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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South Africa Awaits Shale Gas Assessment Outcome

- South Africa Awaits Shale Gas Assessment Outcome

Thursday, September 08, 2011
OilPrice.com
by Charles Kennedy

As South Africa has very limited natural gas reserves, the country's Department of Energy is awaiting the outcome of an assessment of the nation's shale gas potential.

South Africa's Department of Energy Deputy Director General for Hydrocarbon Tseliso Maqubela said at the 4th annual Natural Gas Conference, "The truth that we have to face and effectively deal with is that South Africa has very limited gas reserves. We are awaiting the outcome of the assessment of the shale gas potential, which is currently estimated to be around 485 trillion cubic feet. There are also projects afoot to explore the potential of importing natural gas both as liquefied natural gas (LNG) and compressed natural gas (CNG) to meet our country's energy demands," BuaNews news agency reported.

The Department of Energy has noted environmentalists' concerns about the controversial hydraulic fracturing technique, also known as "fracking," used to liberate the natural gas from surrounding rock formations. Maqubela said that an interdepartmental task team was investigating the procedure's possible impact on the environment, led by the Department of Mineral Resources.

The Department of Energy is in the process of reviewing the 2001 Gas Act, with the regulation of LNG and CNG being reviewed as well as concepts for improving the nation's natural gas regulatory framework.

(Charles Kennedy is Deputy Editor of OilPrice.com. The original article appears here.)

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Foreign Companies Apply for Czech Shale Gas Exploration Permits

- Foreign Companies Apply for Czech Shale Gas Exploration Permits

Tuesday, September 06, 2011
OilPrice.com
by Joao Peixe

Following the lead of neighboring Poland, where shale gas exploration is already under way, foreign and local companies have applied for exploration permits in the Czech Republic.

Current applicants for the exploration permits include Basgas Energia Czech, a unit of the Australian-based exploration company Basgas and the Czech unit of British company Cuadrilla Morava, along with domestic oil and gas company Moravske Naftove Doly, Hospodarske Noviny newspaper reported.

Local Cuadrilla representative Stanislav Benada expects to hear from the Czech authorities about the applications in the autumn, but added that discussions with environmental officials regarding other possible exploration areas near the capital Prague indicated substantial resistance, commenting, "We are prepared to work with local authorities and hold meetings to explain the extraction process" before concluding that as yet no exploratory drilling has been approved and commenced, no one currently had an idea what shale gas reserves might be exploitable in the Czech Republic.

The Environment Ministry expanded on Beneda's observation, telling the media, "In the Czech Republic until now there has been no consideration of extracting natural gas from shale stone, and reserves of this type have not been found (or systematically searched for) or technically and economically evaluated."

(Joao Peixe is Deputy Editor of OilPrice.com. The original article appears here.)

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Entek Updates Activities in Niobrara Shale Oil Proj.

- Entek Updates Activities in Niobrara Shale Oil Proj.

Thursday, September 01, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The Frontier (secondary objective) has been successfully fracture stimulated. Limited testing has been performed before completion and testing operations start on the lowest of the Niobrara Benches in the well. Test results suggest the discovery of an oil prone sweet-spot in the Frontier Formation which is part of the Mowry Shale Resource Play. The play has been a secondary target across the Company's acreage since it tested hydrocarbons at an initial rate of 1.2 MMCFD and 10 BOPD in the Focus Ranch 12-1 well and since has shown significant oil and gas shows in each well where penetrated across the acreage.

Test results suggest that the 14 ft perforated zone in the Battle Mountain 14-10 well will be capable of around 20 BOPD and over 100 MCFD. It is most likely that the production from the Frontier will be comingled with production from the Niobrara once planned completion and testing operations in the well are complete. In the future the Frontier, like the Niobrara, is likely to become a candidate for horizontal drilling. The Company will provide an update as the appraisal program continues on the potential of the Frontier and Mowry Shale Resource Play across its acreage position.

The completion program for the Niobrara (primary objective), which includes fracture stimulation and testing, will be initiated this week with fracture stimulation planned around September 15.

Slater Dome (SD) Federal 24-9DL – The well has successfully reached its total depth of 8,300 ft after penetrating both the Niobrara and Frontier Formations. The well had significant oil and gas shows while drilling and was prepared for logging, with good hole condition reported. While pulling out of hole to run wireline logs a drill string connection mechanically failed. Operations are continuing to remove the drill string from the hole prior to logging.

C&C Cattle 18-8 – Location preparation is complete. It is anticipated that the rig will be mobilized from the 24-9 location to the 18-8 location over the next week. An additional rig is on standby to mobilize to the 18-8 location if operations on the 24-9 well take longer than expected.

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TGS Scores Seismic Survey in Utica Shale

- TGS Scores Seismic Survey in Utica Shale

Thursday, September 01, 2011
TGS-NOPEC Geophysical Co. ASA

TGS has awarded the acquisition of a 307 mi2 (795 km2) multi-client 3D project located onshore United States. The new seismic program, Firestone 3D, is designed to illuminate the Utica Shale play in Northeast Ohio and aid in the development of this unconventional play. Tidelands Geophysical Services is expected to begin acquisition on the project in 1Q 2012. Data acquisition is anticipated to take seven months.

The Utica Shale is a geologic formation located a few thousand feet below the Marcellus Shale that is characterized by a western oil phase, a central wet gas and an eastern dry gas phase. The new seismic survey is located over the wet gas/liquids rich portion of the Utica Shale. Many see the Utica Shale play as analogous to the prolific Eagle Ford Shale in Texas. The Utica Shale is thicker and more geographically extensive than the Marcellus Shale Trend and has already proven its ability to support commercial production.

