Drilling Tools Industry Newsletter

U.S. unconventionals will be crucial for oil majors in the near future and the majors are taking note. In a new report released by Wood Mackenzie, the potential of unconventionals in the Lower 48 is examined by looking at five U.S. majors (BP, Chevron, Equinor, Exxon Mobil, and Shell). “Following BP’s $10.5 billion deal with BHP, all of the supermajors have a footprint in the Permian Basin, and are poised to deliver an unprecedented phase of production growth that will see output reach new highs over the next decade,” In terms of value and volume, tight oil and shale gas will be essential to the majors’ portfolios. By the mid-2020s, U.S. unconventionals will generate $15-$20 billion of yearly cash flow and account for 20 percent of total upstream value. “U.S. unconventionals will drive the majors’ output to new highs,” said Martin. “Their investment in the resource theme is set to nearly double over the next five years, underpinned by tight oil.” The big player here seems to be ExxonMobil, who has the most acreage, biggest resource and highest peak production. “Underpinned by its low-royalty Permian position, Chevron possesses the most attractive Internal Rate of Returns (IRR) on new U.S. conventional projects among the majors,” Martin said. “Its future investment in the resource theme of $54 billion is second only to ExxonMobil.” We expect the majors to continue to expand their footprint in tight oil, and the Permian inparticular, over the coming decade. Any increase in the majors’ share of Permian output will have knock-on ramifications for global supply,” Martin said. “However, other factors driving the majors’ strategies in unconventionals competition for capital, portfolio mix, balance sheet strength, cost advantages, shifting investor sentiment will have a much greater impact.”

US independent Fieldwood Energy has taken a Rowan ultra-deepwater drillship for at least one year for work in the US Gulf of Mexico. The R-class Rowan Reliance will start the firm one-year charter in the first quarter, with Fieldwood also holding three 90-day extension options. The unit is currently warm-stacked off Louisiana. Rowan also saw US independent Cantium extend its charter with the Rowan jack-up EXL III for another three months, also in the US Gulf. The unit is currently with US independent Freeport-McMoRan in the US Gulf for a one-well commitment, having come off a charter with Cantium, but was due to go back to Cantium for six months after that well. Cantium now also has two six-month extension options after the firm nine-month charter.UK supermajor BP has extended its deal with the Rowan jack-up Joe Douglas in Trinidad & Tobago for one well, set to take around 76 days. BP also holds a single two-well extension option on the unit.

Talos Energy Inc., Houston, entered into a transaction with Hokchi Energy SA de CV, a subsidiary of Pan American Energy LLC, to cross-assign its participating interest (PI) in Block 2 and Hokchi’s PI in Block 31. Both blocks are in the Sureste basin offshore Mexico. Talos will assign a 25% PI in Block 2 to Hokchi in exchange for a 25% PI in Block 31, immediately to the south of Block 2. Hokchi will be the operator of both blocks and Talos will own a 25% PI on Block 2 and a 25% PI on Block 31. The swap is a way to aggregate and accelerate the investment in various prospects existing in both blocks, specifically the Acan (formerly known as Bacab) prospect in Block 2, where the first of a two-well exploration campaign will begin in second quarter 2019, Talos said. Soon thereafter, Talos plans to participate in two wells in Block 31.

Earthstone Energy, Inc. will acquire assets in the Midland Basin through two agreements for a cash and stock purchase price of $950 million ($650 million cash plus $300 million stock). In one deal, Woodlands, Texas-based Earthstone will acquire producing and non-producing oil and gas assets in the northern Midland Basin from Sabalo Energy. In a separate deal announced Oct. 17, Sabalo agreed to acquire well-bore interests by Shad Permian part of a drilling joint venture between the two companies. As a result of both transactions, referred to as the Sabalo Acquisition, Earthstone will acquire 20,800 net acres in the Midland Basin as well as 488 gross operated horizontal drilling locations and 349 gross non-operated horizontal drilling locations. The Sabalo Acquisition will significantly expand Earthstone’s footprint in the Midland Basin. “The Sabalo Acquisition adds strong cash flow generation and increases our footprint in the Midland Basin by 69 percent and includes substantial operated acreage with high working interests,” Earthstone president Robert J. Anderson stated in a release. "This larger scale of operations combined with being a much bigger company should drive a number of additional benefits as we now have the ability to secure dedicated services and focus on further improving corporate and field-level operating efficiency.

The Noble Tom Madden drillship arrived offshore Guyana on Friday. The 752 ft vessel was contracted by ExxonMobil Guyana to undertake exploration activities in the 6.6 million acres Stabtoek Block where a record 9 discoveries have already been made, amounting to more than 4 billion barrels of recoverable oil. ExxonMobil Guyana’s Senior Director, Public and Government Affairs, Deedra Moe, told OilNOW on Friday that the company is excited about the Tom Madden’s arrival OilNOW understands that the vessel will begin drilling for oil at the Pluma 1 prospect early November. Its drilling programme offshore the South American country includes two firm wells, plus three optional wells. The Tom Madden has a water depth of 10,000 ft and drilling depth of 40,000 ft. The vessel, built in 2014 by Hyundai Heavy Industries, will be ExxonMobil’s third drillship to operate in the Stabroek Block. The Noble Bob Douglas and the Stena Carron have been operating off the Guyana coast over the last several months.

