Hydrocarbons occupy a vital role in our life and continue to play an important role for many more years to come. We need to follow all technological innovations to continue our productivity standards to achieve our production targets. Let us extend our vision to achieve this mission.

Friday, April 29, 2011

Gas Jobs Await Trained Work Force

The list of want ads is long.

Project engineer, gas marketing administrator, landman, heavy equipment operator, compressor technician, business development director, regulatory clerk, petrophysicist.

In late March, the member companies of the Marcellus Shale Coalition advertised hundreds of open positions they want to fill in Pennsylvania or just over the border in New York. Three years into the gas-drilling boom, the job listings testify to the continued need for workers with a variety of skills to propel the growing industry.

Researchers with the Marcellus Shale Education and Training Center estimate shale drilling will require between 3,700 and 15,000 direct jobs in central and northern Pennsylvania by 2013 and an additional 8,100 to 13,500 direct jobs in southwestern Pennsylvania by 2014.

About 75 percent of the jobs will be blue-collar work, said the study's author, James Ladlee, director of Penn State Cooperative Extension in Clinton County. A significant amount, 20 percent, of the jobs can be characterized as general office work -- everything from information technology to receptionists.

"People think about the workers on the drilling rig and they think those are the only jobs out there," he said. "There are a whole bunch of people that are backing them up in a variety of ways to make sure that they are able to do their jobs out in the field."

The Education and Training Center, based at Pennsylvania College of Technology in Williamsport, has continued to adapt to the industry's work force needs, but the basic framework for many of the skills necessary for industry jobs are already available in general skills courses at most technical schools.

For example, many of the skills learned in a diesel mechanics course will apply to the diesel compressors used to push gas from wells into pipelines, Mr. Ladlee said.

Some higher-paying jobs will require more education. Engineers, a real need for the industry, will need four or more years of college education to acquire the necessary skills.

Larry Milliken, director of energy programs at Lackawanna College, said a certified pipeline welder can make more than $100,000 anywhere in the country because they are in such high demand.

"You can't get that skill in a year, but you can develop that skill in four years," he said. "And most of that is paid, on-the-job training after you get a two-year technical degree."

Prospective employees will need to accept a demanding schedule if they want to work in the gas industry, Mr. Milliken said. It is a hard truth he reiterates to the 50 students in the college's natural-gas technology program.

"A lot of people want to work an eight-hour day, go home, not work holidays or weekends and never be interrupted on their personal schedule. That's not the oil and gas business," he said.

"It's a 24-hours-a-day business. It is demanding. You've got to be available when the job calls."



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Knight Ridder/Tribune Business News

EPA to Shed Light on Fracturing Rules


Federal regulators will soon clarify the rules for natural gas companies that inject diesel fuel into the ground as part of their hydraulic fracturing operations, the head of the Environmental Protection Agency said Tuesday.

The guidance, which EPA Administrator Lisa Jackson says is coming "very shortly," is meant to clear up rules for natural gas producers.

A congressional investigation concluded earlier this year that companies have not secured EPA permits before injecting more than 32 million gallons of diesel fuel and other fluids into the ground in fracturing operations between 2005 and 2009.

States historically have regulated hydraulic fracturing. The technique involves injecting mixtures of water, sand and chemicals including diesel fuel deep underground at high pressures to break up dense shale rock and release gas locked in it. Although Congress exempted most hydraulic fracturing activities from EPA's jurisdiction as part of a 2005 rewrite of the Safe Drinking Water Act, that exception does not apply to diesel -- even though the government only began to regulate it last year.

Jackson insisted that the EPA has authority to regulate diesel fuel in fracturing fluids.

"Our belief is that this is not exempt," she said. "That exception specifically says that diesel is not exempt. So if you are injecting diesel, that is a concern."

Environmental worries

The move comes amid mounting environmental fears about the hydraulic fracturing process, which is being combined with horizontal drilling techniques to extract previously unrecoverable natural gas from shale formations across North America.

