PAPS - Pipeline Accident Prevention Services

George Mitchell Still Pushes Energy Conservation
Houston Chronicle, August 1, 2008; by Kristen Hays

George Mitchell was an ecoconscious oilman before it was cool.

The 89-year-old Houston wildcatter, real estate developer and philanthropist assembled business and academic leaders to address solutions to energy, food, environment and population growth problems more than 30 years ago.

Now Americans are grappling with record-high oil, gasoline and food prices, climate change concerns are at the forefront and emerging economies in Asia and the Middle East are thirsting for energy.

For Mitchell, it's a big dose of déjà vu.

"A lot of these things could have been predicted," Mitchell said during a recent interview in his downtown Houston office. "We have cars that get an average 22 miles per gallon. We could have had cars that get 40 by now."

Mitchell has been a strong booster of sustainability — meeting needs in a way that preserves resources for future generations — since the early 1970s. That's when an Arab oil embargo touched off oil shocks that cut U.S. fuel consumption, prompted switching from heating oil to natural gas and coal, and set off four decades of presidential rhetoric about achieving energy independence.

Bob Malone, president of London-based BP's U.S. arm, BP America in Houston, listed those pledges for independence dating back to the Nixon administration in a recent speech at a National Governors Association gathering in Philadelphia.

During the same stretch, U.S. energy consumption jumped 30 percent, Malone said. While efficiency has increased, "we might have done better if high-mileage, pollution-free vehicles we've been working so hard to develop had arrived in significant numbers." He added that current high energy prices stem from "a decades-long failure of U.S. energy policy."

Mitchell agrees.

"We used to try to work with Washington to no avail," he said.

But he kept pushing. While running Mitchell Energy & Development, a natural gas company he sold to Oklahoma City-based Devon Energy in 2002, Mitchell sought to encourage collaborative efforts to address food and energy needs as well as environmental issues as the globe's population grew.

In 1975, he established the Woodlands Conference Series to encourage business leaders, government representatives and universities to study sustainability issues. The Woodlands, a planned community north of Houston that Mitchell envisioned in the mid-1960s, had opened the previous year.

The conference series led to the founding in 1982 of the Woodlands-based Houston Area Research Center to study technical and policy issues with funds from contracts, grants, and gifts.

The most recent conference in the series was several years ago, but the research center evolved into what is now called the Houston Advanced Research Center, focusing on sustainability research, and its Center for Global Studies, which emphasizes environmental issues and sustainable development.

HARC is a consortium of universities, including the University of Houston, Rice University, the University of Texas at Austin and Mitchell's alma mater, Texas
A&M.

HARC's first research program in 1983 involved a laser study related to the federal government's Strategic Defense Initiative, a missile- and satellite-based shield against nuclear attack proposed that year by President Reagan.

Other research programs over the years include analyses of six possible superconducting super collider sites in Texas; HARC's Geotechnology Research Institute that seeks to improve oil and gas exploration technology; DNA technology research; development and testing of superconducting magnetic energy storage systems; establishment of a center for fuel cell research; and a team effort with Mexico's Monterrey Institute of Technology and Higher Education on water and development issues in the lower Rio Grande basin.

The center's work continues.

But conservation-heavy reactions to the 1970s oil shocks softened after oil prices plummeted in the 1980s. Fuel was cheap and plentiful, though the nation's dependence on foreign oil increased. For many Americans, interest in sustainability waned.

At the same time, European countries imposed high fuel taxes to keep consumers on the continent focused on conservation, efficiency and investment in public transportation.

"Europe was way ahead of us on that," Mitchell said.

The Paris-based International Energy Agency emphasized the same issues last month, supporting the Group of Eight industrialized nations' push for energy security and sustainability.

"With energy demand continuing to grow, prices breaking records and concern about climate change intensifying, we need policies that bring sustainable solutions," IEA executive director Nobuo Tanaka said when the recent G8 summit in Japan concluded, according to a statement. "The energy challenges we face — in terms of energy security and climate change — are global and call for a global response."

The need for global collaboration to achieve sustainability by addressing multiple issues — energy, food, the environment and population growth — is more important now, Mitchell said.

"Sustainability will be one of our most serious problems. Energy is part of it. The global climate is part of it. We need to do solar and wind, but they're not enough. Now we've got 6.5 billion people. In 2050, we'll have another 3 billion. If you can't make it work now, you've got more wars, more poverty, and everything you can think of," he said.

Black Powder and Gas Pipelines
Pipeline & Gas Journal, October 2007

Black powder in pipelines can create blockages and damage compressors, plug filters and damage user equipment. One operator removed 60 tons of black powder from piping upstream of a compressor.

The black powder is usually made up of iron compounds, sand, clay, salt and other contaminants and is typically generated in wet gas pipelines containing hydrogen sulfide, carbon dioxide, or oxygen. Bacterial corrosion of steel and improperly cleaned out construction materials can also be part of the black powder.

Pipeline velocity and pigging can dislodge or move the powder along the line.

No-Blow Device for Removing and Stopping Steel Service Tees

Need to stop gas flowing so that ¾”, 1”,1 and ¼” , so even up to 2” Mueller tees can be replaced? Mazco Safety-T-Stopper is one answer. It has been upgraded to allow more flexibility. More and more adapters are being developed so that the tool can be used on steel and cast iron systems. The Safety-T-Stopper is a no-blow device designed for removing and stopping straight-gut, steel service tees. Several Canadian gas distribution companies are currently using it and at least one US gas distribution company is running it through its standards group.

