Four wastewater wells tied to Oklahoma quake surge, study says

Four wastewater wells used in oil and natural gas drilling may be responsible for triggering 20% of all earthquakes in the central and eastern U.S. from 2008 to 2013, according to a study published in the journal Science.

The wells are used to dispose of high volumes of wastewater released from underground rocks when they are fractured using modern oil-drilling techniques. The four wells are likely responsible for a dramatic rise in earthquakes near Oklahoma City since 2009, according to the research.

Oklahoma has had more earthquakes than California so far this year, making it the most seismically active state in the continental U.S. and raising suspicions that drilling activity is influencing a surge in temblors there. The state had 238 earthquakes with a magnitude 3.0 or greater through June, more than double the number in California, which has historically ranked second in earthquakes behind Alaska.

Scientists studied wastewater-injection volumes, geologic information and data from earthquake sensors to show that fluids pumped into the wells increased underground pressures and spread them. The area of elevated underground pressure grew in a way that overlapped with a “migrating front” of earthquakes centered near Oklahoma City.

The data showed that water pumped into wastewater wells can increase and affect underground pressures as far away as 35 km (22 miles), potentially triggering earthquakes at faults that would have previously been considered too distant.

Researchers from Cornell University, University of Colorado, Columbia University, and the U.S. Geological Survey collaborated on the study.

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Towns in New York state win right to ban fracing

New York’s cities and towns can block hydraulic fracturing within their borders, the state’s highest court ruled, dealing a blow to an industry awaiting Governor Andrew Cuomo’s decision on whether to uphold a six-year-old statewide moratorium.

The state Court of Appeals in Albany today, June 30, ruled 5-2 to uphold the dismissal of lawsuits challenging bans in the upstate towns of Dryden and Middlefield.

The towns engaged in a “reasonable exercise” of their zoning authority when they banned oil and gas extraction and production, the court said in an opinion by Judge Victoria Graffeo.

“The towns both studied the issue and acted within their home-rule powers in determining that gas drilling would permanently alter and adversely affect the deliberately cultivated small-town character of their communities,” Graffeo wrote.

The ruling may lead the oil and gas industry to abandon fracing in New York as Cuomo considers whether to lift a statewide moratorium instituted in 2008 that he inherited when he took office. It might create a patchwork across the state of municipalities that do and don’t permit the process.

“These appeals are not just about whether hydrofracking is beneficial or detrimental to the economy, environment or energy needs of New York, and we pass no judgment on its merits,” Graffeo wrote. “These are major policy questions for the coordinate branches of government to resolve.”

Enlarging Cracks

Fracing, used in states from North Dakota to Pennsylvania, has helped push U.S. natural gas production to new highs in each of the past seven years, according to the U.S. Energy Information Administration. It has come under increasing scrutiny from environmental advocates.

Parts of New York sit above the Marcellus shale, a rock formation that the Energy Information Administration estimates may hold enough natural gas to meet U.S. consumption for almost six years.

The state barred fracing in 2008 while studying the environmental effects of the drilling method, which is allowed in more than 30 states.

N.Y. Bans

Since then, more than 75 New York towns have banned fracing while more than 40 have passed resolutions stating they support it or are open to it, according to Karen Edelstein, an Ithaca consultant affiliated with FracTracker Alliance, which analyzes the effects of oil and gas drilling.

Other jurisdictions are adopting similar laws. Beverly Hills in May became the first municipality in California to prohibit fracing. The industry also has sued the Colorado cities of Fort Collins, Lafayette and Longmont over bans.

Scott Kurkoski, attorney for a dairy farm in Middlefield that sued the township to overturn a ban passed in August 2011, argued to the Court of Appeals on June 3 that the state’s Oil, Gas and Solution Mining Law prevents local governments from enacting zoning ordinances that ban fracing. The dairy farm signed leases in 2007 to explore and develop natural-gas resources under the property.

Anschutz Lawsuit

In September 2011, Anschutz Exploration Corp., an affiliate of billionaire Philip Anschutz’s closely held company, sued Dryden over its ban after buying about 22,000 acres of gas leases there. Norse Energy, a Lysaker, Norway-based explorer whose U.S. unit filed for bankruptcy in December 2012, replaced Anschutz Exploration in the Dryden appeal.

