Crosstex, a midstream energy firm in Dallas, said it would make the investment in its E2 company. The facility, like the others, is supported by a long-term, fee-based contract with Denver-based Antero Resources.

The compressor stations are the sort of midstream facilities needed to move oil and gas from well sites to end users such as chemical plants, requisite infrastructure still needed in Ohio’s Utica shale play.

MATCOR is a leading provider of ISO 9001:2008-certified cathodic protection products that product compressor stations and many other infrastructure needs within the Utica Shale. Learn more about our services and cathodic protection installation that carry a 10 year guarantee. MATCOR offers the latest insights on anodes for cathodic protection, cathodic protection equipment and more.

SOURCE: http://www.bizjournals.com/columbus/morning_call/2013/05/crosstex-plans-3rd-utica-natural-gas.html

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The strengthened regulations require companies to actively address safety, pipeline integrity, safety, environmental protection and emergency management.

The measures intend to make senior management at pipelines accountable and responsible for their projects. Responsibilities include creation of annual reports on pipeline integrity and safety that will be evaluated by the National Energy Board.

The board is mandating companies name specific points of contact that are accountable for ensuring protection of pipelines. The board hopes tasking senior management at pipeline companies with this responsibility will make a significant throughout every pipeline management company.

The National Energy Board stated the move has been a work in progress for several years. The board was also quick to point out the changes have not been motivated by any recent environmental or safety concerns.

A spokesperson with the Canadian Energy Pipeline Association said member companies will comply with the new requirements. However, further comment was declined.

Nathan Lemphers of the Pembina Institute said the changes are a marked positive change that will ensure real action in Canadian pipeline management. The old regulations failed to create corporate responsibility around pipeline environmental safety and integrity management.

MATCOR’s Insight That Works

MATCOR applauds this move by the National Energy Board. There are certainly concerns for ease of rule implementation. However, MATCOR has experienced significant long-term benefit through proactive environmental protection and sustainability measures. The move to enhance pipeline safety through government regulation may speed these measures and greatly improve Canadian peace of mind.

SOURCE: http://www.ctvnews.ca/canada/energy-board-says-it-has-strengthened-pipeline-safety-rules-1.1247608

MATCOR is a leading provider of ISO 9001:2008-certified cathodic and anodic protection. Read more about cathodic protection equipment and systems for storage tanks. MATCOR is pleased to offer the latest analysis weekly on its blog, Cathodically Protected: Pipeline Corrosion Control Insights.

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The Cactus Pipeline is expected to begin service in the first quarter of 2015. It will move both sweet and sour crude from McCamey to Gardendale, according to the announcement.

Total investment is expected to be as much as $375 million.

The partnership said it has entered into a letter of intent with a third party regarding a long-term commitment for a majority of the pipeline’s capacity and is in discussions with other potential shippers for the remaining capacity.

Initial capacity will be approximately 200,000 barrels per day, although the company’s announcement said that could be increased as demand warrants.

Plains All American Pipeline is a publicly traded master limited partnership based in Houston, engaged in the transportation, storage, terminaling and marketing of crude oil and refined products, as well as the processing, transportation, fractionation, storage and marketing of natural gas liquids.

The company has been aggressively investing in new projects as part of its plan for growth.

In December it announced a $500 million deal with Houston-based U.S. Development Group to buy crude oil rail terminals in three of the nation’s most active shale plays: the Eagle Ford in South Texas, the Bakken in North Dakota, and the Niobrara in Colorado, along with an existing unloading terminal in St. James, La., and one under development in Bakersfield, Calif.

MATCOR’s Insight That Works

The new pipeline is a strategic move for all parties involved. The Cactus Pipeline will run crude from the Permian to the Plains All American/Enterprise Products Partners Eagle Ford Joint Venture Pipeline, which serves the Three Rivers and Corpus Christi markets. The Three Rivers and Corpus Christi markets are booming with the current opportunities in the Eagle Ford Shale. That venture can also serve the Houston-area market through a connection to the Enterprise South Texas Crude Oil Pipeline, according to the Plains announcement.

The Cactus Pipeline is a long term investment. It is servicing a lucrative area that holds a large amount of promise both in economic and geological terms. However, the pipeline appears to be a complex project that will require expert coordination of pumps, valves, cathodic protection equipment and more.

SOURCE: http://fuelfix.com/blog/2012/12/05/plains-pipeline-company-expands-rail-network-in-500-million-deal/

MATCOR is a leading provider of ISO 9001:2008-certified turnkey cathodic protection systems. Read more industry news and analysis in their corrosion protection services magazine. MATCOR is pleased to offer the latest insights weekly on its blog.