"The use of 3D multi-client seismic by oil and gas companies in the development of the unconventional plays in the onshore United States has grown substantially in recent years. We have carefully watched the development of this market and are excited to expand our existing onshore library to include this 3D seismic data," said Robert Hobbs, CEO of TGS. "TGS continues to be successful in diversifying its multi-client library both by product as well as geography," continued Hobbs.

This multi-client program is supported by industry pre-funding.

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Ukraine, Shell Sign Shale Gas Exploration Deal

- Ukraine, Shell Sign Shale Gas Exploration Deal

Thursday, September 01, 2011
Dow Jones Newswires
KIEV

Ukraine Thursday awarded its first shale gas exploration contract to the Anglo-Dutch giant Shell in a deal worth up to $800 million, Ukraine's state gas exploration company said.

"In case of successful exploration work and the start of intense project development, Shell's total investment under the agreement may come to $800 million," Ukrgazvydobuvannya said in a statement issued after the signing.

Ukraine is widely believed to be one of Europe's largest holders of the new energy resource, with estimated reserves up to 1.5 trillion cubic meters, according to industry analysts.

No official estimate has been made and there is no confirmed figure of how much shale gas might be hidden in the six blocks awarded to Shell near northeastern city of Kharkiv.

Ukraine lacks the advanced technology necessary to produce the hard-to-recover resource and is also holding negotiations with such Western majors as the U.S. firms Chevron and ExxonMobil.

The former Soviet republic has few other natural resources and relies on Russia for most of its gas imports.

But it has been trying to lower its energy dependence on its neighbor since a price dispute temporarily cut Russian gas flows in January 2009 and is now focusing on other sources of energy that include coal.

"The agreement with Shell will be one of the first examples of Ukraine's successful cooperation in hydrocarbons development with an international energy company," Ukrgazvydobuvannya chief Yuriy Borysov said.

Ukrgazvydobuvannya said Shell would be operating in Ukraine through a joint venture but offered no other immediate details.

Copyright (c) 2011 Dow Jones & Company, Inc.

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DNR Secretary Spotlights 3rd Possible Shale Play in La.

- DNR Secretary Spotlights 3rd Possible Shale Play in La.

Wednesday, August 31, 2011
Louisiana Department of Natural Resources

Louisiana Department of Natural Resources (DNR) Secretary Scott Angelle said Wednesday that the energy exploration industry has begun work on developing yet another new oil and natural gas shale play in Louisiana – giving the state one proven and producing shale formation and two that are being watched closely as the early stages of activity begin.

The potential new interest area, spanning portions of North Louisiana and southern Arkansas, is referred to as the "Brown Dense" or the "Lower Smackover," and is believed to be a layer of limestone at the base of the Smackover Formation – which itself is a well-known formation that has long been a source for traditionally produced oil and natural gas in North Louisiana.

The "Brown Dense" joins the Tuscaloosa Marine Shale as the second half of Louisiana's duo of dense rock plays believed to have the kind of production potential that has made shale plays such as Louisiana's Haynesville and the Barnett and Eagle Ford Shales of Texas the new normal in energy exploration. The Tuscaloosa Marine Shale is believed to underlie much of Central Louisiana, with potential productive areas currently being explored from Vernon Parish to East Feliciana Parish.

The energy industry is watching the development of the Tuscaloosa Marine Shale and the Brown Dense closely, as both are believed to have the potential to contain oil reserves, in addition to natural gas. New processes and technology have led to rapid gains in domestic oil and natural gas reserves, making them recoverable from ultra-dense formations once thought uneconomical to produce.

"We in Louisiana have a long and distinguished history of providing the energy that fuels this nation, and I am bullish on the future of energy production in this state and the role it will play in providing jobs and economic strength," Angelle said. "We are seeing that exploration companies and investors share that optimism and belief in Louisiana's natural resources as they seek new domestic reserves of oil and natural gas. The development of the Haynesville Shale natural gas play, the top-producing natural gas play in the nation, has helped give them that confidence."

Initial development of the Brown Dense formation, generally believed to underlie northern Claiborne, Union and Morehouse parishes in North Louisiana, has barely begun – with Southwestern Energy having begun the process of drilling its first well in Arkansas and having announced that it will seek a permit to begin drilling for a Brown Dense well in Claiborne Parish before the end of 2011.

Southwestern Energy has also announced that it has invested $150 million in leasing mineral rights for 460,000 acres to develop the play. Southwestern Energy recently applied to the Louisiana Office of Conservation for approval of an area of the Lower Smackover formation in Claiborne Parish near the Arkansas border as a designated unit for drilling.

Devon Energy has also announced that is has secured 40,000 acres in mineral leases for the Brown Dense and that the company intends to drill a test well for the play. Devon has already received a permit for a well targeting the deeper section of the Smackover in Morehouse Parish.

Devon is also active in the Tuscaloosa Marine Shale, where the company has secured 250,000 acres of mineral leases and is in the process of drilling two wells in the shale. About half a dozen wells targeting the Tuscaloosa Marine Shale – long thought to contain substantial reserves, but considered uneconomical to reach through previous methods – are currently in the process of permitting or drilling.

"New exploration methods have changed the game for development of energy prospects in Louisiana and the nation, as we saw firsthand with the incredible upswing investment and economic activity in North Louisiana in 2008," said Angelle. "This is yet another opportunity for Louisiana to show that we can be an inviting and exciting province to do the business of finding and providing new sources of domestic energy that provide economic strength and opportunity for our state and our nation."

