Saudi Aramco plans $125 billion spending spree

Saudi Aramco plans $125 billion spending spree

Apr 26, 2011

Sangim Han

SEOUL // Saudi Aramco, the world's largest oil exporter, will spend about $125 billion (Dh459bn) on projects over the next five years as it seeks to increase refining capacity by 50 per cent, Chief Executive Officer Khalid al-Falih said.

The company wants to boost oil-processing capacity to 6 million barrels a day from the current 4m barrels, Mr al-Falih said in a speech in Seoul today. Aramco is building two plants in the kingdom and is considering a further four "grassroots" facilities, he said. That includes one refinery at Jaizan in Saudi Arabia and possible joint-venture projects in China, Vietnam and Indonesia, he said.

"Saudi Aramco isn't just about petroleum production," he said. "We are also one of the world's largest producers of natural gas, a major player in refining, and we are ramping up our petrochemical activities."

Aramco's domestic and international spending plans include oil exploration and production as well as natural gas, refining and petrochemical facilities, he said. Saudi Arabia plans capital expenditure of more than $450bn in the same period, according to Mr al-Falih.

All 12 members of the Organisation of Petroleum Exporting Countries including Saudi Arabia will need to provide a daily average of 29.8m barrels a day this year to satisfy global requirements, or about 600,000 a day more than they pumped in March, the International Energy Agency said April 12.

Aramco built the world's largest natural gas network about 30 years ago, and doubled its processing capacity.

The company plans to expand the network to exceed 14bn standard-cubic-feet per day of capacity in the next five years when the network will encompass seven world-scale gas plants.

For the expansion, the company continues to make natural gas discoveries in places including the Gulf, while beginning exploration in areas such as the Red Sea and the north-west region of the kingdom.

These activities are adding to the company's reserves of 275 trillion cubic feet, the world's fifth-largest proven holdings of gas, in addition to the world's biggest reserves of conventional crude oil, he estimated.

The company is also expanding its petrochemical capabilities in the kingdom, through a petrochemical project in Jubail with Dow Chemical and a planned expansion of Rabigh Refining & Petrochemicals, its joint venture with Sumitomo Chemical.

Mr Al-Falih said South Korea is now among Saudi Arabia's four largest trading partners.

The country accounts for about a fifth of Saudi Arabia's total petroleum exports, and Aramco supplies 30 per cent of South Korea's crude imports.

Aramco is holding its board meeting for the first time in South Korea this week, Mr al-Falih said.

"The Far East is the destination for two out of every three barrels of crude oil" that Aramco exports, he said.

Aramco owns 35 per cent of S-Oil, South Korea's third- largest refiner that's expanding its processing capacity in Ulsan to more than 650,000 barrels a day.

Export Import Bank of Korea and Korea Trade Insurance each signed a memorandum of understanding with Aramco on possible future project financing, according to the website of the oil and gas producer.

Marcellus Panel Looks for Common Ground at First Meeting

Marcellus Panel Looks for Common Ground at First Meeting

Monday, March 28, 2011
Pittsburgh Post-Gazette
by  Laura Olson

The public comments at the end of Friday's inaugural meeting of the state Marcellus Shale Advisory Commission showed part of the challenge facing that panel during the next four months.

One county commissioner stood up to laud the number of jobs that gas drilling has brought to his community. He was followed by a northeastern resident who said her property value has plummeted because of the surrounding well pads, and another woman citing concerns about water quality.

"I moved up here to be at peace with nature," Wyoming County resident Joanne Fiorito told the panel. "You have now ripped my American dream apart, and I am appalled and outraged."

The 30-member panel has 120 days to assess how the state is managing natural gas drilling, as well as find some policy agreement between those skeptical of the booming business and those benefiting from it.

The group will report back to Gov. Tom Corbett in mid-July on what changes they recommend to balance job growth and environmental protection.

Their first task during the meeting, which lasted for more than four hours, was dividing the topics to be tackled among four work groups -- health, safety and environmental protection; economic and workforce development; infrastructure; and local impacts and emergency response.

Those groups will begin their work shortly, and give an update of their progress at the commission's next meeting on April 27.

A locally assessed impact fee on gas drillers will be part of those talks, said Lt. Gov. Jim Cawley, the commission's chairman. But a statewide severance tax, which the Corbett administration opposes, is "off the table," he added.

Several of the commission members -- who represent state government, local communities, environmental advocates, industry leaders and academia -- noted a need for some form of levy or fee to help local governments with rising costs.

Mr. Cawley said he'd like to see figures on what the drilling industry is costing municipalities and counties in additional road construction, staffing, emergency response calls and other growing demands.

Several on the panel talked about using a "fact-based" process to figure out how to responsibly grow the drilling industry, and to present Pennsylvania as the best place for drilling companies to invest.

"We have to win," said Nicholas Haden, vice president of Reserved Environmental Services, a wastewater treatment facility in New Stanton, Westmoreland County. "The Marcellus Shale is not the only shale play in the world."

Presenters giving a snapshot of the industry's activities relayed data on how much interest the Marcellus, and the state's other shale formations, already have garnered.

Southwestern Pennsylvania is near the forefront of activity, with Washington and Greene among the top five counties for number of wells. Department of Environmental Protection statistics show Washington with 305 wells drilled since 2007 and 179 in Greene, which puts them third and fourth behind Bradford and Tioga.

Those wells, and others in the works, are expected to bring more than 10,000 industry jobs to the state's southwest by 2014, said Tom Murphy, of Penn State's Marcellus Center for Outreach and Research.

But amid the presentations came questions to be discussed in the coming months: How should the state help non-drilling businesses, which are losing workers to higher-paying gas companies and having trouble filling the resulting openings?

And how many hotel rooms and apartment buildings should towns add to accommodate an industry that tends to move money and manpower quickly if markets shift?

Some lessons may be found in looking at the southern shale gas-producing states, said Teri Ooms, of the Institute for Public Policy and Economic Development.

A major complaint in Arkansas, and in some parts of Pennsylvania already, is road damage and congestion, said Ms. Ooms. She said one strategy that helped ease tensions was posting truck routes and advertising when those roads would have heavy traffic.

Other problems and solutions will be the source of much-welcomed debate by the commission and members of the public, said Mr. Cawley.

"We want to hear it from all sectors, because we want to provide a blueprint to Gov. Corbett in the middle of July that truly outlines all of the benefits as well as any potential impacts so that he can make an informed decision," he said.