The system is priced at $5,400 (Canadian) which includes a minimum of one set of attachments. A full set of attachments will add another $2,000 to the price.

Specifics of the Safety-T-Stopper can be viewed on Mazco’s website: http://www.mazcoproducts.com

Growing Pains en Route
Houston Chroncle (March 25, 2008) ; Tom Fowler

A rush of new projects moving natural gas from areas like Texas' Barnett Shale through a pair of Louisiana pipeline hubs could increase volatility for the fuel in the short term and drive down prices in the long term, according to a new study.

Some 40 pipeline, storage and liquefied natural gas terminal projects will come on line over the next 18 to 24 months, providing billions of cubic feet of new gas supplies for the key pipeline hubs of Perryville and Henry Hub in Louisiana.

Those new sources of fuel are likely to outpace capacity to move the fuel farther east to markets including Florida, Ohio and New York, according to data compiled by Bentek Energy, a Golden, Colo.-based research and consulting firm.

That could first mean greater price swings as markets figure out how to accommodate the new supplies and, ultimately, put downward pressure on prices because of oversupply.

Lower prices at the Henry Hub would affect prices throughout the country, because it's a widely used benchmark price.

"It's too much gas in the wrong place," said Rusty Braziel, managing director of Bentek. "It's going to be a roller coaster ride for a while."

Following the hurricane-induced price spikes of 2005, natural gas prices were relatively stable in 2006 and 2007, mostly trading in a range of $6 to $8 per million British thermal units.

In 2008, however, gas has been more volatile. Prices climbed as much as 35 percent earlier this month to more than $10 per million Btu, driven by winter demand and the expectation that natural gas imports would lag far behind last year's.

Prices have backed down somewhat but were up 26.4 cents on Monday, closing at $9.33 per million Btu on the New York Mercantile Exchange.

Higher prices have led to increased production in areas including the Rocky Mountains, Texas and Arkansas, and a boom in pipeline construction. A handful of large projects out of the Rockies will run through Illinois and Ohio, but a greater number of projects from Texas will go through an area Bentek refers to as the Southeast/Gulf region.

On average 29 percent of the pipeline capacity in the Southeast/Gulf is unused, but it tightens significantly during seasonal peaks. In the winter, when the Northeast draws heavily on natural gas for heating, that unused capacity shrinks to 10 percent.

In the summer peak, when gas-fired power plants come on line to handle the increase in air conditioning, that figure is closer to 7 percent.

But as pipeline projects from companies like CenterPoint Energy, Spectra Energy, Energy Transfer, Enterprise, Kinder Morgan and others are completed in the next two years, it will bring up to 14 billion cubic feet per day of new supplies into the Southeast/Gulf area.

Four liquefied natural gas terminals are also expected to open in the region in the next year — ranging from Freeport to Sabine Pass, La. — add- ing the potential for an additional 7.1 billion cubic feet of supply.

But only about 4.2 billion cubic feet of new projects are under way to move gas out of the Southeast/Gulf region to northern and eastern markets, Braziel said. Ultimately, the region could have 2 1/2 times more supply coming in than it can ship out.

A situation could develop similar to what occurred in the Rocky Mountains last summer when a surge of new production outpaced the new pipeline capacity being built out of the region. Prices in some parts of the Rockies fell as low as 5 cents per million Btu.

"I'm not saying that's going to happen with Henry Hub, but there's a similar dynamic at work," Braziel said.

For Exxon Mobil - Bragging Rights
Houston Chroncle (February 7, 2008) ; Kristen Hays

Offshore oil wells aren't out of reach for onshore drilling rigs.

And Exxon Mobil Corp.'s reach now stretches farther than anyone else's, more than seven miles from the frigid shores of Sakhalin Island off Russia's east coast, where the Chayvo oil field holds potentially a billion barrels of oil.

The world's largest oil company recently broke its own industry record for the longest "extended-reach" oil well. Such wells begin vertically on land and then curve to bore through layers of rock under the seabed to offshore reservoirs.

The well is 8,350 feet beneath the Sea of Okhotsk and 38,322 feet from shore to reservoir — about the length of 125 football fields. It blows past Exxon's previous record of 37,016 feet.

"It's almost an underground pipeline," said Joel Kiker, vice president of drilling for Exxon Mobil's development arm.

The 230-foot-tall Yastreb rig on the Chayvo project, operated by Houston-based Parker Drilling, also holds a title — the world's most powerful land drilling rig.

Such wells push technological limits to steer the drill bit and withstand massive pressures and temperatures. They also negate the need for pipelines and offshore platforms, particularly in harsh arctic areas like Sakhalin where conditions don't favor such installations and onshore facilities reduce environmental impact.

Jerome Schubert, an assistant professor of petroleum engineering at Texas A&M University whose research includes extended-reach drilling, said the practice isn't new. But pushing wells as far from shore as Exxon Mobil has illustrates how technological advances increase access to undersea oil.

"It kind of gives them bragging rights," Schubert said. "It's, 'We've gotten a little farther,' and it gives a target for someone else.

"But they're not going to try to beat the record just to beat the record. Every time they drill another extended-reach well, they get better at it."

