Focus on Relentless Improvement Needed for Big Oil's Success in Shale

Big oil companies can be successful in shale, but success requires a focus on "relentless productivity improvement," according to the leader of BHP Billiton's US onshore business.

Big oil companies can be successful in shale, but success requires a focus on “relentless productivity improvement”, according to the leader of BHP Billiton’s U.S. onshore business.

BHP’s U.S. shale production from its assets in the Eagle Ford, Permian Basin, Fayetteville and Haynesville comprised 42 percent of the company’s 670,000 barrel of oil equivalent per day (boepd) production, compared with 34 percent from Australia, 13 percent from the Gulf of Mexico and 11 percent from international operations. The company’s oil and gas production has doubled in the past five years due to development of its Australia and U.S. Gulf assets and acquisition of unconventional U.S. assets.

But the company, which had primarily been focused on deepwater, realized a year into its operations in U.S. shale that its offshore business model would not work, Rod Skaufel, assets president of shale for BHP Billiton, told reporters at a briefing in Houston June 2.  

“The first year was tough,” Skaufelf said. BHP saw high costs initially in its shale operations, higher than the costs seen by Chesapeake Energy Corp. or Petrohawk Energy. BHP entered U.S. shale through its acquisition of Petrohawk in 2011 and acquisition of shale assets from Chesapeake.

“Saying that, our skill set clearly was offshore deepwater, and it requires a different mentality, a more fit-for-purpose oversight model. We had to rethink how we work.”

Today, the company’s U.S. onshore shale operations are cost-competitive, said Skaufel, noting that he’s talked with competitors who also had a tough time entering shale plays. Entering shale was a big learning curve for the company, but the company is now well down that curve.

To bring down costs and boost productivity, the company had to adopt of strategy of relentless productivity improvements in which it aims for each shale well drilled to be cheaper than the last and more productive than the last. This focus requires that companies have the capacity to learn quickly to improve their performance, Skaufel noted.

This approach including constant benchmarking of well performance versus that of competitors, building on best in class performance, using numerical and analytical models to drive trials and pilots, applying design of experiment principles to accelerate feedback, investing in diagnostics to validate models and gather insights, and leveraging learnings across the company, said Skaufel.

To improve speed and reduce cost, BHP sought to balance its drilling focus between time and cost improvements, tendered key contracts for tangibles and services, continually reviewed of well specification and procedures to ensure fit-for-purpose design, eliminating waste and wait time in process, and reducing variability in drilling performance.

A year and a half ago, BHP began benchmarking by examining the drilling costs of its joint venture partners, and found that these companies were drilling wells 30 percent cheaper than BHP. This data prompted the company to develop the Pacesetter concept which looked at how quickly any section of hole could be drilled.

Skaufel said that BHP emphasizes quarter on quarter improvements in its teams, ensuring that BHP is cost competitive in this area.  

“We look at whether what we’re doing is working, or if someone is doing it better,” said Skaufel.

However, benchmarking in the Eagle Ford needs to be very geographic specific, given that the variability across the play is tremendous.

“IP [initial production] is not the name of the game, it’s sustainable rate.”

As a result, BHP has improved productivity in its drilling time and cost performance of three Black Hawk wells in the Eagle Ford by around 26 and 24 percent over the last six quarters, from first quarter for fiscal year (FY) 2013 to the second quarter of FY 2014.

On average, the company’s well costs in its North America operations are just over $4 million, but the company has drilled 15 wells this year for less than $3 million. In the Eagle Ford, drilling costs per well are already at $4 million, depending on the mix of two and three-string wells. In the Permian, drilling costs are running between $4 to $6 million per well. BHP is using a four-string design on wells, which costs more but is more reliable. In the future, BHP will drill Permian wells for less than $4 million, Skaufel said. While improving cost performance is a focus, the company is willing to spend more on completions in order to get better results.

BHP’s efforts to use modelling to reverse shale production declines suggests that only 36 percent of vertical frac height is effectively propped, and that BHP sees an opportunity to increase EUR by 20 to 60 percent higher with improved vertical coverage and frac conductivity. BHP has used the frac and Eclipse models to quantify the benefit of improved proppant placement, and currently is working on an alternative frac design.

Skaufel said BHP is seeing early encouraging results for its use of diversion techniques to improve stimulated rock volume and create a more uniform distribution across clusters. The company is using microseismic to examine production data to determine how to get more uniform distribution, and has experimented with shorter frac stages and fewer clusters to get higher rates.

