“I’ll be back.” Those were the immortal words of Arnold Schwarzenegger in the hit ’80s movie The Terminator. He wasn’t kidding.

For the oil and gas business in the Gulf of Mexico (GoM) in the months and years immediately following the Macondo tragedy in 2010 anyone uttering a promise similar to that on behalf of the U.S. Gulf would have been quickly consigned to the “extras” list.

But fast-forward to today, and the GoM is indeed back—and back with a vengeance. Declining offshore production is forecast to rise, and a succession of major or significant fields have been brought onstream both on time and on budget despite the despondent air of gloom within the industry caused by concerns over a falling oil price and rising costs.

Can this renaissance be sustained? The answer appears to be yes, with the GoM starting the year with a bang and ending it with a resounding boom.

But don’t take our word for it—here are the views of a cross-section of some of the Gulf’s leading players, with a broad portfolio of interests ranging from the traditional shallow-water shelf out into the ultradeep frontier.

The Chevron-operated Jack-St. Malo semisubmersible platform began producing in the Walker Ridge area early in December. One of the highest-profile projects of 2014, the semisub unit is the largest of its kind in the GoM and has a production capacity of 170 Mbbl/d of oil and 1.2 MMcm/d (42 MMcf/d) of gas. Technology innovations include using the industry’s largest seafloor boost system and the largest capacity high-pressure deepwater subsea pumps. Jack-St. Malo is the third ultradeepwater project in the Lower Tertiary (Paleogene) trend, following the Cascade and Chinook fields and Shell’s Perdido Field. More than 500 MMboe of reserves will initially be recovered over a planned production life of 30 years from Jack-St. Malo. (Source: Chevron)

One of the loudest proponents of the Gulf’s emerging renaissance over the past four years has been Brian Reinsborough, president and CEO of one of the most recent entrants to the sector—privately held Venari Resources LLC.

Since the Dallas-based company started up in 2012, it has received commitments of $2.4 billion from Warburg Pincus and other private equity investors, and it’s a participant in some of the GoM’s largest oil finds in the Lower Tertiary play, including the large Shenandoah Field operated by Anadarko Petroleum in deepwater Walker Ridge Block 52.

Reinsborough, a former president of U.S. operations for Nexen, recalled, “I wrote the business plan for Venari in the middle of the drilling moratorium. At the base of its principles was that, at the darkest moments of the industry, I wanted to get into the Gulf of Mexico, and I wanted to get into it big. That was based on a future that I felt that the industry would eventually emerge into. That was the genesis of Venari.”

His company’s strategy is currently that of a non-operator. Speaking at Hart Energy’s recent Offshore Executive Conference (OEC) in Houston, he outlined the importance of the company’s focus on the subsalt in the GoM, principally in the Lower Tertiary. “It’s an area that I feel has a tremendous amount of potential left, and the industry is now not only beginning to see it but understand it. And we want to be part of that.

“We call ourselves a subsurface operator, and we invest very heavily in seismic and try to influence in the front end of the business cycle in exploration and appraisal. And we leave the heavy lifting of the developments to some of the best operators in the industry.”

Leaving the Gulf a mistake

Someone whose company has been in the GoM for a lot longer than two or three years is Tracy Krohn, CEO of W&T Offshore. He said he’s long since learned that leaving it for dead is a mistake.

“We think that there’s a tremendous future in the Gulf of Mexico. I’ve been in this business for three decades. We’ve carried the company on the basis that the GoM is always going to have an abundance of resources. I’ve heard the death knell for the GoM several times: ‘The Gulf is dead, the Gulf is dead, long live the Gulf.’ Every time that’s occurred it’s been a situation of opportunity for us, so we’ve always looked at the GoM as there’s going to be another well, there’s going to be another deal…

“We’ve been in the shallows since 1985 and in deepwater since the turn of the century. We’ve found hundreds of millions of barrels of oil in the GoM over a long period of time.”

Price-dependent

Krohn is the first to admit, however, that the industry’s fortunes can be price-dependent. “The price moves downward, and activity slows down. We always get caught in these cycles,” he said. “The oil production goes up for a longer period of time, and then it crashes down. That’s how domestic U.S. production has been for 100 years, so we get caught in one of these down trends—and I’m not sure we’re in a down trend. I would rather refer to it as a correction at this point in time, based on a number of different things.”