To meet ever-growing global demand, companies are pushing to reach oil and gas in remote areas once deemed too difficult to tap. The Chayvo field was discovered nearly 30 years ago, but sat untouched until new technologies made it accessible.

Similar challenges also once hindered drilling in other areas, including the deep-water Gulf of Mexico. There, Chevron holds the record for the deepest vertical well — 34,189 feet in the company's Knotty Head development about 170 miles southeast of New Orleans.

A tricky salt layer

Deep water Gulf drilling requires the ability to plow through a thick, undulating salt layer as well as rock and sediment amid high pressures. The salt makes it more difficult to scope out reservoirs, even using 3-D seismic imaging that Exxon Mobil pioneered.

Kiker said the Sakhalin drilling doesn't contend with salt, but has a host of other challenges, including the need to control friction between pipe used in drilling and rock as the well-path curves to head offshore. And when the horizontal path traverses layers of softer rock it must be protected from caving in.

The Sakhalin team evaluates each step with real-time digital data, he said.

1996 agreement

Exxon Mobil began studying Sakhalin exploration in the late 1980s. In 1996, as the operator of a consortium that owns the multiphase project, the company forged an agreement with the Russian government to get started.

Exxon Mobil has a 30 percent interest in the project. The other partners are affiliates of Russia's Rosneft RN-Astra and Sakhalinmorneftetgas-Shelf; Japan's Sakhalin Oil and Gas Development; and India's ONGC Videsh.

The entire Sakhalin-1 project involves development of the Chayvo, Odoptu and Arkutun-Dagi fields, which combined have potentially recoverable reserves of 2.3 billion barrels of oil.

The first Chayvo well was drilled in 2003 and production began two years later. The project reached peak production of 250,000 barrels a day a year ago.

Since that first well was drilled, Exxon Mobil has slashed its drill time by half to about two months, Kiker said.

"We've been employing fast-drill for over a year. We're continuing to push the limits of what we've done before," he said.

BP in the game

Other companies in the extended-reach game include London-based BP, which is seeking permits and developing technology for its Liberty project, a 100 million-barrel field off the shores of Alaska's North Slope.

If approved, the project would involve drilling wells anticipated to be seven miles long or longer from an existing manmade island connected to shore by a four-mile causeway, BP spokesman Steve Reinhardt said.

U.S. President Bush Signs Energy Bill
On Wednesday, Dec. 19, U.S. President George Bush signed an energy bill into law to increase fuel efficiency and reduce U.S. dependence on foreign oil. The bill did not include a tax package that would have rolled back $13.5 billion in oil and gas company tax breaks. The legislation previously passed both the House and Senate by wide margins after a bi-partison agreement was reached to take out the punitive tax language directed at the oil and gas industry. To view full legislation text, go to http://thomas.loc.gov/. In the line that reads "Search Bill Text," enter: hr 6. Click on the link next to the line that reads, "6 . Energy Independence and Security Act of 2007 (Engrossed Amendment as Agreed to by Senate)."

New Technology Paving Way for Solving Pipeline Problems
Pipeline & Gas Journal (08/07) P. 38
New technology aims to solve pigging problems. Aging infrastructure and more remote field developments have created new challenges for the industry, particularly in the area of pipeline integrity. Rising environmental concerns and stricter codes and regulations have forced energy firms to develop new ways to probe the integrity of unpiggable pipelines. Many firms have had success with external ultrasonic solutions such as corrosion mapping and time of flight diffraction (TOFD), which allows the pipeline to be inspected during operation. Inspection data gleaned from these methods can be used with operational conditions, environmental readings and other data about the pipeline as base data for the performance of direct assessment. There are also tethered systems for internal interventions on the market, the majority of which are ultrasonic tools. A popular tool is the PipeIntruder, which is particularly effective when used with the WeldScan technology, which incorporates TOFD capabilities and stops on selected positions along the pipe to look for defects in the welds and cracks.

Ultrasound Tool Can Combine Metal Loss And Crack Inspection Of Gas Pipelines
Pipeline & Gas Journal (08/07) P. 30 ; Vogel, Roger ; Pollard, Lee ; Yates, Ray
A new ultrasound inspection tool can pinpoint metal loss and cracks in gas pipelines in one shot. Modeled after a special configuration of the modular LineExplorer, the tool offers greater efficiency in pipeline preparation, operations and cleaning during inspections. The inspection tool also delivers improved data quality. As a proven and reliable technology for crack detection in pipelines, ultrasound is credited with ushering in a new generation of tools that integrate advances in electronic and mechanical design. New ultrasound tools feature a new and optimized sensor carrier design, which allows crack inspection and metal loss to be done at the same time. Combining metal loss and crack inspection capabilities enhances data quality, delivering more information to pipeline operators. This information, combined with reliable corrosion growth studies, remaining lifetime and fitness-for-purpose calculations offer a more accurate assessment of the true condition of the gas pipeline or pipeline system.