"With that exploration of the denser formations will come the need for water for hydraulic fracturing," said state Conservation Commissioner Jim Welsh.

Welsh said that companies drilling for the Brown Dense formation have informed the Office of Conservation they intend to use surface water and recycled water for their overall project needs, in conformance with guidelines and advisories issued in nearby areas experiencing stressed ground water conditions.

The anticipated Brown Dense area of development in Louisiana underlies the Sparta Aquifer, which is currently experiencing improved water levels after combined state and local efforts to manage ground water use in the area.

"We are still discouraging new high-volume users from using ground water in that area, and giving guidance on alternative sources for water," Welsh said.

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ExxonMobil, Americas Petrogas to Explore Argentina Shale

- ExxonMobil, Americas Petrogas to Explore Argentina Shale

Tuesday, August 30, 2011
Americas Petrogas

Americas Petrogas, a Canadian company, is pleased to announce that it has, through its wholly-owned Argentina subsidiary, Americas Petrogas Argentina S.A., entered into a farm-out agreement (FOA) with ExxonMobil Exploration Argentina S.R.L., a wholly-owned subsidiary of Exxon Mobil Corporation for the exploration and potential exploitation of Americas Petrogas's Los Toldos blocks (163,500 gross acres or 255 sections or 660 square kilometers) located in Neuquen, Argentina. The Los Toldos blocks are located in the western region of the Neuquen Basin and are in a favorable location relative to other recent discoveries of shale oil and shale gas in the Vaca Muerta formation.

Barclay Hambrook, President and CEO of Americas Petrogas, stated "As the world's largest publicly-owned integrated oil and gas company, ExxonMobil brings vast experience, technology, research and financial resources to this joint venture with Americas Petrogas."

Pursuant to the terms of the FOA, ExxonMobil has committed to fund US$53.9 million (including taxes) during the exploration phase with a further US$22.4 million (including taxes) if the parties proceed to the exploitation phase, for a total potential initial investment of US$76.3 million. This focus of exploration, exploitation and other related activities is expected to be directed towards the Los Toldos 1 and 2 blocks. ExxonMobil will earn a 45% interest in the Los Toldos blocks with Americas Petrogas retaining a 45% interest and the government entity, Gas y Petroleo del Neuquen ("G&P"), maintaining a 10% interest. ExxonMobil will also provide technical assistance on the Los Toldos blocks. The FOA is subject to approval by G&P.

Americas Petrogas is the operator of the Los Toldos blocks and expects to spud the first well in the fourth quarter of 2011 with the primary target being the unconventional Vaca Muerta formation and potential secondary targets in other conventional and unconventional formations.

In addition to the Los Toldos blocks, Americas Petrogas has five other blocks within the Neuquen Basin's western shale corridor, including the Huacalera block which is located south of the Los Toldos blocks and which was recently drilled, cased and cemented, having intersected 1,742 feet of Vaca Muerta shale. In published reports, the U.S. Energy Information Administration has cited a risked, recoverable resource of 240 trillion cubic feet ("TCF") of gas for the Vaca Muerta shale in the Neuquen Basin.

Mr. Guimar Vaca Coca, Managing Director of Americas Petrogas' Argentina subsidiary, said, "We believe the next major shale development outside of North America will be in the Neuquen Basin. Our Argentina management and technical personnel look forward to working with ExxonMobil to explore the substantial hydrocarbon potential of the Los Toldos blocks."

Daniel De Nigris, General Manager of ExxonMobil Exploration Argentina, said, "We are pleased to be working with Americas Petrogas on the highly prospective Los Toldos blocks and if successful, look forward to providing clean and reliable energy for Argentina."

About Americas Petrogas Inc.

Americas Petrogas Inc. is a Canadian company whose shares trade on the TSX Venture Exchange under the symbol "BOE". Americas Petrogas has oil and gas interests in numerous blocks involving exploration, development and production. Americas Petrogas has proven conventional oil and gas reserves, as well as evolving unconventional resource plays including shale gas, shale oil, and tight sand oil and gas in Argentina's prolific Neuquen Basin. For more information about Americas Petrogas, please visit www.americaspetrogas.com

About Vaca Muerta Shales

The Vaca Muerta Shale is one of two principal source rocks in the Neuquen Basin of Argentina. The shale is late Jurassic-early Cretaceous in age, covers an area of approximately 8,500 square miles, varies in depth between 5,500 to 14,000 feet and in places is up to 2,000 feet in thickness.

The Vaca Muerta characteristics are believed to be similar to shale reservoirs such as the Eagle Ford, Haynesville and Horn River in North America which have so far resulted in discoveries of both shale gas and shale oil. The shale has recently become the focus for many of the important shale gas players in North America, including Apache, ExxonMobil, Total as well as YPF in Argentina.

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Beach Secures Rigs for Shale Gas Plays in Cooper Basin

- Beach Secures Rigs for Shale Gas Plays in Cooper Basin

Monday, August 29, 2011
Beach Energy Ltd.

Beach has secured two Ensign rigs, Ensign#65 and Ensign#16, to drill both horizontal and vertical wells targeting its unconventional gas play in the Nappamerri Trough of the Cooper Basin. From recent drilling results, it is clear that the target zone in PEL 218 (Beach 90%) goes beyond shale and incorporates other lithologies that are also gas saturated. Beach believes, that in addition to the substantial shale gas potential, it is now dealing with an unconventional basin centered gas play.