Conservationists are concerned about the high water demands of fracturing. Environmentalists warn that natural gas can escape out of poorly designed wells and that chemicals in fracturing fluids can taint nearby water sources.

A blowout at a Chesapeake Energy natural gas well in Pennsylvania last week renewed those fears. The incident prompted the company to temporarily stop hydraulic fracturing in the region.

Easing public concerns about the process is key to natural gas development, said Gene Sperling, the chairman of the White House's National Economic Council.

Speaking at an Energy Information Administration conference, Sperling said the energy industry should embrace "common-sense regulation that builds the public trust" that fracturing does not put at risk clean or safe drinking water.

Industry representatives broadly have argued against federal regulation of hydraulic fracturing and insist state officials are better positioned to oversee the work. Although some oil field services companies and natural gas producers have begun voluntarily providing details about the ingredients of their fracturing fluids, there is no federal mandate for that disclosure.

Backing from Shell

Marvin Odum, the president of Shell Oil Co., said the company "supports regulations that require companies to disclose the chemicals they use in the process ... and adhere to the highest safety standards."

"Responsible operators should have no problem complying," Odum added.

Odum said that Shell is working toward a goal of recycling 100 percent of the water it uses in its hydraulic fracturing operations.

He insisted that hydraulic fracturing techniques can be used to extract natural gas safely.

"Make no mistake," he said. "It can be done without harming the environment. Anything less is unacceptable."


Musings: Natural Gas Is So 2010; Now It's All About Liquids-rich Shale

Last week the Baker Hughes U.S. active drilling rig count hit 1,800, up 1.6% from the prior week and up 21.5% over the past year.  These were notable achievements. The increases reflect the exploration and development fever that is gripping oil and gas companies. This should be good news for the country's oilfield service industry, but maybe even better news for consumers as the increased drilling should lead to higher oil and gas production, and maybe lower fuel prices.  More production means the nation's economy need not import as much oil and gas from abroad, which could have a significant impact on our balance of trade and payments, and the value of the dollar.

The most notable bit of data about last week's rig count was that for the first time in nearly 16 years, the oil and gas industry is employing more rigs targeting crude oil prospects (913 rigs) than drilling for natural gas wells (878 rigs). Analysts and investors, keen to see higher natural gas prices, have seized on this switch in drilling focus as a signal that future gas production will soon stop climbing.  Assuming that the nation's natural gas consumption continues to rise, the drilling switch portends a shrinking of the oversupply of natural gas. That should mean higher natural gas prices – the only question is when. 

Those E&P companies that are leading the charge into the gas shale plays around the country will be happy to see higher natural gas prices. They continue to claim that they can be profitable drilling these gas shale plays at natural gas prices in the $4.00 to $5.00 per thousand cubic feet (Mcf) of gas. Their financial results suggest something different. They still proclaim the success of the gas shale revolution, a movement that is beginning to spread globally. 

Slightly over two weeks ago, the Energy Information Administration (EIA) released an analysis of gas shale resources around the world.  It was clear from the report that the EIA believes the domestic gas shale revolution will be embraced globally. The EIA report estimates that 32 countries with known gas shale resources have added 5,760 trillion cubic feet (Tcf) of technically recoverable natural gas to the world's resources. With the addition of the U.S. gas shale resources, the global total would swell to 6,622Tcf. For comparison purposes, the world's proven natural gas reserves as of January 1, 2010, were 6,609Tcf. The world's total technically recoverable gas resources were 16,000Tcf as of the beginning of 2010, so with the new gas shale resources added in, the world now has over 22,000Tcf of gas resources. 

The 32 countries with gas shale resources span the world and are likely to become energy-headline locations before long. Most people are familiar with the gas shale drilling underway in Poland and China, but those are only two of the 32 countries that span the globe.  China leads the world with an estimated 1,275Tcf of gas shale resources. In Europe, Poland is in first place with an estimated 1,867Tcf of potential reserves, followed closely by France with 180Tcf. Interestingly, France has announced it is considering banning the drilling of gas shale wells until a study of possible water pollution problems associated with hydraulic fracturing are investigated and proven false. Equally surprisingly is that Norway has nearly half the gas shale resources of Poland and France.

