One sign that things are getting better for US onshore exploration is the revival of talk about looming shortages and bottlenecks.
By mid-year, sand to prop open fractures and trucks to pump those jobs are expected to be in short supply. Oilfield hands are already a scarce commodity. Those are solvable problems, but at a price some companies may find uncomfortably high.
Surveys by branches of the US Federal Reserve Bank done in the fourth quarter of 2016 said that the break-even oil price for companies in Texas and surrounding states varies widely, and is generally greater than USD 50/bbl. The survey by the bank’s Dallas branch found that nearly 60% of the 141 companies surveyed said that it would take a price from USD 55/bbl to USD 65/bbl to “substantially increase” US crude oil drilling. And that was before service costs began rising.
The smallest bar on the chart was for companies that can make money drilling when oil is USD 49/bbl or less. Some analysts publish estimates of average oil prices needed to profitably produce oil, but those averages mask a wide range of break-even levels. There are also differences among analysts on what percentage of the cost reductions made in the industry since 2014 will vaporize in the face of the double-digit service price increases that are expected this year in the unconventional services sector.
“We hear every ratio possible,” said Jackson Sandeen, a senior research analyst for Wood Mackenzie, who said the savings are 40% from more efficient operations and 60% due to service sector price concessions, which will shrink. Bain & Company clients put it at 60% of sustainable efficiencies and 40% from price concessions, said Jorge Leis, a Bain partner that leads its Americas Oil & Gas Practice.
Rystad Energy said the average price needed to profitably produce oil in the US nonconventional sector has dropped by 50% since the downturn hit in late 2014, but a lot of that is based on supplier discounts. “Lower unit prices of service companies are a major reason for the drop,” said Jon Duesund, senior project manager for Rystad, during a recent briefing in Houston.
Rystad concludes that 40% of the cuts are unsustainable because they are based on supplier discounts, 40% are sustainable because they are based on greater efficiency, and 20% are cost savings that erode over time.
At the top of its list of sustainable ways to save is high-grading. That covers everything from hiring only the most efficient drilling rigs and crews to methods used to target the most productive rock. The payoff from high-grading, though, will be lessened when rising demand forces companies to be less selective about the equipment leased and the spots drilled, Duesund said.
“Some of the efficiencies we see disappearing,” he said. “We will not see the [break-even cost] level in 2014, but it will be higher than current levels.”
Richard Spears, managing partner for Spears & Associates, said discounts from service companies could be as much as 75% of the reduction in the break-even cost of producing a barrel of oil.
No one expects the price shock to stall the rally in unconventional exploration at a time when the OPEC deal to reduce production is pushing up oil prices, or at least reduce the risk of a repeat of the price plunge early last year, and billions of dollars in investor money are flowing into hot spots, mostly in the Permian Basin.
The service sector price increases expected in 2017 are a fraction of the total concessions those companies made over the past 2 years, Leis said.
But engineers on exploration teams will be feeling pressure to hold the line on the price of production by finding ways to reduce costs to make up for lost discounts, such as fracturing methods that require less horsepower to pump.
Pressure Differential
Based on presentations from leading, publicly traded producers in the Permian Basin, USD 50/bbl oil can be highly profitable. EOG, which has a goal of drilling what it calls premium wells, is earning a 30% rate of return when oil is selling for USD 40/bbl and twice that at USD 50/bbl. By 2018 its goal is to move nearly all its wells into the premium category.
In 2016, EOG said 95% of its wells earned a return of greater than 10% with oil at USD 50/bbl, while it estimated that only 39% of the wells drilled industrywide reached that standard.
“The things that are affected by service cost increases [such as drilling, wireline, and pumping services] represent maybe one-fourth of the total savings we have achieved to date,” said Billy Helms, executive vice president of exploration and production for EOG. He added, “If those go up 10% to 20%, that will not dramatically affect our well cost but, at the same time, we are making greater strides at reducing our well costs.”
EOG and other low-cost firms have made large investments in physical and virtual assets that target the best rock, control the cost of the sand and water pumped on ever-bigger jobs, and efficiently handle the water, oil, and gas in their own facilities.
The best way to reduce the cost of a barrel of oil is to produce more of it, and do that consistently by using data and analysis to pick the best targets.
“Targeting is having a larger role than people think it would,” Helms said during a presentation last November.
The impact of targeting over time at EOG is evident as it completes it backlog of drilled but uncompleted wells (DUCs) built up over the past couple years. Helms said that “a lot of DUCs are not premium wells. Because of targeting, things drilled 2 years ago are not in that [high-margin] category.”
Going Longer
The rising number of drilling rigs now working understates the increase in drilling because faster rigs are drilling longer laterals.