The 2012 program for these rigs will focus on pilot horizontal production wells in both ATP 855P (Beach 40%) and PEL 218, as well as a series of vertical delineation wells in PEL 218. The program is designed to test the significant potential of the basin centered play in what is now considered a thick, continuous, multi lithology gas accumulation across the PEL 218 permit and potentially ATP 855P.
Details of the rigs and the two separate programs are as follows:

Ensign#65 (ADR1500):

• New build 1,500 horsepower rig out of Canada and the US which is expected to arrive around April 2012;
• Encompasses the latest proven technology being used for drilling horizontal wells in the Haynesville shale province in the US;
• Will be built to meet Australian standards and conditions and has the capability to drill 1,500 meter laterals from a depth of 4,000 meters; and
• Will drill the first horizontal well in ATP 855P to target shale and other lithology target zones. Upon completion of this well, the rig will commence the horizontal pilot well program in PEL218, with two pilot horizontal wells planned adjacent to Holdfast-1 and Encounter-1.

Ensign#16:

• 1,200 horsepower rig used to drill Holdfast-1 and Encounter-1, which is currently in the Officer Basin and expected to be available around January 2012;
• Will drill a series of vertical wells in PEL 218 to continue the evaluation of the continuous basin centred gas play in the permit; and
• Has the capability of drilling to 4,270 meters, with the vertical program set to increase the size of the resource in PEL 218 beyond the initial booking of 2 trillion cubic feet. This booking relates to a restricted area of 100km2 around each of Holdfast-1 and Encounter-1.

Beach Managing Director Reg Nelson said, “Beach has started to unlock a significant basin centred unconventional gas play in the Cooper Basin. These two rigs will take us a step closer to understanding the extent of the gas resource that resides within our permits. The horizontal pilot wells to be drilled by Ensign#65 will be production style wells designed to flow gas at commercial rates. Should these wells be successful we will seek to commence a pilot development program as soon as possible.”

• PEL 218 (Permian JV): Beach (90% and Operator), Adelaide Energy Ltd (10%)
• ATP 855P: Beach (40% and Operator), Icon Energy Ltd (40%) and Adelaide Energy Ltd (20%)

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Entek IDs Oil Shows at Niobrara Shale Well

- Entek IDs Oil Shows at Niobrara Shale Well

Thursday, August 25, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The Frontier (secondary objective) has been successfully fracture stimulated and is currently flowing back fracture stimulation fluid. The well is being unloaded and initial testing will commence over the next week. The completion program for the Niobrara (primary objective), which includes fracture stimulation and testing, is on schedule to start in September 2011.

Slater Dome (SD) Federal 24-9DL – The well has successfully reached its total depth of 8,300 ft after penetrating both the Niobrara and Frontier Formations Formations with oil shows while drilling. The well is now being prepared for wire-line logging.

C&C Cattle 18-8 – Location preparation is complete and awaiting arrival of the rig from the SD Federal 24-9 location.

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Encana to Sell Barnett Shale Assets

- Encana to Sell Barnett Shale Assets

Thursday, August 25, 2011
Encana Corp.

Encana has initiated a process to divest of its North Texas natural gas producing assets in the Fort Worth Basin located in the Barnett Shale play. Scotia Waterous (USA) Inc. has been retained as advisor to assist in the process.

"The initiation of the process to sell Encana's North Texas assets is a continuation of the company's ongoing divestiture program, which is well underway and is targeting net divestitures of between US $1 billion and $2 billion for 2011. Encana continuously looks for opportunities to manage its portfolio of producing assets and improve the long-term value creation capacity of its vast resource portfolio. These North Texas assets are high-quality, relatively mature producing properties that hold strong potential for future development. The assets currently produce about 125 million cubic feet equivalent per day (MMcfe/d) and include the associated processing and pipeline facilities on about 52,000 net acres of land in the Fort Worth Basin. We would expect this divestiture to be completed in late 2011 or early 2012," said Jeff Wojahn, Encana's Executive Vice-President & President, USA Division.

"We acquired our core position in the Barnett Shale play in 2004 as a result of a corporate acquisition that was focused on building a major land and production position in the U.S. Rockies. Alongside developing this strong asset, over the years we built a suite of high-growth, early-life resource plays in the Mid-Continent, led by about 295,000 net acres of land in the Haynesville Shale play, where our production is now more than 500 MMcfe/d. In East Texas, our production is about 250 MMcfe/d and our 240,000 net acres hold strong growth potential. Our Mid-Continent resource play teams and operations, based in Dallas, will continue to be a leading contributor to Encana's long-term growth strategy," Wojahn said.

As a leading North American natural gas shale property, the Barnett Shale has provided Encana with high-quality natural gas growth and foundational knowledge which the company has applied across its U.S. and Canadian portfolio of newer resource plays. That foundational knowledge will continue to provide Encana with operational expertise as the company applies multiple advanced technologies to manage costs over the long term and pursue maximizing the margins from all of its natural gas production.

A sale of Encana's North Texas assets would be subject to receiving an acceptable bid, the approval of the companies' boards of directors, normal closing conditions as well as regulatory approvals.

On other fronts, Encana is actively engaged with a number of parties in a competitive process to divest of midstream and producing assets in the U.S. and Canada that no longer fit with its development plans. The company is also in discussions with a number of potential partners looking to make third-party investments aimed at accelerating the value recognition of Encana's enormous resource potential on its undeveloped lands. Proceeds from these transactions are expected to supplement cash flow generation and strengthen the company's balance sheet, providing financial flexibility going into 2012.

