Special Report: Worldwide Gas Processing: Production growth has global gas processing set for expansion

June 6, 2011
Plans and proposals for new gas processing plants for much of North America’s newly minted gas production regions—that is, its shale gas areas—failed as of Jan. 1 to bump 2010 gas plant data much higher, as reflected in Oil & Gas Journal’s latest plant-by-plant survey of global gas processing.

Warren R. True
Chief Technology Editor—LNG/Gas Processing

Plans and proposals for new gas processing plants for much of North America’s newly minted gas production regions—that is, its shale gas areas—failed as of Jan. 1 to bump 2010 gas plant data much higher, as reflected in Oil & Gas Journal’s latest plant-by-plant survey of global gas processing.

While global gas processing capacity last year grew by only about 1.3 bcfd, much of that was in the US. Canada’s gas processing capacity for the year was again flat, in line with no growth evident for 2009 and consistent with its slightly declining natural gas production in 2010.

Overall, global natural gas production in 2010, however, raced ahead over production in 2009 (OGJ, Mar. 14, 2011, p. 33). The US, which last year produced more than 20% of global 2010 gas, increased production over 2009. And, despite Canada, Western Hemisphere countries overall increased natural gas production by more than 2%.

But the global leaders in increasing natural gas production in 2010 were the countries of the Middle East, Eastern Europe and the former Soviet Union, and Asia-Pacific.

Gas processing capacity in the US moved ahead by only 1.5%; Canada’s growth as stated was flat for the third year running (Table 1). For the entire world, OGJ’s data show that global capacity grew by a mere 0.5% in 2010.

Continuing a trend begun in 2005, natural gas processing capacity outside the US and Canada outgrew combined capacities in the world’s two largest gas processing countries. For 2010, processing capacities of the two North American nations held at less than 49% of world capacity, a slight erosion of their share for 2009.

OGJ expects that, when several shale-related gas plants in the US come on stream over 2011-14 and beyond, the portion of global capacity held by the two gas processing giants will surge. But natural gas production, especially in the Middle East and Asia-Pacific, will likely continue its strong growth over those years and beyond, requiring even more processing capacity there.

Highlights

OGJ data for 2010 show again nearly flat growth for NGL production in both Canada and the US, as NGL output from the two countries’ gas plants continued a trend evident for several years, bucked only in 2007. NGL production, especially in the Lower 48 should grow sharply, however, in 2011-14 as several gas plants under construction to process wetter shale-gas come on line. (An accompanying article on p. 98 analyzes the major NGL-producing shale-gas plays in the Lower 48.)

Total NGL production for both North American countries declined slightly in 2010, down to 108.35 million gpd from 108.5 million gpd in 2009, holding 37% of global NGL production for each year, the same as for 2008. For 2007, the countries’ combined production was 130.4 million gpd, or more than 44% of global NGL production. For 2006, the figure was 38.7% of world totals; for 2005, slightly more than 33%.

On Jan. 1, 2011, OGJ data show that US gas processing capacity stood at nearly 74.9 bcfd, up from more than 73.7 bcfd for 2009 and more than 72 bcfd for 2008.

Throughput in 2010 moved slightly ahead of the figure for 2009, averaging a bit more than 45.8 bcfd (a little more than 61% utilization). NGL production averaged nearly 76.3 million gpd, essentially flat compared with 2009 and ahead of about 75.7 million gpd for 2008 (Table 1; Fig. 1).

On Jan. 1, 2011, gas processing capacity outside Canada and the US stood about where it was when 2010 began: a bit more than 133 bcfd. Throughput outside Canada and the US for 2010 averaged about 80.4 bcfd, nearly identical with 2009 and flat compared with 2008, up from 77.8 bcfd in 2007 and 80 bcfd in 2006.

NGL production in 2010 outside the US and Canada averaged about 152 million gpd, down from 182 million gpd in 2009, which was nearly unchanged compared with 2008, and compared with 163 million gpd in 2007 and 170 million gpd in 2006.

Fig. 2 shows pricing differentials in the US between LPG—the most widely traded NGL on the world market—and crude oil for the first trading day of each month in 2010. Crude oil prices in 2010 continued to march higher.