W&T looks at the GoM daily, he continued, from the basis of what the company can do with the available pool of cash that it has. “We have the same issue that Shell does. We don’t have a $35 billion budget; we have a $650 million capex budget, but it’s the same problem. What do you put in there to accomplish your goals, and where do you best apply it?”

Gift that keeps on giving

“The GoM continues to give,” he added. “We find new production and new technology; we find new fields. We find it with the drillbit, we find it through exploitation, we find it through EOR and we find it through better imaging techniques. We intend to be there for the rest of our existence. It’s just a great province, and you can actually own the reserves, unlike elsewhere where there are PSCs [production-sharing contracts], for example. So here you have more control and more predictability.”

W&T has recently made discoveries in 2,134 m (7,000 ft) of water, but it relies on a relatively simple process for its activities, according to Krohn. It tries to find a single point injection and ultimately capture 2 MMbbl to 3 MMbbl in reserves. For the company, it’s economically viable to have a well produce 5,000 bbl/d, he said. “For us, it’s a significant (find). It doesn’t cost a lot of money. We do see those increasingly on the shelf and in deepwater.”

The Technip-built hull for Anadarko Petroleum’s deepwater Lucius spar is seen being transported by Dockwise’s Mighty Servant 1 barge. Lucius was due onstream before the end of 2014, with the operator opting for a ‘design one, build two’ approach that saw it repeat the process for its Heidelberg development also in the GoM. This saw Anadarko apply lessons from the first project, which it says has resulted in significant cost savings and a shortening of the development cycle by up to 18 months. Heidelberg is due onstream mid-2016. (Source: Dockwise)

Heavy hitters

One of Reinsborough’s typical “heavy lifters” in the GoM is Shell Exploration & Production Co., currently the largest offshore producer in the area. According to Martijn Dekker, vice president of appraisal and hydrocarbon maturation, Upstream Americas Exploration for Shell, the Gulf always seems to reveal more resources than anyone thought possible.

Though rigs and regulations are mostly costing operators more and more, Dekker said the company is eager to keep exploring. “The GoM has an amazing capability to reinvent itself,” he said. “To paraphrase Mark Twain, ‘The rumors of the death of the Gulf of Mexico are highly exaggerated.’”

A couple of years ago Dekker said Shell’s “thinkers” went beyond the present GoM conditions and imagined a working petroleum system in some of the deepest waters a mile or more down. “And boy, did that work out. We stepped into the deepwater,” he said.

The company’s high-profile startup of oil production in February 2014 from the Mars B development via the newbuild Olympus tension-leg platform (TLP) was Shell’s sixth and largest floating deepwater platform in the GoM. Combined production from Olympus and the operator’s original Mars platform is expected to be 1 Bboe. The Mars development sits in 896 m (2,940 ft) of water.

It also started up production from Cardamom Deep, which is helping to extend the life of its long-serving deepwater Auger platform.

Shell has another GoM project in the works that will reach nearly 3.2 km (2 miles) down to 2,896 m (9,500 ft)—its Stones Field that will be developed via an FPSO vessel, the Turritella. “That looks very good and is supposed to come online in 2016,” said Dekker. “Our Vito and Appomattox fields we are hopefully going to take to sanction in the next couple of years,” he added.

“Shell opened the deepwater book; we are definitely writing the next chapter, and we’re writing the next sequel too.”

Unique qualities

So what are some of the unique qualities and advantages of the U.S. Gulf that enable it to survive and reinvent itself so well?

According to Dekker, there are three main things:

  • Geology—“It’s complex, but it keeps on giving;”
  • The political and economic environment—“It’s very stable. Also key is the combination of intense competition and collaboration. I think that’s the cornerstone of human progress;” and
  • People—“Skills and experience are unrivaled here. It makes the GoM and Houston a hotbed of innovation.”

Also at the OEC, James H. Painter, executive vice president at Cobalt International Energy, added to this list.

“First, it’s the margins. You’ll find that there’s not really a place that can compete with the margins anywhere that I’ve worked in the world. Because of the tax and royalty setup, whatever you get is yours vs. being more of a production-sharing agreement or regime as in different parts of the world.

