Global Valve and Controls
31Mar/11Off

Sunoco Expand Pipeline Deal

Sunoco Expand Pipeline Deal

MarkWest Liberty Midstream & Resources, LLC, Denver, Colo., a partnership between MarkWest Energy Partners, L.P. and The Energy & Minerals Group, and Sunoco Logistics Partners L.P., Philadephia, Penn., have reported the development of Project Mariner West, a pipeline project to deliver Marcellus Shale ethane from MarkWest Liberty’s Houston, Pennsylvania processing and fractionation complex to Sarnia, Ontario, Canada markets. Mariner West, which is being developed at the request of Marcellus producer customers and is supported by Sarnia ethane consumers, will utilize new and existing pipelines and is anticipated to have a maximum capacity to transport up to 65,000 barrels per day of ethane by the third quarter of 2012. Mariner West is an expansion of Project Mariner, a pipeline and marine project developed to transport ethane produced in the Marcellus Shale basin to US Gulf Coast and international markets by mid-2013.
To support deliveries to Canadian markets in 2012, MarkWest Liberty will make minor modifications to its natural gas processing complexes and will install ethane extraction facilities at its Houston complex to deliver ethane to Mariner West earlier than will be required for deliveries to Project Mariner. In addition, MarkWest Liberty will construct a 25-mile pipeline from the Houston complex to an interconnection with an existing Sunoco Logistics pipeline at Vanport, Pennsylvania. The ethane will then be transported from Vanport to markets in Sarnia utilizing existing Sunoco Logistics pipelines, which will be modified for ethane service. Project Mariner and Mariner West are both designed to provide Marcellus producers with access to multiple ethane markets to match the growing rich-gas production in the Marcellus.
“When combined with our growing NGL pipeline network in the Marcellus and our highly integrated Houston fractionation and marketing complex, Mariner West provides a very significant advantage to Marcellus producers,” said Frank Semple, Chairman, President and Chief Executive Officer of MarkWest. “MarkWest and The Energy & Minerals Group are very pleased to partner again with Sunoco Logistics to further expand the midstream services we provide to our producer customers.”
“Project Mariner West has the advantage of allowing us to modify our existing pipeline facilities to reach Sarnia, Canada where there is a market for Marcellus ethane. We are pleased to participate in Project Mariner West and to partner with MarkWest Liberty in serving Marcellus producer customers," said Lynn L. Elsenhans, Chairman and Chief Executive Officer of Sunoco Logistics. “Our existing infrastructure is well positioned to provide an efficient solution for producers to move ethane to Sarnia as well as across Pennsylvania to a Delaware River marine port to access multiple markets.”
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29Mar/11Off