Sources

Oil & Gas Journal’s exclusive, plant-by-plant, worldwide gas processing survey and its international survey of petroleum-derived sulfur recovery provide industry activity figures.

Canadian data are based on information from Alberta’s Energy and Utilities Board that reflect actual figures for gas that moved through the province’s plants and are reported monthly to the EUB. For 2000 for the first time, OGJ took these data for all of Alberta and compiled annual figures and thereby created a new baseline for data comparisons thenceforth.

(Effective Jan. 1, 2008, the province realigned the EUB into two separate regulatory bodies: the Energy Resources Conservation Board to regulate the oil and gas industry upstream of utilities and the Alberta Utilities Commission to regulate utilities.)

In addition to EUB figures for Alberta and to operators’ responses to its annual survey, OGJ has supplemented its Canadian data with information from the British Columbia Ministry of Energy, Mines and Petroleum Resources and the Saskatchewan Ministry of Energy & Resources.

Activity

In Canada last year, Keyera Facilities Income Fund began expanding its gas processing capability in west central Alberta. The company invested about $65 million (Can.) for ownership interests in two more gas plants and increased ownership in four other plants.

At midyear 2010, Keyera owned parts of 17 gas plants and had increased its net gas processing capacity by 9%, or 151 MMcfd. All of the incremental capacity is able to extract NGLs and handle sour gas.

Keyera gained a 57% interest in the 100-MMcfd Minnehik Buck Lake gas plant and a 20% interest in the 375-MMcfd Edson gas plant. Both plants can process sweet and sour gas and extract NGLs.

It bought an additional 7% ownership interest in the Keyera West Pembina gas plant, bringing its ownership there to 76%. Keyera also added a 7% ownership in the Nordegg River gas plant, increasing ownership to 89%; a 1.7% ownership in various components of the Gilby gas plant, bringing ownership to 79%; and a 1% ownership in the Brazeau River gas plant, bringing ownership to 92%.

Late in 2010, AltaGas Ltd. said it would begin building a 120-MMcfd gas plant and associated gas gathering in the Gordondale area of the Montney shale play, about 100 km northwest of Grande Prairie, Alta. The plant will be equipped to extract liquids.

The Gordondale plant and gathering system will cost about $235 million (Can.) and likely come on stream in late 2012.

About the same time, AltaGas reported it had received regulatory approval from Alberta’s ERCB for its Harmattan gas processing project. The company expected the project to start contributing to operating income in early 2012.

The Harmattan plant would process 250 MMcfd of rich, sweet natural gas to recover ethane and NGLs, using existing spare capacity.

In March 2011, Williams Cos., Tulsa, signed a long-term agreement to produce as much as 17,000 b/d of ethane and ethylene for NOVA Chemicals Corp. Williams will invest $311 million (Can.) to expand its two main Alberta plants, which will begin operating in first-quarter 2013. This will permit production of ethane and ethylene from Williams’s operations that process offgas from Alberta oil sands operations.

The company is modifying its oil sands offgas extraction plant near Fort McMurray and building a de-ethanizer at its Redwater NGL-olefins fractionation plant near Edmonton. Upgrades at Fort McMurray will add ethane and ethylene into the NGL-olefins mix being extracted from the offgas and sent to Redwater for fractionation.

The new de-ethanizer at Redwater will initially permit production of about 10,000 b/d of an ethane-ethylene mix, which will add to current production of about 14,000 b/d of an NGL-olefins mix.

And very recently, Fairborne Energy Ltd. announced construction of the Marlboro gas plant, designed to handle Fairborne’s growing Wilrich production, had been completed and was entering commissioning with start-up under way.

The 40-MMcfd Marlboro gas plant handles sweet gas and includes NGL and a sales line that delivers gas to TransCanada PipeLines Ltd.’s meter station at Nose Hill.

Shortly after the announcement of the plant’s completion, Fairborne announced it would sell 40% working interest in the Marlboro plant to an unnamed third-party midstream company. Fairborne will retain a 42% working interest in the plant and operatorship.