“About 1,000 horizontal rigs could be enough to get back to same number of horizontal well spuds as seen in 2014,” Duesund said. Three years ago, the Baker Hughes rig counts showed more than 1,500 rigs drilling horizontal or directional wells, less than half the current level.
Rising prices will push companies to speed the transition to drilling longer horizontal wells. In the past year, Richard Spears has seen a surge in the number of 10,000-ft and 12,000-ft laterals drilled. He said, “10,000-ft laterals used to be used just in North Dakota. Now it is something we are seeing absolutely everywhere.” He predicts that, in a couple of years, 15,000-ft laterals will be standard.
There are sustainable savings in these designs, which reduce the number of vertical wells and drilling pads needed to drain a large area. A slide from EOG Resources showed that moving from a 4,500-ft lateral to a 7,200-ft one cut the cost of developing a 19,200-acre lease from USD 40.2 million to USD 31.6 million, increasing the net present value of the asset by more than 50%.
That is a sustainable gain as is faster drilling, which has allowed EOG to reduce the time it takes to drill a 7,000‑ft well from more than 38 days in 2014 to 21 days in late 2016. EOG and others are also using their growing trove of data from the Permian to target the most productive rock, where they are using new fracturing designs to better fracture the rock.
Go Bigger
When it comes to fracturing, the trend has always been toward pumping more water and sand.
When Richard Spears started in the service business more than 30 years ago selling completion services for Halliburton, he jokes that when he would ask whether to sell a big frac job or a little one, the answer was always: “Richard, sell them a big one.”
The industry has profited from that advice. The average fracturing job now is using volumes of sand that would have been incomprehensible back then, and are twice what was common 5 years ago.
Pioneer Natural Resources has gone from pumping sand at 1,000 lb/ft of lateral in 2014 to 1,700 lb/ft in its latest completion designs. Stages have gone from 240 ft apart to 100 ft apart, according to a December 2016 presentation on the company’s website.
The industry is pushing beyond that limit. Chesapeake Energy and Southwestern Energy have both reported fracturing jobs using 5,000 pounds or more per lateral foot, according to the Bloomberg news service.
Rising prices in the face of greater demand is likely to change habits, and already has in the sand business. The enormous rise in proppant used per well helped push the industry away from higher-cost ceramics and proppant, as it went first to white sand and more recently to lower-cost brown sand.
This trend runs counter to studies concluding that proppants that are stronger and rounder perform better because they offer greater crush resistance and conductivity. But studies by Rystad and Bain & Company based on production data from completions using greater volumes of lower-grade sand, argue that the reward for using far more sand outweigh the gains from paying more for proppant with higher technical specifications.
To control costs, some independents such as EOG and Pioneer have invested in sand mines, Sandeen said.
Ever-bigger fracturing jobs continue to deliver greater production with no end in sight. That adds cost, but by reducing expenses such as the number of days required for drilling, EOG said it was able to reduce the overall cost of drilling and completing wells though the third quarter of last year.
When it comes to pumping the job, though, the work can only go so fast. That is by the design specifications and the capacity of the well casing. As Richard Spears put it, “A 100-bbl/min frac job goes at 100 bbl/min.”
Partners Required
As prices rise, grinding out profits in shale will require a greater focus on more efficient completions, said Leis of Bain.He sees a lot of potential to save money by reducing the number of fracture stages that contribute little or nothing, using the optimal amount of the most efficient hardware in the well, and eventually using automation to reduce labor costs and ensure that fracture designs are executed as planned.
For many companies, the expertise required and hours of work entailed to target wells and design better completions is more than they can do with their reduced staff and will require developing partnerships with service companies, Leis said.
Maximizing the value and trust within these partnerships will require some changes in habits. Service companies are looking for ways to do more with less, and clients may need to be willing to pay a premium price if an innovative idea or device adds significant value.
While developing an unconventional play looks more like running a large mine, where continuous gains in efficiency are valued, the biggest profits are still to be found by identifying the few spots likely to be highly productive.
While the number of highly productive places to drill, commonly known as sweet spots, is limited by geology, EOG said the number of premium wells is also a function of how they are drilled and completed in addition to the cost of that work. A 10% increase in expected output or a 10% reduction in costs can significantly add to an inventory of premium locations to drill.
Replicating the results of EOG and other highly efficient producers will be difficult because it is based on factors such as low-cost leases, contiguous acreage allowing the building of efficient facilities, and a costly accumulation of years of data plus in-house expertise.
The potential for sustainable gains appears to be there, but even some of the biggest oil companies have been unable to replicate the results of the most efficient unconventional producers. Over the next few years, it will become clear which companies have sustainably reduced their expenses.
Sandeen is watching how small E&P firms backed by private equity that have reported big productivity gains by intensively fracturing the best rock will fare over the long term. “When prices recover, how repeatable is that well as you start to ramp up to more rigs?” he said.