Marcellus Impact Fee Proposal In The Works

Marcellus Impact Fee Proposal In The Works

Monday, March 28, 2011

Knight Ridder/Tribune Business News

by  Brad Bumsted, The Pittsburgh Tribune-Review

 

Republican senators will introduce legislation to impose a fee on Marcellus shale drillers in a few weeks, in an effort to offset costs municipalities experience dealing with the growing natural gas industry, said a top Senate staffer.

Senate President Pro Tempore Joe Scarnati of Jefferson County, the party's highest-ranking senator in the GOP-controlled General Assembly, could be lead sponsor of the bill, said his chief counsel Andrew Crompton.

Counties where drilling occurs would benefit the most monetarily, but lawmakers likely will try to compensate contiguous municipalities, Crompton said. Those municipal boundaries could cross county lines, he said, so "contiguous counties could well get money."

Lt. Gov. Jim Cawley said yesterday a shale advisory panel he chairs will report to Gov. Tom Corbett in 120 days and include a recommendation on assessing a local impact fee to help municipalities defray costs such as road repairs and first responder units.

Corbett has said he would consider a fee to help local government finances. But the money should not go to the state, he said.

The Senate might produce a different interpretation. Scarnati "believes local needs are paramount, but knows that there needs to be a statewide portion, likely for 'Growing Greener' projects and/or hazardous site cleanup," Crompton said.

Cawley said the administration would not impose a severance tax on gas extraction, and the Marcellus Shale Advisory Commission wants evidence of damage that's occurring from drilling operations.

"We want to understand what the actual impact is," he said.

It's not clear whether the full Senate would vote on a bill before the commission concludes its work. Crompton said senators do not want to usurp the commission, but Scarnati senses urgency among local government officials and doesn't want to wait until fall to address it.

The commission will consider a range of issues, such as environmental impacts and the extent to which natural gas eventually could be used to fuel state vehicles, prisons and schools, Cawley said.

Corbett's critics have said the commission's makeup is industry-heavy. It includes drilling company executives, business representatives, six members of Corbett's cabinet, a member of the Public Utility Commission, environmentalists, local government officials and the governor's energy executive, Patrick Henderson.

"This is a very interesting group of cheerleaders," Virginia Cody of Wyoming County told the panel during its first meeting.

Joanne Fiorito, who lives near drilling sites in that county, said she moved there "to be at peace with nature."

"You have ripped my American dream apart, and I am appalled and outraged," she said. 

Total CEO: Gas Production in Yemen Almost Normal

Total CEO: Gas Production in Yemen Almost Normal

Monday, March 28, 2011
Dow Jones Newswires
by  Adam Mitchell

Total continues to produce liquefied natural gas in Yemen at close to normal levels, Chief Executive Christophe de Margerie said Monday.

Like a number of other countries in the region, Yemen is in political crisis with protests against the regime there.

Total's priority in the country is the safety of its workers and its installations, de Margerie told reporters, adding that it will produce there for "as long as we can."

The company currently is producing "almost normally," he said, without elaborating.

OGX Reports Operational Reports for 2010

OGX Reports Operational Reports for 2010 

Monday, March 28, 2011
OGX S.A.

OGX announced its 2010 results. The following financial and operating information is presented on a consolidated basis, in accordance with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board - IASB, in reais (R$), unless stated otherwise.

"2010 was a year of tremendous achievements for OGX. Our drilling success and identification of extraordinary accumulations in the Campos, Santos and Parnaiba basins validated the geological models developed by our team, revealed the significant potential of our portfolio located mostly in shallow waters, and encouraged the mapping of additional prospects. With 9 drilling rigs now at our disposal, we are also prepared to enter another exploratory cycle in under-explored basins, such as the Espirito Santo and Para-Maranhão, as well as commence seismic studies in five recently-acquired blocks in Colombia," commented Mr. Paulo Mendonça, OGX's General Executive Officer.

"In particular, I would like to highlight our accomplishments in the Campos Basin, where we achieved a success rate of 100% and registered excellent discoveries, most of them located in an extensive carbonate platform, which had its production potential proved through one of the best horizontal well drill-stem tests ever performed in Brazil," added Mr. Mendonça.
"With all necessary equipment already procured from renowned suppliers, the drilling of the first production well and related drill-stem test both completed, we are on track and poised to reach a very important milestone for OGX with the initiation of production in the third quarter of 2011. The successful horizontal well drill-stem test recently performed in Waimea, where we will begin our production, surpassed our expectations. We look forward to conducting the upcoming extended well test, which signals the beginning of production and, ultimately, commercialization of our resources," noted Reinaldo Belotti, Production Officer of OGX. 

2010 Highlights and Subsequent Events

• Drilling of 26 wells during the year of 2010 and 11 in the subsequent months in the Campos, Santos and Parnaíba Basins;
• Confirmed the existence of important oil-bearing regions in the Campos basin: an extensive carbonate platform in the Albian section, as well as important sandstone reservoirs in the Tertiary of the BM-C-41, BM-C-42 and BM-C-43 blocks in the south of the Campos Basin, and another one in BM-C-39 and BM-C-40 blocks, more to the north, with large discoveries in the Santonian, Albian and Albian-Cenomanian sections;
• Performed several drill-stem tests, proving high levels of productivity in several discovered accumulations;
• Concluded the drilling of the first horizontal well (OGX-26HP) of the Waimea accumulation, which tested and confirmed the productive potential of 40,000 barrels per day and productivity index of 100m³/day/kgf/cm² in carbonate reservoirs in the Campos Basin. OGX's production phase will commence at this well through an extended well test (EWT);
• Three discoveries in the Santos Basin, with the identification of liquid hydrocarbons and associated gas;
• Revealed the great hydrocarbon-bearing potential in the Parnaíba Basin with the results obtained in the drilling of the wells OGX-16 and OGX-22, allowing for a volume estimate of potential resources of approximately 15 trillion cubic feet (Tcf) of natural gas in the region;
• Acquired five high-potential exploratory blocks in three onshore basins in Colombia: Cesar-Ranchería, Lower Magdalena Valley and Middle Magdalena Valley Basins;
• Procured all of the essential equipment for beginning production in the Waimea accumulation in the Campos Basin. 