Exhibit 1.  Gas Shales Located Around The World
Gas Shales Located Around The World
Source:  EIA

In South America, Argentina is highly prospective with nearly 90% of the total gas shale resources estimated to be in the United States.  Brazil has about a third of the resources of Argentina with most of the potential resources located in the area close to some of the key manufacturing sites in the country. Surprisingly, Mexico has a huge potential with almost 80% of the estimated United States gas shale resources.

In Africa, the greatest potential source of natural gas from shales lies in South Africa, which has an estimated 485Tcf of resources.  Libya, the site of the current civil war involving the country's crude oil reserves and production, has an estimated 290Tcf of gas shale resources. Algeria follows with nearly 80% of Libya's estimate. 

While the world has lots of gas shale resource potential, it is in North America, and primarily the United States, where the gas shale revolution is in high gear producing substantial volumes of new gas production. According to the EIA, 2010's 4.87Tcf of gas shale production represents about 23% of total U.S. output, but it is projected to account for 45% of the nation's gas supply by 2035. The huge potential of gas shales in this country was first highlighted by the 2009 report of the Potential Gas Committee (PGC) at the Colorado School of Mines. In that report, the PGC estimated that there was about 616Tcf of gas shale resource, or about a third of the country's total resource potential. 

Recently, Ken Medlock, a professor at Rice University, delivered a presentation about the gas shale industry at the American Association of Petroleum Geologists (AAPG) annual meeting. In his presentation he listed a timeline of potential gas shale resource estimates beginning with the 2003 National Petroleum Council estimate of 38Tcf. Two years later the estimate was raised to 140 Tcf and then in 2008 Navigant, a consulting company, estimated there was 520Tcf of potential reserves. The next year came the PGC estimate of 616Tcf and last year, consultant ARI estimated gas shale resources of more than 1,000Tcf. Mr. Medlock said there is a Department of Energy study underway with a May release date that will contain an estimate greater than ARI's estimate, likely putting it close to China's estimated 1,275Tcf of potential reserves.

All this potential gas has led politicians, investment professionals and E&P company executives to announce that the United States has in excess of 100 years of natural gas supply. In his presentation at the AARP, Art Berman showed that by reading the PGC report it becomes clear that gas shale reserves will likely only supply about 20 years of demand at the current 23Tcf of annual consumption. 

Mr. Berman's pricking of the gas shale 100-year supply bubble should be having a greater impact, but instead the air is barely slipping out of the balloon. In fact, President Barack Obama has endorsed the huge potential gas supply mantra. In a recent presentation about the nation's energy situation, President Obama said, "We have a lot of natural gas here in this county." In doing so, however, he touched on the key issue now swirling around the gas shale revolution, which is the use of hydraulic fracturing to release the trapped gas from the formation   President Obama's observation was, "The problem is…extracting it [shale gas] from the ground. The technologies aren't as developed as we'd like and so there are some concerns that it might create pollution in our groundwater, for

Exhibit 2.  Gas Shale Reserves Less Than 100 Years
Gas Shale Reserves Less Than 100 Years
Source:  Art Berman

example. So we've got to make sure that if we're going to do it [fracking], we do it in a way that doesn't poison people." There is plenty of evidence to refute the President's observation, but it is having a hard time being recognized.

A recent article by Stephen Hayward of the American Enterprise Institute highlighted the two problems confronting gas shale development. First is the issue of the safety of hydraulic fracturing. The other issue is what to do about the gas bounty being developed. The gas shale revolution has put these issues on the front pages of the papers and has drawn into the discussion the one factor that can derail the revolution – politics, such as the views of the President.

