GAO: Water Supply Poses Obstacle to Green River Oil Shale Dev't

- GAO: Water Supply Poses Obstacle to Green River Oil Shale Dev't

Thursday, September 08, 2011
Rigzone Staff

The Green River formation – an assemblage of more than 1,000 feet of sedimentary rocks that lie beneath parts of Colorado, Utah and Wyoming, is estimated to contain up to 3 trillion barrels of oil – or an amount equal to the world's proven oil reserves. However, extracting these oil shale resources is expected to require substantial amounts of water and could impact groundwater and surface water.

The U.S. General Accountability Office (GAO) reported that, while U.S. oil shale development could have significant impacts on the quality and quantity of water resources, the magnitude is unknown because technologies are not yet commercially proven, the size of a future industry is uncertain, and knowledge of current water conditions is limited.

Commercial oil shale development requires water for numerous activities throughout its life cycle, but estimates vary widely for the amount of water needed to commercially produce oil shale primarily because of the unproven nature of some technologies and because the various ways of generating power for operations use differing quantities of water.

The thickest and richest oil shale within the Green River formation exists in the Piceance Basin of northwest Colorado and the Uintah Basin of northeast Utah. GAO reported that water is likely to be available for the initial development of an oil shale industry but that the size of an industry in Colorado or Utah may eventually by limited by water availability.

"Water limitations may arise from increases in water demand from municipal and industrial users, the potential of reduced water supplies from a warming climate, the need to fulfill obligations under interstate water compacts, and decreases on withdrawals from the Colorado River system to meet the requirements to protect threatened and endangered fish species," said Anu K. Mittal, director of GAO's natural resources and environment team, in testimony before the House of Representatives' subcommittee on energy and mineral resources in Grand Junction, Colo. on Aug. 24.

Some analysts project that large scale oil shale development within Colorado could require more water than is currently supplied to over 1 million residents of the Denver metro area and that water diverted for oil shale operations would restrict agricultural and urban development. Potential water demand is further complicated by the past decade of drought in the West and projections of a warming climate in the future, GAO noted.

In the absence of effective mitigation measures, water resources could be impacted by disturbing the ground surface during the construction of roads and production facilities, withdrawing water from streams and aquifers for oil shale operations, underground mining and extraction, and discharging waste waters produced from or used in such operations, Mittal said.

About 72 percent of this oil shale is located beneath federal lands managed by the Department of the Interior's Bureau of Land Management, making the federal government a key player in potential development of this resource. The federal government through the Department of Energy and Interior sponsors research on the impacts of oil shale on water resources.

However, nearly all the officials and experts that GAO contacted said that there are "insufficient data to understand baseline conditions of water resources in the oil shale regions of Colorado and Utah and that additional research is needed to understand the movement of groundwater and its interaction with surface water," GAO reported. Federal agency officials also told GAO that they seldom coordinate water-related oil shale research among themselves or with state agencies that regulate water.

Interest in oil shale as a domestic energy source has waxed and waned since the early 1900s. The Energy Policy Act of 2005 directed BLM to lease its lands for oil shale research and development. In June 2005, BLM initiated a leasing program for research, development and demonstration (RD&D) of oil shale recovery technologies; by early 2007, six small RD&D leases had been awarded, including five in the Piceance Basin and one in Uintah Basin.

Another significant challenge to oil shale development is the technology to economically extract oil from oil shale. The rock needs to be heated to temperatures between 650 and 1,000 Fahrenheit to extract the oil, or retorting. Retorting can be accomplished either by mining oil shale, bringing it to the surface, and heating it in a vessel known as a retort. While this process is done to a limited extent in Estonia, China and Brazil, a commercial mining operation with surface retorts has never been developed in the U.S. because the oil it produces competes directly with conventional crude oil, which historically has been less expensive to produce.

The other method, the in-situ process, involves drilling holes into the oil shale, inserting heaters to heat the rock, and then collecting the oil as it is freed from the rock. Some in-situ technologies have been demonstrated on very small scales, but other technologies have yet to be proven, and none has been shown to be economically or environmentally viable.

GAO's review of available studies indicates that expected total water needs for the entire life cycle of oil shale production range from about 1 barrel (or 42 gallons) to 12 barrels of water per barrel of oil produced from in-situ operations, with an average of about five barrels, and from about two to four barrels of water per barrel of oil produced from mining operations with surface heating, with an average of about three barrels.