The post Plains Pipeline Company Expands Rail Network in $500 MM Deal – Update appeared first on Matcor.

“Act 13 is a law that has helped bring Pennsylvania forward both economically and environmentally,” Corbett said. “In addition to enacting some of the most rigorous environmental standards in the nation, we’ve brought in more than $400 million for our communities directly impacted by unconventional drilling, along with other environmental efforts across the state.”

“As this industry grows, benefitting all Pennsylvanians with thousands of new jobs, lower energy prices, and increased energy independence, Act 13 has played a key part in our role making sure that it grows safely and responsibly,” Corbett said.

Collections for 2012 were due to the Pennsylvania Public Utility Commission (PUC) by April 1.

Nearly $198 million is expected to come into the state from the 2012 collections. This is in addition to the $204 million collected during the first round of collections. The 2012 amounts were released yesterday.

The collections this year are slightly lower than last year due mainly to the lower price of natural gas.

Information on the amount of money expected for 2012, as well as the amount of money collected to date, can be found on the Act 13 page on the PUC’s website, www.puc.pa.gov.

SOURCE: http://gantdaily.com/2013/04/05/corbett-impact-fee-proceeds-above-400m-198m-collected-for-2012/

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The Calgary-based pipeline giant said Tuesday that it has launched a formal process to acquire shipping commitments from energy companies for the Energy East Pipeline, which could reach New Brunswick’s Irving Oil Ltd. refinery and port of Saint John.

TransCanada said it is confident in gaining such support, and will then file for regulatory review with the goal to begin shipments by late 2017.

“We’re committed,” said Jeff Matthews, Irving Oil’s director of business development. The proposed pipeline “increases our ability to compete in a tough industry by allowing our refinery access to a crude supply region in Western Canada that has not been accessible in the past,” he said.

The west-to-east project – unveiled just a year ago – is gaining considerable momentum at a time when other pipeline projects such as TransCanada’s Keystone XL and Enbridge Inc.’s Northern Gateway face uncertainty amid political friction and environmental concerns.

Energy East is expected to largely handle light oil, along with some heavy crude from the oil sands. As a result, projects such as the Keystone XL and Northern Gateway pipelines will still be needed to bring Alberta’s vast oil sands reserves to market.

The proposed Energy East Pipeline would carry as much as 850,000 barrels a day of western crude to eastern markets, with an option of either stopping in Quebec or extending it to Saint John. At its maximum, it would be 4,400 kilometres long, including the conversion of TransCanada’s underutilized natural gas line to a point near the Ontario-Quebec border, and new construction from there to Saint John.

The Saint John facility is Canada’s largest and most complex refinery. Mr. Matthews said oil producers are also interested in accessing Irving’s Canaport marine terminal for export.

With support from a wide range of politicians, Energy East now faces the acid test of commercial viability as producers weigh competing projects and the appeal of various markets.

While Alberta producers have been keen to reach the huge refining hub on the U.S. Gulf Coast, or access fast-growing markets through Asia, the Eastern Canadian market appears to be their most problem-free alternative, at least in the short term. But there is limited capacity to process oil sands bitumen at refineries in Ontario, Quebec and Atlantic Canada.

Keystone XL, which would carry bitumen to the Texas Gulf Coast, has encountered lengthy delays from the Obama administration in the face of fierce criticism from environmentalists. The company says it remains confident of eventual approval, but the political risk remains high.

At the same time, Northern Gateway – which aims to transport oil sands crude to Kitimat, B.C., for export to Asia – has run into a wall of opposition from First Nations, the environmental community and the B.C. New Democrats, who may well win government in the upcoming provincial election.

The eastern pipeline proposal has won broad endorsement from the federal government, the New Democratic Party opposition, and New Brunswick Premier David Alward. Quebec Premier Pauline Marois has been consulted on the project and has given support in principle.

IHS Inc. analyst Jackie Forrest said the industry would face 1-million barrels per day of pipeline over-capacity if all the proposed projects were completed on schedule in the 2015 to 2018 time period.

“However, producers are looking for market options – so it is possible we would see a future scenario with excess pipeline capacity,” Ms. Forrest said. “And since we expect oil sands to grow beyond 2020, this extra capacity would be needed in the early part of the next decade.”

SOURCE: http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/transcanada-moves-ahead-on-ambitious-plan-to-pipe-oil-to-quebec-nb/article10663042/

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MATCOR has learned that Anadarko is close to completing its new $100 million natural gas processing plant in Texas.

