When it comes to the Gulf of Mexico (GoM), while many of the big headlines go to the majors venturing out into the region’s frontier deep waters, some of the most innovative work is being done much closer to shore.

Compared to some of the big hitters in the GoM, Energy XXI and Fieldwood Energy can both be considered youngsters. Houston-based Energy XXI was formed in 2005 as a special acquisition corporation after successfully raising $300 million during a six-week road trip to parts of Europe and across the U.S. as hurricanes Katrina and Ike barreled through the GoM. In the years since, it has grown to become a major player in the GoM, operating 10 of the largest oil fields on the shallow-water shelf.

Fieldwood, meanwhile, is even younger, having only started up in 2013 with minimal staffing, $5 million in invested capital and no properties. It is a portfolio company of New York-based private equity firm Riverstone Holdings LLC and has grown rapidly to become the largest operator on the GoM Shelf. Two of its most recent acquisitions were the $3.75 billion purchase of Apache Corp.’s GoM Shelf business and the $750 million gain of SandRidge Energy’s GoM and Gulf Coast business unit.

The bosses of both companies have clearly defined strategies on how to maximize their returns from the shelf while also sharing more than a few of the same concerns on topics such as regulatory burdens, increased costs and the need to acquire both the right assets and the right people.

View from the top

Key milestones identified by Energy XXI CEO John Schiller, speaking at Hart Energy’s recent Offshore Executive Conference (OEC), included three major acquisitions from 2006 to 2007, listing on NASDAQ in August 2007, a $1 billion deal with Exxon Mobil for its Grand Isle assets in 2010 and the $2.3 billion acquisition of EPL Oil & Gas.

With its main fields located offshore Louisiana, the oil-focused company has continued to build up proved reserves, which have increased 38%, and its reserve replacement ratio (up 510%), with each acquisition pushing a strategy that centers on developing only the core pieces of acquired portfolios and ditching the rest.

For Energy XXI, the steps to sustaining people, profits and the environment involve “a focus on acquiring the right assets [and] finding the right people,” Schiller said. “Everybody knows that with offshore technology you have to have the best and brightest working for you. It’s not a place where mistakes can be tolerated.”

Positive revisions

Also crucial to achieving success are leadership and implementing the right technologies, which impact the industry’s abilities to tap the estimated 7 Bbbl of new reserves believed to lie in the GoM within the next five years.

As the company produces proved reserves, additional downdip oil and gas booked as 2P and 3P upgrade to 1P and 2P, respectively. “That’s why you see most of us in the GoM having consistently positive revisions on reserves,” Schiller said, after pointing out the company has proved reserves of 246 MMboe and probable reserves of 96 MMboe and currently produces about 59,000 boe/d from its 252 blocks on the shelf.

Schiller spoke about how some technologies and techniques have led to improved E&P efforts in the GoM for the company. Among these are better seismic data, horizontal drilling and dump floods.

In the past, many shallow wells bypassed productive sands, focus was on high-decline gas in a low oil-price environment, 3-D seismic was limited, and horizontal drilling technology was not readily applied, according to Schiller. But times have changed as technology drives “better imaging, reduced risk profile, and greater drilling and extraction efficiencies” as “big fields get bigger” with “significant resource potential just below field plays.”

Lessons from ultradeep

Reprocessing of seismic data alone has resulted in better quality, and “the new acquisition data are really changing how we look at these old salt domes,” Schiller said.

He noted how work with partner Freeport-McMoRan in the ultradeep has taught his company about salt movement and how it is different than was envisioned 20 years ago. Today there is better definition of salt and greater ability to see seismic amplitudes updip as well as hidden amplitudes underneath overhangs that previously could not be seen.

Using its Main Pass Field model as an example, Schiller described how the redefined salt model generated growth and opportunities for more growth.

“We drilled updip on it. At 1,463 m (4,800 ft) we got into a reservoir and put the well on at 1,200 bbl/d for a year,” he said. “We started studying and realized we had two more downdip wells that had never been completed.” Better seismic data helped send production up to 9,000 bbl/d. “[Seismic] is giving us better definition in the existing sands. It has also given us a lot better look at depth.”

Energy XXI claims to have the largest seismic footprint among its GoM peers, having more than 42,476 sq km (16,400 sq miles) of 3-D data and ongoing seismic acquisition.