Oil’s Changing Landscape: Ship Low, Sell High

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Editor’s Note: This is the fourth in a multi-part series examining the fundamentals behind the structural transformation of the U.S. oil markets and the downstream logistics challenges that are resulting. The third installment covered the “disconnect” between inland crudes priced off Cushing crude values when the North American oil hub is flush with crude in storage. (Image Source: CN)
As geopolitical turmoil drives crude prices skyward and lifts retail gasoline to US$4.89 per gallon (/gal) in cities like Los Angeles, it’s anything but business as usual in the U.S. oil patch.
Inland producers who are left in the dust amid triple-digit waterborne crude prices on most every U.S. coast are pioneering inventive downstream logistics to ship crude at low cost to higher-priced markets – thereby avoiding the disconnect in the wild west of North America’s oil industry.
Nearly every multimodal logistics opportunity short of yesteryear’s Pony Express and today’s Federal Express is being considered to cost-effectively ship crude oil to profit from high-price spreads between landlocked and waterborne crudes.
In intra-day trading on March 2, a remarkable spread was logged as the West Canadian Select (WCS) grade saw discount pricing around $80.00 per barrel (/ bbl), while both Heavy Louisiana Sweet and Light Louisiana Sweet (HLS and LLS) crudes on the Gulf Coast traded at more than $122.00/bbl.
That astounding discount of more than $40.00/bbl represents 50% of the then current WCS value. The basis differential can partly be explained by crude quality, but these theoretically, wide-open arbitrage opportunities attract pioneering innovators like the land rush days of old.
Furthermore, the $19.70/bbl discount to LLS prices that day for 38 million barrels of crude stored inland at Cushing at the time represented $750 million in dollar terms.
In the void left by insufficient pipeline takeaway capacity, tankers are stepping in to ship crude via rail and inland waterways away from the heavily utilized and smaller Mid-Continent refining fleet toward a Gulf Coast refining fleet twice its size.
Canadian Railway Company Rides the Rails to the Rescue?
Canadian National Railway Co. (CN), based in Montreal, Quebec, has pioneered and trademarked, PipelineOnRail – described as an “economically sound, surprisingly fast way to ship crude oil products within Alberta to the rest of Canada, the U.S. Midwest, the Gulf coast and other export markets.”
The plan seeks to use its extensive North American rail system that already traverses the Canadian continent on an East-West axis to tank crude south along its interconnected rail spine spanning the U.S. down the Mississippi River valley all the way to and around the U.S. Gulf Coast.
On March 1, Hart Energy contacted CN’s Kelli Svendsen, senior manager of regional public and government affairs, and learned that “CN has been testing concepts to move crude (heavy, light, and pure bitumen) from areas in Western Canada to various markets in the U.S.”
Svendsen said two areas of Canada are already exporting crude oil to the U.S: “CN has moved pure bitumen from Fort McMurray to U.S. markets,” and “from the Bakken reserves in Saskatchewan (Canada) to the U.S.”
The Bakken effort began recently with shipments “in October 2010.” Svendsen said, adding that “CN is optimistic that rail will play an increasing role in the transport of crude moving forward.”
EnSys Study Documents Crude-by-Rail Potential
EnSys Energy noted in a December 2010 North American crude logistics assessment that “CN Rail currently imports condensate, for blending with oil-sands bitumen to make DilBit (a.k.a. diluted bitumen)” from the Kitimat Port on Canada’s west coast.
According to EnSys, the “PipelineOnRail … avoids the large, fixed investments associated with major pipelines.” EnSys also noted that CN indicates potential capacity to move “as many as 200,000 b/d or more.”
EnSys said the study did not allow for the expansion of the PipelineOnRail capacity in any scenario, because tariffs for rail are generally not considered attractive relative to pipelines.
“However, during a period of constrained pipeline capacity, the PipelineOnRail could compete as an alternative,” the assessment reads.
Pioneers on the U.S. Side of the Border
The Bakken petroleum that CN is shipping originates from a producing region that extends into the U.S. states of North Dakota and Montana. Drillers in North Dakota produce the area’s greatest share of petroleum using unconventional hydraulic fracturing and horizontal drilling techniques.
Justin Kringstad, director of the North Dakota Pipeline Authority (PA), wrote in a September 10, 2010, release: “Because of our distance to market, regional producers have always absorbed a per-barrel discount on production.” Yet he noted that recent increases in rail and pipeline “takeaway capacity has pared that discount down substantially.”
Kringstad tabulated new capacity for crude oil shipments from several takeaway projects, including new rail-loading terminals in the area. These include EOG Resource’s 65,000-b/d rail facility in Stanley, N.D., which began rail tanker shipments to Cushing, Okla., in December 2009.
Hart contacted EOG spokesperson K. Leonard on March 1, who shared that “EOG is currently utilizing five trains, with plans to add a sixth in the future.” Leonard said EOG leases the rail tankers it uses to ship crude.
“The company typically loads one train daily and regularly hauls 68,000 gross barrels of crude per train,” Leonard said, adding that “Each train has approximately 100 cars.”
North Dakota PA’s Kringstad further noted in his release that Hess Corp. is readying a $48-million, 60,000 b/d rail facility in Tioga, N.D., for an early-2012 start-up. His post also said that Dakota Transport Solutions began shipping crude from New Town, N.D., to St. James, La., in August 2010. Kringstad said that facility reportedly had the capacity to transport 20,000 b/d by the end of 2010.
Kringstad also noted that smaller rail facilities operate with an estimated combined capacity of 30,000 b/d and include North Dakota locations in Minot, Dore, Donnybrook and Stampede.
Rangeland Energy LLC a New Pioneer
Rangeland Energy LLC (Rangeland), based in Sugar Land, Texas, has also announced plans that would enable Bakken producers to ship crude by rail tanker to the U.S. Gulf Coast.