The battle over the safety of hydraulic fracturing grew in intensity the closer gas shale drilling moved to the East Coast. The emergence of the Marcellus shale as probably the largest gas field in the United States brought drilling rigs and pressure pumping equipment into the hilly topography of New York, Pennsylvania, Ohio and West Virginia. Despite the American oil industry getting its start in 1859 when Col. Drake drilled the first oil well in northwestern Pennsylvania, the region is not used to the intensity of drilling and producing activity experienced in regions such as the Southwest and Gulf Coast. The lack of equipment and workers has created a huge in-migration of both, creating an unsettled feeling among the local population. New oilfield service company equipment bases, heavy traffic consisting of large trucks with loads of equipment and supplies driving through small towns and rural areas, and lots of temporary workers from foreign places such as Texas, Oklahoma, Louisiana and Canada is changing the pace of everyday living in the Northeast. 

The low price of natural gas, combined with the high-efficiency gas power plant designs, makes gas-fired power plants cheaper than coal-fired power plants. This has been the case for at least two decades, but due to the volatility of natural gas prices, these plants have been limited to peak electricity generating roles. Now it appears gas could be used for more baseload generation, replacing aging coal plants that are under pressure from costly new Environmental Protection Agency (EPA) clean air requirements and the long-standing environmental crusade against coal plants. 

For the first time ever, natural gas producers and utilities have joined with environmentalists to alter the status quo over replacing coal-fired power plants with gas-fired ones. This alliance will not last for long, however, as cheap natural gas makes the favorite energy sources of environmentalists – wind and solar – that much less competitive. Environmentalists used to love natural gas so long as it was expensive and used merely as a backstop for "clean" wind and solar power. Now that it may displace their favorite fuels, they don't love natural gas as much.

Mr. Hayward refers to this attitude about natural gas on the part of environmentalists as "the theorem of environmental duplicity: namely, there is no form of 'clean' or 'alternative' energy that environmentalists won't decide to oppose if it becomes practical and affordable on a large scale." Last week's Chesapeake gas shale well blowout certainly gives more ammunition to the environmental movement to oppose the use of hydraulic fracturing. The Chesapeake well was plugged late last week and the company and state regulators are monitoring the pollution as well fluids were spilled and migrated across the land. 

Environmental opposition to hydraulic fracturing has been helped along by a sympathetic media that writes "investigative" reports that often create false impressions about the safety of hydraulic fracturing and even the exploitation of gas shale formations. Every study conducted about hydraulic fracturing has found no problems. The reason is simple: the target shale formations are thousands of feet below the surface and thousands of feet below the aquifer. Both the distance and the nature of the rock that separates the formations prevent fracturing fluids from migrating to the aquifer, as demonstrated in Exhibit 3. What has been a problem in certain wells where natural gas has migrated into drinking water was the primary cement job for the surface pipe, which is designed to isolate the gas well from the ground water. Due to cement bond failures, it is possible for flowing natural gas to leak out and into the ground water, which then can flow to a homeowner's water faucets. 

Other than gas migrating into ground water formations, water associated with gas shale activity has become a major challenge for the E&P industry. Water is needed for drilling and for hydraulic fracturing completions. As a result of the large volumes of water required in the completion process, huge volumes of contaminated

Exhibit 3.  Gas Shale Wells Are Well Below Groundwater
Gas Shale Wells Are Well Below Groundwater
Source:  Ohio Department of Natural Resources

water are returned in the initial well flow. This flow-back water needs to be disposed of either by cleaning it up to meet standards for dumping into local waste water disposal systems or by placing it into streams and rivers. An alternative disposal method is to inject it into special disposal wells. Because Pennsylvania has few disposal wells, flow-back water and water produced in association with oil and gas output is either cleaned up or hauled to disposal wells, many of which are located in neighboring Ohio.

While water and hydraulic fracturing concerns are, and will continue to be, an ongoing issue, the more critical consideration is the economic viability of gas shale drilling. When Mitchell Energy solved the key critical variables in unlocking natural gas trapped in the shale formation underlying the Barnett basin in Texas, they probably had little comprehension of the revolution they were starting. That revolution was perceived to have certain characteristics that would unlock tremendous gas resources. Those characteristics included: uniform shale formations that blanketed the areas underlying oil and gas producing basins; that formations would yield significant gas volumes, which was directly correlated with the number of wells drilled and hydraulic fracturing treatments administered; that horizontal drilling exposed greater amounts of the shale formation helping release more of its trapped gas; and that all wells in shale formations would be equally productive enabling rapid drilling employing uniform drilling techniques producing low drilling costs. The combination of these characteristics was supposed to translate into large volumes of low-cost natural gas.