Additional economic challenges include transporting oil produced from oil shale to refineries because pipelines and major highways are not prolific in the remote areas where oil shale is located, and the large-scale infrastructure needed to supply power to heat oil shale is lacking. Average crude oil prices also have been lower than the threshold necessary to make oil shale development profitable over time. The influx of workers associated with such projects, as well as their environmental impact, also are issues.

While industry has focused primarily on overcoming technological challenges and trying to develop a commercially viable operation, "the uncertainties associated with the impacts that a commercially viable oil shale industry could have on water availability and quality that should be an important focus for federal agencies and policymakers going forward," Mittal said.

Colorado Reps. Scott Tipton and Doug Lamborn testified at the oversight field hearing that the Obama Administration has repeatedly delayed and hindered oil shale development to the detriment of local economies, job creators and "American families struggling with high energy costs."

"The United States is blessed with tremendous oil shale resources – and we have appropriately been called the 'Saudi Arabia' of oil shale," said Lamborn, noting that the Western U.S. may hold more than 1.5 trillion barrels of oil, enough to supply the U.S. with energy for the next 200 years.

Dan Whitney, heavy oil development manager for Shell Exploration and Production Company, said that the lack of policy and regulatory consistency from one administration to another makes the investment climate even more risky and potentially untenable.

Gary Aho, representing the National Oil Shale Association, said that industry " needs a clear, consistent federal program and a national commitment to develop oil shale. Access to lands and regulatory certainty are crucial to companies starting a new, capital intensive industry."

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Exxon Mobil Estimates Oil spill in Yellowstone River will Cost Over $42 Million

- Exxon Mobil Estimates Oil spill in Yellowstone River will Cost Over $42 Million



Aug 22, 2011

Exxon Mobil (NYSE:XOM) Pipeline told federal regulators that its oil pipeline spill into Montana's Yellowstone River will cost an estimated $42.6 million.

The July 1 pipeline break near Laurel spilled about 42,000 gallons, or 1,000 barrels, of crude oil into the scenic waterway.

Exxon Mobil's cost estimate includes $40 million for emergency response work and $2.5 million for damage to public and private property. The company valued the lost oil at $100,000.

The company announced last week that the clean up might continue for several more months.

Exxon Mobil (NYSE:XOM) has a potential upside of 30.6% based on a current price of $70.78 and an average consensus analyst price target of $92.46.

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Entek Launches Green River Basin Work Program

- Entek Launches Green River Basin Work Program

Tuesday, July 19, 2011
Entek Energy Ltd.

Entek announced the commencement of its Green River Basin work program for 2011.

DHS Rig-18 has spudded the Battle Mountain 14-10L well, which is the first of a minimum 3 well Niobrara Shale Oil appraisal drilling program in 2011. Battle Mountain 14-10L was selected from 7 currently permitted well locations based on close proximity to the Battle Mountain 14-15 well which flowed oil last year against all odds from a severely damage well bore (drilled by the previous operator). Subsequent wells in the program will be located based on drilling results, local operating season constraints and field operational considerations.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas NL holding 45%. Entek is the Operator of the GRBJV. As a result of continued leasing activity and ongoing lease maintenance the GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

The wells planned in the 2011 appraisal program will be drilled vertically to intersect the oilprone Niobrara Shale which can be up to 1,100 ft thick in the area. The wells are expected to penetrate the brittle naturally fractured bench intervals within the Niobrara section that have been proven as porous and permeable reservoirs in offset wells. As an example the Sierra Madre 12-20 well owned by Anadarko which is approximately 8 miles from the 14-10 well, had initial production of around 550 BOPD, has recovered in excess of 355,000 BO and is still on production. In addition, the fractured igneous intrusive reservoirs that are present in this area will be further
evaluated. The Company's Focus Ranch 12-1 well (which was tested in 2009 at a cumulative rate of 240 BOPD and 2.75 MMCFD) has already indicated the potential of the igneous intrusive reservoirs in the area.

The primary objectives of the 2011 vertical well appraisal program are to:

• establish deliverability and commercial production of the oil prone Niobrara Shale;
• identify the most prospective Niobrara intervals;
• gather technical information necessary to design and execute effective fracture stimulation treatments; and
• select which intervals to target with both vertical and horizontal wells in 2012 as part of the continued appraisal and development program.

The Company is working closely with Halliburton to design fracture stimulation treatments for at least one interval in each well this year with scheduled slots available from August. Initial flow test results from these wells are not expected to be available immediately after reaching total depth and logging. Rather, weekly announcements will be made each Thursday morning where drilling progress, fracture stimulation, testing and completion operations for each well will be updated as these operations will be occurring concurrently across all wells in the work program.