The Cathodically Protected Brasada plant will process natural gas produced from the company’s Eagle Ford shale wells.  Components like methane, ethane, propane and butane will be separated before they they are transported through the cathodically protected pipeline for further processing.

Anadarko’s plant is designed to process 200 million cubic feet of gas per day but can expand to process up to 400 MMcf/d.  This could lead to capacity expansion if Anadarko undertakes processing of third party gas at some point.

Although the Eagle Ford Shale region has a lot of potential for company’s such as MATCOR it cannot be optmized until the supporting midstream infrastructure comprising of gathering systems, pipeline and processing plants are developed to move oil and gas to to market.

Anadarko’s Eagle Ford Operations

Anadarko explores for shale oil and gas in a gross area of 400,000 acres in the Dimmit, LaSalle, Maverick and Webb Counties in the Eagle Ford region. Its current resources are estimated at over 600 million barrels of oil equivalent (MMBOE), 65% of which is estimated to be liquids. In 2012, the company achieved a gross processed production record of approximately 152,600 BOE per day. With its higher-margin oil and natural gas/condensate, the Eagle Ford shale region is among the most capital-efficient shale plays in Anadarko’s U.S. onshore portfolio.

Anadarko currently operates approximately 380 miles of oil and natural gas pipelines throughout the southwest Texas region, with additional gathering facilities that support more than 50% of its Eagle Ford shale production. In March 2012, Anadarko and Western Gas Partners began construction of the Brasada gas processing plant. The Brasada plant and the construction of an additional 200 miles of gathering lines will enhance the value of Anadarko’s Eagle Ford assets.

The Brasada Plant

All of Anadarko’s Eagle Ford acreage is located to the west of the Brasada plant, and a pipeline network will bring natural gas into the facility as well as move it off site to market. The pipeline will enable the company to eliminate its dependence on trucks. This will speed up transportation of its gas as there are too many trucks on the road in the region which causes a slowdown in the overall movement.

The Brasada plant also will also reduce flaring of methane in the field because Anadarko will be able to move it directly to market through pipelines. Flaring of methane is a common industry practice in cases where transportation is not viable.

From the plant, natural gas liquids will travel further through a pipeline to a plant in Yoakum and to fractionation facilities in Mont Belvieu, east of Houston. Gas also will go south to Corpus Christi, where it can be used in refining or fed into the existing network of interstate pipelines

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Enbridge, Inc. will begin work on Oxford and Addison’s portions of what is known as Line 6B at some point between June 1 and Dec. 31, according to Jack Manshum, a spokesman for the company.

“That’s the plan as of right now,” he said. “We’re in the process of developing the construction timeline.”

Line 6B is a 285-mile crude oil pipeline that begins in Indiana, crosses southeastern Michigan and ends in Sarnia, Ontario, Canada. It serves refineries in Michigan, Ohio and eastern Canada.

This year, Enbridge plans to replace approximately 50 miles of Line 6B with new 30-inch diameter pipeline (the same size as the existing one) from Ortonville to the St. Clair River in Marysville. The portion that runs through Oxford is approximately 6.5 miles in length, while Addison’s portion is approximately 6 miles long, according to Manshum.

This is part of a much larger construction project that spans approximately 210 miles across Michigan and Indiana.

The Michigan Public Service Commission approved Enbridge’s application for this phase of the pipeline project on Jan. 31

“We’ve haven’t formally announced the details yet as to when we’ll be in each county or in each area,” Manshum said. “We’re in the middle of outlining that entire plan. So, I don’t know exactly when we’ll be in Oakland County.”

The old underground pipeline will not be removed to make way for the new one. It will be left in place.

“It will run parallel and adjacent to the existing line that’s in place now using the same right-of-way,” Manshum said. “When the new line is tied in and activated, the old line will be deactivated.”

Deactivation will involve purging all the oil from the old line and cleaning it thoroughly to remove any remaining crude, he explained. The old line will then be “taken apart in small segments” and capped.

“Each chunk of that pipe will have caps on it and then it’s filled with nitrogen,” Manshum said. “We will monitor the pressure inside that line as long as the line exists. The reason you fill it with the nitrogen and you monitor the pressure is to help make sure it doesn’t have any internal corrosion.”

With regard to the line’s exterior, he said Enbridge will maintain the cathodic protection that’s already on it to ensure there’s no external corrosion either.

Enbridge can’t simply walk away from the old pipeline.

“It’s a federal requirement,” Manshum said. “You have to maintain it as if you were using it.”

Manshum explained that leaving the old pipeline in place is “pretty standard in the energy transportation industry.”

“To completely take that line out of service, then replace it with a new one” is not practical for Enbridge’s customers, which are oil refineries.