Tremendous resource potential across Encana lands

Across North America, Encana has about 7 million net acres of undeveloped land holding tremendous resource potential. Based on an independent assessment of Encana's proved reserves and low estimate economic contingent resources, as of December 31, 2010, this natural gas inventory would last approximately 30 years based on 2010 annualized production.

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Estimates for Greenhouse Emissions from Shale Production Overstated -Study

- Estimates for Greenhouse Emissions from Shale Production Overstated -Study

Wednesday, August 24, 2011
IHS CERA

Estimates used by the United States Environmental Protection Agency (EPA) and others for greenhouse gas emissions from upstream shale gas production are likely significantly overstated, according to a new report by IHS Cambridge Energy Research Associates (IHS CERA). The estimates are based on assumptions that do not reflect current industry practice and should be reevaluated, it says.

"Methane emissions have become a very important and controversial issue given their potency as a greenhouse gas," said Mary Barcella, IHS CERA director of North American natural gas. "Unfortunately, such emissions are not being measured. Estimates are being used that are not supported by data, do not reflect current industry practice and would be unreliable to use as a base for decision-making."

The report cites as one example the EPA's 2010 revised estimates of methane emissions during well completion—the period after the well has been drilled but before it is placed into production. The current EPA methodology for estimating methane emitted during this phase was based on a small sample of wells and primarily measured methane that was captured rather than released into the atmosphere, the report says.

The EPA estimates were based on two workshop presentations describing methane captured during "green completions"—operations designed to capture as much methane as possible. The EPA assumed that (1) similar levels of methane were produced at every other well in the United States and (2) that those emissions went completely uncaptured. Such assumptions do not conform to current industry practices, the report says.

"The assumption that all methane recovered from these sample wells would otherwise have been flared or vented is questionable at best, given that common industry practice is to capture gas for sale as soon as it is technically feasible," said Surya Rajan, IHS CERA director. "Gas that cannot be sold is generally flared rather than vented for safety reasons. If the methane emissions at wells were as high as some methodologies assume, you would have extremely hazardous conditions at the well site that neither regulators nor industry would permit."

Another key mis-characterization found in the EPA estimates and other recent reports, such as a study led by Cornell University professor Robert W. Howarth, is the assumption that wells in flowback contain methane in quantities equal to their post-completion daily production, the report says. This assumption results in a significant overestimation of methane emissions. (The flowback phase is the phase of production when fluids injected into the well flow back out ahead of the tapped gas.)

The IHS CERA report notes that data on unconventional gas well GHG emissions is currently lacking due to the fact that they are not adequately measured. More reliable data is needed in order to produce estimates with any degree of certainty.

The report says that the most productive result of additional regulations proposed by the EPA in July could be better documentation of actual GHG emissions which would provide the accurate measurement that is needed. Some of the other proposed regulations, such as requiring green completions and flaring of any produced gas that is not suitable for sale, are already common practice in the industry, it says.

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Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

- Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

Thursday, August 18, 2011
Halliburton Co.

Halliburton has successfully executed the first horizontal, multistage hydraulic fracture shale gas completion in Argentina's Neuquén Basin for Apache. Halliburton provided all major well construction and completion services for the project, resulting in the successful delivery of South America's first horizontal and deepest shale gas well.

As global development of unconventional resources materialize, Halliburton is in the process of pre-positioning Unconventional Reservoir Solutions Teams around the world. These teams draw upon the extensive knowledge and experience garnered from Halliburton's unrivalled position in North America's unconventional reservoir development. Halliburton, chosen by Apache because of its Buenos Aires-based Unconventional Reservoir Solutions Team's expertise and understanding of the specific complexities of the Los Molles shale formation, placed 10 hydraulic fracture stages in the horizontal section at a depth of over 4,400 meters.

"Halliburton's ability to apply its expertise globally will assist operators to efficiently develop frontier unconventional reservoirs," said Roberto Munoz, vice president, Latin America Region, Halliburton. "With the third largest estimated unconventional reserves after China and the United States, Argentina's shale gas potential will benefit greatly from the application of these technologies."

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Entek to Test Ops at Niobrara Shale Program

- Entek to Test Ops at Niobrara Shale Program

Thursday, August 18, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The Frontier (secondary objective) test program will be initiated within the next 10 days. The Niobrara (primary objective) completion program, which includes testing and fracture stimulation of the potential Niobrara pay zones, is scheduled to start in September 2011.

Slater Dome (SD) Federal 24-9DL – The well is currently drilling ahead at 3,200 ft after successfully setting casing at 2,520 ft. The planned total depth of the well is 8,627 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald O&G holding 45%. Entek is the operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

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Marcellus Shale Driller Fighting South Fayette Ordinance

- Marcellus Shale Driller Fighting South Fayette Ordinance

Wednesday, August 17, 2011
Pittsburgh Post-Gazette
by Erich Schwartzel

Range Resources made a significant move Tuesday in what is likely the first step in a legal challenge to the wave of small-town regulations on natural gas drilling in the Marcellus Shale.

The Fort Worth, Texas-based company filed an appeal to the zoning hearing board of South Fayette that calls its drilling ordinance an "illegal" infraction against the company's business pursuits.

Range Resources says the township's zoning ordinance enforces buffer zones around schools, hospitals and certain commercial areas that force a de facto moratorium on drilling throughout the entire township.

That violates the portion of Pennsylvania's Municipalities Planning Code that requires all municipalities to "allow for reasonable development of minerals" as part of any zoning ordinance, the company said.

The matter is before the zoning hearing board because the drilling regulations involved the township's zoning ordinance.

