OGJ Newsletter

Sept. 21, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

EIA: US oil, gas supply less vulnerable to hurricanes

A relatively light hurricane season anticipated for 2015 and an overall decline in the Gulf of Mexico’s share of US crude oil and natural gas production both serve to minimize the risk of supply disruptions, the US Energy Information Administration noted in a recent energy update.

EIA explained that offshore energy output from the gulf “has experienced relatively minor disruptions because of tropical storms and hurricanes in recent years,” adding that the National Oceanic and Atmospheric Administration expects a below-normal 2015 hurricane season.

In 2003, 27% of the nation’s oil was produced in the gulf. By 2014, that share had declined to 16%. EIA earlier in the year projected crude output would reach 1.52 million b/d in 2015 and 1.61 million b/d in 2016-or respectively 16% and 17% of total US crude production during each year (OGJ Online, Mar. 3, 2015).

The gulf’s share of gas production also declined from a high of 26% in 1997 to merely 5% in 2014.

Based on NOAA’s outlook, EIA estimated in its June Short-Term Energy Outlook that storm-related disruptions in the gulf during the this hurricane season would total 9.7 million bbl of crude and 15.9 bcf of gas-or 3.5% and 2.8% of total gulf oil and gas production, respectively.

EIA projected a 14% probability that production during the current hurricane season will be unaffected. No production was affected during last year’s season.

As for the Gulf Coast region, where about half of US refining capacity and several gas processing and distribution facilities reside, EIA noted that high levels of crude inventories-both domestically and globally-could mitigate the supply impacts of weather-related disruptions, and gas processing capacity has been added in areas beyond the Gulf Coast in recent years.

Cedigaz: Marketed gas output up slightly

Global growth in marketed production of natural gas remained low in 2014 as competition from coal in Europe and Asia, the economic slowdown in China, and Northern Hemisphere warmth restrained demand, Cedigaz reports.

Marketed gas production increased 1.3% to 3.445 trillion cu m (tcm) last year after rising 1.2% in 2013, according to revised and final Cedigaz data.

During 2000-10, marketed production grew at a sustained average of about 2.8%/year, including a decline in 2009 offset by an increase related to economic recovery in 2010.

Gross worldwide gas production increased 1.7% to 4.319 tcm last year, the association says. The increase reflects gains of 4.6% in reinjected gas, 2.9% in flared and vented gas, and 2.2% in losses related to processing and field operations.

With demand decreasing in Europe and the Commonwealth of Independent States, international gas trade fell 3% to 1.007 tcm last year, Cedigaz says. Pipeline flows fell 4.3%.

LNG supply increased 0.8% to 312.8 billion cu m after several years of decline as liquefaction outages remained low and plants started up in Papua New Guinea and Algeria.

Gas demand in Asia fell 2.7% in 2014 after increasing by an average 6.5%/year the previous 5 years.

The LNG supply gain and Asian demand slowdown “have led to the emergence of a global LNG glut and the collapse in spot prices in both Europe and Asia,” Cedigaz notes.

Gas reserves increased 0.3% to 200 tcm last year, according to the association. Russia and the US had the largest increases, while European reserves fell by almost 7%.

Rand Corp. releases energy workforce studies

Rand Corp. released two energy workforce development studies commissioned by the US Department of Energy’s National Energy Technology Laboratory in Morgantown, W.Va.

The first study evaluated how West Virginia’s high schools and community and technical college systems prepare workers for the shale gas industry, DOE’s Fossil Energy Office (FEO) said. It said the second study considered ways that 32 contiguous counties in Pennsylvania, Maryland, West Virginia, and Ohio could recognize the direction of technological innovations and align workforce training to encourage these trends.

FEO said it already has implemented several other workforce development initiatives in West Virginia and the southwestern Pennsylvania area. These include an advanced energy simulator at NETL, which focuses on safe, reliable, and efficient energy plant operations and control; and ShaleNET, a consortium of community colleges led by Westmoreland County Community College that helps build oil and gas industry careers, it said.

Exploration & DevelopmentQuick Takes

Judge vacates listing bird species as threatened

A federal district judge in Texas vacated the US Fish & Wildlife Service’s listing of the lesser prairie chicken as a threatened species after finding that the US Department of the Interior agency failed to follow its own evaluation procedures for conservation efforts that already were under way (OGJ Online, Mar. 24, 2014).

The decision potentially could affect FWS’s long-anticipated decision whether to list the greater sage grouse as a threatened or endangered species, which is expected by the end of this month. Both birds dwell in oil and gas producing areas, so listing either or both species as threatened would have a profound effect on operations.