“The second is the ability for technology to move quickly. You’ve got the service vendors; you’ve got the seismic. Everything starts in the GoM and then moves around the world, by and large, whether it’s new seismic techniques or the newer drilling rigs or whether it’s bit technology. All these things start in the GoM and then move out. And it’s a relatively small number of companies that work the deepwater, so again your competitive pool tends to be fairly reduced.”

Reinsborough agreed that the U.S. Gulf stands out for its high margins as well as the technology. “This is the incubator of technology, and we’re seeing it unfold right in front of our eyes in terms of unlocking areas that we couldn’t see 10 years ago in the subsalt. But also from our point of view, it’s access. This is a very commercially driven regime, and that’s great for small companies like ours that can enter into the market. It’s also a transparent fiscal regime. It’s completely above board, very predictable and a very stable political environment compared to many other areas.”

Highly ranked

These qualities make the GoM rank highly compared to E&P opportunities elsewhere in the world, but costs such as drilling day rates will need to be controlled.

This is so the industry can continue to further explore and exploit its undoubted reserves potential, with the Lower Tertiary Trend cited by many as key to its future. Thanks to ever-improving 3-D seismic processing, exploration in subsalt and near-salt zones is likely to be the next big thing as operators seek to understand more about the Paleogene formations.

In the next decade, drilling activity will move south and west into ever-deeper waters as the industry continues to expand its search for fresh reserves, according to Reinsborough.

In addition, the Inboard Wilcox Trend alone is likely to hold billions of barrels of yet-to-find reserves, he added “It’s very attractive. In the subsalt provinces we believe there’s 5.5 Bboe to 6 Bboe of yet-to-find resources, just in the Inboard Wilcox Trend. That’s a good prize for us to go after. So when you stack all those up, I think the GoM ranks very high globally.”

Cost and technology challenges

Numerous challenges remain, of course, including ones that are not just specific to the GoM—those of rising industry costs and a lack of standardized development approaches. These were elements touched upon by many of the speakers at the EOC.

“Most of the value destruction occurs in the appraisal phase when you drill too many wells before making the final investment decision [FID],” Reinsborough said.

He pointed out that costs are “our biggest pressure point right now. On a large-scale development, almost 65% of the capex is on drilling and completion costs. You have to get that down to have a good breakeven price. We’ve seen costs over the last five years going up by almost 10% compound annual growth rate over that period of time. There are typical wells right now in the subsalt Wilcox Trend that will cost a quarter of a billion dollars, so that’s a big ticket.”

He flagged rig day rates as the biggest factor, although the industry is starting to see those soften. But, he added, “We’d like to see more rig contracts come in under $400,000 per day, which would be more acceptable over time.”

Knowledge transfer

One company that has been steadily increasing its GoM presence over the past few years is Statoil.

“It’s a core area in our portfolio, and we see a lot of potential. We’re here on a long-term basis,” said Ola Gussias, the operator’s technology manager for U.S. offshore. The company is the world’s largest deepwater operator and has over the past three years been busy researching the industrialization and standardization of the seabed for aspects such as subsea processing, where it visualizes an eventual “subsea factory.”

It has been transferring much of its technology know-how from the North Sea to its operations in the GoM, which it entered in 2005, said Gussias. It’s presently involved in nine producing fields, including Tahiti and Caesar-Tonga, and has another seven in the execution or concept phases. The technologies it is focused on include through-tubing electric submersible pumps, currently being developed alongside Chevron and Schlumberger. Early in 2014 it also announced a global technical efficiency program.

But it was standardization that many speakers touched upon, related to platform topsides facilities as well as interconnections both above and below the surface. The idea is, of course, to save both time and money.

“It’s a balance between thoroughness and front-end design and good, tried and true management practices,” said Stephen Pastor, asset president, conventional, for BHP Billiton. Pastor describes the GoM as “a heartland for BHP,” and it was the first operator to resume production drilling in the region post-Macondo. “The more you can mature the front-end engineering and design process before you get to the FID, the better. Don’t feel you need to blank-engineer everything or over-engineer everything. It’s being smart about what you do and what you don’t do.”

Industry solutions

Much of the technology focus in the GoM right now is on drilling advances and HP/HT reservoirs and equipment.