Separate state judges dismissed the lawsuits challenging the bans in February 2012. Those rulings were affirmed by an intermediate appellate court in Albany in May 2013. A judge in Livingston County in April dismissed another lawsuit seeking to overturn a ban in Avon, a town of about 7,000 people south of Rochester.

While state law prohibits municipalities from passing laws or ordinances related to oil, gas and mining regulations, the zoning restrictions enacted in Dryden and Middletown don’t qualify as attempts to regulate the industry and aren’t preempted, the appellate court said in the May 2013 ruling.

Attorneys for the towns have contended they have the right to enact zoning laws as long as they don’t impede state regulations.

Municipalities’ Rights

Deborah Goldberg, an attorney for the nonprofit group EarthJustice representing Dryden, told the Court of Appeals on June 3 that the state legislature can take away municipalities’ rights to specific zoning laws, yet usually leaves protections in place when it does so.

Thomas West, an attorney for Norse Energy, said the industry may decide to turn its back on the state if local bans are allowed.

Cuomo, a 56-year-old Democrat, is trying to balance the prospect of the type of economic development seen in Ohio and Pennsylvania against claims by environmental groups that drilling will contaminate drinking water.

Cuomo took office in 2011. The following year he put Health Commissioner Nirav Shah in charge of studying how drilling may affect residents’ well-being. The governor had said he would base his determination on Shah’s conclusions.

Shah resigned in May to take a job with the Kaiser Foundation Health Plan in southern California, leaving the review to acting Health Commissioner Howard Zucker.

Joe Martens, head of the state’s Environmental Conservation Department, told state lawmakers in January that he won’t issue fracing regulations until at least April 2015, signaling that Cuomo probably won’t make a decision before he faces re-election in November.

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Oilfield set aside for U.S. Navy 99 years ago goes to auction

The U.S. government wants to sell a naval petroleum reserve field first set aside by presidential decree 99 years ago to ensure fuel supplies for American warships.

The Energy Department is seeking bids for the Teapot Dome field north of Casper, Wyoming, by Sept. 30, according to an offering document published on the website of Meagher Energy Advisors Inc. today, June 23. The field, which includes several layers of shale and oil wells more than 1 mile (1.6 km) deep, currently produces about 240 bbl of crude a day.

The Teapot Dome field was designated a naval reserve in 1915. The 9,481-acre parcel is the last such reserve still under control of the Energy Department, according to the offering document.

The field has several untapped layers of oil- and gas-soaked rocks that may be suitable for enhanced recovery techniques such as carbon-dioxide flooding, according to the offering. A data room with technical details about the geology of the field is scheduled to open on July 30.

The U.S. began divesting naval petroleum reserves in 1998, when it sold the Elk Hills field near Bakersfield, California, to Occidental Petroleum Corp. for $3.65 billion.

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GDI is awarded long term contracts by QP for two new land rigs

Gulf Drilling International(GDI), reported that it has been awarded two new contracts by Qatar Petroleum(QP) for the provision of drilling rig services. The new contracts will cover services to be performed by two new land rigs (GDI-7 and GDI-8) that GDI is in the process of acquiring from a rig builder based in the United States. Each contract will have a term of five years and the combined value of both contracts is 297 billion.

The two new land rigs (GDI-7 and GDI-8) are being custom designed according to QP’s specifications. GDI-8 will be GDI’s largest land rig, and at 3000HP, it will have the capability of drilling deeper wells and executing extended reach wells to a much greater distance. The new land rigs will also come with a number of ancillary assets that are required to support these operations including water well rigs, mobile cranes, trucks and trailers. The total investment is being financed from a local bank on competitive terms.

Construction of the two new land rigs will soon commence and the rigs are expected to be received, mobilized from the United States and placed into service during the second half of 2015. GDI’s onshore base camp, workshop, storage yards, warehouses and accommodation facilities are also being expanded to accommodate these new operations.

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Suncor approves facility to test water treatment, recycling technologies

Suncor Energy and five industry partners have announced an estimated $165 million funding commitment to sanction the construction of a dedicated Water Technology Development Centre (WTDC).