A date for the zoning hearing has not been set, but Range Resources spokesman Matt Pitzarella said his company will take the issue to the Court of Common Pleas and up the legal ladder if it is rejected by the South Fayette authorities.

If Range Resources wins a ruling in a higher court, it could create a precedent and threaten to overturn scores of small-town ordinances across Pennsylvania.

Throughout Western Pennsylvania, townships have passed ordinances that further regulate drilling beyond state law or take steps to mitigate side effects like road damage or noise control.

Range Resources owns approximately 4,000 acres in South Fayette but has not drilled any Marcellus wells. The ordinance was approved last November after more than a year of public hearings and input from energy companies, including Range Resources.

South Fayette solicitor Jonathan Kamin said the ordinance still allows drilling in "many zoning districts" throughout the township -- they just might not be in the convenient areas that Range Resources would prefer.

"Everyone has recognized that this is a use that cannot be banned," said Mr. Kamin.

Local communities like South Fayette have drafted conditional use ordinances to deal with natural gas drilling, which require every well site to undergo an approval process prior to drilling.

Energy companies say the site-specific requirements make as much sense as requiring a new driver's license in every town, and that the process slows predictability in an industry that plans years in advance.

"It's death by a thousand paper cuts," said Mr. Pitzarella.

The South Fayette ordinance enforces regulations that are already in place as part of the Pennsylvania Oil and Gas Act, and Range Resources says that regulatory double-dipping is illegal.

"[South Fayette] unlawfully seeks to achieve the same purposes and to regulate the same features of the development of oil and natural gas which are regulated exclusively and comprehensively by the Commonwealth," the appeal states.

Range Resources said the conditions of the ordinance are a "de facto taking" of land that make it impossible to drill. The company says this violates the Fifth Amendment of the U.S. Constitution, which says private property cannot be taken for public use "without just compensation."

With the ordinance in place, Range Resources calculated the potential loss to the company and its leaseholders in South Fayette to be nearly $200 million.

Range Resources has already challenged local ordinances that it interprets as going too far. During deliberations for a conditional use ordinance in Mount Pleasant last April, the company sent a letter to residents threatening to move into "more cooperative communities" should the ordinance pass.

That ordinance did pass in June, and Range Resources has kept its promise to not drill any new wells in Mount Pleasant as long as it stays in place.

The appeal filed Tuesday in South Fayette is the latest in a series of recent challenges to local drilling regulations. Earlier this month, Pittsburgh Mayor Luke Ravenstahl refused to sign a city council measure that would have banned drilling within Pittsburgh city limits, and a similar ban in Morgantown, W.Va., was overturned by a judge last Friday.

Copyright (c) 2011, Pittsburgh Post-Gazette

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Devon Energy's Barnett Shale Bet Pays Off

- Devon Energy's Barnett Shale Bet Pays Off

Monday, August 15, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

Ten years ago Sunday, Devon Energy made a multibillion-dollar bet on the Barnett Shale.

On Aug. 14, 2001, the Oklahoma City-based oil and gas company announced a deal to acquire Mitchell Energy & Development of Houston for $3.5 billion.

Mitchell Energy, led by legendary oilman George Mitchell, was the pioneering company that cracked the code of the Barnett's dense shale rock by using new hydraulic fracturing techniques and experimenting with horizontal drilling. At the time, it had drilled about 400 wells in the Barnett, and executives saw the potential for 1,200.

But over the decade, Devon would advance the ball significantly with improved horizontal drilling and an expansion of drilling far beyond areas north of Fort Worth where Mitchell Energy had focused. The result would be a drilling boom that by 2008 would draw numerous rivals into the field and make the Barnett the biggest gas-producing area in the U.S. Tarrant and Johnson counties would emerge as the top two gas-producing counties in Texas.

Today, Devon has drilled more than 4,700 wells in the Barnett. The field now accounts for 39 percent of the company's total production, which includes operations that stretch to the Rocky Mountains and into Canada.

In the Barnett, "our drilling costs are down, our production is up and our efficiencies are increasing," said Brad Foster, senior vice president of Devon's Central Division, which includes Barnett operations.

Devon has achieved, or is on the verge of, several Barnett milestones:

It posted record production in this year's second quarter, averaging the equivalent of 1.28 billion cubic feet of gas per day, even while keeping only 12 drilling rigs busy. That's less than a third as many as it ran in 2008, before gas prices cratered.

Devon's total Barnett production since the Mitchell acquisition is expected to hit the equivalent of 3 trillion cubic feet by year's end, spokesman Chip Minty said. It's at 2.8 trillion now.

Despite weak gas prices, now about $4 per 1,000 cubic feet, Devon is realizing solid returns from the Barnett because "our ability to drill wells economically just gets better every year," said Chairman Larry Nichols, who was CEO during the Mitchell acquisition.

A 35-well pad site

Devon's advances in the Barnett are exemplified at a rural 12-acre drilling site in far southwest Tarrant County. The 31st well there was drilled last week by contractor Patterson-UTI Drilling Co.

Devon expects to have 35 producing wells at the site by March, said Jay Ewing, its manager of Barnett well completions.

That will be the most wells ever on a single Barnett Shale pad site, but the project development has "been pretty routine. ... It's been pretty close to plan," Ewing said. Horizontal legs of the wells, called "laterals," will be steered thousands of feet under Benbrook Lake.

Devon estimates that the 350 Barnett wells it drills this year will yield, on average, the equivalent of 3.2 billion cubic feet of gas apiece over their producing lifetimes. By that measure, the 35 at the southwest Tarrant pad site cumulatively would produce 112 billion cubic feet.