Painter has total confidence in the industry’s ability to overcome the engineering problems. “They’re always solved,” he said. He pointed out that the industry is today drilling wells in the GoM to a total depth of 10,670 m (35,000 ft). Key to their success will be “making sure you do it in the right way, each of the individual parts. The other part is about efficiency, so looking at ways to reduce cycle time is important.”

With engineering problems, he continued, it essentially comes down to “time, effort and money.” He recalled, “When Cobalt started nine years ago we were using 1.5 million-pound hookload rigs and drilling 25,000-ft [7,620-m] wells. Now we’re using 2.5 million-pound hookload rigs and are looking for 3 million-pound hookload rigs, potentially in the future to drill 40,000-ft [12,192-m] wells.

“So the industry always finds a way to break the technology barriers. It’s the geologic barriers that tend to be a little harder for people to understand through time.”

So how easy is it for the transfer of knowledge and technology to take place in the GoM?

It’s not, according to Gussias. “It’s not straightforward. Some of the principles could be transferable, but we have different operating conditions. We have over the last four or five years had a program called ‘Cracking the Paleogene’ that had the target to take the most promising technologies and tailor-make them for GoM conditions, especially the Paleogene conditions. There is a gap, and we have been working on filling that gap.”

Value of seismic

Pastor pointed out the benefits of applying its 3-D and 4-D seismic experience, with which it has had good results in its homeland waters of Australia. “We certainly see more opportunities to apply 4-D seismic in the GoM. We’re already onto that at the Atlantis Field, where we’re getting some pretty positive results. We’re pushing hard to do the same at Shenzi and some other assets.

“You can appreciate that there’s tremendous value in that. When you’re talking about wells that cost $150 million a piece on the low end and up to $250 million-plus on the high end, it pays to be really efficient and effective with how many and where you’re placing infill wells as a function of understanding your drainage pattern. That’s the one technology that’s been most transferable, I’d say.”

HP/HT

Regarding HP/HT wells of 20,000 psi and 25,000 psi, Reinsborough said that this was a problem that has to be solved to unlock the Lower Tertiary. “It will take a collaboration effort between the operator companies and the service companies to solve it,” he said. “But I agree that the industry has a tendency to solve these problems when there’s a great value proposition behind it. The industry will get that right over time.”

David Reid, deepwater appraisal manager at Shell Upstream Americas, agreed with this. “As we move forward, I think we’re going to see a need for more robust completion technology,” Reid said. “As we drill deeper we’ll get into hotter temperatures and higher pressures. The drawdowns that we’re going to see, the depths and pressures, are just going to be a lot larger. We’re going to get into things such as ceramic screens and all this really great technology that you’re going to see deployed into oil and gas.”

However, water depth—once a challenge that seemed insurmountable beyond certain depths—is now barely even an issue, according to the experts at OEC. The greater technical challenge is well depth, again due to the HP/HT issue. “The rigs and the drilling capacity are there,” Painter said.

Reinsborough agreed. “I don’t think water depth is the limiting factor,” he said. “I think drilling depth is. Drilling below the mudline, that’s probably the bigger challenge for the industry. The industry can drill wells in 10,000 ft [3,050 m] of water and probably will go well beyond that in the next decade. But it’s the drilling depth and the pressures and temperatures that occur that are going to be the challenging and potentially limiting factors.”

Gussias pointed out, however, that although water depth was not an issue as such, phenomena such as deepwater loop currents were still a challenge.

Threats to the GoM

When it comes to the biggest perceived threats to the aspirations of companies in the GoM and what keeps oil company executives awake at night, it is the regulatory environment that rears its ugly head.

According to Painter, for smaller companies the regulatory environment is of concern due to changes “that could occur that are not within our control.” The company has risk and mitigation plans for things that are within its control, he said, but outside issues such as “What are the things that could change through time, especially in a post-Macondo GoM?” cause sleepless nights.

Causing Pastor restless nights are “the confluence of increasing cost, regulatory requirements and other things. And scarcity of resource as we cream the curve in some of the easier-to-find significant oil pools in the Miocene and elsewhere in the GoM. We’re getting into the Paleogene, which is tougher to crack, and so that whole idea, which I call scarcity of resource, just makes it more difficult to find oil fields with the size and productivity that are needed to underpin the $10 billion development costs we’re tending toward nowadays for a single field.”

