By: Sharyn Alden
Nov/Dec 2011

Chevron Harnesses the Power of the Sun for Recovering Heavy Crude Oil

We’ve all heard about solar being used in a variety of innovations but now a 29-megawatt solar thermal “green steam” project from Chevron is underway.

The “solar enhanced oil recovery” project is a strong reason why solar energy may be tapped for years to come. In California the sun is being used to heat water in order to generate steam and expedite the recovery of oil.

Chevron is behind the aggressive push to recover oil with solar energy. The project is located about 200 miles northwest of Los Angeles in California’s Central Valley desert town of Coalinga. Investors in the solar project include Google, BP and Morgan Stanley. The group is banking on new solar thermal energy technology from BrightSource Energy.

In early October Chevron unveiled its BrightSource Energy project currently under construction. The project’s solar thermal technology is expected to be one of the most significant demonstrations of solar energy to date — particularly asit relates to extracting oil from older wells.

Why use solar technology instead of burning natural gas to heat water for steam? Solar steam lacks polluting emissions common with natural gas. Another reason is that solar steam has the potential for unlocking hard-to-extract oil. Industry statistics show that in any given reservoir about 10-30 percent of potential oil can be extracted but that leaves a significant amount of oil still underground.

At the heart of the solar operation is BrightSource Energy’s power tower high atop a 120-year-old oilfield covering 65 acres. The 370-megawatt Ivanpah Solar Electric Generating System is the first project from BrightSource.

The desert-based solar project maximizes the use of thermal solar technology by tracking the sun with mirrors. Sun tracking is accomplished with 7,644 10-foot high mirrors (called heliostats) that direct the sun’s rays to the 327-foot-tall tower.

The sun’s energy takes over and does its work from here by heating a large water-filled boiler on the tower. Next, solar steam is injected into wells to ease the flow of heavy crude oil. The result is solar steam ready to loosen oil in nearby wells. Some of these oil wells share a production history that goes back to the 1890s.
In the future BrightSource’s solar energy operation will also be used to supply Pacific Gas & Electric and Southern California Edison with 2,610 megawatts of electricity.

BrightSource has noted the company’s solar thermal energy may someday be used on a global scale. The project is gaining attention because it may have far-reaching applications. It’s not much of a leap to consider the technology may help global energy and industrial companies produce lower emissions in countries throughout the world.
Desmond King, president of Chevron Technology Ventures said in a company statement, “This technology has the potential to augment gas-powered steam generation and may provide an additional resource in areas of the world where natural gas is expensive or not readily available.

New Offshore Rig Safety Rules Proposed

In the aftermath of the Deepwater Horizon oil spill, rules and guidelines for comprehensive drilling procedures in the Gulf continue to be a work in progress.

That message was heard loud and clear in September as the U.S. Department of Interior and the Bureau of Ocean Energy Management Regulation and Enforcement (BOEMRE) announced new safety standards for offshore oil and gas operations.

The new regulations called “Safety and Environmental Management Systems” (SEMS) are the first new major safety upgrade for offshore drilling since October 2010.

SEMS will strengthen employee training, safety management, auditing procedures and guidelines for reporting unsafe conditions. Another new mandate will update procedures for giving employees “stop work authority” if they see dangerous workplace activities taking place.

What activities will be considered dangerous or unsafe will be clearly defined. Definitions are forthcoming as to what person or persons have decision-making authority on offshore facilities. Another change will require safety audits conducted by third parties.

The public had until November 14 to weigh in with comments before the official rule-making process took place. The first workplace safety upgrade is expected to be implemented in late November.

Not unexpectedly, the latest regulations are not without controversy. Insiders call the stricter safety requirements just another hurdle in the already slow offshore drilling permit process.

Following the Deep Horizon spill and the Obama administration’s subsequent moratorium on offshore drilling, Republicans and some Democrats from oil states have been troubled by what they call a lack of responsiveness to approving offshore permits.

In fact, a recent report released by FBR Capital Markets, an investment bank headquartered in Arlington, Virginia, said the snail-like approval process has slowed operations offshore. The report also pointed out that unless BOEMRE steps up the permitting process, 20 drilling rigs are prepared to pull out of the Gulf.

BOEMRE countered by stating that since June 8, 2010 they have issued 74 shallow water-well permits and 13 others are pending with 10 returned to operators for more information.

The bureau also claimed that since February they have approved 129 permits for 40 subsea wells that require containments, with 12 more pending and 23 in need of further information.

BOEMRE Director Michael R. Bromwich responded by saying their workload is enormous and that they are reviewing and issuing permits as quickly as possible, given current resources.

Bromwich congratulated oil and gas leaders who have helped develop the new regulations, but he attacked others who didn’t have correct information to draw from.

If the Bureau is accused of dragging its feet, Bromwich said consider the enormity of the workload in front of them.