Exploratory Campaign

2010 was a year of extraordinary accomplishments and major achievements for OGX, notable for significant discoveries and the confirmation of the high productivity potential of our main hydrocarbon accumulations. We intensified our exploratory campaign and conducted important drill-stem tests that confirmed the Company's geological model and the potential of the discoveries we have made. These tests yielded fundamental information that provided for a better understanding of the reservoirs that had been discovered in the Campos Basin, allowing us to further enhance the calibration of the production model to be put into place.

At the moment we are drilling the 39th well of OGX, which added to the four other wells drilled by Maersk Oil, bring the total number of wells drilled in the Campos, Santos and Parnaíba Basins to 43 in approximately 18 months since the beginning of our exploratory campaign. Of the 43 total wells, 26 were drilled in 2010, demonstrating the intensification of our activities, and resulting in important discoveries, some of them in areas that until now had been under-explored, including the Parnaíba onshore basin in the interior of the state of Maranhão. These results were made possible due to both a more robust operating structure and the superior geological knowledge that has been acquired about the region. We expanded the number of available drilling rigs from four to nine and now have nearly 5,000 people working on our behalf including outsourced personnel. 

Campos Basin

We ended 2010 with 18 wells drilled in the Campos Basin, all of which identified hydrocarbons, confirming a success rate of 100% in this basin. Of this total, 11 were drilled in the BM-C-41, BM-C-42 and BM-C-43 blocks and allowed for the identification of several accumulations in different geological ages, confirming the presence of a vast oil-bearing province in these blocks. Through the wells OGX-2A, OGX-3, OGX-5, OGX-6, OGX-7A, OGX-8, OGX-10, OGX-15, OGX-20, OGX-21D, OGX-26HP, OGX-28, as well as the MRK-3/4 wells, we have also confirmed the existence of an extensive carbonate platform in the Albian section with great permo-porosity conditions and good quality oil. Moreover, we recorded important discoveries in the Tertiary age and in the Aptian section, reaffirming the enormous potential of the region.

We also began our drilling activities in the blocks BM-C-39 and BM-C-40, located between the Peregrino and Polvo fields, and have obtained excellent results, especially with the OGX-14 (Peró), OGX-18 (Ingá) and OGX-25 (Waikiki) wells. For OGX-14 and OGX-18, drill-stem tests were performed which identified production potential of 3,000 barrels/day using a vertical well for the Peró accumulation that could reach 15,000 barrels/day using a horizontal well, and 8,000 to 12,000 barrels/day through a vertical well at the Ingá accumulation that could reach 25,000-35,000 barrels/day through a horizontal well. The tests also enabled us to measure the quality of the oil at approximately 27° API in each accumulation. Well OGX-25, also known as Waikiki, was an exceptional discovery with the largest detected net pay of approximately 145 meters in the Albian-Cenomanian section.

In addition to the exploratory wells, the first appraisal well for the Waimea accumulation, OGX‐21D (BM-C-41 block) was drilled. It was converted into a horizontal well, OGX-26HP, which extended 1,000 meters within the carbonate reservoirs of the Albian section of the Waimea accumulation, originally discovered by well OGX‐3. The well OGX-26HP, which will be OGX's first production well, was tested and registered a productivity index (PI) of 100m³/day/kgf/cm², one of the highest seen to date in Brazil, as well as a production potential of 40,000 barrels/day and oil gravity of approximately 20° API. This well is currently equipped for an extended well test (EWT) that could record flows of up to 20,000 barrels/day and reach even higher flow levels in a definitive project scenario. The results to date have exceeded initial expectations regarding the Waimea accumulation and offer an even more solid foundation for the initiation of OGX's production phase.

Besides this, two other appraisal wells in the Pipeline (OGX-36D) and Waikiki (OGX-35D) accumulations confirmed their extensions, advancing significantly the delineation of these accumulations, which are respectively located in the southern and northern blocks of the Campos Basin. These directional wells, which were drilled at respective distances of 2.6km and 2.0 km from the wildcat wells, were the pilots for the horizontal wells in these accumulations. Therefore, OGX initiated the drilling of the first horizontal well in the Pipeline accumulation (OGX-39HP) which will be used in the future for production in this area. 

Santos Basin

With respect to the Santos Basin, of particular note was the drilling in the Natal prospect (OGX-11D) in the BM-S-59 block adjacent to the Mexilhão field, which identified liquid hydrocarbons and associated gas in the Santonian section with net pay of around 75 meters. The liquid hydrocarbons proved to be of excellent quality, rated at about 41° API, indicating a higher level of attractiveness of the project. Two other wells registered important discoveries: Belém (OGX-17, with net pay of 43 meters in the Albian section), located in the BM-S-56 block; and Aracajú (OGX-19, with net pay of 40 meters in the Santonian section), located in the BM-S-58 block.

Drilling of the OGX-12 (Niterói), OGX-23 (Ilhéus) and OGX-24 (Itagi) wells has been concluded and resulted in shows of non-commercial hydrocarbons. However, the information acquired through these wells has been of great importance in the calibration of a new geological model for the region. In addition, with the transfer of exploratory rights of the BM-S-29 block from Maersk to OGX, the Company now owns 100% of this block, which is in the evaluation phase. To date, the company's success rate in the Santos Basin has been approximately 60%. 

Parnaíba Basin

In the Parnaíba Basin, the Company's subsidiary OGX Maranhão, drilled two wells in the PN-T-68 block, reaffirming the great oil-bearing potential of this new frontier which had not been explored since the 1980s. In the first well, OGX-16 (Califórnia), an important gas discovery was made in the Devonian section with a drill-stem test that encountered 1,900-psi pressure and generated a flame 15 meters long. In addition, evidence of gas was also encountered in the Pimenteiras and Itaim formations, also in the Devonian section. The data obtained through this drilling campaign, coupled with the seismic information recently acquired in the area as well as technical analysis, have made it possible to identify approximately 20 prospects similar to the one drilled by OGX-16 and to estimate a volume of resources of approximately 15 trillion cubic feet (Tcf) of natural gas for our portfolio in this region. In the second well, OGX-22 (Fazenda São José), two accumulations were found with net pay of 49 and 47 meters in the Poti and Cabeças formations, respectively. The top of the Poti formation was tested with exceptional results which indicated a production potential of up to 3.4 million m³ per day in Absolute Open Flow (AOF).

