Onshore drillers pull all available cost levers to economize wells

North America remains hardest-hit while Middle East sees more stability, but all regions challenged by rig rates that hover near operating costs

By Alex Endress, Editorial Coordinator

Such cost reductions can only go so far, however. It seems that any meaningful increase in onshore drilling activity will only come with an increase in oil prices, and that seems unlikely for the foreseeable future. Analysts point to continued record production levels from OPEC and Russia, which are sustaining the global oil oversupply.

“The reality is that at current oil prices, operators are challenged to be profitable in any but the most prolific reservoirs,” said Harris Swartz, Vice President of Drilling and Completions at Occidental Oil & Gas. “I think, as an industry, the objective should be to keep organizations intact and retain knowledge so that when the price of oil recovers, we can return to profitability quickly. Surviving this downturn means reducing costs to at least a break-even basis.”

Looking at onshore drilling markets around the world, North America continues to be the hardest-hit while the Middle East is seeing more stability. Not only are Middle Eastern NOCs issuing more stable work due to government objectives to sustain crude production, but contract lengths tended to be longer in that region anyway. A newbuild drilling contract there can range from five to six years on average, compared with two to four years in North America. “They’ll drill through this downturn because they’re not governed by return-on-investment economics, but that doesn’t mean they don’t keep pressure on dayrates,” said Kevin Neveu, President and CEO of Precision Drilling.

Sustained onshore production

In Q4 2015, the EIA had projected that oil prices could rise to $55-60 by mid-2016, which would then bring some North American shale plays back into affordability. But the EIA has since lowered its forecast – its March report predicted only $35/bbl, citing continued high levels of production from OPEC. This means that cheaper plays in the Middle East are still keeping higher-cost North American production out of the market. “There is skepticism that OPEC will agree on cutting production any time soon,” EIA Senior Analyst Jozef Lieskovsky said.

In February, Russia and OPEC announced a deal to maintain production at January levels and refrain from further increase. Yet that will not go very far in alleviating the oil oversupply, according to Douglas-Westwood Analyst Matt Cook. “Simply maintaining production at current levels isn’t really going to help anything, given that these production levels are creating the low oil prices that we’ve got at the moment.” Russia’s crude production tallied at 10.9 million bbl/day in January, which is the highest month of production in the post-Soviet era. Saudi Arabia’s last reported crude oil output amounted to 10.6 million bbl/day, which is also the highest recorded production level for the country.

Mr Cook predicts these countries will maintain their production levels despite the low oil prices. Their strategy to defend market share and to force out higher-cost producers – especially those in North America – seems to be working. Douglas-Westwood expects US onshore liquids production to fall by at least 900,000 bbl/day in 2016.

North America will also account for the biggest chunk of the decrease in number of onshore development wells drilled around the world – from 56,383 wells in 2015 to 50,182 in 2016, an 11% reduction. North American onshore wells will fall from 24,322 last year to 19,428 this year. The reason that this region has been hit so hard is simply because the majority of the unconventional plays just aren’t economically viable at $30-40/bbl oil prices, even with all the aggressive cost cutting that has already taken place, Mr Cook said.

In March 2016, IHS released a study on the decline in costs of US onshore wells since 2012. The study, commissioned by the EIA, shows that wells drilled last year in the Eagle Ford, Bakken, Marcellus and Permian cost 7-22% less than wells drilled in 2014 and 25-30% less than wells drilled in 2012. The study cited faster drilling and completion times, more efficient well designs and better well performance as major factors in these cost reductions.

The report also pointed specifically to longer laterals, improved geosteering, increased drilling rates, minimal casing and liner, multi-pad drilling and improved efficiency in surface operations as key technical enhancements. On the completion side, the reported cited the main factors for cost reductions as increased proppant volumes, number and position of fracturing stages, shift to hybrid fluid systems, faster fracturing operations, less premium proppant, and optimization of spacing and stacking.

Such cost reduction efforts are commendable, but Mr Cook warned that more is still needed for US unconventionals to become economically viable again. Average shale plays require an oil price of $70/bbl, he said, adding: “Some of the really high-cost shale plays will only be profitable perhaps at more than $100/bbl.”

