this reservoir in the GOM by 2012–14.

The essential driver of the success so far, and of that possibly just over the horizon, is technology that continually challenges and in so many cases finds ways to overcome steep technical obstacles that once seemed indomitable. Recent advances in seismic-acquisition techniques, for example, have brought step changes in the quality of images obtained from beneath the extensive and often thick salt canopy of the deepwater GOM, areas that not too long ago were simply avoided as virtually impossible imaging targets. Fifth-generation dynamically positioned (DP) rigs being delivered are equipped to lead drillers out to 12,000-ft waters, while synthetic mooring lines are enabling floating production facilities to cross the 8,000-ft threshold and look beyond to where the new rigs will go and the next producing floaters will follow. Innovative real-time monitoring tools are guiding drillers down some of the longest, costliest, and riskiest wellbores with the narrowest pressure-gradient windows for reaching their targets safely. And expandable pipe is enabling these drillers to meet high-risk downhole contingencies with flexible, optimized casing programs.

What follows is a look at those and other technologies, with perspectives from the people who work with them and in some cases helped develop them.

New Seismic-Acquisition Techniques

Surely one of the biggest technical challenges posed by the deepwater GOM is the difficulty of obtaining clear seismic images from beneath the salt canopy that extends across much of the region’s subsurface and is as thick as 15,000 ft in some places. Years ago, the industry essentially ignored seismic acquisition beneath significant salt layers because of the data distortions they caused and the resulting poor images. Industry strategy in the Gulf began to change as the frontier for large discoveries shifted to deep water. As long as the areas surveyed were not under salt, the industry’s continuing use of 3D time-migration algorithms worked reasonably well. However, the encounter with salt became inevitable and pushed the industry into the use of depth migration. This led to some improvement in imaging, but data continued to be plagued by noise from multiples that masked true seismic signals and troublesome illumination gaps in the final images. The industry looked for new answers, and one company that played a leading role in finding an answer was BP.

“About 8 years ago, BP embarked on an effort to go after novel acquisition techniques to try to solve some of the issues at hand, mainly around subsalt and initially in the Gulf of Mexico, the deepwater Gulf of Mexico, and the Nile Delta,” said Scott Michell, Advanced Seismic Imaging Program Manager in BP’s Exploration/Production Technology Group. “We had been working on reprocessing data—standard narrow-azimuth data—obtained at assets like Mad Dog and Atlantis. The industry for a long time had been after better algorithms; it was always ‘get a better algorithm, a better velocity model, and that will solve the imaging problem.’ And we reached a point somewhere in that time frame where we realized that just a better algorithm or velocity model wasn’t going to give us development-quality seismic data.”

What emerged from this effort were two novel concepts for the acquisition of seismic data. In the deepwater GOM, a wide-azimuth towed-streamer (WATS) acquisition method, the first of its kind, was tested successfully at the Mad Dog field from November 2004 through April 2005. The WATS method employs at least two source boats and a recording vessel, instead of one recording vessel with a source, to shoot a wide range of azimuths and offsets. Meanwhile during fall 2004, BP successfully tested a multiazimuth (MAZ) towed-streamer acquisition method at Raven, below a partially eroded and interbedded anhydrite structure in the Nile Delta. In this method, a single recording vessel shoots several standard, conventional, narrow-azimuth surveys in different directions. This survey overall was shot in six directions. Fig. 1 shows the acquisition geometries used in the WATS survey at Mad Dog and the MAZ survey at Raven.

Fig. 1—The WATS acquisition geometry (left) that BP used in its deepwater GOM Mad Dog field survey, conducted by two source boats and a recording vessel. By comparison, the MAZ acquisition geometry (right) that the company used in its Nile Delta Raven field survey employed one recording vessel, which shot narrow-azimuth surveys in six directions. (Images courtesy of BP.)

In fall through spring of 2005–06, BP worked a variant on its previously used wide-azimuth acquisition method, this time surveying a much smaller grid at the deepwater Atlantis field in the GOM. Instead of surface streamers, the receivers were nodes placed on the ocean bottom by remotely operated vehicles. It marked the deepest, most-extensive deployment of nodes to that date. All three of these acquisition techniques were discussed by BP in two papers at the Offshore Technology Conference (OTC) in Houston last month.