Gas Distribution Integrity Management Rule is On Its Way
Pipeline & Gas Journal (06/07) Vol. 234 , No. 6 , P. 36 ; Erickson, John
The Pipeline and Hazardous Materials Safety Administration (PHMSA) will propose legislation this year requiring utilities to adhere to procedures regarding distribution integrity management programs (DIMP). PHMA's advisory group recommended the organization employ a rule containing seven factors, among which developing an integrity management plan and reporting results were included. The rule noted that evaluating, maintaining, and upkeep of infrastructure was essential, as well as assessing and prioritizing risk. Additionally, identifying threats to distribution integrity such as excavation, natural forces, equipment malfunctioning, and operational errors is crucial to the overall system. Once risks have been identified, procedures to redress and mitigate the likelihood of problems should be implemented. Although most leaks are found before they are a safety hazard, the potential for the leak's hazard and recording both hazardous and non-hazardous leaks is necessary in proper leak management. Performance of an operator's DIMP plan should be measured, including threats to any component of the system and internal and external performance measures. The Simple Handy Risk-based Integrity Management Plan (SHRIMP) plan has been developed as a DIMP plan for smaller systems, including each of the factors in the DIMP plan. The APGA is slated to conduct workshops to assist in implementing operations and promoting DIMP-compliance.

Natural Gas Reserves at Highest Level Since 1978, AGA Says
Pipeline & Gas Journal (05/07) Vol. 234 , No. 5 , P. 4

The level of gas thought to be in American reserves inventory last year increased for the eighth consecutive year, an American Gas Association (AGA) study of reserves claims. The study is based on numbers reported by a representative sample of 30 reserves holders who comprise more than half of overall American booked reserves and slightly under 50 percent of all American production. The AGA's Preliminary Findings Concerning 2006 Natural Gas Reserves states reserves were thought to have risen from 204 Tcf at 2005's end to over 205 Tcf at the end of last year, which puts U.S. reserves at their steepest levels since 1978. Last year, around 30,000 gas wells were finalized in the United States, which is the greatest level of completions ever recorded. The majority of these wells, though, were drilled onshore in coal seams, shale, and tight sands, and it takes a large number of these smaller wells to meet production. As such, increasing reserves inventories do not automatically mean that U.S. production ability is substantially growing; in addition, the shelf-life of current natural gas reserves has risen as the reserves-to-manufacturing ratio has risen from around nine years in 2001 to around 11 years in 2006. On the plus side, a strong long-term manufacturing ability baseline is being formed, while the downside is that it takes a lot more wells to maintain manufacturing ability as more typical production is used up. The study predicts that future manufacturing ability will stay in the 18 to 19 Tcf range annually during the near future, unless substantial policy decisions to grant access to possible natural gas resources are conducted.

Energy Markets in 2040 Will Be Very Different
Pipeline & Gas Journal (05/07) Vol. 234 , No. 5 , P. 120 ; Learsy, Raymond J.

Energy analyst Raymond J. Learsy discusses what the condition of energy markets will be in 2040. Learsy says by that time, he believes there will be government-required restrictions on the use of fossil fuels, most particularly gas and petroleum-based fuels. In addition, he says, there will be a vast changeover from gas-powered vehicles to flex fuel, hybrid, and electric automobiles on the United States' roads. Learsy also thinks there will be a renaissance concerning train travel and a revamping of its infrastructure offering services that is similar to the European model, and of mass transportation overall. Next, he says, millions of acres will be handed over to raising crops for the manufacturing of agri-based ethanol which will be utilized to manufacture fuels to power the new offerings of bio-powered automobiles. Learsy feels the 54-cent per gallon tax on imported sugar cane ethanol from Brazil and other locations will be no more, and the oil-manufacturing facilities still around will be shielded against productivity pricing by offshore rivals by a nationwide floor price for hydrocarbons. He states there will be more oversight by the government of commodity trading pits and electronic trading of oil and all energy-associated products, and there will be substantial development of America's massive reserves of Western oil shale. "OPEC will have been reduced to an aged and toothless tiger," Learsy writes, and the United States will have set up a nationwide oil trust which will oversee and promote the energy resources located on federal lands.

Oil companies go deep into Gulf's potential
They are taking the bet they can extract oil lying 30,000 feet below the sea floor
Houston Chronicle Online - June 13, 2007 - Brett Clanton

View Graphic: Oil and gas discovered deep in Gulf of Mexico

Last fall, a team led by Chevron Corp. became the toast of the oil industry when it demonstrated that an alluring deepwater region of the Gulf of Mexico could deliver on its promise.

Now, oil companies are taking concrete steps to unlock the area's potential, with an eye toward extracting oil from there in as little as two years.

Devon Energy Corp., an Oklahoma City-based firm with about 2,000 employees in Houston, is planning to drill what could be the first commercially producing oil field in the region by late 2009. Chevron has assembled a 60-person team to explore how it will develop the offshore frontier. Shell Oil has ordered a floating platform and plucked 200 employees to work on a project planned to come online by the turn of the decade. Others are also studying ways to turn prospects and discoveries into producing oil fields.

The activity has been spurred by predictions that up to 15 billion barrels of oil — enough to increase the nation's reserves by 50 percent — could be trapped in an ancient rockbed known as the lower tertiary.

The area of greatest interest, known in industry lexicon as the lower tertiary trend, has been hailed as the biggest discovery since
Alaska's North Slope in the late 1960s. It runs about 200 miles from the central Gulf of Mexico to the South Texas Coast, spanning an area about the size of West Virginia.

But the challenges of pulling oil from the region still loom large. Not only are the reservoirs more than 30,000 feet under the sea floor in places, they are hidden under nearly 10,000 feet of water. Getting to the rock means sending drills into densely compacted formations that will be stubborn in yielding resources and that may require new tools that can withstand higher temperatures and higher pressures. All of that means huge costs.