That's enough fuel for gas heating and cooking at more than 1.5 million homes for a year, based on American Gas Association data.

If Devon maintains its current drilling pace, it will drill its 5,000th well next year. Less than 1 percent of Devon's Barnett wells have been dry or otherwise not worth putting into production.

Devon, which has more than 600 Barnett employees and an office in downtown Fort Worth, has boosted its Barnett reserves for seven straight years. Proven reserves are now the equivalent of 6.7 trillion cubic feet.

Drilling time slashed

When Devon began drilling in the Barnett in 2002, it took three to six weeks to drill a single horizontal well, said David Fortenberry, Devon vice president of technology.

"The rigs we used were really too small and underpowered for horizontal wells," he said.

Now, with higher-efficiency rigs and much more experience, Devon averages only about 12 days to drill a Barnett well, and "we've actually drilled some wells down in southwest Johnson County in about six days," Foster said.

Drilling-rig design "has improved dramatically in the past 10 years," with rigs now "ideally suited to drill these horizontal wells," Nichols said.

Devon uses a "walking rig" device to scoot a 156-foot-high rig between surface well bores at its southwest Tarrant pad site. If well bores are 20 feet apart, the rig can move that far in just an hour. Without the walking device, it could take two days to disassemble a rig and set it up 20 feet away.

The Barnett wells that Devon has drilled this year have provided "some of the best results we've ever gotten," Nichols said.

Supply rises, prices fall

Ample supplies from dramatic increases in U.S. shale-gas production have kept prices low, as the industry has become "in part ... a victim of our own success," Nichols said.

Devon has dropped to 12 drilling rigs because it can keep production at least flat at that level of activity and because "at this time, the country just doesn't need any more natural gas," Nichols said.

Production declines have been lower than expected in Barnett wells, he said. There will be "steep declines in the first year, but it flattens out a lot sooner than we originally thought" -- often after 12 to 18 months of production, he said.

The Barnett may soon lose its spot as the top gas-producing area, if it hasn't been already, to the Haynesville Shale in northwest Louisiana and East Texas. But Devon has lots more drilling to do in the Barnett.

7,500 drill sites left

Foster said Devon still has "7,500 potential drilling locations," which represent "probably over 20 years of inventory" for future drilling.

About 2,500 are in "the liquids-rich portion of the play," Foster said. Natural gas liquids such as ethane, propane and butane generate higher profit margins.

Future gas prices will determine how many of the 7,500 locations are eventually drilled, he said.

On average, drilling and completing a Barnett well costs Devon $2.8 million. Wells are 6,500 to 9,200 feet deep, and the average lateral length is more than 4,000 feet.

Devon's Barnett production is 78 percent natural gas, 21 percent natural gas liquids, and 1 percent oil.

In announcing Devon's purchase of Mitchell Energy 10 years ago, Nichols said the Mitchell properties "fit perfectly with our long-term objectives."

That appears perhaps even more so now, as Devon has sold international and Gulf of Mexico properties in the last two years as it embraces a new focus on onshore production in North America.

Copyright (c) 2011, Fort Worth Star-Telegram, Texas

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Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

- Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

Thursday, August 11, 2011
PwC

Ongoing interest in shale acreage, deals for midstream assets and increased investments from foreign buyers in the U.S. oil and gas industry helped drive U.S. oil and gas mergers and acquisitions (M&A) value to $39 billion in the second quarter of 2011, according to PwC US.

In the second quarter of 2011, there were 51 deals with values greater than $50 million, compared to 61 announced deals totaling $41 billion in the same period last year. While the volume and value of transactions dipped slightly in the second quarter of 2011 when compared to the same period last year, average deal value for deals over $50 million jumped to $765 million in the second quarter 2011, a 14 percent increase over the same period last year when average deal value was $672 million.

"There continues to be steady M&A activity in the oil and gas sector with strong competition for prized assets, which has maintained the deal momentum throughout the first half of the year. The second half of the year has already kicked off with one mega deal announced, and we expect that deal momentum to continue," said Rick Roberge, principal in PwC's energy M&A practice. "Foreign and private equity interest in North American oil and gas assets remains very high and will likely be a driver of ongoing activity."

Foreign buyers announced 18 deals valued at over $50 million or more in the second quarter of 2011, which contributed $36.2 billion or 72 percent of total deal value, versus 27 deals valued at $24.2 billion in the same period last year.

For deals valued at over $50 million, there were 11 midstream deals that accounted for $19.9 billion, or 51 percent of total deal value, compared to six deals worth $3.4 billion in the same period last year. Transactions in the upstream space led all oil and gas subsectors with 26 deals, or 51 percent of volume in the second quarter.

According to PwC, seven of the top 10 deals by value in the second quarter of 2011 were related to shale plays, including four upstream deals and three transactions in the midstream and oil field services space. For all deals greater than $50 million, there were 10 shale-related transactions totaling $7.5 billion, or 19 percent of total deal value, including two deals involving the Marcellus Shale totaling $2.3 billion.

"Shale-gas assets continue to be very attractive acquisition targets as multinationals look to gain technical know-how and exploit the long-term value and opportunities from rising energy needs," said Steve Haffner, a Pittsburgh-based partner with PwC's energy practice. "At the same time, there is tremendous activity developing around natural gas infrastructure, which is necessary to move the extracted gas to market. The U.S. 'shale gale' continues to attract the attention of global companies."