US

In March Energy Transfer Partners LP and Regency Energy Partners LP announced that Lone Star NGL LLC, the joint venture that acquired the midstream assets of Louis Dreyfus Highbridge Energy (OGJ Mar. 28, 2011, p. 9), will build a 100,000-b/d NGL fractionator at Mont Belvieu. ETP will use much of this capacity to handle NGLs it will deliver from its Jackson County, Tex., processing plant, which is supported by contracts with producers as a part of ETP’s Eagle Ford shale projects.

Lone Star expects to have the fractionation completed by first-quarter 2013 at an estimated cost of $350-375 million. As part of the project, Lone Star will develop additional storage for Y-grade liquids and other components. The project will also include interconnectivity infrastructure to provide NGL suppliers and NGL markets with access to storage, other fractionators, pipelines, and multiple markets along the Texas and Louisiana Gulf Coast.

Also in March, Rex Energy Corp. announced it will increase capacity at a second cryogenic plant planned for Butler County, Pa., to 50 MMcfd from 40 MMcfd. The Blue Stone plant will come on stream by early 2012.

Stonehenge Energy Resources LP has a 60% interest in Keystone Midstream Services LLC; Rex a 28% interest; and Sumitomo 12%. The existing Keystone Midstream cryogenic plant in Butler County, known as Sarsen, currently processes 40 MMcfd.

In the Rockies in mid-2010, Williams Partners LP announced plans to expand cryogenic processing capacity in the Piceance basin. It is building a 450-MMcfd gas plant at Williams’s Parachute, Colo., complex, capable of recovering up to 25,000 b/d of NGLs. It will be in service in 2013 to process Williams’s gas production in the Piceance that exceeds capacity at Williams Partners’ Willow Creek plant.

Also last year, Williams Partners increased ownership in Overland Pass Pipeline Co. LLC to 50%. Oneok Partners LP, Tulsa, owns the rest. Overland Pass pipeline includes a 760-mile NGL pipeline from Opal, Wyo., to Conway, Kan., along with 150 and 125-mile extensions into the Piceance and Denver-Joules basins in Colorado.

In August 2010, Anadarko Petroleum Corp. announced it was selling a major Colorado natural gas pipeline system to affiliate Western Gas Partners LP, Houston, for $498 million. The sale includes the 105-MMcfd gas plant in Fort Lupton and contracts held by Anadarko to process gas for producers.

The Wattenberg system in northeastern Colorado includes 1,734 miles of pipelines that move about 275 MMcfd of natural gas from wellheads to processing.

Also in August last year, Targa Resources Partners LP, Houston, agreed to acquire Targa Resources Inc.’s 63% interest in Versado Gas Processors, LLC, a joint venture owned by Targa Resources and Chevron USA Inc. (37%). The natural gas gathering and processing are in West Texas and New Mexico. Total value of the transaction was about $230 million.

In March this year, Anadarko agreed to pay BP PLC $575.5 million to achieve sole ownership of the Wattenberg processing plant. Anadarko, which had owned 7% of the Wattenberg plant, is buying BP’s 93%. The plant can process about 195 MMcfd and produce 15,000 b/d of gas liquids and condensate.

Shale gas

Many gas plant and related developments in the past year have been in response to a virtual storm of activity in US shale gas plays, especially if not primarily where abundant hydrocarbon liquids were produced along with the much-less valuable methane.

Just how big is the resource was made clear in a report earlier this year from the Potential Gas Committee, which said the US now has an undiscovered gas resource potential of 1,898 tcf—the highest level in the 46-year history of the committee’s work, it said (OGJ Online, Apr. 28, 2011). The 2010 biennial assessment is 61 tcf higher than the previous record yearend 2008 figure.

When the PGC’s results are combined with the US Department of Energy’s latest available determination of dry gas proved reserves, which were 273 tcf at the end of 2009, the US has a total available future supply of 2,170 tcf, or 89 tcf more than the previous evaluation.

The PGC’s end-2010 assessment of 1,898 tcf includes 1,739 tcf of gas attributable to “traditional” reservoirs (conventional, tight sands and carbonates, and shales) and 159 tcf in coalbed reservoirs.