Last week, Devon talked of those challenges during a tour of the Ocean Endeavor, a newly renovated drilling rig it has under contract for the next four years as part of a huge company bet on the lower tertiary.

Stephen Hadden, Devon's senior vice president of exploration and production, compared the task to trying to thread a needle from 10 feet away in the dark. Yet if successful, the company could double its proven oil and gas reserves and see a huge return on investments, he said.

"The reward is worth the risk," he said.

Incentives growing

The excitement over the ultra-deepwater Gulf region comes as high commodity prices and growing global energy demands are providing incentive for companies to invest in higher-risk projects.

Chevron's successful test in September of its Jack No. 2 well told the industry that enough oil could be drawn from the lower tertiary trend to justify the massive investments.

"It proved that this trend could be produced economically and that it even holds a good potential to impact domestic and global oil production," said Matt Pickard, an analyst with Quest Offshore Resources in Sugar Land, which does market research and analysis for the global offshore energy industry.

The Jack well was completed and tested in 7,000 feet of water, and more than 20,000 feet under the sea floor, including a wide salt layer. Such layers, called salt canopies, have been obstacles for oil companies in the region because the formations hampered traditional seismic survey work needed to map underground deposits. But in recent years, more sophisticated 3-D seismic equipment has allowed oil companies to "see" through the salt.

12 finds and counting

So far, 12 discoveries have been announced in the lower tertiary trend since 2001, according to the Interior Department's Minerals Management Service. Yet that number could grow as international oil companies and state-owned firms including Brazil's Petrobras show more interest in the area.

Devon has leased more than 230 blocks — second only to Chevron — from the federal government. Each block is about 5,000 acres.

In coming weeks, Devon will use the Ocean Endeavor to drill a prospect well at its Chuck field, which it owns with Exxon Mobil and ConocoPhillips. Then, it will drill another well at Chevron's Jack field, in which it owns a partial stake. After that, it will move the massive rig to Cascade, a field in which it holds a majority interest and expects to begin producing oil from in 2009.

Each well will cost at least $100 million and take three to four months to drill, Devon said.

That's why operators are cautious about diving into the region too quickly.

James Cearley, Chevron's general manager of deepwater exploration, said Chevron's team is in the "earliest stage" of a feasibility study to determine how it should invest resources to develop oil fields in the lower tertiary trend.

The company won't begin producing oil in the region until at least 2010, he said.

Other firms, including Houston's BHP Billiton, have sold some stakes in discoveries to focus on lower-risk projects. Such moves are a reminder that not everyone is sold on the outer waters of the Gulf.

Gregory Simmons, Devon's manager of Gulf of Mexico deepwater exploration, said after many years in the industry and seeing many booms and busts, it is hard to blame them.

"Regardless of how good these look," he said, "there's never a sure thing."

Differential Impedance Obstacle Detection (DIOD) System

Traditional Approach: Rely on locates (not always accurate and plastic sewer lines are not readily located) or use ground penetrating radar which can be expensive and time consuming. The negative result is either high cost or damage that is not apparent until later.

Successful Practice Solution: An alternative to a variety of obstacle-detection technologies that have been investigated in recent years with limited success is being developed by Gas Technology Institute (GTI). With an effective obstacle-detection system, operators will be able to take advantage of the cost-saving benefits provided by HDD while enhancing the safety and efficiency of utility installation operations.

One New System: GTI is developing a differential impedance obstacle detection (DIOD) system that uses lower frequencies—in the 100kHz range—and less costly electronics than ground-penetrating radar. The system will have the ability to send data directly to a receiver at the drill rig. In laboratory-scale proof-of-concept testing, the DIOD system was able to differentiate between metallic and non-metallic obstacles placed to the side of sensor elements. Tests in soils established that each of the four elements (distributed around the sensor) could detect obstacles in the quadrant that it faced.

SCADA Security Protections are on the Increase
Pipeline & Gas Journal (02/07) Vol. 234 , No. 2 , P. 24 ; Njemanze, Hugh
The threat to Pipeline Supervisory Control and Data Acquisition Systems (SCADA) from Internet hackers is growing as SCADA becomes more integrated with business information systems. In addition, the security of SCADA is also threatened by employees who surf the Web, download Internet files, or do not obtain new protection software. Contractors working for companies can also undermine the security of SCADA, if their systems are without adequate security measures. Operators of SCADA networks should view a potential attack by terrorists as a real danger, though many security experts believe the likelihood of such an occurrence is remote. The discovery in 2001 that al-Qaida terrorists were considering a potential attack against SCADA systems illustrates that the technology is an attractive target. The Linking the Oil and Gas Industry to Improve Cyber Security (LOGIIC) consortium determined that control systems are becoming more vulnerable to potential terrorist attacks as the trend towards Internet integration continues. LOGIIC cited two scenarios that demonstrated the ability of hackers to gain access to SCADA. One scenario showed that a hacker could gain unauthorized access to a SCADA system through a business network, while the other showed that an intruder could physically access process control systems from an isolated location in the field. The consortium partnered with ArcSight and other technology companies to implement solutions that would help determine when hackers are trying to gain entry into a system by collecting and analyzing suspicious activity, such as multiple failed attempts to input a password.