These estimates point to a production potential for the region of approximately 15 million cubic meters per day of natural gas. Based on this relevant new data, OGX decided to review the scope of its exploratory campaign for the region and boosted the forecast for the number of wells to be drilled from 7 to 15. 

Drilling Activity in Progress operated by OGX

• 1-OGX-30-RJS, also known as Salvador prospect, is being drilled by the rig Ocean Quest in the BM-S-58 block in the Santos basin. Drilling was initiated on January 11th;
• 1-OGX-33-RJS, also known as Chimborazo prospect, is being drilled by the rig Pride Venezuela in the BM-C-41 block in the Campos basin. Drilling was initiated on February 3rd;
• 1-OGX-34-MA, also known as Bom Jesus prospect, is being drilled by the rig QG-1 in the PN-T-68 block in the Parnaíba basin. Drilling was initiated on February 13th;
• 1-OGX-37-RJS, also known as Potosi prospect, is being drilled by the rig Ocean Ambassador in the BM-C-43 block in the Campos basin. Drilling was initiated on March 6th;
• 3-OGX-38-MA, the first appraisal well of the Fazenda São José accumulation, is being drilled by the rig BCH-05 in the PN-T-68 block in the Parnaíba basin. Drilling was initiated on March 25th;
• 9-OGX-39HP-RJS, first horizontal well of the Pipeline accumulation, is being drilled by the rig Ocean Star in the BM-C-41 block in the Campos basin. Drilling was initiated on March 25th. This well will be used in the future for production in the area.

The drilling rig Sea Explorer, which drilled well 9-OGX-26HP, an appraisal well of the Waimea accumulation in which the extended well test (EWT) will be performed, will drill the third appraisal well of the Pipeline accumulation.
The drilling rig Ocean Lexington has just drilled well 3-OGX-35D, the first appraisal well of the Waikiki accumulation, which will be used as a pilot for a horizontal well.
The jack up rig, Ocean Scepter, will start operating soon and will be dedicated to the Pará-Maranhão Basin. 

Beginning of Production

The beginning of OGX's production is expected for the third quarter of 2011. This will be an important milestone in the Company's history and will contribute to its ongoing growth trajectory in the coming years. The production will be in the Waimea accumulation, in block BM-C-41 in the Campos Basin, through an extended well test (EWT), which could record flows of up to 20,000 barrels/day.

The technology that will be employed for this first project has been widely applied within the oil industry and calls for using wet christmas trees and flexible lines that will be directly connected to the FPSO OSX-1. The well was prepared for production using the subsea centrifugal pumping method.

All of the key equipment for this phase of production has already been contracted from globally renowned suppliers and some pieces have already been delivered. Suppliers of equipment and services include: Schlumberger (Integrated Project Management and equipment and services for well completion), GE Oil & Gas (subsea X-trees), Wellstream (flexible lines and a vessel for launching the lines), Oceaneering (control umbilical), Baker Hughes (electrical subsea pumping) and OSX, which will supply the FPSO OSX-1. This FPSO (Floating Production Storage & Offloading system) is currently in Singapore, undergoing modifications to its processing plant in order to conform to the characteristics of the Waimea oil and is expected to arrive in Brazil by mid 2011.

More Gas Wells for Southwest Virginia?

More Gas Wells for Southwest Virginia?

Monday, March 28, 2011
Knight Ridder/Tribune Business News

by  Debra McCown, Bristol Herald Courier, Va.

 

Another county might soon be added to the list of those producing natural gas in Southwest Virginia: Washington. But only if the county will change its zoning ordinance to allow it.

The Virginia Gas and Oil Board has approved the creation of two drilling units and forced pooling orders for the first of four proposed gas wells in the Benhams area of Washington County.

Forced pooling is a process authorized by Virginia law that allows gas companies to drill even without leases from all affected property owners and that provides the uncooperative owners a default one-eighth royalty. The system is the subject of a set of class-action federal lawsuits in which coalfield landowners claim that gas companies benefit at the expense of citizens -- and that promised payouts are not always delivered.

Charlie Bartlett, a geological consultant who's long advocated for Washington County's gas potential, said he also has long advocated for landowners getting their rightful royalties when gas is produced from beneath their land, and he's making it a point to go about the project in Washington County the right way.

He also said that Washington County could ultimately have many more gas wells.

"If those [first ones] are successful, it will lead to a couple of dozen wells," Bartlett said. "So basically we're hoping for the establishment of a new gas field in Washington County."

Abingdon-based Southeast Land and Mineral wants to drill the proposed wells in an area about a mile north of Benhams, Bartlett said, about five miles north of Bristol and eight miles northwest of Abingdon. He also said the county has gas development potential in the area "between about the North Fork of the Holston and about Route 700."

Were Washington County to enact a severance tax, each well could generate thousands of dollars in revenue, Bartlett said, not to mention thousands in royalties for landowners and the creation of jobs.

"We're hoping that we can make them [Southeast Land and Mineral] some money, make the landowners some money, make the county some money and make the state some money, and everybody will be happy," Bartlett said.

Regarding the concerns raised by the federal lawsuits, Bartlett said he does not anticipate any effects on his project -- except the possible assurance that landowners would get fairer treatment under the law.

First, however, the project, financed by a coal investor from Kentucky, must hurdle the zoning ordinance that currently prohibits natural gas drilling in Washington County. And if the county agrees to change the ordinance to allow drilling, that would open the county for any gas company to operate.

"It would be sort of ridiculous for us to use gas from other places and not allow gas to be drilled here," Bartlett said.

Bartlett said he's run into some skepticism from county zoning officials. But Odell Owens, the county supervisor who represents the district where the wells are proposed, said it's an idea worth exploring.

"If we're sitting on natural gas that the landowners can benefit from extracting, and also if it can serve as a revenue source for the county, we have to look at it," Owens said, adding that experts likely will be asked to speak before the board.

While Owens said the county's groundwater resources are precious, he suggested that if drilling can be done safely -- protecting that natural resource -- he'd be supportive.

County Administrator Mark Reeter said he doesn't know why the county's zoning ordinance doesn't mention -- and therefore doesn't allow -- drilling, and county officials are just beginning to research what gas drilling is about.

At a Feb. 22 meeting of the Washington County Board of Supervisors -- more than six months after the county's Board of Zoning Appeals affirmed a decision denying permission to drill -- a man representing the company came to extol the virtues of gas production.