Robert Junell, senior judge for US District Court for Western Texas’s Midland-Odessa Division, said in his Sept. 1 decision that FWS acted arbitrarily and capriciously in disregarding conservation efforts on millions of acres across five states to improve habitat and diminish threats to the bird.

“This ruling serves as vindication of the unprecedented stakeholder participation across the lesser prairie chicken range,” Permian Basin Petroleum Association Pres. Ben Shepperd said on Sept. 2.

“Our members’ good faith efforts to conserve [lesser prairie chicken] habitat and recover the species through the Range-wide Plan began long before this listing decision was made, and will continue unabated now that the court has thrown it out,” he said.

US House Natural Resources Committee Chairman Rob Bishop (R-Utah) said that Junell’s ruling showed that “by listing the lesser prairie chicken as threatened, [FWS] has been illegally steamrolling states by [its] own secret rules.”

Bishop said, “The Obama administration has been merciless in its quest to list species-even when the science says otherwise. This is exactly why the House passed provisions to stop FWS from undoing the states’ conservation work on both the lesser prairie chicken and the greater sage grouse.”

BOEM proposes Gulf of Mexico Lease Sales 226, 241

The US Bureau of Ocean Energy Management (BOEM) reported on Sept. 11 that it will offer 40 million acres offshore Louisiana, Mississippi, and Alabama for oil and gas exploration and development in two separate lease sales scheduled for March 2016 in New Orleans.

Proposed Eastern Planning Area Lease Sale 226 will offer 175 blocks covering 595,475 acres in 2,657-10,213 ft of water. The area is bordered by the Central Planning Area boundary on the west and the Military Mission Line on the east, and is south of eastern Alabama and western Florida with the nearest point of land 125 miles northwest in Louisiana. BOEM estimates that Sale 226 could result in the production of 71 million bbl of oil and 162 bcf of natural gas.

Proposed Central Planning Area Lease Sale 241 will offer 7,919 blocks covering 42.1 million acres in 9-11,000 ft of water. The area ranges 3-230 nautical miles offshore. BOEM estimates the proposed sale could result in the production of 460 million-894 million bbl of oil and 1.9-3.9 tcf of gas.

The sales will be the ninth and tenth offshore sales under the Outer Continental Shelf Oil and Gas Leasing Program for 2012-17. The first eight sales in the current program have offered more than 60 million acres and netted nearly $3 billion.

Drilling & ProductionQuick Takes

Seadrill cancels West Mira rig construction contract

Seadrill Ltd. has notified Hyundai Heavy Industries Co. Ltd. that it has exercised its right to cancel the contract for construction of West Mira-a sixth generation ultradeepwater, harsh environment semisubmersible drilling unit-given the shipyard’s inability to deliver the unit under the specified timeframe.

The unit was ordered during second-quarter 2012, and the delivery date stated in the construction contract was by Dec. 31, 2014. Under the contract terms, Seadrill has the ability to recoup the $168 million in predelivery installments to the Shipyard plus accrued interest.

Seadrill in fourth-quarter 2012 was awarded a 5-year contract for West Mira with Husky Oil Operations Ltd. for operations in Canada and Greenland.

Due to the late delivery of the unit, the company had tentatively agreed with Husky to reduce the dayrate of the West Mira drilling contract. Seadrill remains in discussions with Husky to find an alternative solution to meet its drilling requirements.

Wintershall eyes old fields in southern Germany

Wintershall Holding GMBH is taking a hard look at old fields in southern Germany.

The company said it completed two exploratory wells in Bedernau and Lauben fields in the state of Bavaria. In the next 6 months, Wintershall will determine whether “resuming traditional oil production” is commercially feasible.

Also in Bavaria, Wintershall plans to drill at least one well in 2016 in Aitingen field, which has been producing since 1979.

The company also is looking into developing two old fields-Monchsrot and Hauerz-in the state of Baden-Wurttemberg. Production stopped 20 years ago “because it was no longer profitable.”

Monchsrot, Hauerz, Aitingen, Bedernau, and Lauben lie in a string of crude-oil reservoirs in the foothills of the Alps, the company said.

Wintershall also plans to build up its operations at Landau in the state of Rhineland-Palatinate, where it has been producing oil for 60 years in the midst of vineyards.

Andreas Scheck, head of Wintershall Deutschland, told the German Energy Congress in Munich this week that the debate about the use of hydraulic fracturing for shale gas production has blocked “traditional” production in Germany (OGJ Online, Jan. 20, 2015). He cited an “investment backlog” and declining production in Germany.