Cost still an issue

It is the cost issue that still bothers Reinsborough. “Costs probably keep me up. But interest is still massive in the deepwater. The industry still feels there are large quantities of oil to be found in the GoM. So that’s why you continue to see large investments. And quite honestly, we’re in a high-margin business, and I think that requires a little education of the market that typically a standalone deepwater project in subsalt will have a breakeven in the $50/bbl range.”

Reid pointed out what he now sees as a “leveling off” of costs and even a decline. “I think we’re at a time where we’ll see some softening. But it’s still an expensive business to be in, and it’s a risky business,” he said.

Apache Energy’s Cory Loegering, region vice president, GoM, said costs go beyond contractual prices. The regulatory environment has added a lot of costs, he said. Apache has to spend two weeks testing BOPs before it can even get on a well. “That’s a clear cost. And then there’s a retest of the BOPs every two weeks that’s probably added 20% to our well costs,” he added. “So the regulatory requirement has driven up costs and impacted us. But we will always be compliant and so will bear those costs.”

Loegering went on to highlight Apache’s current plans for the GoM since the large sale of much of its Gulf blocks to Fieldwood Energy and Freeport-McMoRan for $5 billion a couple of years ago. “I’ve gotten questions like, ‘Are we still active in the Gulf?’” he said.

But with still around 650 blocks offshore, it remains the fourth-largest leaseholder in the GoM. With free cash flow generated from its international regions, Apache is now intending to spend it on North American assets, including the GoM. “We’ve already identified plenty of targets we want to chase,” he said.

Loegering said Apache’s focus for the Gulf is more clearly on exploration. “The way we look at the Gulf is kind of like the Bakken and Permian. Those plays really emerged into where they are today based on technology,” he said. “Our approach to the Gulf is the application of the technology we already have. And that already exists.”

Apache’s GoM capex for 2014 was about $300 million, with Loegering saying he hoped in 2015 to spend substantially more. “We are pretty excited about the opportunities in the Gulf. Having really focused in the 1990s in the deepwater through to 2013 prior to the merger there was a lot that we learned and picked up. We are taking that technology and moving it to the shelf. There’s a lot that’s been left behind.”

He added that Apache is retooling and reprocessing new seismic and “plans to hit the ground running in 2015, testing these new ideas we’ve come up with. There’s a real future here in the GoM—it really does keep on giving.”

Looking ahead

So what lies in store for the GoM over the next five to 10 years?

Much of the focus remains on the deepwater, according to Painter. “Cracking the Paleogene. Understanding the economics, getting the cost down and the production rates up. That’s the next five-year plan for all of us in the deepwater GoM. Improve the economics and returns from the Paleogene.”

Pastor agreed that the play is “the biggest material game-changing opportunity we have in the GoM.” But he stressed the need for his company to continue to exploit the many opportunities in and around discovered resources in the Miocene through near-field exploration and “taking advantage of having infrastructure already installed that you can quickly and inexpensively tie back to.” BHP has managed to keep its Shenzi TLP at nameplate production capacity for the past five years with a continuous infill drilling program.

The application of technologies such as 4-D seismic, subsea pumping and other EOR techniques such as miscible gas floods or better techniques for water injection would also be important. “I think there’s a lot of value creation that can come from that, and I believe we need to apply an ‘all of the above’ strategy to extract the best potential.”

The GoM, he added, has huge fields such as BHP’s Atlantis and Mad Dog, with the latter’s Phase 2 to potentially deliver 750 MMbbl of recoverable oil and further possible upside beyond that (more than double Atlantis).

“It’s a place we have aspirations to do a heck of a lot more. We see this as a place to exploit our capability and strengths by also pursuing low-risk, high-return infill drilling and brownfield expansion.”

Reinsborough concluded, “The industry will move west and south in the GoM. I also think we’ll see the push-out of infrastructure into these areas. We’ll see a lot more hubs, a lot more subsea tiebacks. The industry tends to repeat itself, and if it unfolds the way we see it, then we’ll see a broader infrastructure base and more subsea tiebacks as you go west and south.”

55 finds by 2021 to sustain GoM plateau

Offshore production from the U.S. Gulf of Mexico (GoM) is forecast to hit a peak of 1.9 MMboe/d by 2016, which would see it overtake its previous highest level set in 2009, according to the latest survey by Wood Mackenzie.