After about five years of active drilling in the oldest shale basins has begun to disprove certain of these characteristics and their implications on well economics. We have learned that gas shale basins still need a trapping mechanism in order to be productive.  Drilling has also shown that gas shale plays have "sweet" spots that produce higher well volumes than wells drilled outside of the "sweet" spots. These realizations have begun to dispel the manufacturing concept for how gas shale fields would be developed. 

We have learned that by drilling longer lateral sections and applying greater numbers of hydraulic fracturing treatments to wells, gas volumes can be maximized. The problem has been that the cost to secure the acreage to drill these gas shale wells and the drilling and completion costs are not particularly cheap.  Since natural gas prices are so low due to growing gas production and weak gas demand, the economics of many gas shale wells have been called into question. We are also finding that many gas shale wells are not producing the volumes projected. This latter observation is highly contentious among participants within the oil and gas industry. However, the more data that is collected, the greater the confidence the critics of gas shale profitability have that these plays may not be the goldmines proponents claim.

In Art Berman's AAPG presentation, he presented the chart in Exhibit 4 showing that within the Barnett Shale play, when the production from newly drilled wells during the last 12 months is excluded, gas production declined at a 44% annual rate. The importance of this static well analysis is that it highlights the need for producers to continually drill new wells in order to grow production, or maybe merely to offset production declines. The significance of the analysis is that the E&P industry is on a treadmill of new well drilling with the likelihood that the slope of drilling activity is rising with cost implications unknown. 

Exhibit 4.  Without Drilling Production Falls Rapidly
Without Drilling Production Falls Rapidly
Source:  Art Berman

Another analysis of the Barnett Shale play shows how the wells are not producing the necessary volumes of natural gas to support the Economically Ultimately Recoverability (EUR) reserve estimates being used by producers. In determining profitability, producers estimate the total number of reserves they will produce from their wells and divide that figure into the total cost estimate for finding, developing and producing the reserves. The resulting cost per Mcf of gas produced is amortized against the revenue earned from its sale. If any of the assumptions is wrong, the profitability calculation can be way off.

If we examine two slides from Chesapeake's 2010 institutional investor and analyst meeting in October 2010, we can see how the EUR and well costs interact to impact profitability of gas shale developments. The first chart (Exhibit 5) shows the decline curves and basic data about the four major gas shale plays in which Chesapeake is involved. The data on this chart shows that Chesapeake expects the EUR for its Barnett Shale wells to be 3.0 billion cubic feet (Bcf).

Exhibit 5.  3Bcf EUR Estimated For Barnett Shale
3Bcf EUR Estimated For Barnett Shale
Source:  Chesapeake Energy

The next chart (Exhibit 6) shows the sensitivity of its profitability to the price of natural gas and the EUR.  As the data for the Barnett Shale shows, Chesapeake believes that with a EUR of 3.0 Bcf and a price of $5.05/Mcf, the company will earn a 10% rate of return. By moving along the green curve on the chart, one can see that a smaller EUR needs a much higher natural gas price to achieve the same 10% rate of return. 

An analysis of the Barnett Shale field shows how production from 1992 through November 2010 has climbed. The chart (Exhibit 7)

Exhibit 6.  Economics Of Gas Shale Plays
Economics Of Gas Shale Plays
Source:  Chesapeake Energy

shows that the number of new well completions has decline sharply in the past two years with a corresponding decline in natural gas output. 

Exhibit 7.  Barnett Shale Gas Production
Barnett Shale Gas Production
Source:  Robert Gray

This analysis, prepared by Robert Gray, an associate of Art Berman's, focused on examining the performance of a static universe of producing wells in the Barnett Shale. In Exhibit 8, he tracked the production from a universe of wells that he stopped growing in November 2009. One can see the historic gas production in blue, which had begun to decline prior to 2009, and the monthly gas production subsequent to creating the static well universe. 