On March 1, Hart spoke with Chris Keene, Rangeland president and CEO, and learned the company is developing the “COLT” rail terminal hub or connector to ship 100 rail tankers daily (60,000 b/d) of Bakken crude via the BNSF Railway Company to points including the Gulf Coast.
Keene said his company was formed in 2009 and noted: “It’s a huge opportunity, and I think our facility that we are building will be extremely valuable to the industry. It’s been great.”
“There are new rail tank cars being built as we speak. As fast as they can build them, they are being leased. In fact, they are being leased before they build them. Tank car makers, Keene said, have a huge backlog at present – driven by this trend.
Although Keene would not name names, Hart learned that Dallas-based Trinity Industries, Inc., and Oregon-based The Greenbriar Companies, manufacture multi-modal tankers for rail, barge and/or land transport. A review of company disclosures suggested a confirmation of strong backlogs in tanker manufacturers.
The new rail tankers “are coming on because you have a huge demand that has grown not only in North Dakota but also in the Eagle Ford,” Keene added.
Shippers also “are doing whatever they can using existing fleets … a refiner that has an existing fleet of rail cars that maybe they were moving refined products. They convert them and move crude oil,” according to Keene.
“We have not looked at rail into Canada although we have talked with the folks working Saskatchewan’s Bakken trend. Everything we have looked at doing is in and around Williams County in North Dakota where we will be building,” Keene noted. “But certainly the opportunity exists wherever there is existing infrastructure, rail infrastructure, there is an opportunity to do manifest or unit trains.
“Currently, we have a huge draw to get it to the Gulf Coast, into the LLS market,” he said, but “non-traditional” markets for inland crude could soon take the rising flows shipped by rail tanker from Bakken and Eagle Ford producers. “Bakken crude is going to California at Bakersfield right now, by manifest trains, a few cars at a time.”
Keene further mused about the potential for Eagle Ford to flood the Gulf Coast, saying that this could back crude up at Cushing and further back in the Bakken.
“Now you have this rush of light, sweet crude coming on the market; where is it going to go? It’s an interesting story,” Keene said. “It will be interesting to see which refiners run it given that a lot of these refiners just a couple years ago were converting to run heavy, sour crude with investments of billions of dollars.”
Musket Trading Makes The Connection
On March 1, Hart Energy also contacted Oklahoma-based Musket Trading and spoke to Dan House, managing director of crude oil. House said the shifting North American oil industry landscape has “been pretty active as far as the changes that are going on. That creates opportunity, so it’s a good place for us.”
Musket owns and operates rail-served terminals; maintains some 2,000 railcars; provides shipment logistics in 39 states and Canada; and distributes crude oil and other commodities via more than 20,000 railcars annually. That includes crude from the Bakken region to the U.S. Gulf Coast.
House confirmed that rail shipments of Canadian crude are increasingly being talked about and occurring in small batches. “We have done a small amount of it, and I know there are a lot of people looking at it in a bigger way recently,” House said.
Regarding Eagle Ford production, House said producers there yield “a lot more condensate type material that will be railed out of the Eagle Ford. The crude seems to have a good local market, but the condensate volumes that they are talking about do not seem to have a natural home down there.”
Hart also asked House if the Eagle Ford condensate could be sent northward to Alberta’s bitumen producers for use as diluent instead of importing it at Kitimat and shipping it by CN rails to Alberta. House agreed that this opportunity is “most likely” and “that’s where we are seeing it make sense.”
Kirby Inland – Heavy Oil to Crude Tanker?
To obtain the waterborne tank barge perspective, Hart Energy spoke with Steve Holcomb, communications officer for Kirby Corp. in Houston – among the largest inland waterway shippers in the U.S.
According to Holcomb: “We carry very little crude oil. We’ve had a lot of inquiries into it, but they have got to get the product to the Mississippi River or the Arkansas River. So it’s a logistics problem of getting the crude to a river system that is navigable.”
When asked about CN’s rail plan, Holcomb said: “A tank barge would be much more economical way to move it than rail cars. But then, of course, you have to have access to [load the crude] on a viable waterway.”
“Our utilization is pretty high, so we don’t have a lot of barges available, but the industry may have some available … If you move refined products in a barge and you switch it over to crude service, then you have a significant cost of cleaning that barge. You cannot carry a petroleum product upriver and bring crude oil back.
“That doesn’t work. It must be dedicated,” Holcomb said, or the shipper could incur something like “$50,000 to $60,000 to clean it.” That cleaning cost could be justifiable, Holcomb said, if spread-over barrels shipped over a lengthy lease commitment.
“If it’s moved in a black oil barge, it’s a little different. We have 112 black oil barges out of our total fleet of 825,” Holcomb told Hart, noting that such costly cleaning procedures would be unnecessary.
Hart noted the EnSys stance that “rail linked in to barge (or tanker) could also play a role in the transport market. Small volumes of WCSB crudes are currently arriving in the Gulf Coast in part via barge.”
Holcomb offered assurance that “Somebody will figure it out before long. If it involves inland tank barges, Kirby will benefit, because it will tighten up the inland barge market. Barge availability will be much less than what it is today, and rates will begin to escalate.”
According to Holcomb, several other black oil barge firms provide similar services. If Hart Energy makes headway on researching those, they will be covered in a future segment of Hart Energy’s Oil’s Changing Landscape special series.