“(The pipeline) would be out of service for six to 12 months – there would be no product flowing through (it),” Manshum said. “(The refineries) don’t have enough storage capacity to go that long.”

Once the new line is up and running, why can’t Enbridge come back and remove the old one? “That’s more of an inconvenience for landowners,” Manshum said. “We’re already there during one construction season, digging up their property, creating the trench.”

If Enbridge returns for another construction season, the workers will “basically redig everything that we just put back into place the year prior.”

Manshum noted it would involve the “same amount of time and process” to remove the old pipeline as it did to install the new one.

“It’s much less disruptive to landowners for us to only be in there once, instead of having to come back,” he said.

SOURCE: http://www.clarkstonnews.com/Articles-News-i-2013-03-20-250883.113121-sub-Work-on-oil-line-to-begin-later-this-year.html

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That means resources from the Marcellus Shale will now be accessible by facilities in Texas and Louisiana, which can then export them around the world. Kentucky.com reports that the pipeline, once completed, would allow for the initial transport of some 200,000 barrels of natural gas liquids per day from the shale operations in Pennsylvania, Ohio, and West Virginia over to the facilities along the Coast. This capacity would later be upgraded to 400,000 barrels per day, chiefly by the addition of liquids-pumping capacity.

The venture also means wholly new facilities, both along the pipeline’s route and in the South where it terminates, would be constructed and developed, the Pittsburgh Post-Gazette reports. Roughly 40 percent of the project proposal comprises new construction and development, and this is focused largely within the Marcellus region, though no exact locations have yet been decided upon.

An interconnect in Kentucky would connect to origin points of the pipeline located in Ohio and West Virginia. Also in Kentucky, an existing system will partially be reconfigured to allow for the transportation of natural-gas liquids, Kentucky.com reports. The final route the pipeline will follow has not been determined yet.

This project comes as the latest in a series of high-profile pipeline development efforts in and near the Marcellus Shale region, as companies try to exploit the lacking American pipeline infrastructure situation by building new networks that can handle the rush of shale-derived oil and natural gas (and related products), which the existing heavy crude pipelines cannot readily do.

In fact, the situation is so complex that some Marcellus and Utica shale producers have had to slow down their operations as they wait for the pipeline network infrastructure to play catch-up. But natural gas prices have dropped even further, so developers are showing more interest in liquids derived from natural gas, like condensate, ethane, and other natural-gas liquids, Kentucky.com reports, which could be sold in numerous markets both domestic and international.

According to Williams, the present system is likely to be under too much pressure as soon as 2016, with the total volume of natural-gas liquids being produced in the Northeast projected to go over 1.2 million barrels per day by 2020.

Kentucky.com quotes Williams President and CEO, Alan Armstrong:

“We are designing Bluegrass Pipeline to provide these two world-class resource plays with access to one of the largest and most dynamic petrochemical markets in the world,” Armstrong said. “This will help producers in Ohio, Pennsylvania and West Virginia achieve an attractive value for their ethane and other liquids.”

The way Boardwalk and Williams envision this project is for the pipeline to deliver mixed natural-gas liquids from the shale zones in Ohio, W. Virginia, and Pennsylvania to numerous fractionation plants and storage centers. These have yet to be built, but they will be positioned along the pipeline’s route. They would subsequently link up with petrochem plants and end-product pipelines along the Texas and Louisiana coasts.

No costs have been cited yet, as those are part of the details still being worked out. The problem of moving the shale derivatives out of the Northeast and nearer to the refineries and other facilities is one of the U.S. shale sector’s biggest issues, and this project will undoubtedly do its part in alleviating the pressure.

Roughly 60 percent of existing pipeline can be used, according to Kentucky.com; this is mostly owned by Boardwalk, named the Texas Gas Pipeline. New construction would simply expand on this network. It would allow the project to possibly come online by or in the second half of 2015, while also keeping construction costs down.

Boardwalk has nearly 1,420 miles of natural gas pipeline networking through Western Kentucky and employs 315 out of its 1,200 employees within that state.

Prior to this development, Enterprise Products Partners LLP and Chesapeake Energy (NYSE: CHK) came up with a similar plan in 2011 to develop a pipeline that would transport ethane from the Marcellus Shale region, connecting it to refineries and facilities along the Gulf Coast. More such projects will need to be developed before the Appalachian shale bottleneck can see some real relief.

SOURCE: http://www.energyandcapital.com/articles/bluegrass-natural-gas-pipeline-approved/3192

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One of MATCOR’s key clients Texas Eastern Transmission LP, is seeking federal approval of a $5.3-million expansion of its pipeline and compressor station system to distribute Marcellus shale gas produced locally by Chevron and EQT.