But the long-term challenge to sustain this rise and replace reserves remains significant—just to replace the oil and gas extracted from currently producing fields between now and 2021 (4.2 Bboe in total) requires the industry to find up to 55 deepwater GoM discoveries (77 MMboe on average), the company estimated. EOR techniques also must play a major part in further improving recovery rates from the emerging plays, it added.

New developments and the continued expansion of mature fields will drive the forecast rise in output between 2014 and 2016 to the 1.9 MMboe/d figure before then leveling off for the remainder of the decade, as production from older fields continues to decline and a more limited number of new projects come onstream because of the current tightening of capex budgets by operators looking to control their costs. A total of 15 development projects are expected onstream between 2014 and 2016, but only eight are currently planned to start flowing between 2017 and 2020.

Production to recover

In recent years, deepwater GoM production has plunged from 1.8 MMboe/d in 2010 to 1.3 MMboe/d in 2013. The report, however, said that deepwater Gulf production will rise 18% per year from 2014 to 2016, with 2015 to see it climb 21% from 2014’s level and 2016 then seeing the planned production startup of Anadarko Petroleum’s Heidelberg Field and the continued ramp-up of output from Chevron’s Jack-St. Malo project. Other new developments driving the rise include Delta House, Lucius and Big Foot.

Heidelberg (in Green Canyon Blocks 816, 859, 860 and 903) and Jack-St. Malo (in Walker Ridge Blocks 758 and 759) will produce a forecast 115 Mboe/d in 2016, the report stated.

The production growth forecast will be supported to a certain extent, it added, by the redevelopment and extension of mature fields, including Thunder Horse and Mars.

In 2016, it continued, the five fields (Delta House, Lucius, Big Foot, Thunder Horse and Mars) will account for 26% of output.

WoodMac’s production forecast would entail the industry spending $17 billion in capex in 2014 to attain the 2015 target, some 30% more than in 2013. The Lower Tertiary play will make up 21% of the capex in 2014, rising to 53% of the total by 2021.

Long-term success

Of the forecast slowdown from 2017 to 2020, Imran Khan, Wood Mackenzie’s GoM analyst, said that although only eight developments were expected to come online in that period (compared to 15 from 2014 to 2016), those eight would be important fields that could define the long-term success of the region. “Stones, Shenandoah and North Platte are part of the Lower Tertiary, which has garnered attention because of the potential to find large discoveries. However, the economics are currently challenging because of high costs, technological limitations and low recovery rates,” he said in a prepared statement.

“Unless these obstacles are overcome, it will be difficult for the region to grow in the next decade. Not including yet-to-find reserves, we forecast that production will start to decline after plateauing out at 1.9 MMboe/d in 2021. The current slide in oil prices does not help the long-term outlook either, especially if the downward trend continues for a protracted period.”

Khan emphasized the need for the industry to sustain investment levels to support the production increase, with recent discoveries in deeper waters and emerging plays requiring more complex drilling and advanced technologies, both of which are highly capital-intensive. He commented, “A typical development well in the Lower Tertiary can cost $300 million as compared to the shallower, more established well-known plays such as the Upper/Middle Miocene, where development well costs are closer to $100 million.”

55 finds required

Beyond 2021, the report also pointed out, some of the GoM’s largest fields such as Mars and Mad Dog will have been producing for 15 to 20 years. “The impact from this depletion will be significant. Those fields currently onstream are expected to produce 4.2 Bboe between now until 2021. Based on the average deepwater GoM discovery size of 77 MMboe, almost 55 discoveries would be required to make up this amount.

“We believe this obstacle will potentially be overcome if recovery factors can be improved to take advantage of large resource volumes found in emerging plays. For example, if recovery rates double at the three large emerging fields—Appomattox, North Platte and Vito—their reserve base will increase to 2.5 Bboe.”

­The company’s outlook also highlighted the increased level of competition from other regions around the world, including nearby neighbor Mexico, especially as the GoM is still suffering from a sustained level of cost increases. Costs are rising at 5% to 10% annually, it said, despite the recent softening of the rig market. Khan concluded, “Unless the technology to improve recovery rates is developed and costs are reduced, the operating environment will only become more challenging, and it will be difficult for the region to maintain a long-term production growth trajectory.”