 

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29Mar/11Off

Keeping Up Todate With Global Valves and Controls

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Southcross Energy Agrees To Construct Major Natural Gas Pipeline Extension In South Texas
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March 8, 2011
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Southcross Energy, Dallas, Texas, has reported that the company has entered into a long-term agreement with Swift Energy Company to provide natural gas gathering, transportation and processing services for production from Swift Energy’s acreage in McMullen County, Texas. Southcross will construct a 25-mile, 20-inch natural gas pipeline with related lateral gathering lines and convert an existing dry pipeline system to rich gas service in order to gather the Swift Energy gas for processing.
The McMullen extension will have an initial, expandable capacity of 120 million cubic feet of natural gas per day. The system, which is expected to be in service in mid-2011, will originate in McMullen County, Texas and extend to Southcross’ CCNG Transmission pipeline for gas delivery to and processing at Southcross’ processing plant near Gregory, Texas.
“This pipeline will be an additional extension for Southcross into the Eagle Ford Shale play, an important step in accomplishing our growth strategy. We are delighted to establish this relationship with Swift Energy and provide the important services Swift Energy requires in South Texas,” says David W. Biegler, Southcross Chairman and Chief Executive Officer.
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28Mar/11Off

Flanged Valves and More At GVC

An elevated section of the Alaska Pipeline.
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March 2, 2011
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Endeavour International Corp., Houston, has received approval from the UK’s Department of Energy and Climate Change to go ahead with the Rochelle Field Development Plan (FDP) for Block 15/27 in the Central North Sea, now known as East Rochelle.
The current FDP calls for the subsea gas and condensate development to be linked by a 30 km pipeline to production facilities on the Scott Platform.
First production is planned for the second half of 2012.
Endeavour is operator of East Rochelle and holds a 55.6 per cent working interest in the development. Nexen Petroleum UK Ltd holds the remaining 44.4 per cent interest.
This approval represents phase one of the development of the Greater Rochelle area.
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28Mar/11Off