In six months alone, from mid-March through mid-September, he said the Bureau’s employees worked over 1,350 hours reviewing drilling plans and permits.

It remains to be seen if overtime will increase or whittle down once new offshore regulations are introduced later this year.

New Barnett Shale Study

Many have wondered how significant the Barnett Shale really is when it comes to economic growth in Texas. Now, a new study sheds some important light on that question.

Positive economic news stories are few these days, but in North Texas, the extraordinary rippling effect of the Barnett Shale development is making plenty of people smile.

Over a 10-year period the research, which was commissioned by Fort Worth Chamber of Commerce, found that the natural gas field is an economic driver of enormous proportions.

In late September, The Perryman Group released the study that examined economic stimulus related to the Barnett Shale. The Waco-based company studied the impact of shale development between 2001 and 2011.

The resulting study showed a steady boom of economic activities across the board — all related to the Barnett Shale operation.

The research unveiled that the natural gas field has generated $65.4 billion in economic activity since 2001 and over 100,200 jobs have been created in a 24-county area in Texas. The job growth has been direct employment by the energy industry. Personal income is also up — about 8.5 percent higher than if the Barnett Shale wasn’t generating jobs.

Estimates of tax revenues from North Texas cities are staggering — estimated to be $730 million. Tax revenue for the state of Texas this year alone is estimated at $1.6 billion from the Barnett Shale. Additionally, about 38.5 percent of economic growth in the area can be traced back to the Barnett Shale.

School districts in the Barnett Shale benefitted, too. Last year they received about $2.7 million in royalty payments and $45.8 million in tax revenue from gas and mineral rights.

The way things are going in exploration, drilling, pipeline investments and related operations, coupled with state and local revenues, the Barnett Shale development could be an exciting backdrop for another “Dallas” type of TV show.

Bill Thornton, chamber president and CEO, said, “We commissioned the study to see how or if the economic downturn had impacted past projections about the industry. What we found was that it’s a bulwark of our economy.”

Shale gas production in the U.S. is helping consumers save money on heating costs. In a recent Washington Post article the Secretary of Energy Advisory Board’s Natural Gas Subcommittee said shale production has significantly helped lower costs to consumers for heating their homes and generating electricity.

The reason is the increase of shale production not only in the Barnett Shale but in other states such as Pennsylvania, West Virginia and North Dakota.

Other bits of good news came out of The Perryman Group study. Only a small part of the estimated production in the Barnett Shale area has come about. What that means for the future is a strong potential for continued economic benefits.

Accurate Underground Seismic Mapping

Companies with leased land in Laramie County, Wyoming have been waiting for a bonanza, but so far, only a couple dozen wells have been drilled in the oil-rich Niobrara shale region.

Why the delay? A better seismic mapping guide is needed. But now, a map of that caliber is in the final stages of development. It is expected to give operators a better and more accurate look at Niobrara’s naturally occurring fractures deep in the earth.

For the past several years the Niobraba, in southeastern Wyoming, has been hyped as the next great oil boom site. The Wyoming fields have been the subject of great speculation with some insiders saying that once the underground seismic maps are used in combination with the right drilling techniques, the Niobrara may yield vast amounts of oil.

The formation’s complex geology demands an in-depth study before accurate seismic mapping can be produced. Tom Doll, supervisor of the Wyoming Oil and Gas Conservation Commission says some oil drilling companies are moving ahead but most are still in the data collection phase. The strata and geology of the Niobrara has been called complicated. It requires detailed studies before horizontal drilling takes place on a wide scale.

In mid September, at the Wyoming Natural Gas Fair, Doll said underground seismic mapping is key to finding the Niobrara’s sweet spots.

Analysts reiterated that the deep oil-bearing Niobrara, generally felt to be a medium-risk play, could produce as much oil as North Dakota’s fields.

That’s good news indeed especially since an uptick in drilling is expected soon. Companies with drilling rights in the area are just getting going. Since early 2010 about 240 drilling permits have been approved in Laramie County, Wyoming, but only about 25 to 27 wells have been drilled.

It’s possible that more wells have been drilled, but it’s difficult to know the exact number. The reason is the Wyoming Oil and Gas Conservation Commission allows companies to keep their production numbers confidential for a period of time.

Underground mapping involves sending seismic vibrations deep under the surface of the earth and then measuring the reflected echoes that bounce back. The resulting data gives operators a map for finding the best spots to drill horizontal wells.

In the recent past, over 800 square miles in Wyoming has been studied by seismic crews. Final underground mapping work is expected to take place in Cheyenne sometime this year.

Roger Pinkerton, director of exploration with Marathon Oil Co. recently said in the near future the company is planning to bring a drilling rig onto their leased land in southeast Wyoming.

When there’s good news about productivity, they will come. That in extent is the essence of what insiders say about the Niobrara. If news of very productive wells starts circulating, exploration in the Niobrara will increase.