Microhole Drilling Technology Gets Successful Demonstration
American Gas (02/07) Vol. 89 , No. 1 , P. 54
Two tests of Microhole drilling technology in western Kansas and eastern Colorado indicated that the approach offers 25 percent to 35 percent fewer costs compared to drilling conventional gas wells. The DOE said the technology has made retrieving roughly 1 trillion CF of natural gas economically viable. The Niobara drilling program was able to drill a series of wells that are 3,000 feet deep within just 19 hours. The Gas Technology Institute collaborated with Advanced Drilling Technologies and Rosewood Resources in researching the modification of a regular coiled tubing rig for drilling exploratory and development wells prior to the launch of the project. The Office of Fossil Energy's National Energy Technology Laboratory oversees the project that hopes to develop equipment and approaches to drilling relatively tiny boreholes. In addition, the project seeks to develop equipment and approaches for employing compact coiled-tubing drilling rigs for downhole micro-instrumentation applications.

Rust Top Cause of Pipeline Spills
Harris County leads nation in accidents caused by corrosion
Houston Chronicle (TX) (11/19/06) Cappiello, Dina

Corrosion has become the leading cause of hazardous-liquid pipeline accidents, causing a quarter of all reported spills in the past six years, and the shutdown earlier this year of one of the nation's largest oil fields, a review by the Houston Chronicle and industry groups shows.
From 2000 to 2005, 217 of the 832 incidents reported to the federal Pipeline and Hazardous Materials Safety Administration were attributed to corrosion. Rusting pipes also spilled the most petroleum products — more than 5 million gallons — in those six years.

Decaying pipelines have leaked oil, fuel and other volatile liquids at least once in 32 states, led by Texas, Oklahoma, Kansas and Louisiana. Harris County ranked No. 1 in the nation in spills caused by corrosion, with seven.

Corrosion has risen to the top of the list because pipeline accidents triggered by a dozen other causes have declined, particularly "third-party damage" — which includes everything from a farm backhoe hitting a pipeline to a hole made by a hunter's bullet.

The consistency of corrosion's role in pipeline incidents has raised questions about how well the industry has worked to maintain the nation's aging pipeline network.

"In 2005, for the first time (since the early 1990s) ... we are seeing corrosion as the leading cause," said Carolyn Kolovich, an engineer and pipeline consultant, who sits on an American Society of Mechanical Engineers committee that looks at the federal data each year.

On average, corrosion is responsible for 36 spills across the country annually, down from an average of 49 between 1993 and 1998. And though the size of the spills tends to be smaller, experts say that incidents caused by corrosion are harder to detect and can cause even more environmental damage.

A March leak along a 34-inch BP pipeline on Alaska's North Slope spilled an estimated 201,000 gallons of crude oil and drowned 2 acres of tundra.

It became the poster child for pipeline corrosion. Months after the incident, BP temporarily shut down other major conduits in the Prudhoe Bay field, which supplies the U.S. with 8 percent of its crude oil supply, because portions were corroded.

BP's incident would not be included in the federal data because the low-pressure line is not yet subject to federal regulations. However, the Chronicle's review shows that four other spills, all bigger than the BP incident, occurred between 2000 and 2005, three of them in Texas.

In March 2000, a 28-inch pipeline running from the Gulf Coast to Indiana broke in rural Hunt County, Texas, spilling enough gasoline to fill 60 tanker trucks and contaminating Dallas' drinking-water supply. The city pulled 25 percent to 30 percent of its water from Lake Tawakoni, which was tainted with a gasoline additive after the accident.

The company, Explorer Pipeline Co., eventually reached an $8 million settlement with the city and paid a $3 million federal fine.

Two years later, in a Navarro County pasture, a 14-inch Chevron pipeline carrying liquefied petroleum gas ruptured and burst into flames, sending smoke and flames about 100 feet into the air, according to newspaper reports. No one was injured.

And in 2003, a propane pipeline owned by BP subsidiary Dome Pipeline Co. caught fire in Barnes County, N.D., burning 9,000 barrels of gas. No one was hurt, but during the repairs, eight families were evacuated when another leak developed.

Closer to home
The fourth-largest spill from corrosion occurred in January 2005 at the Lyondell-Citgo refinery in Harris County. About 219,000 barrels of Venezuelan crude oil seeped from a rusting above-ground storage tank that receives oil from a pipeline connected to a tanker ship. The oil was contained inside the tanks' berm and cleaned up by the company.

Advocates for pipeline safety are questioning why measures enacted by the federal government in 2000 aimed at improving detection have not reduced corrosion's role in accidents.

"I would have thought it would decrease," said Lois Epstein, an engineer for the Cook InletKeeper, an advocacy group dedicated to protecting the Cook Inlet watershed in Alaska. "What I have said about corrosion is that it is complicated; you always have to stay on top of it."

Part of the problem is that there is no silver bullet when it comes to dealing with corrosion. Sometimes it is caused by water; other times, a gas or even bacteria growing in the line starts the rust. The pipe's material, its age and the type of soil in which it sits all play roles, experts say.

Throughout much of the 1990s, third-party damage spilled more product along the nation's 183,000 miles of liquid pipelines than any other cause, according to industry reports.

The recent shift has occurred because, as the percentage of spills from most other causes has declined, the share of accidents from corrosion has remained relatively constant for the past decade.