A subsidiary of Spectra Energy Transmission, of Houston, Texas, Texas Eastern wants to gain Federal Energy Regulatory Commission (FERC) approval in November this year

A subsidiary of Spectra Energy Transmission, of Houston, Texas, Texas Eastern wants to gain Federal Energy Regulatory Commission (FERC) approval in November this year and put the new pipelines into service by November 2014, according to a pre-application filing recently submitted to FERC.

The project involves installing a total of 33.6 miles of new pipeline in five counties in the state; upgrading four compressor stations in the state and other work at 41 company facilities between Pennsylvania and Mississippi.  MATCOR has the ability to provide its SPL Mixed Metal Oxide Linear Anode to cathodically protect this pipeline expansion.

“Texas Eastern’s (pipeline) runs from the Gulf of Mexico to Lambertville, N.J. This is an expansion of that system,” said Spectra spokeswoman Marylee Hanley.

Texas Eastern has agreements with Chevron and EQT to charge them for the work, which would provide both producers with the capacity to transport 300,000 additional Btu/d.

These two shippers are major producers in the Marcellus shale play need the project to ensure that pipeline capacity exists to transport their gas to markets as the production comes on line. The shippers have agreed to pay negotiated rates for the pipeline service, according to Texas Eastern’s FERC filing.

“We are an open access pipeline, which means we are required to provide service to our customers,” Hanley said.

The new pipelines would be installed adjacent to existing pipelines in existing rights of way, and all the compressor station work would be done on the stations’ existing property, she said.

Specifically, the project would transport 300,000 Btu/d of gas from western Pennsylvania to the eastern end of the system in Lambertville, N.J., and Staten Island, N.Y.; 50,000 Btu/d from western Pennsylvania to the Lebanon, Ohio, hub and 250,000 Btu/d of of gas from western Pennsylvania to markets in Mississippi and Louisiana.

In addition to providing access to markets for the producers, the project would promote commodity price competition and reduce price volatility by introducing new supply sources from the Appalachian production area, particularly the prolific Marcellus shale, to these market areas, Texas Eastern said. The project would also provide gas to developing markets in the Gulf Coast Region and improve the company’s transportation security, flexibility and reliability, according to the filing

SOURCE: http://www.elp.com/news/2013/03/10/texas-eastern-transmission-planning-pipeline-extension.html

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The state department study argued that production in the oil sands of Alberta would increase even if the pipeline were not built because companies could make more use of rail transport to reach US refineries.

It also suggested that building Keystone XL would create more than 42,100 jobs across the US for one to two years, although once in operation it would support just 35 permanent jobs.

The conclusions make it more likely that President Barack Obama’s administration will approve the controversial project, which has become a battleground for the oil industry and environmental campaigners.

Formally, the state department has responsibility for deciding on the pipeline, because it crosses the border from Canada.

The pipeline would carry diluted bitumen from the oil sands – also known as the tar sands – which create higher levels of greenhouse gas emissions than many other forms of oil production.

Alison Redford, premier of Alberta, praised the study as “extensive, exacting and comprehensive”.

TransCanada, the company behind the project, addressed earlier concerns about leaks from the pipeline by re-routing it away from the environmentally sensitive Sand Hills area of Nebraska.

The new route is 875 miles long, and could carry up to 830,000 barrels of diluted bitumen per day to Steele City, Nebraska, where it will connect with a southern section already under construction. The aim is to connect to refineries on the Gulf of Mexico coast that are configured to use heavy oil including Canadian production.

The pipeline could also take some production from the fast-growing Bakken shale of North Dakota, the heart of the new US oil boom.

The state department study suggests that the oil sands of Alberta will be developed whether or not Keystone XL is built.

It argues: “Approval or denial of any one crude oil transport project, including the proposed project [Keystone XL], remains unlikely to significantly impact the rate of extraction in the oil sands, or the continued demand for heavy crude oil at refineries in the US.”

Blocking Keystone XL would cut output from the oil sands by only 0.4-0.6 per cent by 2030, the study said. Even if all new pipeline capacity were restricted, oil sands production would drop just 2-4 per cent.

The study argues that other transport routes, particularly rail, would be capable of “providing the capacity needed to transport all incremental Western Canadian and Bakken crude oil production to markets if there were no additional pipeline projects approved”.

The state department will now take comments about the study, before a final decision from the administration on whether the pipeline is in the US national interest.

SOURCE: http://www.ft.com/cms/s/0/9763476c-82b3-11e2-8404-00144feabdc0.html

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