Doll echoed those sentiments by saying that all they need now is a little good news to change the current drilling stalemate.

Natural Gas Flames Light up North Dakota Prairie

Winesses to the dramatic skies ablaze with color in North Dakota say it could be a backdrop for a sci-fi film.

Every day in North Dakota’s Bakken over 100 million cubic feet of natural gas or about 30 percent of gas produced is burned off as waste. The 15,000 square-mile-field is the largest discovery of natural gas in over 40 years.

With the price of oil high and natural gas prices low, Bakken drillers have found it more profitable to go after the oil and flare the gas.

The daily flares are seen for great distances over the prairie and not unexpectedly have brought numerous objections. Primarily the concerns are about air pollution. The practice is not uncommon in countries such as Russia, Nigeria and Iran, but flaring of this size is not commonly seen in the U.S.

Some industry experts point out that most oil and gas fields in the U.S. have well-developed facilities to gather and process gas. But drillers in North Dakota’s Bakken operation see the flaring process as a way to control costs.

Many companies today are concerned about the high costs associated with putting in pipelines and processing plants before they drill oil and determine how much gas they have. No matter how you cut it, building an infrastructure to capture gas, to say nothing about the costs to build and maintain a pipeline, is an expensive proposition.

What do scientists say about the Bakken flaring process? Most would prefer to see the gas captured instead of burned, but they see flaring as a better choice than venting the gas into the atmosphere. There are few government regulations about flaring.

Environmentalists like those at the Natural Resources Defense Council are beginning to drum up support for anti-flaring. Amy Mall, senior policy analyst at the organization points out that some companies such as Whiting Petroleum Corporation are investing in pipelines and large processing plants to deliver gas instead of burning it. Whiting, one of the companies working in the Bakken, is investing a reported $3 billion in processing and transporting the gas to Midwest markets.

Other analysts point out that gas in the Bakken field has a high amount of propane and butane. That in itself may give companies the motivation to use it and turn a profit in addition to processing the gas.

Even with the concern about North Dakota’s flaring, health officials in the state have not uncovered serious health problem associated with flaring.

Recently, though, the Environmental Protection Agency has proposed new emission rules where fracking is used. As a first step in gathering information, the agency has started asking oil companies to keep track of greenhouse gas emissions from drilling operations. That may have an impact on how long or how viable flaring may be in the Bakken reserve.

Expert Stricter Rules and Steeper Fees

Natural gas development recently took a turn in Pennsylvania as the state rolled out proposals for new fair drilling practices.

Pennsylvania’s Marcellus Shale has been making news for some time but now the state is making news because of raising drilling operations fees.

Last March Pennsylvania Governor Tom Corbett formed the Marcellus Shale Advisory Commission, an advisory panel that can recommend drilling standards in the Marcellus shale.

Pennsylvania has the largest deposit of shale gas in the country. It has also been home to ongoing controversy involving hydraulic fracturing, which is blamed for contaminating local water supplies.

Fracking concerns have prompted the state to implement new, stricter drilling recommendations and fees.

Governor Corbett’s Commission has taken up the issue by proposing stricter drilling regulations state-wide and something else that has insiders shaking their heads.

In early October, Corbett announced plans to levy an “impact” fee — for impacting the environment. The fees, which could be as high as $160,000, would be assessed on each well drilled in Pennsylvania. The money would allow counties to make upgrades like improving roads and bridges, updating emergency response and pipeline safety, and fixing and regulating environmental damage in each impacted area.

That imposed fee structure is based on a per-well fee of $40,000 the first year, with decreased fees of $30,000 the second year, and $20,000 in the third year followed by $10,000 the fourth through tenth years that a well is being drilled.

The idea behind the impact fees is that the more wells that are drilled, the more money that can be brought in to protect the environment. Specifically how the revenue will be used hasn’t been outlined.
About 75 percent of revenue from impact fees would go to counties and municipalities where drilling is taking place. The fees are expected to bring in about $120 million the first year and will be used by local governments where the impact of drilling is felt the most.

The commission also ramped up new recommendations for drilling sites which will need to be 500 feet from private wells and 1,000 feet from public water areas. Drilling away from streams, ponds and rivers will triple from a previous 100 feet to 300 feet.

While some industry advocacy groups praise the tightened drilling restrictions, some environmental groups see the proposals as not going far enough.

Citizens for Pennsylvania’s Future pointed out the plan is loaded with loopholes for drillers and what’s more it won’t provide enough money to adequately protect the environment.

Pennsylvania’s Legislature will have the final say in approving the plans. Since 2008, when the natural gas industry arrived in full force, they have been debating whether to levy fees on Marcellus Shale drilling. Now they have an opportunity to weigh in before thousands of planned wells are drilled in the area in the coming years.