The 1,898 tcf assessment included 687 tcf of shale gas, up from 616 tcf of shale gas at the end of 2008, PGC said.

Eagle Ford

In November 2010, DCP Midstream LLC, Denver, was looking for expressions of interest for the proposed DCP Sandhills Pipeline, an NGL line to run more than 700 miles from West Texas to fractionation and storage along the Texas Gulf Coast, including Mont Belvieu, to open new capacity for NGLs produced from the Avalon shale in West Texas and the Eagle Ford in South Texas.

The pipeline, estimated to be operating in 2013, will have a target capacity of 130,000 b/d, although the company said the project was not restricted to this capacity and was “scalable to meet customer needs.”

Late last year, Enterprise Products Partners LP, Houston, entered into 10-year agreements to handle much of Chesapeake Energy Corp.’s liquids-rich gas production in the Eagle Ford.

Chesapeake’s rich gas will initially be gathered and compressed by affiliate Chesapeake Midstream Development LLC for delivery to a central location. Enterprise will then transport and process the rich gas at its existing facilities, while a previously announced natural gas processing plant under development in Texas is completed. This cryogenic processing plant, expected to come on line early next year, will have an initial inlet capacity of 600 MMcfd and be able to extract as much as 75,000 b/d of NGLs.

NGL production from Chesapeake’s gas will ultimately move on Enterprise’s previously announced 127-mile NGL pipeline that will extend from the new gas plant to Enterprise’s NGL fractionation at Mont Belvieu, Tex. This new NGL pipeline, also set for completion in early 2012, will have initial capacity of more than 85,000 b/d and be expandable to more than 120,000 b/d.

In January of this year, Copano Energy LLC executed agreements to increase its capacity to handle NGLs associated with growing gas volumes from Eagle Ford.

Copano’s long-term fractionation and product sales agreements were with Formosa Hydrocarbons Co. Inc. to facilitate deliveries of mixed NGLs to Formosa. Earlier, Copano had formed a 50/50 joint venture with a subsidiary of Energy Transfer Partners to construct, own, and operate the 12-in. Liberty NGL pipeline extending about 83 miles from Copano’s Houston Central plant in Colorado County, Tex., first to Formosa’s leased NGL product storage in Matagorda County and then to Formosa’s petrochemical plant in Calhoun County.

The agreement provided Copano with up to 37,500 b/d of firm fractionation services beginning in first-quarter 2013 for 15 years. Liberty pipeline will have initial capacity of 75,000 b/d, which is committed to Copano and Energy Transfer (50% each) under firm throughput agreements. Copano and Energy Transfer have invested about $52 million for the pipeline and related facilities.

R. Bruce Northcutt, president and CEO of Copano Energy, said at the time the Formosa agreement and Liberty Pipeline, along with other projects, will increase Copano’s total NGL handling capability to more than 80,000 b/d.

Also in January of this year, DCP Midstream signed a long-term gathering and processing agreement with a joint-venture operating in the Eagle Ford. The joint venture consists of Pioneer Natural Resources USA Inc., Reliance Eagle-ford Upstream Holding LP, and Newpek LLC.

The agreement covers gathering, processing, fractionation, and marketing of raw NGLs by DCP Midstream for the Pioneer JV’s production from more than 300,000 gross acres.

DCP Midstream will build about 130 miles of 16, 20, and 24-in. gathering lines to connect the Pioneer JV companies to DCP Midstream’s existing area gathering and processing. In its announcement, DCP Midstream said it has excess processing capacity of 250 MMcfd available in the area.

In addition, the company announced plans to build a sixth plant (Eagle gas plant) of 200 MMcfd capacity and related NGL infrastructure, which it expects to bring on line in third-quarter 2012. These plans will increase DCP Midstream’s total capacity in the area to 1 bcfd.

The agreement follows DCP Midstream’s earlier announcement of the Trunkline Gas pipeline transaction, in which DCP Midstream will be the anchor shipper on Trunkline Gas’s 20-in. South Texas pipeline. This step will integrate DCP Midstream’s South and Central Texas area gathering systems with Trunkline Gas’s 165-mile South Texas system, said the announcement.