Exhibit 8.  Barnett Shale Static Well Production
Barnett Shale Static Well Production
Source:  Robert Gray

By using the production data through November 2009, Mr. Gray was able to generate models for predicting the future decline rates, which, over the remaining production life of the wells, produces an estimate of the EURs for the wells. 

Exhibit 9.  Production Basis For Curve Projections
Production Basis For Curve Projections
Source:  Robert Gray

Shown in Exhibit 10 are the two type curves – hyperbolic and exponential – calculated from the historic data as of November 2009.  Under the hyperbolic curve, the estimated EUR per well is 2.395 Bcf. The exponential curve shows a future EUR of only 1.133 Bcf.  Both of these EUR estimates are well below the EUR projected by Chesapeake for its wells in this field.

Exhibit 10.  2009 Production Decline Curves
2009 Production Decline Curves
Source:  Robert Gray

Now that we have an additional year's worth of production data, Mr. Gray was able to estimate new decline curves incorporating that information. As seen in Exhibit 11, the new 2010 hyperbolic and exponential curves fall below those estimated from the 2009 data. We now have EUR estimates of 1.452 Bcf for the hyperbolic curve and only 0.850 Bcf for the exponential curve. 

Exhibit 11.  2010 EUR Curves Well Below Estimates
2010 EUR Curves Well Below Estimates
Source:  Robert Gray

If we go back to the rate of return chart from the Chesapeake presentation, it does not show what gas price is required for EURs smaller than 2.4 Bcf.  Even at that EUR, the 10% rate of return requires a gas price slightly below $6.00/Mcf. Our guess is that a producer will need a gas price somewhere around $7/Mcf to achieve a modest return on investment given the exponential EUR Mr. Gray has calculated. In a more recent update, Mr. Gray has increased his exponential EUR estimate to about 1.0 Bcf. Even that increased estimate is still only a third of Chesapeake's EUR estimate. 

Exhibit 12.  Well Production Short Of EUR Estimates
Well Production Short Of EUR Estimates
Source:  Art Berman

In prior presentations, Mr. Berman has shown the chart in Exhibit 12. It presents the range of EURs claimed in investor presentations by the major producers in the Barnett Shale plotted against their cumulative production. The data shows how production does not seem to be coming anywhere close to the estimated EURs. Quite possibly this helps to explain why 16 significant E&P companies active in the gas shale plays have written off goodwill and the value of their reserves to the tune of $67 billion over 2008-2010. If producers acted in a more rational manner and cut back their drilling, the rapid decline in gas shale production as demonstrated by Mr. Berman's chart should lead to higher natural gas prices. Therein lays the conundrum for the gas market – drill to grow and satisfy Wall Street or cut back, secure higher prices and stop destroying shareholders' capital. 

G. Allen Brooks works as the Managing Director at Parks Paton Hoepfl & Brown. Reprinted with permission of PPH & B.

Change in Oil Funding Priorities Concerns Western Legislators

Lawmakers have passed a bill that changes the way oil money will be allocated amid cries from some western legislators that it will short the oil producing counties.

House Bill 1451, which now goes to the governor for signature, eliminates the Permanent Oil Trust Fund, where most oil revenue goes now, and disperses it into other funds --mainly the state's general fund -- while all setting the stage for locking more of it away in the Legacy Fund down the road.

Some legislators' problem with the Permanent Oil Trust Fund was one of semantics -- they complained there was nothing permanent about it and the fund should be dissolved and dispersed into more project-specific funds.

The bill does just that, putting more money from oil revenue into the general fund to cover projects that would've likely been funded by oil money anyway. The rest of the money funnels into funds, hitting an upper limit before moving into the next one like a line of dominoes.