"We need to get all the energy we can from beneath the soils of the U.S. instead of being held hostage," Gus Sorensen of Bristol told the board members. "I hope that any sort of rules and regulations can be taken care of so we can extract this energy."

At a county board meeting last week, Damascus resident Judith McBride spoke in opposition to the zoning change that would allow drilling, citing potential risks to water supplies from wastewater disposal. Originally from Pennsylvania, McBride compared the impact of drilling on her family farm back home to the effects of strip mining.

In Abingdon, long an economic center for the coal and gas-producing region of Southwest Virginia and home to many who moved away from the environmental downside of life in coal country, it's not clear yet how residents will react to the proposal.

However, there is no coal -- only gas -- in Washington County.

And, Bartlett said, he has no intention of drilling near the town of Abingdon. Plus, he said, the county, through its zoning ordinance, could restrict drilling to certain areas.

Another Expert Says Haynesville Not Bigger than Shale

Another Expert Says Haynesville Not Bigger than Shale

Friday, March 25, 2011

by  Jack Z. Smith

Fort Worth Star-Telegram, Texas

 

There's a new voice in the debate over whether North Texas' Barnett Shale has been eclipsed by the Haynesville Shale as the No. 1 natural gas field in America.

Lippman Consulting, an El Paso-based natural gas consulting firm, is taking issue with a recent U.S. Energy Information Administration website posting that said the Haynesville in northwest Louisiana and Northeast Texas is the new leader in production among U.S. shales. The administration cited data from Bentek Energy, an Evergreen, Colo.-based consulting firm.

George Lippman, president of Lippman Consulting, has joined those questioning the assumption that Haynesville is the new top dog.

"Our data clearly shows that the Barnett production is still greater than the Haynesville production," Lippman said in an e-mail to the Star-Telegram after reading an article the newspaper published Tuesday on the subject.

Lippman said his firm's estimates show Barnett production averaging 5.52 billion cubic feet per day in February, easily exceeding the output of 5.03 billion cubic feet daily from Haynesville.

He said his company's calculations were derived from Texas Railroad Commission data, "plus the most-recent data from our Gas Processing Plant database that collects daily volumes at the outlet of all gas-processing plants in each region and then extrapolates that data back to wellhead volumes."

Steven Grape, the Dallas-based domestic reserves project manager for the Energy Information Administration, and Gene Powell, publisher of the Fort Worth-based Powell Shale Digest, said Monday that they need further clarification and confirming data before they can be assured that the Haynesville is the new No. 1.

Lippman said he expects that Haynesville will surpass the Barnett in production "in the months ahead ... but that has not happened yet."

Westmoreland County Joins Shale Consortium

Westmoreland County Joins Shale Consortium

Friday, March 25, 2011
by  Rich Cholodofsky, Tribune-Review, Greensburg, Pa
Knight Ridder/Tribune Business News

Westmoreland County commissioners on Thursday voted to join a consortium of landowners as part of a move that could lead to the first Marcellus shale deep gas well on county property on an historic site dating back to 1773.

The unanimous vote did not directly authorize a lease for any company drill at the more than 140-acre property on which the Historic Hanna's Town tourist attraction sits. The town, established as the first county seat west of the Allegheny Mountains, is operated by the Westmoreland County Historical Society.

"We're looking at all properties so we can explore the natural resources on behalf of taxpayers of Westmoreland County," said Commissioner Charles Anderson.

The commissioners said no deal to lease the land was imminent, but attorney John Ward will handle negotiations for the county and nearly two dozen surrounding private property owners.

Those owners and the county will negotiate as a group with oil and gas companies that wish to lease land to install deep well drilling platforms to harvest natural gas from the lucrative Marcellus shale formation.

"I don't think Pennsylvania or this county can write off a valuable reserve such as a pool of natural gas," said Commissioner Tom Balya.

Before the vote, East Huntingdon resident Jan Kiefer asked county officials to consider advocating against Marcellus shale drilling, saying it was unsafe and could potentially damage the environment.

"People are polluting our air and water and it's affecting our health," Kiefer said.

Commissioners said they can't restrict local governments from authorizing Marcellus drilling, and then voted to join the consortium.

"We have to do it smart and we have to stay on top of it," Anderson said.

Commissioner Ted Kopas said revenues generated from leasing drilling rights and gas royalties would be used to provide a dedicated source of revenue to build a new visitors center at Historic Hanna's Town.

The county and the historical society plan to build a $4.2 million center at the site. The county has given the project a $1 million grant, while about half of the overall project cost has been raised.

Analysis: Potential Exists for Small Scale LNG Production in Southeast Asia

Analysis: Potential Exists for Small Scale LNG Production in Southeast Asia

Thursday, March 24, 2011

Rigzone Staff

by  Karen Boman

Investments in infrastructure for small scale liquefied natural gas (LNG) power production might be justified when the total demand for electric power exceeds 500 MW within a 120,000 square kilometers island region with no pipeline connection, according to a joint industry project (JIP) on the future small scale LNG value-chain in Southeast Asia.

Classification society Det Norske Veritas (DNV) reported that the study, which examined two areas of future LNG use in Southeast Asia, also identified noteworthy potential for LNG as a fuel for ships in regional trade, and predicts a future market for LNG bunkering in Singapore.

"Substantial market opportunities will evolve throughout the small scale LNG value-chain in Southeast Asia in the next decade," said managing director Bjorn Tore Markussen of DNV's Clean Technology Centre in Singapore, who has also headed up the JIP. "The companies who seize the opportunities early in these evolving markets will be well positioned for interesting growth if entry risks are managed properly."

The study identified multiple island regions in Southeast Asia outside any pipeline grid where total demand for electrical power exceeds 500 MW. Based on a number of underlying parameters and assumptions, various financially feasible scenarios were modeled. For example, Eastern Indonesia might have a demand for up to 70 small scale 50 MW power plants by 2020. Equally, Southern Philippines could require up to 45 plants, while the estimated demand for Northern Vietnam might be seven small power plants.

The distribution of LNG to these power plants would require close to 60 small scale LNG carriers by 2020 if this number of plants is built. As the price of crude oil is rising faster than the price of natural gas, the financial incentives for using LNG for power generation are equally increasing with considerable environmental benefits to be gained from such a fuel switch.