There were five financial sponsor-backed transactions over $50 million, representing $6.1 billion, or 16 percent of total deal value, compared to 10 financial sponsor deals contributing $6.2 billion during the same period last year. During the first six months of 2011, there were 16 financial sponsor deals contributing $20.6 billion, a whopping 129 percent increase in deal value, compared to the first half of 2010 when there were 15 financial sponsor-backed deals, valued at $9.0 billion.

"With oil prices hovering at $100, private equity funds continue to make a very strong push in the oil and gas sector," added Roberge. "The private equity deal makers, who used to largely play in the midstream space, are now heavily involved in exploration and production (E&P), shale plays, and oil field services and equipment sector. However, along with the great opportunities and rewards of investing in oil and gas, there is still risk in this space – and new entrants need to understand the pitfalls before trying to exploit these possible opportunities."

For deals with values greater than $50 million, there were 18 corporate transactions totaling $26.8 billion or 69 percent of total second quarter deal value, compared to 22 deals that accounted for $25.9 billion in deal value in the same period last year. Thirty-three asset deals for a combined total of $12.2 billion were announced in the second quarter of 2011, versus 39 deals totaling $15.1 billion in the same period last year. However, when comparing the first six months of 2011 to the first half of 2010, the number of corporate transactions increased by three deals to 35 transactions, while total corporate deal value jumped 26 percent to $59.7 billion in 2011 from $47.6 billion in 2010.

Another potential driver for M&A activity is the desire from some oil companies to sell assets and break apart key lines of business, according to PwC.

"We believe that another factor to keep a close eye on throughout the year, which may add to the already robust M&A activity we're seeing, is the trend of integrated oil companies looking at the various options to unlock shareholder value through separating their E&P businesses," said Roberge. "While this trend could be a very positive driver of M&A activity, these are highly complex transactions with potential consequences around tax considerations, valuations and financial reporting. Companies should consider the risk with these types of transactions as every potential scenario needs to be thoroughly and diligently evaluated to succeed."

PwC's Oil & Gas M&A analysis is a quarterly report of announced U.S. transactions with value greater than $50 million analyzed by PwC using transaction data from John S. Herold, Inc.

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SEC Subpoenas Producer for Documents on Shale Gas

- SEC Subpoenas Producer for Documents on Shale Gas

Tuesday, August 09, 2011
Houston Chronicle
by Tom Fowler


Dallas-based Exco Resources is among shale gas producers that have received subpoenas for documents on actual well production and reserve estimates, the company said in a regulatory filing.

Exco Resources said in financial documents filed with the Securities and Exchange Commission that it received a subpoena from the agency Aug. 1.

Exco said the SEC requested "certain information from Jan. 1, 2008, through the present pertaining to our proved developed producing shale gas wells and reserve estimates."

"The SEC stated that this investigation is a fact-finding inquiry. We understand that a number of other shale gas producers have received similar subpoenas from the SEC."

Analysts with Houston-based bank Tudor Pickering & Holt said it polled a number of shale companies to see if they have received subpoenas, but the answer so far has been "not yet."

The Chronicle reported last month on its FuelFix website that some companies were receiving subpoenas for documents relating to the financial viability of shale projects, after the New York Times reported concerns expressed by some in the industry and government that the shale boom has been overstated.

The Times report has prompted industry backlash, and the paper's public editor wrote that the report was short on dissenting views and was misleading in how it described sources -- drawing a rebuttal from editors behind the story.

Copyright (c) 2011, Houston Chronicle

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Gulfmark to Drill 1st Eagleford Shale Well

- Gulfmark to Drill 1st Eagleford Shale Well

Friday, August 05, 2011
Gulfmark Energy Group Inc.

Gulfmark Energy announced its wholly owned subsidiary, Gulfmark Resources, Inc., has filed for drilling permits with the Texas Railroad Commission and intends to drill its initial test well on its 4,261 acre Kiefer Lease in Zavala County, Texas, upon permit approval. The Kiefer lease is situated in the northwestern portion of the oil window of the Eagleford Shale trend of South Texas. Gulfmark intends to drill vertically through the Escondido, Olmos, San Miguel, Austin Chalk and Eagleford Shale formations and will evaluate results by open hole logs and core samples. The Company's primary objective is to penetrate the Eagleford Shale and plans to drill horizontally approximately 3,000 to 4,000 feet upon reaching this prolific shale play.

Michael Ward, President and CEO, stated, "With recent discoveries within the Eagleford Shale formation, we are very excited to begin our development drilling program and increase our shareholder value. With success through the drill bit, we hope to expand our horizons and fully exploit the resources that lie within our leasehold."

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Norse Sets Sights on NY Shale Development

- Norse Sets Sights on NY Shale Development

Friday, August 05, 2011
Norse Energy Corp. ASA

Norse announced a reallocation of corporate resources to focus on Marcellus and Utica Shale development.

In anticipation that rules allowing the use of high volume hydraulic fracturing to develop natural gas resources in the state of New York will soon be in place, Norse Energy has elected to immediately suspend Herkimer drilling. This will preserve cash for potentially more profitable Marcellus and Utica Shale planning, permitting and development.

Subsequent to release of the draft SGEIS on July 8, 2011, Norse Energy filed its first application for a permit to drill a shale well in New York State using high volume hydraulic fracturing. The permit is expected to be issued when final SGEIS regulations are in place. This strategy transition is expected to facilitate rapid and efficient development of the Company's Marcellus and Utica Shale resources.

"With the SGEIS public comment period expected to begin soon, now is the right time to re-focus the company on the development of shale resources across our extensive acreage position in New York State," said Mark Dice, Chief Executive Officer.

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