Interested parties are directed to review the Investor Presentation (to be presented to institutional investors from July) that was released to the ASX on July 14, 2011 for further information on the Niobrara Shale Oil Project in the Green River Basin as well as the Company's
update on its recent successful oil discovery in the Gulf of Mexico.

CEO and Managing Director Trent Spry commented, "It is exciting to have commenced our 2011 Green River Basin appraisal program. I am certain that our appraisal efforts in 2011 will provide the Company with the information and confidence it needs to accelerate appraisal and development in 2012. We are seeing increased industry activity across leasing, well permitting (both vertical and horizontal), and acreage acquisitions and transactions in the area as the attention shifts from the DJ Basin to the Green River Basin this
year. Industry activity and success will provide valuable information on the Niobrara in the GRB and is expected to have a significant impact on acreage value. I look forward to providing further updates from now until the end of the year on what is an exciting time for the Company."

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N.J. Pressures River Panel to Adopt Gas Rules

- N.J. Pressures River Panel to Adopt Gas Rules

Friday, July 15, 2011
The Philadelphia Inquirer
by Sandy Bauers

New Jersey is playing hardball with an interstate commission considering rules on natural gas drilling affecting the Delaware River.

At two recent meetings of the Delaware River Basin Commission (DRBC) -- one of them Wednesday -- the New Jersey representative, John Plonski, said the state might withhold payments to the financially strapped commission if it failed to vote on the rules at its next meeting, in September.

Critics said the state was improperly engaging in strong-arm tactics.

"It's shocking that a state would pull this kind of bullying tactic that amounts to extortion," said Tracy Carluccio of the Delaware Riverkeeper Network, an environmental-advocacy group.

A spokesman for the New Jersey Department of Environmental Protection, where Plonski is the assistant commissioner for water resources management, said Plonski merely wanted the commission to act.

"All we're doing is putting a little pressure on the DRBC, saying let's make sure that you don't sit on this issue, that you assess it properly and come to a decision," said Larry Ragonese.

"The No. 1 complaint about government is that it does not act," he said. "We're trying to have government be responsive in a timely fashion."

The industry has consistently urged the commission to act so that drilling can proceed.

The DEP comments struck Jeff Tittel of the New Jersey Sierra Club as disingenuous. "Then how come they don't act" on other environmental measures, Tittel said. "Want me to go down the list of things they're holding up?"

When it comes to environmental protection, the DEP waits, he said, "and when it comes to what polluters want, they think, we've got to hurry up and do it."

The commission, an interstate agency formed by a federal compact, regulates water quality and quantity in the area drained by the Delaware River and its tributaries, which collectively provide drinking water to Philadelphia and New York City.

Its five members are states with land in the basin -- Pennsylvania, New Jersey, New York, and Delaware -- plus a representative from the Army Corps of Engineers.

Most of the upper basin is atop the Marcellus Shale formation, rich in natural gas. Thousands of drilling leases have been filed in northeastern Pennsylvania within the watershed.

The commission has enacted what amounts to a moratorium on gas drilling in the basin until regulations are in place, and that has led to a tug-of-war not only about the regulations but also how fast the commission should adopt them.

In December, the commission proposed a set of regulations that environmental groups said were weak and the industry said were onerous and unnecessary.

A public comment period that would have ended March 15 was extended to April 15.

By then, the commission had received nearly 70,000 submissions. Now, the staff is categorizing them and preparing a document to respond to them, DRBC spokesman Clarke Rupert said.

Next, revisions might have to be made to the proposed rules.

Rupert said that he could not speculate how long this would take, but that for months the commission staffers have been saying that the earliest they could have something ready for the commission to vote on would be its September meeting.

Whenever the staff work is completed, the commission has a number of options. It could vote on what is presented. Or, if significant revisions are proposed, it could vote to seek more comment.

"Shouldn't the timing of the release of the natural gas rules be based on a careful review and scientific analysis of the comments that were received by the commission?" Carluccio said. "Not when one state arbitrarily sets a deadline."

Ragonese said that New Jersey also wants the regulations to be based on science and fact, and that DEP Commissioner Bob Martin has always said he wants to protect the river.

"We think a lot has been brought to them," Ragonese said. "They have had good time to consider it. We would really like to get something moving."

Pennsylvania and New York officials declined to comment. A spokesman for the Army Corps said its representative would be prepared to vote at the September meeting; he did not say what the vote would be.