In contrast, operators in the Middle East need oil prices at only about $10/bbl or less to break even. Douglas-Westwood expects onshore wells drilled in the Middle East to increase from 2,362 in 2015 to 2,425 in 2016. “The reservoirs in the Middle East are extensive and very well known. You don’t typically have to invest much into exploration to know where to find the oil, and then once drilled, the developments will produce a lot more per well,” Mr Cook said. “Some of these wells in the Middle East can produce tens of thousands of barrels per day at peak production, compared to a US tight oil well, which might produce a thousand barrels per day at its peak production, if you’re lucky.”

Until crude supply and demand come back into balance and oil prices increase, it appears that the best North American companies can hope for is simply to survive. Further, Mr Cook said he believes rig counts will remain far below the most recent boom’s peak levels “until far into the next decade.”

Increasing drilling efficiency

For drilling contractors, pressures and competition are both running high in the face of declining contract opportunities for North American land rigs. “Customer demand continues to fall, driven by budgets that are moving downwards in step with commodity prices,” Mr Neveu said. “There’s no confidence in what the bottom might be, and, as a result, it’s very tough for our customers. When their demand drops, it puts pressure on our business, and we see rigs being put down.”

As of January, Precision’s North American rig count was 107, down by more than half compared with the January 2014 count of 242. By April, that number had fallen further to 43 rigs – 18 in Canada and 25 in the US. “The WTI price has to be substantially higher to stimulate more investment,” Mr Neveu said, noting that he believes North American unconventional shale plays need oil prices in the $40-$70/bbl range to be economically viable.

Outside of North America, Precision was operating three rigs each in Kuwait and Mexico and four in Saudi Arabia, as of April. While expectations for more stable work in the Middle East continues to attract drilling contractors, dayrate pressure also continue to mount. Capital costs of newbuild rigs in the Middle East can be triple that of North America because operators need larger 3,000-hp rigs to hold up to the region’s high-pressure, high-temperature plays. However, at about $45,000, the company’s rigs in the Middle East are achieving approximately double the average dayrate for North American rigs, which is currently about $22,000.

Whether in the Middle East or North America, there simply isn’t much more room for rate reductions, Mr Neveu said. Rates for North American rigs are very close to operating costs already. “I think we’ve done our part,” he said. “We’re a small fraction of the well cost. Whether it be unconventional deep Permian wells, deep Eagle Ford wells, unconventional horizontal heavy oil wells or Canadian Duvernay wells, the drilling cost is typically only 15-20% of the well cost now.”

Rather than push for additional rate reductions, Mr Neveu urged the industry to focus on finding ways to achieve further performance gains. Much has already been achieved over the past few years by using AC-powered, walking rigs to industrialize the drilling process. In the Permian, for example, 12,000-ft wells can now be drilled in 14-20 days, compared with approximately 50 days just two years ago, Mr Neveu said.

At Precision, the downturn has directed the company to focus solely on high-spec assets – rigs that are ideal for factory-style drilling. At year-end 2015, Precision had retired 79 non-AC rigs from the company fleet. Those older units “simply don’t have enough capability, and the upgrade costs are too great,” he said. The remaining 254 rigs are all equipped with digital controls, mechanized pipe handling and vertical pipe racking, and a majority are also equipped with pad walking systems.

Survival during these difficult times has also meant staff cuts, although long-term contracts are providing better financial coverage at Precision, according to Mr Neveu. Of Precision’s 58 currently contracted rigs, 30 have contracts that will carry over into 2017. These are rigs that were delivered in 2014 and 2015 with three- to four-year contracts. “In the past seven years, every single new rig we’ve built has been covered by long-term contract. Those contracts are carrying us into this downturn,” he said. The company has completed 145 newbuilds since January 2009. “Having a good contract book with stable customers that are going to stay with those contracts is a key element to surviving a downturn.”