Global Valve and Controls Always Ahead of the Game

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Pipeline Valves Article

Jeannie Stell - Editor, Pipeline and Gas Technology | March 18, 2011
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The Niobrara oil and gas play is an Upper Cretaceous formation in the Rocky Mountain region. The deep formation underlying northern Colorado, western Nebraska and eastern Wyoming is where the oil rush is taking hold.
Highly productive wells are being tapped in Colorado, just south of the Wyoming line. Horizontal drilling and other newer drilling technologies are being applied to the Niobrara formation, which is geologically similar to North Dakota’s Bakken play.
The self-sourced hydrocarbon system has organic carbon content in the 1% to7% range and is produced at depths of 6,000 to 9,000 feet in the Denver-Julesburg (D-J), North Park and Powder River basins.
Current focus areas are in and around Wattenberg Field in Weld County, Colorado, and in Laramie, Platte and Goshen counties, Wyoming, around Silo Field. Other areas include the southern portion of the Powder River Basin in Campbell, Converse and Natrona counties and North Park Basin in Jackson, Routt and Moffat counties, Colorado.
Today, the play is primarily exploited via horizontal drilling with lateral lengths of 3,500 to 5,000 feet and is fracture stimulated. Well costs run from $3- to $6 million.
Noble Energy (800,000 acres), EOG Resources (400,000 acres), Chesapeake Energy (400,000 acres), East Resources (100,000 acres), Fidelity Exploration and Production (80,000 acres), Petroleum Development (72,000 acres), Voyager Oil & Gas (48,000 acres) and SM Energy (24,000 acres) are some of the major players. Also, Anadarko Petroleum has a large position by way of the Union Pacific Resources Land Grant.
Operators in the area have long produced wet gas and light sweet crude from the D-J Basin. Recent reports suggest the Niobrara could have recoverable resources between 4 billion and 6 billion barrels of oil equivalent.
Oil Take-Away
Several pipelines traverse the Niobrara play, but only one is a major oil system. In Colorado’s D-J Basin, SemGroup Inc.’s much anticipated 526-mile, 12-inch-diameter White Cliffs pipeline now provides about 30,000 barrels of oil take-away from the area into the oil hub at Cushing, Oklahoma.
A year ago, Noble Energy and Anadarko were enthusiastic about hooking up to the system. Both operators subscribed to 10,000 barrels daily.
“There have been times when we had to shut in wells up to a week at a time because the area lacked sufficient refining capacity,” says Anadarko’s facilities engineer Joe Aucoin, from his office at the White Cliffs’ connect near Plattesville. “It’s huge for us.”
At the time, price realizations in the field were expected to improve by as much as $6 per barrel, thanks to cost efficiencies from the new pipeline, according to Anadarko. Field-wide, savings are a potential $65 million per year at the pipeline’s capacity, according to Wood Mackenzie.
White Cliffs will not only provide producers such as Anadarko and Noble Energy with access to more markets and potentially higher prices for their crude, but also nearby oil-polishing facilities see reduced costs that were previously incurred in hot-oiling processes at the individual lease sites.
Other benefits of the pipeline include reduced air emissions from truck traffic, which used to be the transportation mode for take-away from the play, and an onsite centralized truck facility.
The common carrier originates in Platteville, Colorado, northeast of Denver, and terminates at SemCrude’s storage facility in Cushing. It has 100,000 barrels of crude oil storage in Platteville, adjacent to SemCrude’s 10-bay truck-unloading facility with 20,000 barrels of crude oil storage.
White Cliffs is the only line connecting the DJ Basin directly to Cushing. Despite its single-pump stations design, the pipeline is expandable to 50,000 barrels per day. White Cliffs is a major asset for SemGroup, the company that recently emerged from reorganization brought about by its 2009 Chapter 11 bankruptcy.
Operators were also anticipating significant increased take-away capacity for natural gas liquids (NGLs). The DJ Basin Lateral Pipeline, which began operations in March 2009, is a 125-mile NGL line connecting the DJ Basin with the Overland Pass Pipeline.
The 760-mile Overland line can transport 110,000 barrels of NGLs per day. It runs from Opal, Wyoming, to Conway, Kansas.
The pipeline’s capacity is 55,000 barrels per day from existing gas processing facilities in the DJ Basin. Such gas processing facilities include DCP Midstream’s Lucerne and Mewborne plants.
Additionally, DCP’s Platteville and Greeley facilities are connected to Mewborne. Increasing NGL production in the Rocky Mountain region correlates with increasing gas development.
“With the Overland and DJ Lateral in place, take-away constraints are lifting for producers,” says Roz Elliot, director of public affairs for DCP Midstream, Denver.
The new capacity provides a valuable additional outlet for NGLs from the field, agrees Ben MacFarlane, NGLs analyst with Bentek Energy.
Previously, the field’s NGLs had to travel on the Phillips Petroleum line down to Borger, Texas, or be trucked to alternative markets in Kansas.
Gas Take-Away
Most of the other pipelines in the area transport natural gas.
Trailblazer Pipeline Co. LLC owns and operates a 436-mile gas take-away pipeline system that runs from Colorado through southeastern Wyoming to Beatrice, Nebraska. Kinder Morgan Energy Partners owns 100% of Trailblazer.
The pipeline is operated by Natural Gas Pipeline Co. of America, which is operated and partially owned by Kinder Morgan Inc. Trailblazer provides an outlet for Rocky Mountain gas seeking Midwest and East Coast markets. It receives gas from various interconnections and receipt points in Colorado, including Wyoming Inter-Dull Knife and Colorado Inter-Tomahawk.
Some of the largest delivery points for Trailblazer include NGPL-Gage Co and NNG-Beatrice in Nebraska. The top gas transportation customers for Trailblazer are Colorado Interstate Gas Co. and Marathon Oil.
Although the pipeline provides firm transportation and interruptible transportation services, it does not offer storage services.
Colorado Interstate Gas (CIG) pipeline is a 4,200-mile pipeline with a design capacity of about 3.7 billion cubic feet per day. El Paso Pipeline Partners owns the controlling interest (58%) in CIG.
The pipeline delivers gas from production areas in the Rocky Mountains and the Anadarko Basin directly to customers in Colorado and Wyoming and indirectly to the Midwest, Southwest, California and Pacific Northwest. CIG also owns interests in five storage facilities in Colorado and Kansas, which collectively have about 35 billion cubic feet of underground working natural gas storage capacity and one natural gas processing plant in Wyoming.
Also, CIG owns a 50% ownership interest in WYCO Development LLC, or WYCO, a joint venture with an affiliate of Public Service Company of Colorado, and operates WYCO’s High Plains pipeline and Totem Gas Storage facility.
El Paso also owns Wyoming Interstate Co. (WIC), an 800-mile pipeline with a design capacity of some 3.3 billion cubic feet per day. WIC is a mainline system that extends from western Wyoming to northeast Colorado (at the Cheyenne Hub) and several lateral pipeline systems that extend from various interconnections along the WIC mainline into western Colorado and northeast Wyoming and into eastern Utah.
WIC is one of the primary interstate natural gas transportation systems providing take-away capacity from the Overthrust, Piceance, Uinta, Powder River and Green River basins. CIG is the operator of the WIC system via a service agreement with WIC.
Also, El Paso owns 48% of Young Gas Storage Co., a facility with 6 billion cubic feet of capacity in Colorado.
Land Rush
Although the Niobrara play was a sleepy, slowly developed area about nine months ago, the play has drawn the interest of both oil and gas producers. Low gas prices make any U.S. oil play look attractive, and the Niobrara is no slouch.
In July, the Office of State Lands and Investments in Wyoming held a special oil and gas lease auction in response to demand from energy companies looking to acquire leasing rights in the booming eastern region of Wyoming’s share of the Niobrara.
A near-record $42 million of bids came in for the right to drill on state land. High bids reached $3,200 an acre, with the big spender title going to Big Bear Oil & Gas, which purchased 29 leases, including six for $1 million or more. The regularly scheduled state lease auction last May generated a record $45.6 million for Wyoming.
“Those who’ve wanted to be involved in this play have been out there. They’re grabbing up as much acreage as they can,” Harold Kemp, head of state minerals leasing, publicly stated.
The play is geologically similar to North Dakota’s Bakken play. After the rush to lease, ever more producers will begin to drill out their plays and more midstream infrastructure will be needed to move the produced hydrocarbons to market.
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28Mar/11Off