These different acquisition geometries represent different tools for different situations. “With WATS, we recognized that surface tows have advantages in that you can cover large areas quickly,” Michell said. “But if you only need a small area, especially with surface obstructions, WATS can be really expensive, and so a nodal survey can do a more-targeted acquisition. In Egypt, the business problems are different, as is the availability of vessels. There are also different geologies, comparing the massive salt bodies of the Gulf of Mexico with the thinner anhydrites of the Nile Delta.”

BP has now conducted a second development WATS survey, is acquiring a third, and has now underwritten a large, multicompany exploration WATS survey—all in the GOM. Numerous companies by now are using wide-azimuth methods, with a variety of vessel configurations and shooting schemes, in the deepwater Gulf. Shell, contracting with WesternGeco, acquired a wide-azimuth survey at the Fresian prospect, site of a 2006 deepwater discovery on Green Canyon Block 599. The companies presented a paper on the survey at this year’s OTC. On a much larger scale, Shell recently underwrote a mutliclient, wide-azimuth survey, conducted by WesternGeco, of more than 450 blocks in the deepwater GOM. Chevron is currently doing a development wide-azimuth survey at the Jack discovery, site of last year’s deepest successful well test ever in the GOM. Fig. 2 shows examples of seismic data obtained by narrow-azimuth and WATS survey methods (Michell et al. 2007).

Fig. 2—The clearer seismic imaging obtained by the WATS survey method (right) is evident compared with imaging of the same structure acquired by conventional, narrow-azimuth surveying (left). (Images courtesy of BP.)

“If a standard 3D-seismic survey was sampling the same point in the subsurface 40 to 60 times, with the WATS approach, you’re doing it up to 150 to 300 times,” said James Cearley, General Manager, Exploration, Deepwater Exploration/Production, Chevron. “This big footprint and greater redundancy allow you to stack those multiples out so they really don’t contaminate your subsurface image. Some of the brute migrations that we’ve seen with WATS, using unrefined velocity models, are much better than our best efforts in the past, when we’ve spent 5 years fine-tuning our velocity model and working multiple suppression as hard as we could. Additional processing and velocity work will improve these images even more.”

While a wide-azimuth survey may cost anywhere from 3 to 6 times more than a conventional 3D survey, the higher sampling level and improved image quality from the subsalt have more than justified the expense for users.

At the deepwater Shenzi field (Green Canyon Blocks 609, 610, 653, and 654), BHP Billiton and WesternGeco are using a variation called rich-azimuth acquisition that deploys a wide-azimuth configuration to shoot multiple directions in an overlapping pattern—in this case, three azimuths totaling six directions.

“You’re collecting a lot more data and getting to see it from many different angles,” said Jerry Kapoor, Advanced Imaging Manager, North America, WesternGeco. “Depending upon the salt, you may get no illumination from one direction but get it from another.”

Enhancing the Rig Fleet

As drilling moves into the deeper waters of the GOM, innovative technologies and new rigs are enhancing the ability of the rig fleet to meet the demand. Fifth-generation DP drillships and semisubmersibles are enabling the industry to push out toward 10,000-ft water depths and look beyond them. With their bigger hookloads, pumping capacities, and DP systems, the newest of these rigs on order will be able to operate in 12,000 ft of water, with some capable of drilling 40,000 ft wells from water surface to total depth (TD). Dual-activity systems enable two drilling operations to take place simultaneously rather than sequentially, meaning major savings of time and money where spread rates for rigs may run as high as USD 700,000 per day. Fig. 3 shows the design of an ultradeepwater DP semisubmersible rig now under order by Noble for service in the GOM. To be called the Jim Day, it will be capable of operating in 12,000 ft of water and will have living accommodations for 200 persons. The rig is slated for delivery in late 2009 under a 2-year contract with Marathon Oil. A similar DP semi, the Danny Adkins, is being built by Noble for contracted use by Shell in the GOM.

Fig. 3—The ultradeepwater DP semisubmersible to be called the Jim Day is being built by Noble for initial contract use by Marathon in the GOM.

At the same time that new rigs like these are being built, the development of lightweight, synthetic mooring technology is extending the depth ranges of conventional moored mobile drilling rigs.

“The industry wisdom used to be that if it was in over 6,000 ft of water, it should be a DP rig,” said Mike Briggs, Operations Superintendent, Deep Water, Noble Drilling (U.S.). “Now in the last 3 or 4 years, due to the developments in synthetic mooring cables, they’ve been able to extend moored rigs to 8,000–9,000 ft of water.”