The Delaware representative on the commission, Kathy Stiller, water director for the Department of Natural Resources and Environmental Control, said: "We are still looking at the deadline issue and haven't taken a position on it yet. Delaware's goal is to make sure we get the regulations technically correct. We do recognize that some guidance needs to be in place sooner rather than later."

If New Jersey were to withhold funds, the commission could be in a tight spot.

Under the compact, each of the five members pays a "fair share" of the annual budget. For the fiscal year that began July 1, the amounts were $893,000 each for Pennsylvania and New Jersey (25 percent of the total each), $626,000 for New York (17.5 percent), $447,000 for Delaware (12.5 percent), and $715,000 for the federal government (20 percent).

But although the commissioners commit to these amounts, they may never be funded.

With the exception of one year since 1996, the federal government's amount has never been appropriated. The U.S. government is more than $9 million in arrears.

New York's fiscal year began April 1, and it appropriated $355,000, slightly more than half its share.

Pennsylvania, Delaware, and New Jersey have budgeted their full amounts.

Even with that, the commission had to make up a shortfall of more than $400,000 this year, Rupert said, from "undesignated reserves."

Meanwhile, even as the Christie administration is pushing for the DRBC to act, state legislators want to put the brakes on the industry.

On June 29, the Assembly and Senate overwhelmingly passed legislation to prohibit a gas-extraction method known as hydraulic fracturing -- or "fracking" -- in the state. In effect, it would ban most drilling in the state.

Gov. Christie has a 45-day window to act on the legislation.

Copyright (c) 2011, The Philadelphia Inquirer

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Aroway Boosts Production at Peace River Arch Prospect

- Aroway Boosts Production at Peace River Arch Prospect

Monday, June 27, 2011
Aroway Energy Inc.

Aroway reported that the Company's first well of the 2011 drilling program has been on a stable production for 20 days and is producing oil, natural gas liquids and gas from the targeted Leduc formation. The well, which is located in Peace River Arch oil and gas exploration prospects, was placed on restricted flow rate in late May, and in early June the well began to produce oil. Based on the present well pressures and the operators' conservative production practises, the well is expected to stabilize at a rate of 400 boe/day, 200 boe/day net to Aroway. The oil produced from the well is produced and pipelined to a facility owned by the Company's Joint Venture Partner and well operator. Aroway is paying 50% of all costs associated with this well to earn a 50% interest in the well.

The Company also reports that total depth has been reached on the third well of the 2011 drilling program. The well encountered numerous potential hydrocarbon bearing zones in the Triassic deposits and based on the drilling logs, the well will be evaluated in each of the prospective zones. A 100 meter pipeline tie-in has begun and will be complete in the next week, and the well will be production tested directly into the pipeline. Aroway is paying 50% of all costs associated with this well to earn a 50% interest in the well.

Testing on the Company's second well of the 2011 drill program will commence as soon as the roads dry out as heavy rains have hit the area over the past week. We are confident the service rig will be on the location and testing will begin within the next 10 days.

Chris Cooper, President of Aroway commented, "We were quite confident that our first well of 2011 would end up as an oil well as soon as the gas cap was produced. We will have concrete Company production numbers in coming weeks which will bring us much closer to our year-end target of 600 boe/day."

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Sun River Begins Production at Haynesville Well

Sun River Begins Production at Haynesville Well

Tuesday, April 05, 2011

Sun River Energy Inc.

Sun River announced it turned the Neal Heirs # 1 well to production on March 31, 2011.
The Neal Heirs # 1 well (API # 42-365-37706) is drilled vertically to a total depth of 11,057 feet in Panola County, Texas. The well is completed in the Haynesville Shale geological formation at 10,214' to 10,716'. The well is located within the prolific Carthage Field. The well initially shut-in at 5,386 PSI tubing pressure after fracture treatment. Presently, the well is producing both natural gas and crude. The well is flowing at 2,256 MCF a day with a constant flowing tubing pressure of 3,320 PSI.

Sun River Operating, Inc. operates the well. Sun River Energy, Inc. owns a 77.5% working interest in the well.

Donal R. Schmidt, Jr., the Company's CEO and President, stated, "It is always a relief to have your first well in a project come on like the Neal Heirs #1. The well exceeded our team's initial expectation in every way. We are presently preparing to drill two more wells in adjoining gas units and expect similar results. The Neal Heirs #1 confirms my belief that our team has what it takes to consistently develop deep unconventional gas at an attractive cost. Our preliminary estimate is that the net finding and development cost per MCFE of proved gas in this well will be around $1.24. This will place us at the top of low cost producers in our sector of the natural gas market."