Focus on MENA

Dubai-based WDI, a subsidiary of Weatherford, has seen more stability during this downturn by focusing on the onshore markets in the Middle East and North Africa (MENA). “The NOCs in our core MENA markets are very solid,” said Mark Bedford, President of WDI. As of March, WDI had 38 rigs working in MENA – nine in Saudi Arabia, eight in Oman, six each in Iraq, Egypt and Kuwait, and three in Pakistan – but has pulled out of more frontier areas like Bangladesh, Kurdistan and Romania. “We don’t want to be the explorers. We like contract term and volume,” Mr Bedford said.

The top challenge for the rig contractor is to find additional ways to reduce costs and improve efficiency to meet operator demands, he added. “Contract terms are far tougher, and there’s no room for complacency,” he said. Falling dayrates is another challenge, although Mr Bedford doesn’t think rate discounts alone will help operators in the long run. “The never-ending cycle of reducing rates is not going to get the performance where it needs to be,” he said. “We focus on delivery, and if we deliver a high level of quality and reliability, well cost goes down. That’s really where our efforts are.”

Since January 2015, WDI has had to reduce its dayrates by less than 10%, he said. “We share savings rather than give blanket discounts. We aim to have the best people and equipment possible, which might put the costs of the rig higher, but we know in the long term, if our rigs are out-performing other rigs in the field – they would be the last to be released.”

In 2015, the company established a performance measurement group to analyze opportunities for improving efficiency and safety in everything from rig moves to trip times and from casing running to BOP pressure testing. “The discipline that you need to employ to be a safe company is also the discipline that makes you a profitable and reliable company,” Mr Bedford said. “We measure drilling performance and we measure flat time – there is no additional capital equipment required, it’s just measuring what you’re doing, analyzing the data and acting on it.”

WDI currently has a fleet of 101 drilling rigs and 12 workover rigs. These units have an average age of less than 10 years and offer up to 3,000 hp. The rigs have also been built so that Weatherford’s MPD equipment can be easily deployed. “We see that as a real competitive edge because we can combine that technology into our rigs and make them MPD-enabled. We have access to that technology, so we’re taking it one step forward and incorporating that into our rigs.”

Within the past year, WDI also implemented a competency assurance program that develops employees. Another program established behavioral-based safety leadership workshops where the best performers are identified for future managerial roles. “We’re taking the best senior toolpushers from those workshops, and we’re bringing them into our rig manager’s academy to help these guys move forward with us as a company,” Mr Bedford said. “It’s a cost, but there’s no question – it is money well spent on our people.”

Horizontal drilling cut by 50%

As can be expected, onshore US operators are sharply reducing their horizontal drilling activity. Pioneer Natural Resources, for example, has reduced its horizontal drilling budget by 50% for 2016. That falls in line with its CAPEX, which was cut from $2.2 billion last year to $2 billion this year. Rig counts will certainly continue to feel the impact from such cuts. Pioneer has already released two rigs each in the Eagle Ford and in the northern Spraberry/Wolfcamp area since Q4 last year and plans to release all four rigs working in the southern Wolfcamp by the middle of this year. After that, the company will likely have only 12 rigs on contract – only half of the 24 rigs it had working last year. “Whatever vehicles that are available to us, our cost structure just absolutely has to come down,” said Joey Hall, Executive VP of Permian Operations at Pioneer.

Additional cost savings could come from negotiating lower rates from the supply chain, but after what has already been a year of significant reductions, further reductions are becoming less and less feasible. “Everybody is feeling the pain these days,” Mr Hall said. “As the cost structure stands right now, vendors have limited ability to reduce their costs. But I’m not interested in bleeding the turnip to the point where my vendors go out of business. That does me no good.” Instead of putting further pressure on the supply chain, Pioneer is seeking additional cost reductions by being more selective about its vendors. This means working only with companies that perform reliably. “The only thing I can give them is certainty of work. Of course, when there are narrow margins, the only way they can make more money is to have more work.”

Efficiency is another target for cost reductions, although Mr Hall said he believes that parts of the industry may be putting too much emphasis on ROP. Other aspects of a field development, such as acreage position, well placement and choosing the proper fracturing technique for the well completions, are integral to overall efficiency, as well. “If you don’t have the right overall strategy, then the best drilling performance on the face of the planet isn’t going to do you any good.”