Today, as in the early 1990s, corrosion still accounts for about 25 percent of all pipeline accidents and about 20 percent of spilled volume, according to the Chronicle's analysis, even though the average number of incidents — and the average size of spills — has declined.

"By 2000, everyone was still harping on the biggest issue, which was third-party damage. I was saying, 'Here is the data I am looking at, why aren't you doing more on corrosion?' " Epstein said.

The latest numbers from the American Society of Mechanical Engineers show that, in 2005, corrosion accounted for 45 pipeline incidents, or 28 percent of the 161 spills.

Corrosion "is probably the No. 1 thing we think about when we have pipeline incidents, other than people out there with construction equipment," said Eric Meyers, coordinator of the Navarro County Office of Emergency Management, which experienced the largest corrosion incident in the past six years. Jet fuel, crude oil and refined product flow in pipelines lying beneath the county.

Issuing new rules
In 2000, the federal agency in charge of pipeline safety issued new rules requiring companies to keep better tabs on corrosion.

The nation's pipeline-safety administrator said that these regulations have resulted in companies aggressively checking and reporting corrosion.

"Industry is doing a better job on getting on top of that issue; that is partially why you are seeing that number stable," said Adm. Tom Barrett, administrator of the Pipeline and Hazardous Materials Safety Administration.

But Barrett stressed that third-party damage still leads to more injuries and deaths.

A preliminary study of the federal numbers being done for the American Petroleum Institute and the Association of Oil Pipelines actually will show that, in the past five years, corrosion accounts for a bigger share of spills than it has historically, said Cheryl Trench, who studies the numbers for the two groups. The uptick can be explained, in part, by two large spills in Cushing, Okla., and Navarro County, as well as hurricanes in 2004 and 2005, said Trench, president of Allegro Energy Consulting.

Peter Lidiak, director of the pipeline division for the American Petroleum Institute, said that operators continue to make strides in corrosion, and though it remains the leading cause of pipeline incidents, it, like many other causes, is declining.

"Corrosion has to be detected, and the tools for doing that are always getting better, but they are not perfect," he said.

Some experts say that corrosion has remained a problem because the industry has not dealt with the changing composition of the material sent through pipes. As oil fields get older, wells produce more water, which can lead to more rust.

"The pipeline companies have not kept up with the changes in oil," said Don Deaver, an independent pipeline consultant and an expert witness for many plaintiffs suing pipeline operators. Deaver worked for 33 years for Exxon Mobil Pipeline Co.

He said corrosion is like a spreading fungus: "Once it starts, you are going to have a heck of a time cleaning it out."

Not Knowing What Lies Beneath
Houston Chronicle (TX) (11/12/06) Cappiello, Dina

View Graphic: Pipelines out of position

ON THE CALCASIEU RIVER, LA. - The state-issue Boston Whaler plowed through the beer-bottle-brown Calcasieu River, stirring the calm waters that concealed what coursed below.

From their boat, John Snead and Robert Paulsell were tracking Louisiana's man-made rivers of commerce: the thousands of miles of pipeline that crisscross the state transporting fuel, oil and natural gas mined and refined along the Gulf Coast to distant gas stations and homes.

The two men, mapmakers with the Louisiana Geological Survey, knew the pipelines were down there. They just weren't sure where.

"A map of pipelines in Louisiana looks like a web made by a spider on LSD," Snead said.

The problem is that Louisiana — like many other states, including Texas — doesn't know exactly where all its pipelines are. And the federal government, which is supposed to keep maps of pipelines crossing state lines nationwide, may not be much help, a Houston Chronicle review shows.

Interviews with safety officials in nine states, home to more than 100,000 miles of buried pipe, reveal huge differences in the accuracy of maps relied on by emergency responders and, in some cases, by urban planners deciding where to build the next subdivision.

Nowhere is the problem more acute than in Oklahoma, Louisiana and Texas, home to the most extensive and oldest pipeline networks in the nation. In the past five years, these three states have led the nation in the number of accidents and volume spilled from pipelines, according to federal records.

But perhaps the most startling finding is that maps mandated by the federally run National Pipeline Mapping System contain significant errors, pipeline-mapping experts and state officials say. The system relies on the companies that operate pipelines to disclose where they are. The system is supposed to have the location of all 182,833 miles of hazardous-liquid interstate pipes within a margin of error of 500 feet. It's used by more than 30 percent of the nation's counties for planning, zoning and spill response.

Yet if a pipe breaks, releasing a harmful chemical into a neighborhood or spilling oil into a river, emergency workers still would have to perform some geographic guesswork to find it, experts say.

"The information is not nearly as accurate as they claim it to be," said Snead, who served on a technical team that helped design the federal mapping program in the late 1990s. "We have found pipelines a half-mile out of position, being run by the wrong company and filled with the wrong product."

Getting it right

Over the course of their research, about 30 percent of the pipelines mapped in the federal system have not been where they are supposed to be. In one case, south of New Orleans, a pipe was a half-mile from its mapped location, a difference that had it running through a neighborhood instead of a naval base.

"It is an issue in every state. It depends on the level of detail of the mapping," said Don Davis, administrator of Louisiana's Oil Spill Research and Development Program, which has funded Snead and Paulsell's work since 1999 with about $50,000 a year from taxes on the oil and gas industry.

Snead and Paulsell's work was triggered by a flood along the San Jacinto River in 1994. The waters ruptured eight pipelines, and emergency-response teams had to scramble to identify the operators in an attempt to shut down the leaks.

