Companies Reveal New Techniques, Formations In Eagle Ford

NEW ORLEANS—Stack and frack, stack and stagger, and subsea stacks are among three new things announced at the 43rd annual Scotia Howard Weil Conference in New Orleans.

Marathon Oil Co. (NSYE: MRO) released results from its first Eagle Ford “stack and frack” pad in Karnes County, Texas, where IPs ranged from 1,145 to 1,622 barrels of oil equivalent per day (boe/d). Marathon began work on the four well Murphy Sinclair pad in September, targeting the upper and lower benches of the Eagle Ford, plus the Austin Chalk.

“We are still in the early days, but our experience in delineating the initial 18,000 net acres of Austin Chalk co-development has positioned us well to further expand stacked opportunity in our core Eagle Ford position,” Marathon CEO Lee Tillman told attendees at the Scotia Howard Weil conference on March 23.

Marathon is allocating 41% of its $3.5 billion in 2015 capital spending to the Eagle Ford, where the company is emphasizing enhanced well completions, typically defined as longer laterals, greater proppant loading and more stages packed more closely together. However, co-development of multiple pays in an informal stacked pay downhole environment is also gaining traction. The Austin Chalk will comprise 25% of well starts in 2015, according to Tillman. The company is focusing its stack and frack and Austin Chalk co-development program in Karnes County, Texas, along the prolific Karnes Trough.

Marathon recently turned the first production to sales from pad-drilled wells testing both the upper and lower Eagle Ford formation. Previously operators had emphasized landing zones in the lower Eagle Ford bench. Thirty day IPs from the new benches ranged from 903 to 1246 boe/d on the Mohr Hons pad, to 1,093 to 1,195 boe/d on the Jauer Sonka pad, and 1,138 to 1,383 boe/d on the Carter Holm pad, Tillman said, releasing the first production information on the program. Marathon also completed four pads targeting the Austin Chalk and lower Eagle Ford Shale south of the stack and frack Karnes County fairway as part of its co-development program. IPs ranged on the multi-well pads ranged from 915 to 1,277 boe/d.

Looking Further

Further west in the Eagle Ford, SM Energy Co. (NYSE: SM) is looking at stacking laterals to fully exploit thicker sections of the Eagle Ford in the company’s Webb County, Texas, acreage. Total Eagle Ford thickness exceeds 300 feet and may contain seven different facies with hydrocarbon potential, according to Jay Ottoson, SM Energy’s president and CEO.

“What we found, looking at more detailed lithofacies, is there are really six or seven different facies within that 300 feet,” Ottoson said. “And if you look at the upper sections, we have not been effectively completing these. There is a lot of vertical heterogeneity there.”

Basically SM is attempting to demonstrate that it can access the zones, push laterals closer together, and stagger laterals between formations in the upper and lower Eagle Ford to squeeze out additional reservoir yield. The company will be working on stacked and staggered pilots in 2015 involving up to 12-wells from four three-well pads in its northern operation area where the company previously had planned a single four well pad. If the concept works, SM could theoretically double its existing inventory of 1,050 well. SM Energy will allocate 50% of its 2015 Eagle Ford wells to test the inventory expansion program, and do so within cash flow.

“There are three things we have to do to prove up inventory,” Ottoson noted. “We have to prove that when we land wells in those other intervals that we can make good wells. If we can land a well, can we make a completion that is as economic as our lower Eagle Ford completion? Can we push those wells closer together to reduce spacing so we can increase well count that way? And then, can we stack and stagger these wells to achieve a multiple of the original inventory assumptions.”

SM has finished an upper Eagle Ford test in its eastern Webb County acreage and generated 50 or 60% internal rates of return with production performing or exceeding existing lower Eagle Ford type curves. Other tests involve drilling new laterals lower and in between existing lower Eagle Ford laterals to test tighter spacing down to 600 feet between laterals and 450 feet between staggered laterals. The stack and stagger pilot tests should produce results by the third-quarter 2015.

Subsea JV

Apparently one subsea alliance wasn’t enough when it comes to offshore joint ventures among service and manufacturing companies. FMC Technologies Inc. (NYSE: FMC) and Technip (EURONEXT PARIS: TEC) are creating a second subsea joint venture to service an expensive, challenging sector of deepwater oil and gas project development.

“It gives the industry for the first time the opportunity to integrate two components of deepwater development,” John Gremp, FMC Technologies chairman told Scotia Howard Weil attendees. “SURF (subsea umbilical, riser, and flowing systems) and SPS (subsea production systems) have been treated as two different items. We’ve never been able to address both together.”

The 50/50 joint venture (JV), Forsys Subsea, is targeting the way subsea fields are designed and delivered to reduce cost and standardize solutions early in the project by involving vendors in the front end engineering development (FEED) process.

“There are engineering houses today involved in the concept phase, but they are not contractors,” Gremp said. “It is not vendor based. It is not engineers who have access to the technologies and have participated in the execution.”

In theory standardization, which has long been touted as the magic bullet for reducing complexity and expense in deepwater project development, should shorten the cycle to bring production to market. Previously, operators and contractors both have pointed to standardization of subsea components as a necessity to move the industry forward, though each sector has pointed fingers at the other for holding up what is touted as the logical next step in deepwater project design and development. Traditionally operators design projects and request bids from a variety of contractors for discrete portions of the project. The subsea component comprises 30% of project development costs, the second highest portion after drilling.

“Standardization of technology will never be included in deepwater development concept if we are not involved early,” Gremp said. “Operators don’t know about these technologies. They won’t know about the lowest cost standards.”

Gremp said one of the things that needs to change in order to lower deepwater project development costs is to alter the business model so that contractors participate early in the design process—hence the Forsys Subsea JV. High project costs, cost overruns, and long lead times combined with cash flow pressures on international operators in 2014, resulted in a slowdown in deepwater development. Deepwater remains one of the globe’s main sources for future crude oil production.

The world will need as much as 40 million barrels per day of new oil by 2025 to offset depletion and meet new demand. According to Gremp, deepwater is expected to provide 27% of that new oil volume over the next decade compared to 16% from onshore tight formations.

Over the last three years, new deepwater discoveries have averaged 400 MMboe. However the backlog of undeveloped discoveries is rising.

Prior to the alliance, Technip and FMC Technologies contributed a group of engineers to jointly examine deepwater projects commissioned over the last five years. The combined team from both contractors came up with designs that eliminated 30% of the cost for subsea development even before including new technologies. That pilot provided proof of concept and paved the way for the Forsys Subsea JV, Gremp said.

The Scotia Howard Weil conference concludes March 26 in New Orleans.

For more information, contact the author, Richard Mason, at rmason@hartenergy.com.