After the first $200 million goes into the general fund, the next $341 million would fund property tax relief. Then comes more money into the general fund, allotments into the newly-created Strategic Investment and Improvements Fund, then into disaster relief, and then back to the Strategic Investment and Improvements Fund before 25 percent of whatever is left over goes into the Legacy Fund. Created by voter referendum in 2010, the Legacy Fund locks some of the oil revenue away, untouchable by the Legislature until 2017.

As the bill came to a final vote Tuesday in the Senate, some expressed concern about putting even more money in the Legacy Fund, though money is not projected to reach that fund this biennium.

Sen. John Andrist, R-Crosby, said investing in infrastructure, particularly in the western part of the state, should be a No. 1 priority.

"I'm afraid we're going to get short changed because we'll be trying to save money rather than invest it in infrastructure in the oil producing counties that supplied those funds," Andrist said, adding that the infrastructure money from this session had been scattered through the state rather than targeted at the west.

Other discussion surrounded eliminating the Permanent Oil Trust Fund.

Sen. Dwight Cook, R-Mandan, said centralizing spending from one source would be more transparent. Others argued the opposite, saying it made it unclear to what extent oil was funding state projects.

"I think it's always good to know when the state is spending oil money," said Sen. Jim Dotzenrod, D-Wyndmere.

Sen. John Warner, R-Ryder, said much of the state's spending is due to oil, but he's concerned transferring more to the general fund will tempt legislators to spend.

"We can only put so much in the general fund or we'll overspend," Warner said.

Thursday, April 28, 2011

Oil above $113 as dollar weakens on Fed comments

Oil prices rose above $113 a barrel on Thursday in Asia to the highest since 2008 as a weakening U.S. dollar made commodities such as crude cheaper for investors with other currencies.

Benchmark crude for June delivery was up 71 cents at $113.47 a barrel at midday Singapore time in electronic trading on the New York Mercantile Exchange. Crude reached $113.70 earlier in the session, the highest since September 2008.

The contract rose 55 cents to settle at $112.76 on Wednesday.

In London, Brent crude for June delivery was up 54 cents to $125.67 a barrel on the ICE Futures exchange.

Federal Reserve Chairman Ben Bernanke said Wednesday the central bank would complete a second round of Treasury purchases, known as quantitative easing, through June and keep lending rates low.

The euro rose to $1.4860 on Thursday from $1.4773 while the dollar fell to 81.72 yen from 82.26.

Bernanke's comments "suggested a continued loose monetary policy for an extended period that is apt to maintain pressure on the dollar in the process of boosting equities and assets such as oil," Ritterbusch and Associates said in a report.

The Fed has kept rates low and pumped cash into the economy in an effort to boost lending and growth coming out of the 2009 recession. But that policy has also helped inflate the prices of dollar-based commodities such as oil, which is up about 50 percent since last summer.

In other Nymex trading in May contracts, heating oil rose 1.5 cents to $3.25 a gallon and gasoline added 2.6 cents to $3.45 a gallon. Natural gas futures were up 0.5 cent at $4.41 per 1,000 cubic feet.

Fuel For Thought - 27 April 2011



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Weekly Newsletter - 27 April 2011

FUEL FOR THOUGHT

KBR extends Jack-St Malo gig KBR will perform detailed design engineering for the floating production unit at Chevron's deepwater Gulf of Mexico Jack and St Malo development.

Energy News, Careers, Analysis & Technology - 24 / 7 / 365

RIL finds gas at Dhirubhai-53 An exploratory well in the Cauvery-Palar basin offshore India has turned up gas and condensate, operator Reliance Industries announced.


Maersk reports fire off Qatar Maersk Oil reported no serious injuries after a fire broke out on one of its operated accommodation platforms offshore Qatar on 21 April 2011.


COSL readies newbuilds China Oilfield Services Limited's Pioneer semisubmersible rig has arrived in Norway to begin up to five year's work for Statoil, and the company took delivery of the COSL 720 seismic vessel.

Lukoil, Rosneft to cooperate Russian companies Lukoil and Rosneft agreed to cooperate in a number of areas, including joint exploration efforts.


Golar orders conversion Jurong Shipyard's Sembcorp Marine will convert the LNG Khannur tanker into a floating storage and regasification unit (FSRU) to be renamed West Java FSRU.