Rigs use preset anchors or suction piles, which are set into the seafloor by anchor-handling vessels and retrieved when drilling is finished. Some rigs now carry two sets of these anchoring devices, enabling them to have their next site prepared while they’re still drilling the previous location. Synthetic mooring lines are attached by vessels specially equipped with very large winches, either when the anchors are installed or later. In cases where the drilling rig will not be on site immediately, the lines can be tied to buoys until the rig arrives. In some instances, the anchoring devices and possibly the mooring lines are set up months in advance. Once the rig is on location, the synthetic lines are attached to mooring wires extending from the rig, and the mooring system is tensioned to its operating specifications.

The key factor limiting the operating water depths for conventional rigs carrying their own chain-and-wire mooring lines is the weight of the system. With synthetic lines available, rig owners seeking to extend rig-depth capability are no longer forced to make expensive winch upgrades that consume precious working space. They can continue to use their own systems at appropriate depths and go to synthetic mooring for deeper projects. This increases the flexibility of the rig fleet, helping it respond to deepwater demand.

For that matter, perceptions about the limits of conventionally moored rigs were probably changed last year when the Noble semisubmersible Amos Runner drilled the discovery well at the Anadarko Mission Deep prospect on Green Canyon Block 955. Moored at 7,650 ft, Noble’s floater broke the world depth record for conventionally moored rigs by more than 1,700 ft. Built as a submersible to sit on bottom at a maximum of 80 ft, the rig was upgraded to a semisubmersible in 1997 and upgraded again in 2006. The Amos Runner had been on contract with Kerr-McGee (now part of Anadarko) since 1999. “Knowing what this rig was capable of, we believed and Anadarko believed that it had not been pushed,” Briggs said. “With the upgrade done prior to this well, the rig is rated to 8,000 ft with conventional mooring and fully capable of operating conventionally at that depth.” The Amos Runner is shown in Fig. 4.

Fig. 4—Noble’s Amos Runner, which recently broke the world depth record for conventionally moored rigs. (Images on page courtesy of Noble.)

The achievement is significant for several reasons. A number of conventionally moored rigs in the future may be able to drill some wells that are quite deep, if not the deepest in the GOM, improving the flexibility and efficiency of the rig fleet. Furthermore, with synthetic mooring still a relatively new technology, procurement can be very lengthy, deployment vessels are in short supply, and the cost of tying up anchoring installations for months before use is considerable. Conversely, rigs carrying their own mooring with them have some inherent efficiencies. Noble and Anadarko presented a paper on the deployment of the Amos Runner on Green Canyon Block 955 at this year’s OTC.

Innovative Drilling and Completion Technologies

Some of the key enabling technologies for drilling into zones such as the Lower Tertiary layers beneath the deepwater Gulf have been the predictive tools developed for lowering risk levels in these very long, complex, and colossally expensive wellbores, noted Chevron’s James Cearley. Fig. 5 shows a live video and information feed from a Chevron drilling operation.

Fig. 5—Real-time well information with live video enables optimized drilling and reduced risk.

“We’ve really improved the tools for that, all of the logging-while-drilling (LWD) technology that allows you to calculate the key information like pore-pressure and frac gradients so that you can feel your way down a lot better than you used to,” Cearley said. “We’ve still got a long way to go. There will need to be a lot of work in rock mechanics, fluid designs, and estimating capabilities, where we combine the seismic, well data, and the rock-mechanics data to help us design our wells better so that we pick the casing points more intelligently and plan the wellbore with the appropriate contingencies. Also, as we go deeper into higher-pressure and higher-temperature environments (>325°F and >25,000 psi) we are beginning to work beyond the limits of existing LWD tool capabilities which will present new technology challenges to the industry.”

Drillers of some deepwater GOM wells have encountered margins between formation pore- and fracture-pressure gradients as small as 1 lbm/gal of mud weight, which pose large drilling risks, noted Tony Vaughn, Vice President and General Manager, Gulf of Mexico, Devon Energy. “There is a fine line between a column that’s pressured enough to keep the formation from coming up the hole at you and one that exceeds the fracture gradient, which would break the formation down, cause you to lose your fluids, and then face the formation coming up at you, creating a safety issue,” he said.