The WTDC, to be located at Suncor' s Firebag facility, will be used to test water treatment and further develop recycling technologies. The goal of the WTDC is to shorten the timeframe needed to develop and commercialize new technologies, as well as significantly enhance existing technologies.

"The WTDC will help us speed up the pace of innovation, while collaboratively managing the risks and costs of technology development," said Steve Williams, Suncor president and CEO. "We expect to see strong benefits by conducting different tests simultaneously, using process fluids in real world conditions to pilot new technologies and prove their commercial viability."

The centre is being pursued as a joint industry project convened under Canada' s Oil Sands Innovation Alliance (COSIA), with testing to begin by early 2017. In addition to Suncor, the partner companies include Canadian Natural Resources Limited, Devon Canada Corporation, Nexen Energy ULC, Shell Canada Energy and Husky Oil Operations Limited.

Knowledge

"Moving forward on the WTDC is a demonstration of the tangible progress that COSIA is making by bringing companies together to share knowledge and advance innovation," says Dan Wicklum, chief executive of COSIA. "The research and testing conducted at the WTDC will allow participating companies to test drive more technologies than could be evaluated by each company alone. This helps to deliver our vision of accelerated environmental performance improvement in Canada' s oil sands."

The structure of the joint industry project will see Suncor construct, own and operate the WTDC while collaborating with the other partners on design, construction and operations -- including specific tests. As a dedicated test facility, the WTDC is expected to overcome the barriers that are common to field testing at commercial production facilities, which are not typically designed to accommodate simultaneous testing of water treatment technologies.

Testing priorities will include minimizing fresh water use and maximizing reliability for steam assisted gravity drainage production. The facility is expected to provide industry with the opportunity to develop new ways of approaching water treatment and recycling, resulting in positive environmental, social and economic outcomes.

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Scotland may hold billions of barrels of shale oil, report says

Scotland may have billions of barrels of shale oil buried under the country’s most densely populated areas, geologists said June 30.

Scotland’s central belt, running between Glasgow and Edinburgh, may have 6 billion barrels of oil in place, according to a report by the British Geological Survey. While only a fraction of the resource will end up being viable, the deposits could supplement the UK’s 3 billion barrels of proven oil reserves, held mostly in North Sea fields off Scotland’s coast.

The oil and gas industry is central to the debate on Scotland’s independence before a referendum in September. The Scottish government says existing fields in the North Sea will underpin the economy of an independent nation, while opponents say declining production from offshore reserves leaves the country vulnerable.

“This report will give reassurance to investors who wish to explore for oil and gas onshore in Scotland,” said Ken Cronin, CEO of the UK Onshore Operators Group, an industry lobby. The resources “can help replace the UK’s growing dependency on imports and balance the decline of the North Sea.”

Bowland shale

Scotland’s shale gas potential is a fraction of northwest England, the report showed. Scotland’s central belt has shale gas in place of 80.3 Tcf, according to the middle estimate in the report. That compares with 1,300 Tcf in the Bowland shale in northwest England, according to research published by the British Geological Survey last year.

Exploiting the UK’s shale resources has been opposed by environmental campaigners and property owners concerned drilling techniques, including hydraulic fracturing, risk polluting water supplies. Britain’s greater population density will likely make production more difficult than in the U.S, where a shale boom has reversed declining oil and gas output.

The UK government is offering tax breaks to shale drillers to spur development of the resource as North Sea reserves dwindle. The Bowland basin in northern England may supply local natural gas demand for half a century at extraction rates of 10% similar to U.S. fields, according to a report last year.

“Only the broad shoulders of the UK can attract investment in new energy sources and maintain the UK’s position as one of the world’s great energy hubs,” said UK Energy Minister Michael Fallon.

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North Dakota crude oil production barrels past 1 MMbopd

North Dakota, which became just the fourth state to record oil production above 1 MMbopd, could see even stronger growth over the summer as improved weather makes life easier for drilling crews.

Output increased to 1,001,149 barrels a day in April, the state’s Department of Mineral Resources reported yesterday. Texas, California and Alaska have crossed the million-barrel mark. Only Texas remains above the state, at almost 3 MMbopd.