In 2016, Pioneer’s crude production is expected to grow by 10%, from 194 million BOED to 224 million BOED. This can be achieved despite the reductions in CAPEX and rig counts, he said, by focusing on all of the above factors. “With efficiencies gaining and times decreasing, I can do more with less,” Mr Hall said.

Drilling more wells per rig

Like a lot of other operators, Oxy has responded to the fall in oil prices by significantly cutting back on CAPEX – by 50%, in Oxy’s case. “Our big challenge has been to reduce drilling costs and increase profitability of the wells we’re drilling,” Mr Swartz said. “We’ve done that through improved performance, efficiency gains and renegotiated contracts.” Oxy currently has 13 rigs in Oman, five in the US Permian and one each in Qatar and Colombia.

Last year, the operator launched the Oxy Drilling Dynamics program, using industry best practices with proprietary enhancements to improve performance. This contributed heavily to the company’s ability to reduce drilling and completion costs in Permian resources by 33% while increasing production by 47%. “As a result, we drilled more wells per rig. This improvement in our efficiency made a big difference in getting more wells drilled for the amount of capital spent,” said John Willis, Chief of Drilling for Oxy.

In 2015, the operator was able cut its average drilling time per well by 50% on Permian Delaware Wolfcamp A wells – down from an average 44.3 days to 22.4 days. This saved Oxy $2.1 million per well, a 40% cost reduction.

One specific factor that contributed to these achievements was an advanced understanding of mechanical specific energy (MSE). Applying MSE optimization of weight-on-bit resulted in faster ROP and reduced vibration, Mr Willis said. Better rig site crew efficiency also helped, as did using advanced mud systems to eliminate casing across salt intervals. “Oxy did not have a big horizontal program in the Permian until late 2013, so we were learning how to drill Permian curves and laterals efficiently,” Mr Willis said. “The next two years were dedicated to studying our drilling parameters, and Drilling Dynamics allowed us to take everything we learned from our data analyses into actual practice.”

If there is a silver lining to the fall in oil prices, it’s that it has catalyzed companies to focus on efficiency initiatives such as the Drilling Dynamics program.

“During the boom environment, people were too busy with the high rig count to focus on performance improvements,” Mr Willis said. “Now, with time for in-depth engineering, we are able to dramatically improve our performance.” Oxy has also been able to achieve two-fold improvements in its rig operations by keeping the best people. “We not only got some performance improvements from their greater skill level, but it also enabled us to implement different practices because we had people that were willing and interested in trying to learn new things.” DC

Dry gas plays gain attention in Ohio’s Utica

By Alex Endress, Editorial Coordinator

Oily and liquids-rich plays were considered premium in Ohio’s Utica before the downturn began. But with the collapse of oil prices, operators are now choosing to target dry gas in the far eastern part of the state instead. Fields in Belmont and Monroe counties, where wells can achieve ultimate recovery rates (EURs) of up to 22 billion cu ft, have become particularly popular, said Shawn Bennett, Executive VP of the Ohio Oil and Gas Association (OOGA), an upstream-focused industry organization.

Drilling in the Utica unconventionals, one of the newer plays in North America, only started around 2011. Since then, the industry has been working to test longer laterals and shorter frac intervals to see how to get optimal results, Mr Bennett said. For example, five years ago, typical well lateral lengths were about 5,000 ft and fracs were spaced approximately 350 ft apart. Since then, lateral lengths have been extended to 8,000 ft on average, while frac spacing has been shortened to 175- to 250-ft intervals to provide more access points for recovery. Proppant volumes have also risen, he added, as operators have learned that more sand must be pumped to achieve optimal recovery rates.

When unconventional development began in the Utica five years ago, companies applied lessons they had learned from the more mature shale plays, such as the Eagle Ford and Marcellus. Over time, however, they have learned how to tailor wells to the Utica. “As you learn more about the rock, you begin to start implementing things you’ve learned from previous wells into your new wells and developing your own basin-specific drilling program,” he said. “That is what you’re seeing applied here in the Utica.” In the past two years, these improvements have resulted in a 20-30% increase in EURs for Utica wells, according to Mr Bennett.