“To unlock this investment, we need a reliable and proportionate policy framework,” he said. “Policymakers in Berlin intend to pass legislation in the next few weeks which will lay the groundwork for the future of oil and gas production in Germany.”

ExxonMobil lets contract for Iraq’s West Qurna-1 field

ExxonMobil Corp. has let a front-end engineering design (FEED) contract to Kentz, part of SNC-Lavalin Group, for an oil processing facility that will increase production at West Qurna-1 field in Iraq.

With its regional partner, Kentz is providing detailed design engineering, procurement, fabrication, construction, commissioning, and start-up of the facility, which will be capable of producing an average of 100,000 stb/d of crude.

Located in the province of Al Basra, the facility will be designed to process full well stream fluids from the production wellhead area and separate them into associated gas, untreated produced water, and stable product crude for export.

The project will be executed out of Kentz’ Abu Dhabi engineering hub, with support from its Dubai operations, and is expected to be completed in 26 months.

Esso starts oil production from Erha North Phase 2

Esso Exploration & Production Nigeria Ltd., a subsidiary of ExxonMobil Corp., has started oil production ahead of schedule at the Erha North Phase 2 project 60 miles offshore Nigeria (OGJ Online, June 23, 2015).

The deepwater subsea development lies in 3,300 ft of water and 4 miles north of Erha field, which has been producing since 2006 (OGJ Online, May 2, 2006).

The project includes seven wells from three drill centers tied back to the existing Erha North floating production, storage, and offloading vessel, reducing additional infrastructure requirements.

Phase 2 is estimated to develop an additional 165 million bbl from the currently producing Erha North field. Peak production from the expansion is estimated at 65,000 bo/d, increasing total field production to 90,000 b/d.

ExxonMobil expects to increase its global production volumes this year by 2% to 4.1 million boe/d, driven by 7% liquids growth. The increase is supported by the ramp up of projects completed in 2014 and the expected startup of major developments this year.

Esso E&P Nigeria operates Erha North Phase 2 with 56.25% interest. Shell Nigeria Exploration & Production Co. holds 43.75%.

PROCESSINGQuick Takes

Shell adds new units at Singapore petrochemical complex

Royal Dutch Shell PLC has commissioned two new units designed to more than double output of specialty chemicals at the Shell Eastern Petrochemicals Complex (SEPC) in Singapore using feedstock supplied by SEPC’s fully integrated 750,000-tonne/year ethylene oxide-monoethylene glycol (MEG) plant on Jurong Island, 1 million-tpy ethylene cracker complex (ECC) on Bukom Island, and 500,000-b/d Pulau Bukom refinery.

Located on Jurong Island, the new 140,000-tpy high-purity ethylene oxide (HPEO) purification unit and 140,000-tpy ethoxylates plant are intended to help meet Asia-Pacific’s rising demand for HPEO and alcohol ethoxylates, which are used in a variety of household and industrial products, Shell said.

Royal Dutch Shell PLC has commissioned two new units designed to more than double output of specialty chemicals at the Shell Eastern Petrochemicals Complex in Singapore. Photo from Shell.

Feedstock for the HPEO plant comes directly from Shell’s Jurong Island MEG plant, which in turn receives feedstock from the Bukom Island ECC and Pulau Bukom refinery, the company said.

Earlier this year, Shell completed the long-planned upgrade and debottlenecking of the Bukom Island ECC, which increased production capacity at the complex by more than 20% (OGJ Online, Apr. 2, 2015, July 27, 2006).

While the company has yet to disclose a precise figure for the plant’s expanded production capability, a Shell spokesperson told OGJ in April that the upgraded ECC now has a new capacity of more than 1 million tpy.

At the time, the company said increased production from the ECC would be shipped via a subsea pipeline to Jurong Island to support further expansion of intermediates plants, including Shell’s MEG plant as well as third-party installations.

Flint Hills lets contract for Texas refinery expansion

Flint Hills Resources LLC, a subsidiary of Koch Industries Inc., has let a contract to a unit of Wood Group for work related to Project Eagle Ford (PEF), a $600-million program designed to increase processing capabilities for US light crude oil production at its 230,000-b/d West refinery in Corpus Christi, Tex. (OGJ Online, Dec. 2, 2014).

Wood Group Mustang Inc. will provide detailed engineering, procurement, and other services for the refinery modification project, including module fabrication oversight as well as construction engineering support services, Wood Group said.

Engineering work on the project is due to be completed in mid-2016, the service provider said. A value of the contract was not disclosed.