April oilfield work was hampered by heavy rain that shut roads and strong winds that closed down operations. Crews completed 200 wells during the month, and another 600 are already drilled and just waiting on hydraulic fracturing, or fracking. Better weather in the summer months should allow more new wells to start gushing oil.

“As the weather improves, operators should have full utilization of all their rigs, and possibly additional completion crews to whittle down the backlog,” Jonathan Garrett, an upstream analyst at Wood Mackenzie Ltd. in Houston, said in a phone interview today. “I wouldn’t be surprised to see quite a bit of production growth over the summer. It should be pretty impressive.”

Oil and gas from the Bakken and other shale formations helped the U.S. produce the equivalent of 87% of its energy needs in 2013, the highest level since 1985, according to data from the Energy Information Administration. The U.S. imported 7.7 MMbopd in 2013, the least since 1996.

Hydrocarbon-Rich

Most oil produced in North Dakota comes from the Bakken and Three Forks shale formations, layers of hydrocarbon-rich rock more than a mile beneath the Earth’s surface. High crude prices and improvements in drilling technology have helped companies like Continental Resources and Whiting Petroleum tap into the previously inaccessible shale.

Output from shale wells declines by 60% to 70% in the first year, according to Austin, Texas-based Drillinginfo Inc., faster than traditional wells. Because of the steep decline rate, companies need to finish new wells constantly. Bad weather can slow the completion process, curbing production growth.

Adverse Weather

In April, roads were shut for three days because of heavy rain, and there were nine to 11 days of wind blowing faster than 35 mph, too strong for completion work, Lynn Helms, the director of the state’s Department of Mineral Resources, said during a conference call with reporters yesterday. The weather in May and June has been much more benign.

“Permitting and drilling activity indicates that we’ll continue to see production grow and build well above 1 MMbopd,” he said.

Producers are also drilling better wells, Garrett said. They’re increasing horsepower and using more water and sand in the fracking process, which is helping to increase initial production and slow decline rates.

Bakken crude priced at Enbridge Inc.’s pipeline hub at Clearbrook, Minnesota, traded at a discount of $6.50 less than West Texas Intermediate in Cushing, Oklahoma, at 8:59 a.m. New York time, according to data compiled by Bloomberg.

About 30% of North Dakota’s oil left the state by pipeline and 63% by rail in April, according to the state’s pipeline authority. It’s the lowest percentage of rail transportation since September.

It costs $9 to $10 a barrel to transport oil by train to East Coast refineries, and $6 to $7 a barrel to rail crude to Washington plants, Tesoro Corp. said in a February presentation to investors.

The discount of Bakken crude priced at the wellhead to Brent crude, the benchmark for global waterborne crude, is about $20.71 a barrel, according to data compiled by Bloomberg.

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Encana sells Bighorn gas assets to Apollo as part of shift to oil production

Encana, Canada’s largest natural gas producer, is selling its Bighorn assets in Alberta to Apollo Global Management for about $1.8 billion as the company continues its shift into oil production.

The sale includes about 360,000 acres along with interests in pipelines, facilities and service arrangements. Total net proved reserves at the end of 2013 were approximately 1.1 Tcfe, about 75% of which is natural gas.

Encana has been selling gas fields and buying oil fields to boost profit by producing the more valuable fuel. It has sold or agreed to sell $4.1 billion of assets this year, according to data compiled by Bloomberg. Earlier this month, Encana paid $3.1 billion for Freeport-McMoRan assets in the Eagle Ford Basin in Texas, doubling its crude output.

“Bighorn is a high quality asset that has not been receiving significant investment in 2014,” Encana Chief Executive Office Doug Suttles said in the statement. “It should serve as an excellent foundational asset for Jupiter Resources.”

Apollo’s Jupiter Resources, based in Calgary, is a portfolio investment of funds managed by affiliates of the New York-based private-equity firm, which describes itself as “contrarian.”

Liquids-Rich Gas

“We are very excited about the opportunity to actively develop the Bighorn assets, one of North America’s premier liquids-rich natural gas projects,” Simon Bregazzi, CEO of Jupiter Resources, said in a separate statement.

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