Shipping is a vital part of the future LNG supply chains in Southeast Asia, DNV noted. The study forecasts that container feeders might be the first ship segment to adopt LNG for propulsion regionally. About 20 % of the regional container feeders are up for renewal by 2020. Local and regional ferries are also well suited to use LNG for propulsion in the longer term.
Singapore is identified as the regionally preferred site for future LNG bunkering, due to large shipping volumes, calm seas for bunkering operations and the fact that infrastructure for LNG bunkering is already under construction. With stricter requirements for environmental performance, and an increasingly competitive expected price for LNG as fuel for ships, a shift to LNG propulsion may have an exciting impact on Singapore as a bunkering hub.

Lam Yi Young, chief executive of the Maritime and Port Authority of Singapore (MPA), said, "With the push towards cleaner fuel for ships, the results of this Joint Industry Project are timely in evaluating the potential for LNG bunkering services in Singapore. LNG's lower carbon dioxide emissions, minimal sulfur and nitrogen content as well as the abundant availability, allows it to be a viable alternative fuel source for ships, which is also in line with MPA's commitment to promoting environmentally-friendly shipping."
"The consortium is eager to use the findings from the LNG study to build business for the participants and to inform regional stakeholders about the opportunities that lie ahead," said Markussen, "DNV as a company has already decided to invest into a next phase of the JIP. We are now inviting old and new members to join the consortium and one or more of the many project streams that will be kicked off in April and May."

The JIP, which was initiated by DNV during Singapore Maritime Week in 2010, included a consortium of 16 participants from all parts of the LNG value chain, including Gazprom, Rolls-Royce, Wartsila, Hanjin Shipping, I.M. Skaugen, Keppel, The Linde Group, Trans LNG, DNV, BW group, BBG, the Maritime and Port Authority of Singapore, and the two Singapore universities NUS and NTU. The JIP is also supported by Innovation Norway and The Norwegian Embassy in Singapore.

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Ottawa and Quebec reach deal on Old Harry oil and gas prospect

Ottawa and Quebec reach deal on Old Harry oil and gas prospect

March 23, 2011 - 23:22

The Canadian Press

OTTAWA - Ottawa and Quebec have reached a deal on a disputed underwater energy prospect that could mean billions of dollars for the province.

The Canadian Press has learned that federal Natural Resources Minister Christian Paradis and his Quebec counterpart, Nathalie Normandeau, will sign a deal Thursday on the Old Harry oil and natural gas deposit.

Such a deal would come on the eve of an expected federal election call and could prove a boon to the Conservatives as they push to boost their support in Quebec.

Sources within the federal government said the new deal will see Quebec get 100 per cent of the royalties from the area.

Old Harry is located in the Gulf of St. Lawrence and straddles the border between Quebec and Newfoundland and Labrador border. It has been at the centre of a feud between the two provinces for years.

The dispute has centred around ownership of the seabed and the territorial divide between Quebec and Newfoundland.

The reservoir could represent billions of dollars in revenue and has a potential output of two billion barrels of oil and 5,000 billion cubic feet of natural gas.

Newfoundland and Labrador has already laid claim to the bulk of the offshore oil reserve and granted a permit to a company to explore the area.

Quebec meanwhile has been pushing for exclusive rights to the deposit and called on Ottawa to stop any new drilling or seismic testing permits for Old Harry until ongoing environmental studies have been completed.

The environmental work is scheduled for completion in 2012.

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Shell Fires Up Gas Production Offshore Qatar

Wednesday, March 23, 2011

Royal Dutch Shell

 

Qatar Petroleum and Shell announced the first flow of dedicated offshore gas into the Pearl GTL plant located in Ras Laffan Industrial City in the State of Qatar.

Shell, which is the operator of the Pearl GTL plant developed under a Production and Sharing Agreement with QP, has opened natural gas wells offshore allowing the first sour gas to flow through a subsea pipeline into the giant GTL plant onshore. Sections of the Pearl GTL plant will be started up progressively over the coming months.

The Pearl GTL project was launched in July 2006 and the first stone was laid by His Highness Sheikh Tamim bin Hamad Al-Thani, the Heir Apparent in February 2007.

Pearl GTL is the largest energy project ever launched in the State of Qatar, in terms of total investments. It consists of two offshore platforms 60 kilometers off the Qatar coast, connected by pipeline to the largest Gas to Liquids plant ever built, located in Ras Laffan Industrial City.

His Excellency Dr. Mohammed bin Saleh Al-Sada, Qatar's Minister of Energy and Industry said, "This project will play an important role in further enhancing our diversification of the North Field gas utilization and will support the optimization of Qatar’s competitive position in the world markets by supplying ultra clean GTL products. I would like to congratulate the Qatar Petroleum and Shell teams on first on-shore gas. The scale, technology and safety record on Pearl GTL have broken all records. This is a proud day for the State of Qatar, for Qatar Petroleum and for our partner Shell."

Peter Voser, Chief Executive Officer of Royal Dutch Shell said, "Today is an important milestone in the Pearl GTL project, and we are on a clear pathway towards the start up of gas to liquids production. I would like to thank Qatar Petroleum and the State of Qatar for their support throughout, to make such a substantial project possible."

Once fully operational, Pearl will produce 1.6 billion cubic feet of gas per day from the North Field, which will be processed to generate 120,000 barrels per day of condensate and natural gas liquids and 140,000 barrels per day of gas to liquids (GTL) products. Gas-to-liquids products are high quality, clean-burning oil products such as gasoil, high specification lubricants base oils, and chemicals feedstock.

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Today's Trends: Natural Gas Funnelling

Tuesday, March 22, 2011

Rigzone Staff

by  Trey Cowan

The cylinder sections in the graph above represent a range of, plus-to-minus one, standard deviation surrounding the average annual natural gas prices for the corresponding years. Trading patterns over the last three years indicate that the price volatility of natural gas has diminished significantly. Specifically, the range has narrowed from $4.28 in 2008 to just $0.58 at present.

If the cylinders were to be placed concentrically side by side, the resulting effect would be a funnel. Proceeding from the wide-end of the funnel to present day prices, it appears that natural gas has reached a period of price stability.

While much has been written about oversupply issues, the normal corrective mechanisms (i.e. participants leaving) appear to be taking root in the natural gas markets. Specifically, since October 2010, the US land gas rig count has fallen from 950 to 856 rigs, a 10% decline. Taking the conservative assumption that each rig could drill 10 wells per year implies that 940 (10 wells x 94 rigs) fewer natural gas wells will be drilled over the next twelve months.