The enlarged system will connect DCP Midstream’s five existing processing plants with the new Eagle gas plant to create a system with more than 1 bcfd of processing and associated fractionation capacities.

DCP Midstream, which operates in 18 states, is an equally owned joint venture between Spectra Energy and ConocoPhillips. The company owns the general partner of DCP Midstream Partners LP, a master limited partnership.

In February of this year, Anadarko E&P Co. LP, a subsidiary of Anadarko Petroleum, agreed to terms with Eagle Ford Gathering LLC for natural gas transportation, processing, and fractionation.

Eagle Ford Gathering is a joint venture between Kinder Morgan Energy Partners LP and Copano Energy. Eagle Ford Gathering said its 30-in. pipeline in the Eagle Ford shale will be operating by third-quarter. The joint venture also plans to build another 74 miles of gas pipeline by yearend.

In March this year, Enterprise Products Partners said it would start several new infrastructure projects in Texas to deal with growing volumes at gas operations in shale there. It will lay 350 miles of pipelines, build a new gas processing plant, and add a fractionator.

Enterprise also reported it had finished other previously announced projects that will allow it soon to fill the current combined 1.5-bcfd capacity at its seven South Texas natural-gas-processing plants. And it reported progress in expanding its crude-oil pipeline system into the Eagle Ford, which is to be completed in fourth-quarter 2011.

Also in March, Anadarko Petroleum and Enterprise signed a 6-year agreement under which Enterprise will supply Anadarko midstream services in the Eagle Ford. Enterprise will provide gas processing, as well as NGL fractionation and transportation for Anadarko’s NGL-rich gas production from the shale play.

Enterprise will build a 46.5-mile, 24-in. OD pipeline through LaSalle County, Tex., to expand its rich-gas gathering system. Completion of a new cryogenic processing plant in Lavaca County by mid-2012 will add 600 MMcfd of incremental capacity to Enterprise’s system.

In April, SM Energy Co. completed service agreements with Energy Transfer Partners’s Texas unit to transport and process gas produced in the Eagle Ford shale. ETC Texas Pipeline will move up to 240 MMcfd over 10 years, starting in 2013.

Also in April, Copano Energy announced plans to expand processing at its Houston Central plant to meet expected greater producer demand in the Eagle Ford. The company said it will spend $145 million on expanding the Colorado County, Tex., plant.

Expansion will add a 400-MMcfd cryogenic processing plant to be in service by early 2013 and bringing total processing capacity to 1.1 bcfd.

Barnett; East Texas

Elsewhere in Texas but still in developments related to the burgeoning shale plays there, Crosstex Energy in March completed expansions on its gas gathering system in the Barnett shale in North Texas. The company expanded its gas gathering in North Texas with a 15-mile pipeline extension as one of the two expansion projects. The extension includes a 7-mile, low-pressure line, an 8-mile, high-pressure line, and a compressor station in southwest Tarrant County. In 2012, the system will carry peak capacity of more than 100 MMcfd.

Crosstex also signed a 10-year firm gathering and compression agreement with an un-named Barnett shale producer for an additional 50 MMcfd of gas on the North Texas gathering system and built a compressor station on an existing gathering line to accommodate the extra transportation needs.

Crosstex reactivated its Eunice NGL fractionator in Louisiana to handle 15,000 b/d of NGLs. The start-up and expansion will increase Crosstex’s fractionation capacity to 55,000 b/d from 40,000 b/d.

In July last year, Tristream Energy LLC bought East Texas gathering and processing from a subsidiary of Regency Energy Partners LP, Dallas. Included were gas treating and processing in Eustace, Tex., a condensate sweetening plant in Myrtle Springs, and about 371 miles of gathering pipeline.

The Eustace plant consists of s Sulfinol treating unit with a rated capacity of 70 MMcfd, an 800-long ton/day sulfur-recovery unit, a Scot tail-gas treating unit, a 35-MMcfd nitrogen-rejection unit, a cryogenic NGL-recovery plant, an 1,800 b/d condensate-stabilization unit, and a sulfur railcar loading terminal.