While better seismic data have proven beneficial on the geological front, horizontal drilling is enhancing oil recovery. The technique has been used in the GoM since the 1990s, Schiller said.

Typically, with vertical drilling, 200-psi drawdown leads to water coning and inefficient sweep, with late life recovery rates ranging from 40% to 50%, according to Schiller. However, with typical horizontal drilling, 3-psi to 5-psi drawdown leads to stable oil/water contact and enhanced recovery of original oil-in-place. Recovery rates for horizontal wells range from 55% to 65% in the GoM. “It’s a much easier flow regime on the reservoir,” he said.

Real-world lab

Assets acquired from Exxon Mobil in the Grand Isle area provided just what Energy XXI needed to sift through to find what would work best. The area had been used as a kind of “big real-world lab” as Exxon Mobil studied, for example, how it was going to complete wells in West Africa or deal with water control, he said. “So we had pretty much every type of completion you could envision, from prepacked openhole screens to prepacked screens with slotted liners to regular gravel-packed screens and open hole.”

To date, Energy XXI has drilled 19 horizontal wells, resulting in 16 successful horizontal completions.

“We’re spanning the top of some 10- and 16-ft [3- and 5-m] sands. It’s not easy. You’ve got to stay on top of your game. You’ve got to pay attention as you drill wells,” Schiller said. “West Delta 73 is where we’ve had the most success. We’ve already drilled 11 wells here. We’re just shy of 10 MMbbl of reserves, and we’re averaging on the first 30 days about 400 bbl/d [net per well].”

West Delta 73

The horizontal drilling program in the West Delta 73 Field, which has seven platforms and 40 active wells at a water depth of about 67 m (220 ft), has resulted in nearly 33 MMboe of added proved reserves.

Energy XXI remains positive on the future state of oil and gas E&P in the GoM. “We think the economics are going to be good for a long time. There’s going to continue to be a rebirth, I think, of the whole thing,” Schiller said, while adding that the company is looking to continue containing costs. “We are much more efficient now.”

He added that a lot more wide-azimuth seismic is going to be shot, and there will be “a lot more exploration around the salt.”

The biggest hindrance, he added, is “government regulation and intervention. There’s a lot more inspection,” resulting in extra planning.

Four main GoM challenges

Fieldwood’s CEO and President Matt McCarroll spoke at OEC about the four major challenges facing GoM producers, as he saw it: regulation, infrastructure, hurricanes, and staff and equipment.

Regarding regulatory challenges, he lamented the constant changes in the approval process. Permit and approval delays and uncertainty hamper the industry, he said, adding that rig inspection fees have gone up substantially from about $2,000 to $3,000 per rig to about $17,000 to $31,000 per rig, and companies are paying these fees to understaffed and uninformed agencies. In 2010 Fieldwood’s predecessor company paid the federal government $1.2 million in processing fees. In 2014 it paid $8.6 million. “Despite increased fees,” he said, “we’re getting substantially less ability to conduct our operations.”

Aging infrastructure

The second hurdle is the GoM's aging infrastructure. He pointed to older pipelines and devices as one reason for increased downtime.

Increasingly, infrastructure owners are resistant to repairing their possessions, and as a result producers are having to take ownership of the pipelines and conduct the repairs themselves, McCarroll said. “Year to date, Fieldwood has experienced 31 pipeline leaks in pipes that we own and that others own that we use. We plugged three pipelines and made 28 repairs, resulting in a shut-in production of almost 2 MMboe. It’s a big challenge, a big problem, and we’re going to have to work hard to overcome it.”

McCarroll said new technology that could extend the useful lives of pipelines, such as a poly-flow coiled tubing liner tested in Thailand and the North Sea, should be approved as soon as possible.

Hurricanes remain difficult to plan for, and he regretted a lack of a cost-effective and comprehensive risk-transfer solution in the GoM, a situation that has deteriorated since 2005. Additionally, Fieldwood has raised equipment levels, strengthened platforms and removed platforms sooner than in the past.

The final challenge McCarroll spoke about was the availability of trained staff and relevant equipment. “In the end, this is a people business,” he said. “You can have all the new technology you want, but if you don’t have good people to run the companies and work the operations offshore, you’re not going to be successful.”

Fieldwood currently operates 656 platforms and holds 650 Outer Continental Shelf blocks for a total of 2 million net acres. It produces about 115,000 boe/d.

Offshore