Daily Article – Global Valve and Controls

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Frank Nieto | March 11, 2011
Gulf South Is One Of The Largest Pipeline Systems In U.S.- Mar 25, 2011
Just how significant has the Marcellus shale been in increasing the production of natural gas in the Northeast? That’s the question that the Midstream Monitor decided to answer in our first Spotlight feature.
Using data supplied by Hart Energy’s Mapping & GIS division, Midstream Monitor found that production out of the Marcellus region rose from 62.25 million cubic feet per day (MMcf/d) on January 1, 2008 just before the region became hot to 3.19 Bcf/d on December 31, 2010 after production had taken off in the region.
While there have been dips in these production figures during this two-year period, by and large production has gone from strength-to-strength with production peaking on December 24, 2010 at 3.24 Bcf/d.
It is important to note that these figures do not represent the Marcellus shale alone, only receipt figures from gathering systems in the region. These pipe flows do not necessarily represent actual wellhead production.
“Production out of the Marcellus shale is currently approximately 1.3 Bcf/d and should exit the year by jumping over the 2 Bcf/d hurdle,” Opoku Danquah, director of upstream research for Hart Energy, said.
While gas prices remain weak, the Marcellus shale represents a premium market for producers due to its proximity to lucrative markets in the Northeast. However, this location also presents a problem for producers – namely being able to get these volumes to market.
This has turned out to be a boon for midstream operators, who are in the midst of building up the region with much needed infrastructure. The biggest projects attached to the Marcellus from a midstream perspective are, of course, pipelines with companies such as Williams, Spectra, El Paso, Kinder Morgan and EQT building new pipelines, as well as laterals to existing pipelines.
However, there are also strong opportunities for natural gas processing plants since the states that make up the play are among the lowest in terms of processing capacity. Because of this processing shortage in West Virginia and Pennsylvania, we’ve already seen several plants in each state brought online or announced so far this year.
In January, Caiman Energy brought the 120 MMcf/d Ft. Beeler cryogenic plant online in Cameron, West Virginia and that same month MarkWest Liberty Midstream & Resources announced it will build its third natural gas processing plant in the play when it constructs a 120 MMcf/d cryogenic plant in Logansport, W. Va., by mid-2012. This will be MarkWest Liberty’s third plant in the play. – Frank Nieto
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27Mar/11Off

Making Use of Steel Ball Valves

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Making Use of Steel Ball Valves

When it comes to infrastructure, we can really name a lot of companies which are getting into it and one of the most in demand services anywhere today is plumbing. Without plumbing, people would always have a ruin day due to an inadequacy of water. More than that, when we are also going to talk about plumbing, we also need to consider the things that they mostly use and one of which are those valves that are useful in order to make a job successful. If you are among the plumbers, you will surely look for the most durable and top-quality kind of valve, and in such case, the use of steel ball valves should be taken account.

There are now plenty of manufacturing companies who had study hard in order to make the best valve to use in any sorts of plumbing activity and good thing was, Global Valve and Controls had able to establish the perfect valve to be used in any sorts of plumbing constructions. Steel ball valves are among their recent valves being made which has been establish through the finest technological method and had able to pass various evaluations from experts as well. With these steel ball valves, you can really have the guarantee that this would last long despite the fact that it is being use constantly.

Global Valve and Controls had undergone careful study in order to perfectly design the right valves to be use in all sorts of plumbing construction. GVC’s have their own technical support team who see to it that all steel ball valves are of top quality and will even provide you with best function. You can now start buying these steel ball valves since these are now available in all markets in your place.

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18Mar/11Off

Extracting Fossil Fuels For Energy And Electricity

Everyone knows that Americans rely heavily on fossil fuels. Much of our electricity is generated by the burning of coal. Furthermore, you probably cook your dinner on a natural gas range, and you pump gasoline into your car's fuel tank every couple days. What you might not know are some of the different ways these raw materials are extracted from the Earth.

Before you can extract the fossil fuel, of course, you need to figure out where it is. Finding petroleum and natural gas is still an evolving science. Most of the "easy-to-find" oil and gas deposits are already being extracted, so geologists are always on the look for new ones. For example, scientists find off-shore petroleum deposits by bouncing sound waves off of the bottom of the ocean to get an image of the density of the rock, letting them know where to drill.