Despite such improvements, the Utica has still seen a significant drop in overall drilling activity in this downturn. There are currently 10 rigs operating in the Utica, down from 59 in autumn 2014. Of the remaining rigs, eight are drilling for dry gas in Belmont and Monroe counties, while the other two are drilling in the natural gas liquids window in Washington and Carroll counties.

For there to be any significant increase in drilling in Ohio, he  said he believes oil prices would need to reach $70-75. The industry would also need to clear the backlog of approximately 500 uncompleted wells in the region before drilling can ramp up again.

Further, issues related to land unitization must be cleared up to encourage investments in the Utica, Mr Bennett said. Land unitization allows operators to properly compensate landowners for drainage recovered underneath the owners’ land if the owners decide not to lease the land out for drilling operations. “We will be draining their resources, so they need to be compensated,” he said.

Currently, there is no time limit for the state to issue unitization orders, which means it can take years to complete the process. “There have been issues where the unitization orders have not moved forward,” which precluded drilling development altogether, he said.

The OOGA is now backing Ohio’s House Bill 8, which would impose a 45-day limit on land unitization agreements between oil and gas companies and landowners, including state lands. The bill is under review with the state’s Energy and Natural Resources Committee and will come before the state’s 131st General Assembly for approval later this year.

“It is good policy, so I do believe it will be passed. At the end of the day, this is about orderly development, and it’s about allowing companies to properly plan out their drill schedule. By putting these time limits into place, we’ll be able to have more predictability on our drilling programs.”

Deloitte: Increased consolidation likely for upstream oil and gas companies in 2016

By Alex Endress, Editorial Coordinator

Low oil prices that hit the oil and gas industry starting in 2014 haven’t resulted in a substantial increase in M&A activity so far, but that is likely to change this year, according to Deloitte. Many upstream companies have been able to survive by making significant reductions to their CAPEX. However, as oil prices remain below $50/bbl, fewer companies will be able to endure, said Melinda Yee, Partner, M&A Transaction Services for Deloitte. “With such low activity levels and distress becoming more prevalent, more companies are going to need to turn to divestitures and outright sales of themselves to survive,” she said.

Over the past year, as companies have become increasingly distressed financially, most have typically not looked to selling assets or being acquired. Instead, most have explored other options, such as reducing costs through fewer drilling programs and refining drilling processes to make wells more affordable. Companies have also been less likely to sell assets due to remaining optimism that oil prices would rebound.

“There’s also a psychological aspect, where some believed that their assets were worth more, especially because they anticipated the oil prices were going to rebound. Since that hasn’t happened, sellers have been selective,” Ms Yee said. Many distressed companies had hedged contracts in place, which supported potential sellers over the past year. But many of these hedges will soon expire, she said.

M&A activity for operators declined from 492 deals in 2014 to 255 in 2015. This year, Ms Yee is forecasting an increase of M&A activity for E&P companies as hedges expire. “That’s going to depend on a company-by-company basis and what remaining levers they have to pull,” she said. However, if oil prices remain around $40/bbl, the number of M&A deals is much more likely to go up. “It feels like the conditions are ripe in 2016 for more activity to occur.”

Most transactions will be focused on North America this year as E&P companies look to develop known assets with proven reserves, according Deloitte’s 2015 Oil & Gas Year-End M&A Report. Operators are focusing on fields that are already producing, such as unconventional oil and gas assets in the US, Ms Yee said. This trend would remain consistent with 2015, when 60% of announced deals were in the US and Canada. “There are a lot of wells out there that have been drilled but not completed and could be brought online in a shorter time frame,” she said.

For oilfield service companies and drilling contractors, M&A deals decreased from 120 transactions in 2014 to 36 in 2015. The total announced value for M&A deals amounted to $68 billion in 2014 and $24.8 billion in 2015. Deloitte’s report predicts larger oilfield service companies will be better able to survive the downturn and position themselves for a possible recovery. Smaller niche service providers will exit the market this year, the report predicted.