Integration of decision-making for shale also is critical for success. While BHP’s shale asset division is not autonomous from BHP itself, the company is organized so that Skaufel runs the entire shale division.  The company has the flexibility of an independent with the financial backing of a large company.

“You can’t get bogged down in laborious approval processes for decision-making,” Skaufel said.  

Given that investment is being made in numerous wells instead of one large offshore platform, approvals, assurances and technical standards have to look and feel different for onshore versus offshore.

“You still need a return on investment for shareholders,” said Skaufel. “With money comes a lot of accountability. But you need autonomy; otherwise, you die.”

Skaufel credits BHP’s “rigorous” methodology with helping it organize its U.S. portfolio and deciding which assets it should focus its drilling efforts and which it should defer. For each operated well, the company calculates the optimum timing to deliver maximum value, using forward price projections and cost learning curves. Capital is then allocated basis based on this analysis, while accounting for acreage retention requirements; operational capability; competing non-operated opportunities, appraisal and land capture objectives, and capital availability.

“At one point in time, we were running 45 rigs in U.S. shale; today, we’re running 25, and drilling as many wells with 25 rigs as we did with 45,” Skaufel commented.

Over the past year, the company’s costs also have come down, now that it is taking time to analyze data and improve. BHP’s organizational capacity – and the finite technical resources available in Houston – also makes it difficult to operate at higher rates even with good investments. BHP’s shale division now employs over 2,000 people, the majority of whom were recruited externally over the past three years.

BHP will invest $4 billion a year in U.S. onshore shale plays through the end of the decade. The company, which holds 1.5 million net acres in North America, is one of the most active operators in North American shale plays, and is Schlumberger’s largest North American customer, said Skaufel.

BHP is primarily focused on shale liquids production, with 75 percent liquids growth year over year. The company’s current liquids production represents about a third of its 330,000 bopd U.S. onshore production; BHP will double liquids production by FY 2017. BHP’s gas production has declined due to its focus on liquids.

BHP is most active in South Texas’ Eagle Ford play, where 17 of the 25 rigs it has running in North America are operating. Approximately 75 percent of the company’s fiscal year 2014 onshore U.S. drilling activity is focused on the Eagle Ford. BHP has 14 rigs drilling and most of its technical work focused on its 58,000 net acre position in the Black Hawk portion of the Eagle Ford. The company is running three rigs at Hawkville, where it is focusing on the liquids window.

BHP also sees a significant production opportunity in the Permian Basin with lower well cost and higher recovery as the company has done at Black Hawk. Over the past three years, the company has been conducting an extensive appraisal program of its 450,000 net acre position for both vertical and horizontal drilling. BHP, which has assets in the Delaware and South Midland basins, has primarily been focused on Reeves and Loving counties in the Delaware, where BHP is progressing a 100,000 boepd development. In the coming fiscal year, the company will increase the rigs running in the basin this year from four to six, Skaufel said.

BHP is excited about what it’s doing in the Permian, and is constantly trying to hydrate the play, Skaufel commented.

The company is primarily focused on liquids right now, but Skaufel said the economics for its dry gas wells in the Haynesville shale plays are robust, even at current low U.S. gas prices. Skaufel said BHP is drilling the Haynesville to improve its technical understanding of the play before it pursues full sectional development. The company is focused on liquids production to optimize its capital. The company would do more in the Haynesville, but BHP’s shale division is capped at $4 billion organizationally for shale investment.

BHP is not operating any rigs in the Fayetteville, but is still investing $150 million for non-operated interests in Southwestern Energy’s wells, which are in the heart of the Fayetteville play. The United States’ potential role as a significant exporter of liquefied natural gas would put upward pressure on long-term U.S. gas prices has not changed the company’s thinking on delaying dry gas production, said Skaufel. Instead, the company will wait until gas pricing improves.

The company also will take a wait and see approach towards extending its Eagle Ford exploration and production efforts south of the border into Mexico. Skaufel said that BHP sees Mexico development happening at a slower than faster pace, and that the company has concerns over addressing security in possible operations in Mexico.

Safety remains BHP’s highest priority in the challenging U.S. onshore business and its relatively inexperienced workforce in oil and gas. Skaufel noted that partnering with the right contractors, including its partner Helmerich & Payne, is essential for improving and maintaining safety, given that contractors are performing the bulk of the field work. Skaufel said the company has had year on year improvement in its recordable injury rates.

“Safety is important when you’re working in people’s backyard,” Skaufel said.

Petroleum comprises 30 percent of BHP’s global asset portfolio, with iron ore and copper making up 50 and 20 percent of its asset.

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