Here are some of the ways fossil fuels are extracted so they can be used to keep your lights on and heat your burgers at summertime picnics.

Petroleum (Oil)
You've undoubtedly seen the old-fashioned movies and TV shows where a lucky oil man pokes a stick in the ground and a big oil gusher sprays into the air. This doesn't happen often, but when it does, it's a problem. Gushers are not only environmentally dangerous, but they waste the oil that drilling companies are trying to extract. Instead, oil drillers use a network of pipes and valves to regulate the pressure of a new well as much as possible.

When people think "oil drilling," they often think about derricks bobbing up and down on the hot terrain. These kinds of pumps are used to extract petroleum from smaller reservoirs under little pressure. For big, valuable oil fields, companies must use a faster, more thorough way of pulling out the thick liquid. By pumping water or gas into an oil field, the petroleum will be displaced, rising to the surface. When the pressure is high enough on the underground petroleum, it will be channeled into a pipeline and sent on its way to a refinery. Gas and water injection drilling techniques allow oil companies to get as much petroleum as possible from a well; every barrel left under the surface is a wasted opportunity.

Land-based oil drills are only part of the story. Many drilling stations are located off-shore, either floating or anchored to the bottom of the ocean. The people who work on these platforms have a difficult job. Not only must they monitor the complicated machinery that pumps petroleum into barges, but they must contend with the elements. Underwater currents are powerful enough to compromise even the strongest drilling equipment and severe storms pose a huge threat to the hard-working men and women on the ocean's surface.

Natural Gas
Natural gas deposits can sometimes be found layered on top of petroleum deposits. This makes sense because the two fuels are sometimes formed together. The natural gas is captured by drilling holes and inserting pipes into known deposits. After being transported, the gas is fed into municipal and industrial distribution systems.

As natural gas sometimes accompanies petroleum, oil drillers sometimes get rid of unwanted gas with a technique called "flaring." The excess gas is actually burned just to get it out of the way. While this isn't the world's biggest energy-related problem, it's somewhat surprising that approximately 5.3 trillion cubic feet of natural gas are wasted in this manner every year. (When natural gas is burned, of course, carbon dioxide is released into the air.) Thankfully, flaring is used less frequently in the United States than in many other countries.

Coal
There are two ways to remove coal from the earth: surface mining and underground mining. Surface mining techniques are employed when the coal is buried less than 20 feet below the surface. As the cheaper alternative, surface mining is more desirable. Earth-moving machines remove the topsoil and all of the other rock covering the coal. Once exposed, those same machines break up the coal seam and remove the pieces. Once all of the coal is gone, the land can be converted for other uses such as a park, farmland or just about anything else.

Underground mining is a little bit more complicated. When the coal is buried much further below the surface (between 200 and 1,000 feet), miners dig several shafts into the ground. Some of the shafts hold elevators the miners use to get to the coal, while others serve as vents to make sure the miners have breathable air. Once lowered into the shaft, miners use hand and power tools to break the coal seam into manageable pieces that are then carried to the surface on tracks. While underground mining has its risks, the United States Government maintains safety standards that protect miners while ensuring the country has the coal it needs.

Although it's not easy to bring coal, natural gas and petroleum to the surface, it's definitely a necessity. Fortunately for us, technology has risen to the task, ensuring that we have the energy that powers our civilization.


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18Mar/11Off

Extracting Fossil Fuels For Energy And Electricity In Ny

Everyone knows that Americans rely heavily on fossil fuels. Much of our electricity is generated by the burning of coal. Furthermore, you probably cook your dinner on a natural gas range, and you pump gasoline into your car's fuel tank every couple days. What you might not know are some of the different ways these raw materials are extracted from the Earth.

Before you can extract the fossil fuel, of course, you need to figure out where it is. Finding petroleum and natural gas is still an evolving science. Most of the "easy-to-find" oil and gas deposits are already being extracted, so geologists are always on the look for new ones. For example, scientists find off-shore petroleum deposits by bouncing sound waves off of the bottom of the ocean to get an image of the density of the rock, letting them know where to drill.

Here are some of the ways fossil fuels are extracted so they can be used to keep your lights on and heat your burgers at summertime picnics.

Petroleum (Oil)

You've undoubtedly seen the old-fashioned movies and TV shows where a lucky oil man pokes a stick in the ground and a big oil gusher sprays into the air. This doesn't happen often, but when it does, it's a problem. Gushers are not only environmentally dangerous, but they waste the oil that drilling companies are trying to extract. Instead, oil drillers use a network of pipes and valves to regulate the pressure of a new well as much as possible.