The high complexity of deepwater subsalt wells adds to the challenge. Earlier deepwater wells that were not drilled through thick salt layers typically used five casing strings. “Now you’re looking at nine casing strings in these subsalt wells, some very tight tolerances between those strings, and very little annular space in the lower portions of the well,” Cearley said. Fig. 6 shows a bird’s-eye view of typical casing programs for conventional deepwater and GOM deepwater wells. Expandable casing has proved a great problem-solver. “You can design the well with seven standard strings and keep two expandable strings for contingencies,” he said. “If you’ve reached a point where your pore-pressure/frac-gradient margin has eroded to where your hole is no longer drillable at current mud weight, you can run in a string of expandable casing, expand it, cement it in place and stay within your casing program. However, although expandable casing has proved a problem solver, using it also carries some increased risk. Thus, significant planning and front-end-loading time must go into the deployment of this technology. That said, it makes it possible to design a well that is much cheaper than if you had to incorporate nine, 10, or 11 strings to start with, and it increases your chances of reaching TD. The last thing you want is to sink USD 30, 40, or 50 million into a wellbore and have to walk away from it because you couldn’t get to TD.”

Fig. 6—A comparison of deepwater casing programs, five strings for conventional wells and nine strings for GOM wells. (Images on page courtesy of Chevron.)

As more deepwater-Gulf development wells are drilled, the industry is likely to make increasing use of intelligent completions to enable proactive management of these high-investment wellbore and reservoir assets. Likewise, well-path strategies such as extended-reach, high-angle, horizontal, or multilateral completions will become increasingly common, maximizing reservoir exposure to the wellbore while minimizing the number of wells drilled.

“When you think about having rigs that can handle drilling 30,000-ft wells, and you start putting some deviation to those, you could see measured well depths exceeding 35,000 ft pretty easily in the future,” Vaughn said. “These fairly vertical exploration wells are taking 3 to 4 months to drill. So as we add complexity and strategically locate high-angle development wells, that will add to the drill times and certainly the cost.”

Cearley also sees potential for multilaterals completed with proven, pressure-sealed junctions. “If you had those proven and a high confidence in them, you could simply lay in your high-angle, slant wellbores at specific places within each horizon and potentially eliminate the need to pump any kind of sand-control or frac-pack treatment. Wellbores of this type are preferable to horizontal wellbores if the overall pay sections are as thick as some discovered recently in the deepwater Gulf of Mexico (>1,000 ft). And finding ways to simplify the completions is a key objective for reducing the costs of drilling and any future intervention. Replacing multiple, stacked frac packs with single-run, multizone frac-pack tools is one example of how this could be done. It would remove a significant numbers of days from your up-front drilling and completion costs.”

New Horizons for Floating Production Facilities

As commercial discoveries continue in 8,000-ft GOM waters and beyond, the permanent production facilities will be either moored floating systems or subsea wellheads tied back to host facilities on the water’s surface. Recently, Anadarko’s Independence Hub gas-processing platform was installed on Mississippi Canyon Block 920 in 8,000 ft of water. The deep-draft semisubmersible, secured by a 12-line taut polyester mooring system supporting steel catenary risers (SCRs), initially is tying in production over producer-owned flowlines from several surrounding gas fields at depths from 7,000 to 9,000 ft and will be capable of processing 1 billion cubic feet per day of gas. Production startup from the fields is slated for the second half of the year. The project has set a number of world records, including deepest flowline installation (9,000 ft), deepest SCR installation, longest mooring lines (2.4 miles each), deepest suction-pile installation (at 8,000 ft), heaviest SCR load (800 metric tons) on a deepwater floating facility, and deepest in-line future tie-in subsea structure.

As floating facilities go deeper, the riser systems that carry production to the surface become heavier. “That’s really the penalty you pay by going to deeper water, but on a semisubmersible, you just need to fairly marginally increase the size of the hull to carry that,” said Magne Nygard, Vice President, Business Development Products, Aker Kvaerner Engineering and Technology. A paper written by Nygard and coauthors from Aker Kvaerner, BP, and Stress Engineering was presented at this year’s OTC. It discussed how a production semisubmersible capable of high-pressure/high-temperature service could be designed for 10,000-ft operations in the Gulf of Mexico. The paper was written in connection with DeepStar, a 14-year-old joint-industry project, currently with eight member companies, focused on advancing technologies for deepwater business development.

The concept discussed in the paper, Nygard said, is a deep-draft semisubmersible. Fig. 7 shows the design for a facility of this type. “Essentially, we make the draft as deep as necessary to achieve motions sufficiently benign to enable the use of SCRs,” Nygard said. “And it’s not extremely deep. The draft can be extended by about 30 to 40% over a conventional semi. So the draft is still in the general range of 100 ft.”