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McDermott bags Jack, St Malo subsea jobs McDermott International has been awarded fabrication and installation contracts for work at Chevron's deepwater Gulf of Mexico Jack and St Malo fields.


Golden Eagle takes off Nexen approved the development of the Golden Eagle development, a 2007 discovery near the Buzzard development in the North Sea.


Russian LNG plant enters pre-FEED The Japan Far East Gas Co. has signed an agreement with Russia's Gazprom to conduct a joint study for the natural gas utilization project in the Vladivostok area.

Offshore Engineer EVENTS


Deepwater Intervention Forum – "The Next Steps, the New Reality"
16-18 August 2011 - Galveston, Texas
www.deepwaterintervention.com

- The Forum is pleased to announce, Baker Hughes, as Silver Sponsor for 2011. The exhibit floor is nearly sold-out.
To see a complete list of participating and exhibiting companies, click on our link . . .
Read more



Drilling & Completing Trouble Zones - "Challenging Problems, Collaborative Solutions"
25-27 October 2011- Galveston, Texas
www.drillingtroublezones.com

- The DCTZ 2011 Forum workshop organizing committee, focused on Horizontal Drilling, are represen- tatives from: Schlumberger, At Balance, Baker Hughes, 3PS Inc., NOV, Chesapeake and Devon Energy. Read more



Emerging FPSO Forum – "On the Horizon"
20-22 September 2011 - Galveston, Texas
www.emergingfpso.com

- Strong commitments from industry to support the stated agenda are: BW Offshore, SBM, WISON, Helix, MARIN, MODEC, Petrobras. The USCG other agencies will offer an in-depth Regulatory Session.
Read more


OilOnline at OTC 2011 - Booth 4565


OTC 2-5 May 2011 - Houston, Texas

Update your diary to include a visit with the OilOnline team
at booth 4565 at the Offshore Technology Conference, May 2-5, Houston, Texas. We'll be there to answer questions or help you create an account, upload your resume or job openings. We'll have really cool OilOnline branded coffee mugs, wipe cloths, pens and carrier bags so you can transport it all home!

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Wednesday, April 27, 2011

Trade Show Advisor, Honeywell Portable Gauging is Accurate, Whitepaper: Managing Your Supply Chain





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Honeywell: Portable Gauging is Accurate

Manual gauging is not usually associated with advanced technology nor with reducing VOC's emissions, but recent developments by one manufacturer working in this sector have taken the concept onto a different plane.

Honeywell Tanksystem is a world leading supplier of portable level gauging equipment. With headquarters in Switzerland since 1985, Tanksystem has a network of 60 agents and 17 service stations WORLDWIDE. All its gauging and sampling equipment is intrinsically safe and manufactured for use in classified hazardous environments (Zone 0) onboard vessels or on tanks. By increasing reliability and efficiency, Honeywell Tanksystem helps customers improve business performance.



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View Honeywell Product Information


Site of the Week: Trade-Show-Advisor.com

Trade show participation enables you to stay on top of the latest industry trends, gain competitor insights, make key industry contacts, and further solidify relationships with current customers. The articles and resources on Trade-Show-Advisor.com are designed to help business owners, marketers and exhibitors successfully leverage all aspects of tradeshow involvement.

Whether you are participating in an annual industry event, major international exhibition or a local trade fair, you'll learn proven techniques that enable you to establish meaningful goals, masterfully plan and and implement your strategy, and measure your return on investment.





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Visit Trade-Show-Advisor.com


Whitepaper: Managing Your Supply Chain - Accurately Calculating Total Landed Costs

Calculating the total landed cost of materials and finished goods arriving from offshore sources is not always an easy task. Though this fundamental aspect of supply chain management is very important, too many businesses rely on shoddy guesswork that often leads to failed ventures. To safeguard your investments it is helpful to use a landed cost calculation model that accurately projects the total cost of sourcing materials from start to finish.


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Read Managing Your Supply Chain Whitepaper

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