Given the dramatic decline curves associated with shale gas, such as the depleting 70% during the first year in the Marcellus; the downward trend in rig count implies that future reserve replacement will not likely keep pace with existing production. Such a scenario points to a rebalancing of supply and demand in the U.S.
The discipline we are seeing with regards to a lower natural gas rig count is not occurring in a vacuum. These rigs that were drilling for natural gas are now drilling for oil. In fact, the US land oil rig count has increased by 153 rigs over the same time frame (i.e. from last October until now). E&P firms have made it clear that the incremental return per unit of $11, favoring oil, is a strong incentive to continue shifting resources. Thus, additional drilling to reinvigorate gas production will not resume quickly once prices begin to improve because the equipment will likely not be available.

With prices stabilizing and production normalizing, we can now envision a point in the future months where price improvement rather than price destruction can be seen as the ensuing trend. Other factors that are starting to play to the natural gas market's hand are strengthening industrial demand and a trend towards more electricity generation using natural gas as the fuel. Given the recent nuclear crisis in Japan, the backlash on nuclear energy will only make burning natural gas even more desirable.

So, even with the +7% recent surge in natural gas prices last week, we still see reasons to get more bullish on the commodity in the near future.

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Iraq to Auction 12 Exploration Blocks in Nov.

Tuesday, March 22, 2011
Dow Jones Newswires
By  Hassan Hafidh

Iraq plans to auction 12 exploration blocks, believed to contain mostly gas reserves, in November as part of the country's efforts to capture natural gas for electricity generation, said the country's oil minister.

Abdul Kareem al-Luaibi said 70% of these blocks are believed to contain gas reserves only, with the rest containing oil and gas reserves.

"We think that these 12 blocks contain at least 29 trillion cubic feet of [non-associated] gas," the minister told reporters in Baghdad.

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API: New Energy Policy to Add Jobs for Brazil

Tuesday, March 22, 2011

API President and CEO Jack Gerard said the administration's offer to exchange batteries for oil from Brazil reflects its inadequate and illogical energy policy:

"It is beyond comprehension the administration would encourage trade for Brazilian oil while obstructing U.S. oil and natural gas development, eliminating related jobs here at home, and decreasing oil and natural gas revenues to the U.S. Treasury when the government is trillions of dollars in debt. The message from the White House to America's oil and natural gas workers: we're going to outsource your job.

"The administration is missing the obvious: what makes sense for Brazil also makes sense for the United States. Like every other nation, we should be developing our own oil and natural gas resources. It's good for energy security, good for the economy, good for jobs, and it will help bring down our deficit.

"The administration says it supports more oil and natural gas development here in the United States, then at every turn discourages it. And today, the White House is making a deal with Brazil for the oil it is not allowing companies to produce here. There's nothing wrong with buying Brazilian oil, but there's a big problem when we're forced to because we're held back from producing our own."

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Haynesville Surpasses Barnett as Largest Shale Gas-Producer in US

Tuesday, March 22, 2011

by  Jack Z. Smith

Fort Worth Star-Telegram, Texas

 

The Haynesville Shale play in Northwest Louisiana and East Texas has surpassed North Texas' Barnett Shale as the No. 1 natural gas producer among U.S. shale plays, according to the U.S. Energy Information Administration website and an energy consulting firm.

But there's still some debate as to whether Haynesville is the clear-cut No. 1.

Among those wanting further clarification and more detailed confirming data Monday were Steven Grape, the Dallas-based domestic reserves project manager for the EIA, and Gene Powell, publisher of the Fort Worth-based Powell Shale Digest, widely considered an authority on U.S. shale-gas plays and especially the Barnett Shale, which underlies more than 20 North Texas counties.

 

The EIA had posted on its website Monday an item headlined "Haynesville surpasses Barnett as the Nation's leading shale play," based on "reported pipeline flows" of natural gas from the two regions.

It cited as its source Bentek Energy of Evergreen, Colo., a well-known energy consulting firm.

The EIA website included a Bentek chart showing that the Haynesville Shale area had production of an estimated 5.5 billion cubic feet of natural gas per day, compared to 5.25 billion for Barnett. It said Haynesville surpassed Barnett in output even after the North Texas field had recovered fully from "freeze-offs" at wellsites that had briefly reduced production during bitterly cold weather in early February.

Matt Marshall, a senior energy analyst for Bentek, told the Star-Telegram in a telephone interview Monday afternoon that company estimates, updated through Sunday, showed output in the Haynesville production area in Louisiana had jumped to 5.6 billion cubic feet per day.

However, that number includes an estimated 950 million cubic feet of output that, while in the general Haynesville production area, actually comes from geological formations other than the Haynesville Shale itself, Marshall said. But the 5.6 billion does not include roughly "several hundred million" cubic feet of daily gas production from the East Texas portion of the Haynesville Shale, he said.

Marshall said Bentek's latest estimates show that production in the Fort Worth Basin, home to the Barnett Shale, is 5.44 billion cubic feet per day. But that figure includes about 790 million cubic feet that actually is from formations other than the Barnett, he said.

Actual production from the entire Barnett Shale per se and the Haynesville Shale per se in Louisiana is virtually tied at about 4.65 billion cubic feet per day, Marshall said. But if you add in the Haynesville Shale production from East Texas, Haynesville is the clear-cut leader, based on estimates of flows through gas pipelines, Marshall said.

Both Powell and Grape said Monday that they want more information about the Bentek analysis before they can be assured that Haynesville is the new No. 1 shale play in gas production.

Powell said the most-accurate measurement of production from each shale play is actual well production data, rather than estimates based on reported pipeline flows. But there can be a time lag of several months before firm well-production data can be assembled. Grape, the EIA official, stressed that the Bentek information represents "estimates" based on pipeline flows. He said he needed more information before being able to say firmly whether Haynesville or Barnett is now the top producer.

EIA data for 2009, based considerably on natural gas reserves, showed the Barnett Shale as the leading gas-producing area in the nation, with nearly 1.8 trillion cubic feet of output. Grape said earlier this month that he thought Barnett also was the leading producer last year, although the EIA hasn't published final 2010 figures.

 

Link

W&T Offshore Responds to Report of Oil Sheen in Gulf of Mexico

Tuesday, 22 March 2011 06:15 PR Newswire

W&T Offshore, Inc. (NYSE: WTI) announced that it responded to reports of an oil sheen in the Gulf of Mexico that was said to be near a W&T...