This marks Flint Hills’ second PEF-related contract award to Wood Group Mustang, which previously completed conceptual and front-end engineering design phases for the project, Wood Group said.

Initially announced in 2012 and formerly named the Domestic Crude Project, PEF will involve the modification of equipment at the West refinery’s continuous catalytic regeneration hot oil heater, as well as the inclusion of a new saturates gas plant and associated hot oil heater (OGJ Online, May 29, 2014; Aug. 27, 2012).

In addition to equipping the refinery with an ability to process 100% US light US crude from nearby Eagle Ford shale play and boosting its overall crude processing capacity by about 7%, the expansion and modification project will enable reduced criteria air emissions from the Corpus Christi plant by the inclusion of best available control technologies.

PEF also will include installation of a mid-plant cooling tower, equipment piping, process vessels, and two storage tanks at the site.

Construction on the project, which began in December 2014, is scheduled to last 36 months.

Petronas lets contract for RAPID complex

State-run Petronas has let a contract to a consortium led by Muhibbah Engineering (M) Bhd., Selangor, Malaysia, to provide reengineering front-end engineering and design (re-FEED) for the effluent treatment plant for its proposed refinery and petrochemical integrated development (RAPID) complex at Pengerang in southeastern Johor, Malaysia (OGJ Online, May 13, 2011).

As part of the re-FEED contract, which was awarded by Petronas subsidiary PRPC Utilities & Facilities Sdn. Bhd., Muhibbah Engineering, and its partner VA Tech Wabag Ltd., Chennai, India, also will deliver engineering, procurement, construction, and commissioning of the ETP, the service provider said in filing with Bursa Malaysia.

The integrated ETP will enable the RAPID complex to reduce pollution in its aqueous effluents to below regulatory discharge limits, according to Muhibbah Engineering.

The consortium is scheduled to complete its scope of work under the contract, which is valued at 949.6 million ringgit ($224.3 million), by yearend 2018.

With a planned capacity of 300,000 b/d, the proposed RAPID refinery will produce naphtha and liquid petroleum gas feedstock for the petrochemical complex, as well as gasoline and diesel meeting European specifications to help address Asia-Pacific’s growing need for petroleum and petrochemical products (OGJ Online, Mar. 27, 2014).

The refinery and petrochemical complex will have a combined capacity to produce 7.7 million tonnes/year of various grades of products, including differentiated and specialty chemicals products (OGJ Online, Oct. 23, 2014).

Scheduled for start-up in early 2019, RAPID will cost an estimated $16 billion, with associated installations for the project to require an additional investment of about $11 billion, according to Petronas (OGJ Online, June 25, 2015; July 25, 2014).

TRANSPORTATIONQuick Takes

Two Canadian LNG proposals get export nod

Canada’s National Energy Board has approved exports of LNG from two projects under consideration for the Atlantic Coast.

In the latest action, it granted Saint John LNG Development Co. a 25-year license to export as much as 8.12 billion cu m/year from a liquefaction plant at Saint John, NB.

Saint John LNG is an indirectly owned subsidiary of Repsol SA, a partner with Irving Oil in the existing Canaport LNG import terminal, where liquefaction facilities would be built.

The NEB stipulated that the license will expire 10 years from approval by the Governor in Council if exports haven’t begun.

In August, the board approved a 25-year license for export of as much as 19.4 billion cu m/year of LNG from the Bear Head LNG project proposed to be built near Point Tupper, NS (OGJ Online, Mar. 3, 2015).

The license carries a 10-year start-up stipulation.

Bear Head is a wholly owned subsidiary of Liquefied Natural Gas Ltd., Perth.

Ichthys LNG project faces delays, cost overruns

First production from the Inpex Corp.-operated Ichthys LNG-condensate project off Western Australia with pipeline connection to an LNG plant in Darwin has been delayed by about 9 months. There also is a 10% cost overrun over original estimates.

Inpex says the project has been delayed from yearend 2016, when it was originally expected to come on stream, to third-quarter 2017.

The company said the project was 74% complete as of June, but the revised start-up will increase the project investment by a maximum of 10%. This would bring the earlier $34-billion cost estimate up to $37.4 billion.

On the plus side, a recent technical evaluation of the whole LNG production system has prompted Inpex to increase the LNG production capacity to 8.9 million tonnes/year from 8.4 million tpy.

The updated schedule also reflects the expectation of a shortened timeframe between the on-stream date and the point where stable optimum production is reached.

All LNG initially planned to be produced has been sold. About 70% will go to Japan.

Inpex holds 62.245% interest in Ichthys.