The Myrtle Springs plant is a 3,000-b/d condensate treating and stabilization facility, which includes a Merichem treating unit capable of removing H2S and mercaptans.

In December last year, a unit of Tulsa-based Unit Corp. started up the new Lone Tree natural gas processing plant in Hemphill County, Tex., to process up to 50 MMcfd. Plant residue gas is delivered into the Oneok Westex and Southern Star pipeline systems; NGLs from the Hemphill inlet stream are delivered into Oneok Hydrocarbon LP.

Among the most active companies in Oklahoma and Texas is Oneok Partners LP, Tulsa.

Early last month Oneok announced plans to invest between $910 million and $1.2 billion through late 2013 to:

• Construct the $610-810 million Sterling III pipeline, a new 570-plus-mile, 16-in. OD NGL line to move initially as much as 193,000 b/d of unfractionated NGLs or NGL purity products from near Medford, Okla., to storage and fractionation on the Texas Gulf Coast at Mont Belvieu. Once complete, it will double the partnership’s current pipeline capacity between the two points.

• Reconfigure the existing Sterling I and II NGL distribution pipelines, which currently distribute NGL purity products between the Midcontinent and Gulf Coast NGL market centers, to move unfractionated NGLs or NGL purity products.

• Build a new 75,000-b/d NGL fractionator (MB-2) at Mont Belvieu at an estimated cost of $300-390 million (OGJ Online, May 3, 2011). The new unit will supplement the partnership’s 80% owned, 160,000-b/d MB-1 fractionator at Mont Belvieu.

The Sterling III Pipeline will complement the Sterling I and II pipelines, said the company announcement, and when in operation all three will be able to transport unfractionated NGLs or purity NGL products.

Construction is to begin in early 2013, following receipt of permits and acquisition of right of way; the company anticipates a portion of the existing right of way on the Sterling I and II pipelines can be used. Completion is scheduled in late 2013. With additional pump stations, the Sterling III Pipeline’s capacity can be expanded to 250,000 b/d.

Bakken; Marcellus

The North Dakota-Bakken oil shale has also seen a flurry of activity and plans based on the liquids the area contains.

In September last year, Amerada Hess Corp. received approvals to begin a $500-million expansion of its Tioga natural gas processing plant in Williams County in northwestern North Dakota.

The plant, first built in the 1950s, can process 120 MMcfd of natural gas daily and will be expanded to handle 250 MMcfd to help meet demand for processing increased natural gas production from western North Dakota’s oil fields. The expansion will permit ethane recovery, said the company.

Construction is to begin next month and be completed in mid-2013.

Late last year, Bear Paw Energy LLC, a unit of Oneok Partners, received permission to build a $175 million, 100-MMcfd gas plant about 8 miles northeast of Watford City, ND, named the Garden Creek gas plant.

It will process gas produced from the Bakken in eastern McKenzie and southwestern Mountrail counties and be able to recover some 25,000 b/d of NGLs. Completion is to be later this year with full operations beginning next year.

Oneok also is moving on construction of three new natural gas processing plants, with a combined capacity of 300 MMcfd, and related infrastructure in the Bakken shale in the Williston basin.

And it is building a 525 to 615-mile NGL pipeline, the Bakken Pipeline, to transport unfractionated NGLs produced from the shale in the Williston to the Overland Pass Pipeline, a 760-mile NGL pipeline extending from southwestern Wyoming to Conway, Kan.

The company is also expanding its fractionation capacity at Bushton, Kan., by 60,000 b/d to accommodate additional NGL volumes from Overland Pass Pipeline.

In January, in the Eastern US in the Marcellus shale, Caiman Energy LLC completed Fort Beeler Processing Plant I, a cryogenic plant near Cameron, W.Va. In connection with bringing on line the plant’s 120-MMcfd capacity, Caiman also announced a long-term agreement with Chesapeake Energy to process rich gas Chesapeake produces in Marshall and Wetzel counties, W.Va.