When people think "oil drilling," they often think about derricks bobbing up and down on the hot terrain. These kinds of pumps are used to extract petroleum from smaller reservoirs under little pressure. For big, valuable oil fields, companies must use a faster, more thorough way of pulling out the thick liquid. By pumping water or gas into an oil field, the petroleum will be displaced, rising to the surface. When the pressure is high enough on the underground petroleum, it will be channeled into a pipeline and sent on its way to a refinery. Gas and water injection drilling techniques allow oil companies to get as much petroleum as possible from a well; every barrel left under the surface is a wasted opportunity.

Land-based oil drills are only part of the story. Many drilling stations are located off-shore, either floating or anchored to the bottom of the ocean. The people who work on these platforms have a difficult job. Not only must they monitor the complicated machinery that pumps petroleum into barges, but they must contend with the elements. Underwater currents are powerful enough to compromise even the strongest drilling equipment and severe storms pose a huge threat to the hard-working men and women on the ocean's surface.

Natural Gas

Natural gas deposits can sometimes be found layered on top of petroleum deposits. This makes sense because the two fuels are sometimes formed together. The natural gas is captured by drilling holes and inserting pipes into known deposits. After being transported, the gas is fed into municipal and industrial distribution systems.

As natural gas sometimes accompanies petroleum, oil drillers sometimes get rid of unwanted gas with a technique called "flaring." The excess gas is actually burned just to get it out of the way. While this isn't the world's biggest energy-related problem, it's somewhat surprising that approximately 5.3 trillion cubic feet of natural gas are wasted in this manner every year. (When natural gas is burned, of course, carbon dioxide is released into the air.) Thankfully, flaring is used less frequently in the United States than in many other countries.

Coal

There are two ways to remove coal from the earth: surface mining and underground mining. Surface mining techniques are employed when the coal is buried less than 20 feet below the surface. As the cheaper alternative, surface mining is more desirable. Earth-moving machines remove the topsoil and all of the other rock covering the coal. Once exposed, those same machines break up the coal seam and remove the pieces. Once all of the coal is gone, the land can be converted for other uses such as a park, farmland or just about anything else.

Underground mining is a little bit more complicated. When the coal is buried much further below the surface (between 200 and 1,000 feet), miners dig several shafts into the ground. Some of the shafts hold elevators the miners use to get to the coal, while others serve as vents to make sure the miners have breathable air. Once lowered into the shaft, miners use hand and power tools to break the coal seam into manageable pieces that are then carried to the surface on tracks. While underground mining has its risks, the United States Government maintains safety standards that protect miners while ensuring the country has the coal it needs.

Although it's not easy to bring coal, natural gas and petroleum to the surface, it's definitely a necessity. Fortunately for us, technology has risen to the task, ensuring that we have the energy that powers our civilization.


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18Mar/11Off

Discharge Valve

Discharge valves are devices that make it possible to monitor and control the flow of a substance from a source and through some type of circulation system. The idea behind the discharge valve is that it provides the ability to adjust that flow in order to respond to situations that require a change in the volume or speed of that flow. A discharge control valve is included in a number of different systems that process liquids and gases, and may even be utilized as a safety measure in some electrical systems.

A basic discharge valve serves to regulate the flow of a substance, making it possible to increase or decrease that flow so that the desired outcome is achieved. For example, this type of valve may be included in the design of a dam, making it possible to control the flow of water so that the water pressure within the dam is maintained within a safe limit. Doing so helps to preserve the integrity of the dam, since water is periodically released through the discharge relief valve, and allowed to flow into nearby bodies of water. Not only does the valve protect the dam, it also helps to ensure that water levels within those bodies of water are maintained at respectable levels.

The same general approach is used in systems that convey natural gas through a utility system. At various junctions in the pipeline that is used to deliver the natural gas to consumers, discharge valves are strategically placed as safety devices. In the event that there is some type of breach or failure at any point in the system, the valves are closed while repairs are made. This prevents an excessive amount of gas building up at any point in the system and increasing the chances of additional failures.

The discharge valve is also used in manufacturing settings, often as a means of routing air or water through machinery used to produce goods. With the aid of valves that are incorporated along the system, it is possible to control the flow of air so that the machinery is able to function at optimum efficiency. Most fire extinguishing systems within buildings make use of the valves to control the flow of water in the event that a fire does break out. Sensors trigger the valves to open, releasing water into the area, and then trigger the valves to close once the temperature within the space decreases, as the flames are subdued.

Depending on the type of application, a discharge valve may be manually operated or triggered by sensors or some type of computer equipment. It is not unusual today for a hybrid design to be used, allowing for both manual and automated opening and closing of the valve in response to some type of computer program. As with most types of equipment, a discharge valve must be inspected and maintained in order for the device to remain fully functional and efficient over a number of years.


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