Fig. 7—The design of a deep-draft production semisubmersible. (Image courtesy of Aker Kvaerner.)

The major limitation, the authors noted, would be if a pipe-in-pipe (PIP) riser system were adopted as a means of insulating production flow. The issue is not with the floater but the lack of vessels big enough to install PIP risers at that depth. Flow assurance, especially concern about plugs of gas hydrates forming within the flow system, is a major issue for deepwater GOM producers. PIP installations have not been that common in the Gulf, and operators have frequently chosen single-pipe solutions with external pipe insulation, Nygard noted. Nonetheless, he and the other authors pointed out in the paper that under the sour-service conditions assumed in the baseline DeepStar study, sour production flow would reduce the fatigue life of externally insulated single-pipe, carbon-steel catenary risers to unacceptable levels. An option in this case could be to apply heavier insulation over the lower part of the SCR, which would reduce the dynamics of the otherwise relatively light risers.

A potential new-technology solution the authors discussed was to install a high-integrity pressure-protection system (HIPPS) on the seafloor. In that case, flowing-fluid pressures in the flowlines could be sufficiently lowered to enable the use of a PIP system with reduced carrier-pipe diameter and reduced flowline- and carrier-pipe wall thicknesses. System overpressure would be controlled by the HIPPS facility, and the lighter, smaller-diameter pipe system could be installed with current equipment. The HIPPS technology has been used in Europe but is still under review by the U.S. Minerals Management Service (MMS), which has not established generalized permitting but will review individual, project-specific applications to use the technology.

Development decisions are still in process on many of the deepest recent GOM discoveries. Following last year’s successful well test in 7,000 ft of water, Chevron has been assembling its integrated project team for the Jack project.

“All options are on the table, and the biggest decision will be ‘wet trees or dry trees?’ ” Cearley said. “The opportunity at Jack and the Lower Tertiary discoveries is that you’ve got a very large resource target, along with expectations of a fairly low recovery. Wet trees (subsea wellheads) help you get it on line more quickly by doing subsea tiebacks to some kind of floating facility. However, you increase the overall cost of ownership in terms of interventions, and wet trees typically result in higher abandonment pressures, which leads to lower recoveries. Conversely, if you go to some kind of floating structure with a dry tree, like a spar, you can work the wells over more economically. You also have a somewhat cheaper drill rig on that vessel, so you can drill the wells and not tie up the very expensive deepwater drillship fleet.”

Another approach to deepwater-Gulf development challenges is that of Petrobras and Devon, each 50% owners in the 23,000-acre Cascade development unit covering Walker Ridge Blocks 205, 206, 249, and 250. A discovery well in 8,140 ft of water was drilled there in 2002.

The companies have received conceptual approval from the MMS to bring in the GOM’s first floating production, storage, and offloading vessel (FPSO) and drill two development wells, with first oil scheduled for late 2009 or early 2010. The two wells will provide key information on the long-term producing characteristics of the Lower Tertiary, which will be useful in evaluating the potential for expanding Cascade to a full-field development. Fig. 8 shows a schematic of the FPSO and subsea tiebacks for this phased-development option. The MMS granted the companies a suspension of production on the leases involved, which have exceeded their primary terms, to allow the companies to proceed with this plan.

Fig. 8—An FPSO with two subsea-well tiebacks could be used as strategy to expedite production and reduce long-term project risk at the Cascade development. (Image courtesy of Devon Energy.)

“We’re referring to this approach as an early-production system,” said Devon’s Vaughn. Once the producing wells are evaluated, several different scenarios could unfold. “This system could gradually expand to a full-field larger development, using the same FPSO, upgrading it, or bringing in a new one with larger topsides capacity,” Vaughn said. “Alternatively, it could be a fixed, moored structure, such as a semisubmersible or spar. The challenge, for the topsides anyway, is not so much on the technical side as much as on the commercial side.

“Where we are in the business of the Lower Tertiary, in a way, is trying to design these developments to be as flexible as possible because we really don’t know the long-term producing characteristics of these reservoirs. You’re going to have to make some multibillion-dollar decisions with less information than we would prefer. That’s going to cause some challenges, and the early-production system is one method of minimizing or alleviating that risk.”

Reference

Michell, S., Sharp, J., and Chergotis, D. 2007. Dual-azimuth versus wide-azimuth technology as applied in subsalt imaging of Mad Dog Field—a case study. The Leading Edge, 26 (4) 470–478.