US independent Freeport-McMoRan has hired a Rowan jack-up for a one-well campaign in the US Gulf of Mexico. The Rowan EXL III is expected to start work for Freeport-McMoRan at the end of October, according to the contractor's most recent fleet status report. The LeTourneau 116 unit has been idle since August after rolling off a contract with privately held Cantium but has been on rate with Freeport-McMoRan since the beginning of October "while waiting on whether to move," Rowan said. Once the work wraps up, the rig will go back to work for privately held Cantium in early November. That contract is scheduled to last for six months.

Drilling permit activity in Colorado is on pace for a record high in 2018 as producers brace for the possibility of a ballot initiative known as Proposition 112 passing. Oil and natural gas companies filed 7,381 drilling applications for new wells through Monday according to data from the Colorado Oil and Gas Conservation Commission. The vast majority of those were filed for the Denver-Julesburg Basin, which accounts for 7,315 of the permits applied for and received so far this year, according to S&P Global Platts Analytics. For all of last year, just 5,564 drilling permits were issued or applied for in the Denver-Julesburg Basin, which was higher than every other year prior. Multiple producers have indicated they are applying for drilling permits at such an accelerated rate to prepare for the possibility of Proposition 112 receiving public approval on November 6."We've gone through scenarios of how we could still produce if this passed such as drilling three-mile laterals," said Scot Woodall, CEO of the Denver-based HighPoint Resources. "We've also gone out and gotten as many permits for drilling as we can. We've tried to plan, but we're hoping the industry will defeat it." Strong internal rates of return per well in the Denver-Julesburg Basin are also likely driving the increase in permitting activity as well. October IRRs are currently at 46.2%, trailing only the Permian Basin, STACK, Eagle Ford oil window and the Bakken Shale, according to Platts Analytics. IRRs are based on half-cycle analysis, which excludes the expenses associated with exploration and development (sunk costs) and federal income tax.

Tullow Oil and its partners in the Orinduik block off Guyana are considering the possibility of drilling a second well on the tract next year, in addition to the one planned for the third quarter 2019. The Anglo-Irish independent and partners French supermajor Total and London-listed junior Eco Atlantic Oil & Gas are "in discussions to accelerate (their) work programme" on the block, Eco said on Friday. The block lies next door to ExxonMobil's prolific Stabroek block, which has thrown up nine oil discoveries so far, with estimated recoverable resources on Stabroek in excess of 4 billion barrels of oil equivalent. Eco said the partners are considering an additional well on the tract next year, but did not say if this would come before or after the well that was originally planned to spud in the third quarter of 2019. It is believed that the partners were planning to spud their first well on the Latuk (ex-Amalia) prospect. "Additional announcements will be made once drilling plans and targets selection are confirmed by the partners," Eco said. Tullow operates Orinduik on 50% and is joined by Total on 25% and Eco on 15%. Total farmed into the block last month after taking up its option to take a 25% interest from Eco for $12.5 million.

Calgary-based Vermilion Energy has acquired acreage in Wyoming’s Powder River basin, expanding the company’s footprint in the region in the third quarter. In a $186 million cash deal, Vermilion gained 55,700 net acres in Campbell County with production of 2500 barrels of oil equivalent per day. The company has identified 93 future drilling locations targeting the Turner and Parkman tight sandstone formations. The new addition is around 40 miles north-west of Vermilion’s current operations. The acquisition bumped up the company’s US production for the third quarter by 280%, booking average third quarter output of 2979 boepd. Vermilion plans to develop the acreage using horizontal wells and multi-stage fracks and expects to drill eight light oil wells in 2019.

Three years ago, Allen Startz found himself in an unwanted kinship with thousands of other oilfield workers in South Texas’ Eagle Ford shale laid off with few prospects nearby. He left his home in Bryan to work in the Permian Basin in West Texas, making plenty of money, but growing exhausted from the grueling 450-mile trip he made every couple of weeks to visit his family, whom he missed dearly. Today, however, he wakes up in his own bed each morning and heads to a job operating oilfield services trucks in the northeastern Eagle Ford, just 30 miles away. On the 10th anniversary of the first discovery in the Eagle Ford this October, drilling is more active than at any time since the collapse of crude prices in late 2013. Oil companies, contending with rising costs and shortages of workers, materials and pipelines in the Permian, are beginning to make new bets on the Eagle Ford’s 90 million-year-old shale rock. In the communities surrounding the formation, “I’d say it’s a rebirth,” said Rick Saldana, production superintendent for SM Energy, a Denver company drilling near Catarina, not far from the Mexican border. “It’s not a boom, but there’s a resurgence here in the Eagle Ford.” Major Houston energy companies such as ConocoPhillips and Marathon Oil, which both have holdings in the Permian, are pivoting to the Eagle Ford. BP, meanwhile, is poised to become one of the top players in the Eagle Ford when it closes its $10.5 billion acquisition of the Australian mining company BHP Billiton’s Texas shale holdings within the next few days. About 100 drilling rigs are operating in the Eagle Ford. WildHorse Resource Development is targeting the northeastern section of the shale, near College Station, where it holds 400,000 acres and has five rigs operating.