At the same time, Caiman said that drilling projections from existing and potential customers had prompted it to launch construction of a second cryogenic processing plant. The 200-MMcfd Fort Beeler Processing Plant II will be completed by yearend to bring the company’s gas processing capacity at Fort Beeler to 320 MMcfd.

Caiman is also exploring construction of yet a third cryogenic plant, it said, with capacity of 200 MMcfd. Caiman has more than 60 miles of high pressure, large-diameter pipeline in service in the Marcellus and an additional 60 miles of gas gathering lines under construction.

In January of this year, EQT Corp. and MarkWest Energy Partners LP announced that MarkWest was buying EQT’s gas processing complex in Langley, Ky., and an associated NGL pipeline for $230 million.

The Langley processing complex includes a 100-MMcfd cryogenic processing plant, a 75-MMcfd refrigeration processing plant, and about 28,000 hp of compression.

When the transaction was to close earlier this year, MarkWest was to begin building a new 60-MMcfd cryogenic plant to expand the Langley plant.

MarkWest will also complete the Ranger NGL pipeline to allow NGLs recovered at Langley to flow to MarkWest’s Siloam fractionation, storage, and marketing in South Shore, Ky.

In 2008, MarkWest expanded the Siloam fractionator to 24,000 b/d, in part to support the continued growth of EQT’s Huron and Berea shale development in Kentucky and West Virginia. MarkWest will also process EQT’s liquids-rich Marcellus gas in West Virginia.

To moves liquids out of the Marcellus production area, MarkWest Liberty Midstream & Resources LLC and Sunoco Logistics LP in March of this year announced the Mariner West project, designed to deliver Marcellus shale-produced ethane to Sarnia, Ont.

MarkWest Liberty is a partnership between Denver-based MarkWest and private equity firm the Energy & Minerals Group, Houston.

Mariner West will use new and existing pipelines and have a maximum capacity of 65,000 b/d by third-quarter 2012.

MarkWest will build the project’s new pipeline to connect the midstream company’s fractionation south of Pittsburgh to an existing Sunoco Logistics’ pipeline that carries refined products and some LPG.

Elsewhere

Thought of mainly as an oil producing state, Saudi Arabia has begun a major push into natural gas production, especially in the Arabian Gulf, with consequences for its gas processing infrastructure. Two developments will add 4.3 bcfd of gas to a production target by 2014, according to comments made last month at the Offshore Technology Conference in Houston (OGJ, May 9, 2011, p. 22).

Karan will be the first nonassociated offshore gas development in Saudi Aramco’s history. When completed in 2013, the development will be able to deliver 1.8 bcfd of raw gas thorugh a 110-km subsea pipeline to the onshore Khursaniyah gas plant.

That plant came on line last year at 1 bcfd to process raw sour gas from Abu Hadriya, Fadhili, and Khursaniyah fields, which produce about 560 MMcfd of gas, as well as gas from Karan offshore field. The plant’s two NGL processing trains were to be able to produce 280,000 b/d of ethane and other NGLs.

The Wasit development, due on stream in 2014, will involve construction of an onshore central processing plant capable of processing 2.5 bcfd of gas from offshore Arabiyah and Hasbah fields.

Onshore in November last year, Saudi Aramco extended bid closing for construction of the Shaybah NGL project. Shaybah NGL targets completion for fall 2014 and will be able to process 2.4 bcfd of low-sulfur sweet gas and extract 264,000 b/d of NGLs. These latter will be shipped to the Juaymah gas plant for further fractionation.

In March of this year, Aramco finally awarded Samsung four engineering, procurement, and construction packages worth $3 billion for the Shaybah project.

In Europe, what owner-operator BP called the world’s largest floating production, storage, and offloading (FPSO) for gas processing, was officially christened the BP Norge’s Skarv FPSO at its Samsung fab yard in South Korea.

The vessel will operate in the Norwegian Sea, about 130 miles off Nordland County. It should start production at the Skarv oil and gas field in fall 2011.

The vessel can handle 15 MMcfd of gas and 80,000 b/d of oil. Its oil storage capacity is 875,000 bbl.