HOUSTON, March 22, 2011 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) announced that it responded to reports of an oil sheen in the Gulf of Mexico that was said to be near a W&T operated platform in Mississippi Canyon block 243 ("Matterhorn").  Following an onsite and aerial  investigation  by the Company,  it was determined that the source of a reported oil sheen was not the Matterhorn platform or any other nearby W&T operated facilities, as speculated in several media reports.  

About W&T Offshore

W&T Offshore is an independent oil and natural gas company focused primarily in the Gulf of Mexico, including exploration in the deepwater and deep shelf regions, where it has developed significant technical expertise. W&T has grown through acquisition, exploitation and exploration and holds working interests in approximately 67 fields in federal and state waters and a majority of its daily production is derived from wells it operates.  For more information on W&T Offshore, please visit its Web site at http://www.wtoffshore.com/.

Contacts:

Janet Yang, Finance Manager
investorrelations@wtoffshore.com
713-297-8024
Danny Gibbons, SVP & CFO
713-624-7326

SOURCE W&T Offshore, Inc.

 

Link

[Oil and Gas] - Libya oil faces steep hurdles before return to global markets

Libya oil faces steep hurdles before return to global markets

March 21, 2011, 8:17 p.m. EDT

By Claudia Assis, MarketWatch

Reuters - Rebels walk past a burning Al-Sedr Oil Terminal after it was hit by pro-Gaddafi forces during clashes between Ras Lanuf and Bin Jawad March 9, 2011.

 The Iraq invasion was a major conflict in which much of the oil infrastructure suffered not only damage through warfare but also through looting.

SAN FRANCISCO (MarketWatch) — Caught between Libyan rebels, outside forces and Moammar Gadhafi, it could take years before much of Libya’s oil flows to world markets, energy analysts cautioned Monday.

The crisis, which deepened after western forces began bombing Libyan defenses Saturday, bears a resemblance to the situation in fellow OPEC-member Iraq, where output was severely disrupted by two Gulf wars and a diplomatic battle over who controlled the revenue from its sale.

Some of the Libyan oil fields could avoid major damage because they are far away from cities and towns, the target of much of the past weeks’ fighting.

“However, there are no guarantees Gadhafi and his motley crew of fellow believers ... will not follow a scorched earth policy,” said Leo Drollas, chief economist at the Centre for Global Energy Studies in London.

That’s one danger facing Libyan oil fields. As Iraqi forces under Saddam Hussein withdrew from Kuwait during the first Gulf war, they burned oil wells, Drollas noted.

The United Nations on Friday authorized military action in Libya to protect civilians amid fighting between forces loyal to Gadhafi and rebels seeking an end to his rule. Fighting is mostly concentrated in eastern Libya -- where most of the country’s oil’s production is located. Even the most optimistic analysts don’t expect Libyan oil back on line until after the first half of the year.

Output has already been severely curtailed. Most estimates point to production down by about 1 million barrels a day, J.P. Morgan said in a note to clients Monday. Production before the uprising was estimated around 1.6 million to 1.8 million barrels a day, mostly exported to Europe and, to a lesser degree, to Asia.

“U.N. sanctions have effectively imposed an embargo on Libyan exports. Based on the experience in Iraq, we continue to emphasize Libyan production will remain low and volatile for many years,” they said.

Support for crude-oil prices is likely to rise as demand ramps up ahead of the Northern hemisphere summer, although experts say most of Libya’s strife has been factored into the recent high prices for oil futures.

Oil futures for April delivery /quotes/comstock/21n!f:cl\j11 (CLJ11 102.21, -0.12, -0.12%)   rose 1.3% to $103.33 a barrel on the New York Mercantile Exchange Monday, extending the year’s gains to roughly 13%. Oil topped the $100 mark as some pro-democracy protests in North Africa and the Middle East turned to violent conflicts with the ruling regimes, particularly in Libya. Brent crude, the European benchmark, has shot even higher.

Iraq comparisons

Iraq’s oil output following the wars is serving as a model for energy analysts trying to determine how long Libyan oil could be unavailable to European and other refiners.

Production in Iraq was around 2.5 million barrels a day right before the invasion in March 2003
It was back at such levels only in 2007, Drollas said. Recent estimates put Iraq’s current production at 2.8 million barrels a day, Drollas added.


In Libya, much hinges on how the oil installations fare as the battles rage on, and how soon foreign workers will be able to return to the country, said Samuel Ciszuk, a senior Middle East energy analyst at IHS Global Insight in London.

Oil installations near the town of Ras Lanuf have been damaged as the conflict escalated, but experts say most infrastructure has been spared.

As for replacements for Libya’s light, sweet crude, the world has available oil from Nigeria and Angola, which are similar to Libyan oil. Unlike 2008, when Nigerian oil disruptions contributed to the record high oil price, these and other African countries have been able to keep their production, he said.

Some of the heavier Saudi Arabian oil, although not a perfect substitute, is also appropriate for refineries previously using Libyan oil with the addition of natural gas liquids and other liquid hydrocarbons.

But the full price impact of the conflict in Libya may yet to be seen, said Sarah Emerson, managing director of Energy Security Analysis Inc. in Massachusetts.

“We’re in the shoulder season,” she said. Heading to peak season, there may not be enough light, sweet oil to go around, she added. “We may not have the right quality at the right time of the year.”

More sophisticated refineries in Europe and elsewhere are able to process heavier crude but there’s only so much tweaking refiners will be able to do, Emerson said.

Switching grades “is more than a little throw off. We lost a very specific light sweet crude and it is not that easy to replace it.”

The spectrum of another conflict elsewhere in the world also haunts markets.

“The extra capacity (from Saudi Arabia) is there but it tights up the world capacity,” Drollas said. If oil suffers another shock somewhere, “then we are back at 2008.”

Oil hit a record high in the summer of 2008, when it soared to $147 a barrel only to fall to below $50 before the year was out.

Oil around $150 a barrel this year would mean “a slip back into the recession next year,” Drollas said. Prices are at a level they may be already hurting global growth, he added.

The only possible resolution for the conflict is a Libya without Gadhafi, Drollas said. “A wounded Gadhafi is worse, metaphorically speaking,” he said.

Claudia Assis is a San Francisco-based reporter for MarketWatch

Link
http://www.marketwatch.com/