Few states beyond Louisiana are trying to more precisely map pipelines. Those that are, such as Washington, also have found problems when putting the U.S. mapping system to the test.

The system has "based the success of their program on the number of miles collected, not the accuracy of miles collected," said David Cullom, a Geographic Information System analyst with the Washington Utilities and Transportation Commission, which finished mapping its pipelines in 2005, using money from the Pipeline and Hazardous Materials Safety Administration.

The administration does not verify the pipeline information it receives from companies in the field and concedes that at least 7 percent of the pipeline mileage received since June 2005 is outside the 500-foot requirement. About 25 percent is accurate to within 50 feet.

Though the agency corrects the mistakes it knows about, it never has penalized a company for submitting inaccurate pipeline locations.

It also recommends against using its maps for emergency response. Last year alone, the agency recorded 135 accidents along hazardous-liquid pipelines — incidents that caused $93.8 million in property damage and killed two.

People responding to these incidents should use "higher accuracy" maps from local pipeline companies and planning and zoning offices to respond to spills, the administration said.

However, a bill before Congress seeks more money for states, which oversee pipelines within their borders, to improve their maps. If the bill passes, the federal mapping program, which tracks mostly interstate pipelines will also improve its accuracy.

"We want better fidelity. ... There is a lot of activity in the underground, and, to avoid conflicts, you really need to understand with more precision where your liquid and gas lines are," said Adm. Tom Barrett, the safety administration's administrator.

In Texas, companies must submit pipeline locations within a margin of error of plus or minus 1,000 feet. In California, officials require companies to map their portions of the state's 5,500 miles of hazardous-liquid pipelines within 100 feet. In Washington, a deadly pipeline incident in Bellingham prompted efforts to locate all pipelines in urban areas to within 10 feet.

Some states, including New Mexico, Iowa and Louisiana, don't regularly collect information at all.

Bruno Carrara, general manager for the Pipeline Safety Bureau at the New Mexico Public Regulation Commission, said emergency workers and response teams "can go on the national system and look at maps."

And in cases in which the pipeline is not in the federal database, emergency responders need to know what company to call and where the pipeline is, Carrara said.

Texas subscribes to the same policy, even though the San Jacinto River incident, which spilled gasoline, diesel, natural gas and crude oil into the river and later was set on fire by a house gas heater, raised questions about how well-versed first responders were on pipeline locations. The fire burned for days, and nearly 600 people were sent to local hospitals with burns and other injuries. Soon afterward, the Port of Houston Authority stiffened its licensing requirements for pipelines crossing navigable waterways, requiring companies to submit maps based on where the pipeline was built.

"All I can say is that we have not had any issues with our first responders. We have not had anyone say that what we provided them has not been adequate for their needs," said Mary McDaniel, director of the Texas Railroad Commission's safety division.

However, McDaniel acknowledged that Texas' maps are not accurate enough to locate the exact position of a line for construction, for example.

Accuracy often comes down to how well the company operating the line does its mapping. Some use sophisticated software; others have pipes hand-drawn with marker across nothing much more than a road map.

Homeowners worry

Steve Williams' home in Scotlandville, a working-class, black neighborhood north of Baton Rouge, sits on the shoulder of a pipeline superhighway. Nine Exxon pipeline posts, carrying a laboratory's worth of chemicals, are lined up single-file along his chain-link fence.

Where orange and yellow lilies once grew, all that's left is a grass-covered hump. Beneath it, a ridge of cement covers the pipes.

There could be as many as 20 in all, based on maps of the area. But the network is so dense here that Paulsell couldn't separate one from another when he mapped Baton Rouge Parish in 1991. The marker posts don't help, either, because their order changes across the street.

"These pipes shouldn't be near someone's home. There is somewhere else they could be," said Edith Williams Pride, Williams' daughter. The oil companies "are doing quite well, and they will always want to find the cheapest land, so they come to black communities."

In Louisiana, the hope is to map the location of all of the state's pipelines within a margin of error of 50 feet or less.

"It behooves us to know where those pipelines are, in case there is a rupture," said Davis, who works for the state oil-spill office. "We need to know what is in close proximity so we can respond responsibly."

The pipeline industry , which initially resisted disclosing pipeline locations to the government, recently has become an advocate for accuracy. It comes down to money. It's a waste for an operator to be sent to stake a pipeline for an excavation only to find the project is nowhere near the line.

"It's fundamentally in our interest to have people know where pipelines are," said Ben Cooper, a spokesman for the Association of Oil Pipelines, a consortium of the nation's major pipeline operators.

Paulsell and Snead are doing their small part in Louisiana, where so far they have mapped all the major rivers and parts of 15 of 64 parishes, despite little cooperation from pipeline companies.

Forging ahead

That summer morning on the Calcasieu River, they mapped 20 miles. Along the way, they would float over 25 pipelines buried deep within the river's muck. In three cases, they found pipelines not marked on any map. In one case, they could not find a pipeline even though it appeared on the map.

Their search took them to reaches of the river so dark and shallow that they debated whether to forge ahead.

"We're at the end of the river. Let's go home," Paulsell said. "This is not navigable."

But somewhere ahead, beneath the coffee-colored water, among the palms and tangled mass of the Louisiana swamp was another pipeline — or so the map said.