The need for an oil production rebound is Mexico's most obvious economic reality. Mexico’s oil sector has been in free fall since the 2004 peaking of Cantarell in the shallow waters of its Gulf, once the second largest oil field in the world only behind Saudi Arabia’s Ghawar. Since then, Mexico’s production has plummeted nearly 45 percent to around 2 million barre ls per day. The decline of Mexico’s oil production has been the impetus for a historic 2013 Energy Reform to deregulate and allow significant foreign investment. The hope is to install real competition for state-owned energy monopolies. Current Energy Minister Joaquin Coldwell says that a $640 billion investment is needed to expand Mexico’s oil production 50 percent to over 3 MMbpd. Pemex has long lacked the ability to stem the decline, so outside help is absolutely essential. Simply put, major U.S. investment and technical expertise is the only way that Mexico’s fading oil industry can return to former glory. With a potential 60-70 billion barrels of petroleum in the Gulf, Mexico’s deepwater opportunities are as good as any in the world. The shale resource is massive too, but new domestic oil production overall is being hindered by lower oil prices, security risks, rampant corruption, governmental price controls, little to no invest-ment protection, and an emerging political climate that has been vocally anti-reform. The need for an oil production rebound is Mexico’s most obvious economic reality. Although down from 40 percent a decade ago, oil sales still account for 25 percent of federal revenues. New oil production is the cornerstone of a fast growing country where 50 percent of the people are poor. Mexico’s reliance on the U.S. for 65 percent of its gas supply is increasingly problematic. Well beyond the already federally approved 15 billion cubic feet per day of U.S. LNG export projects, there are another 14 projects with a whopping 26 Bcf/d of export capacity under review. Mexico is understandably concerned that loads of gas will be leaving the U.S., so new domestic oil production is imperative to be more self-sufficient in natural gas.

An Australian company is drilling new wells in an oil formation that straddles southwest Mississippi and southeast Louisiana, the first new wells drilled in about three years, after a crash in oil prices dried up activity. Australis Oil & Gas Ltd. announced earlier this month that it had started drilling the first of at least six planned wells near Gillsburg, Mississippi. The company bought 81,000 acres of leases in the region in 2016 and 2017, adding to an interest it already owned. The company says it picked well sites in the most productive and proven part of the Tuscaloosa Marine Shale. It says it plans to spend $43 million in borrowed money on drilling, which would be an average well price of about $7 million, less than the $10 million-plus that was the common cost of a well in the region during an earlier burst of drilling. The new drilling has come as the price of a barrel of oil has risen above $70 at points in recent weeks, the highest price since 2014. That’s about the price level that the other major operator in the field, Houston-based Goodrich Petroleum, said last year is needed to make drilling profitable. Goodrich is currently focused on drilling natural gas wells in northwest Louisiana and east Texas. Australis says it has hired a Nabors Industries drilling rig to drill up to six wells, with an option for more. The company plans to drill a pair of wells from each location, cutting expenses while starting production in two separate leases. Once a well is drilled in a lease unit, the company has secured rights for as long as the well produces.

Global oil and gas development spend needs to increase by around 20 percent, to about $600 billion, to meet future demand growth and ensure companies sustain production next decade. That’s according to Wood Mackenzie, which says development spend will increase five percent this year, after a two percent rise on 2017. WoodMac forecasts investment to rise from a low of $460 billion in 2016 to just over $500 billion in the early 2020s, far below the $750 billion peak in 2014. “Four years of deep capital rationing have had a severe impact on resource renewal, especially in the conventional sector,” Tom Ellacott, senior vice president of corporate research at WoodMac, said in a company state-ment. “Companies are rightly cherry-picking the best conventional projects in their portfolios for greenfield develop-ment. But not enough new high-quality projects are entering the funnel to replace those that have left,” he added. “Conventional growth inventories have shrunk during the downturn, WoodMac highlighted, stating that global pre-FID conventional rese rves now only cover two years of global oil and gas production. The energy research and consultancy group stated that “bigger and better” conventional projects will ultimately be required and said exploration success will also be crucial to replenishing depleted conventional inventories. WoodMac said investment in conventional, deepwater, U.S. shale gas and oil sands will be “well below” pre-downturn levels, with only U.S. tight oil “set for consistent investmen t growth over the next few years, driven by the Permian”. Last month, in a statement posted on WoodMac’s website, WoodMac Chairman and Chief Analyst Simon Flowers warned that the industry isn’t finding enough oil. “Guyana is one of the very few giant oil discoveries made during the downturn. Fact is, we need more Guyanas, a lot more, and we need them soon. Without them, the oil market is in danger of tightening in the not too distant future.” he stated.