OGJ Newsletter

April 13, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

US held top spot in 2014 as world's oil, gas producer

US production volumes of petroleum and natural gas remained tops in the world in 2014, exceeding that of both Russia and Saudi Arabia, according to estimates from the US Energy Information Administration.

EIA specifies that its petroleum production figures encompass crude oil, natural gas liquids, condensates, refinery processing gain, and other liquids such as biofuels.

Despite the 50% decline in crude oil prices that occurred in last year's second half, US petroleum production still increased 3 quadrillion btu (quads)-1.6 million b/d-in 2014. US petroleum production since 2008 has increased more than 11 quads, spurred by dramatic growth in Texas and North Dakota.

US gas production increased 5 quads-13.9 bcfd-over the past 5 years. Combined hydrocarbon output in Russia increased 3 quads and in Saudi Arabia 4 quads over the past 5 years.

EIA notes that total production in both the US and second-placed Russia is almost evenly split between petroleum and gas. While total petroleum and gas production estimates for the US and Russia in 2011 were roughly equivalent, US production by 2014 exceeded Russian production by almost 12 quads.

A report from Cedigaz this week highlighted the challenges in the coming years faced by the Russian gas industry, where stagnating domestic demand and weakening export markets have created a situation of overproduction, made worse by western sanctions and low oil and gas prices (OGJ Online, Apr. 8, 2015).

With the overall increase, the US in 2014 produced nearly twice the petroleum and gas as third-placed Saudi Arabia. Saudi Arabia's total production-which heavily favors petroleum-was nearly unchanged from 2013.

EIA last week reported that in 2014 Saudi Arabia, the Organization of Petroleum Exporting Countries' only true swing producer, earned a third of total OPEC oil revenues, which were down 11% on the year (OGJ Online, Apr. 1, 2015).

Apache to sell Australian operations for $2.1 billion

Houston independent Apache Corp. reported signing an agreement to sell its Australian subsidiary Apache Energy Ltd. to a consortium of private equity funds managed by Macquarie Capital Group Ltd. and Brookfield Asset Management Inc. for cash payment of $2.1 billion.

Apache Energy's assets and subsidiaries produced an average 49,000 boe/d in March. With the announcement of this sale, Apache is fully exiting its exploration and production business in Australia, but will retain its 49% ownership interest in fertilizer producer Yara Pilbara Holdings Pty. Ltd.

On Apr. 2, Apache announced the completion of sale of its Wheatstone LNG project and related oil and natural gas properties to Woodside Petroleum Ltd. for $2.8 billion (OGJ Online, Apr. 7, 2015).

Following the sale of its Australian assets about 70% of the company's production will come from North America onshore, said John J. Christmann IV, chief executive officer and president.

The transaction is expected to close midyear and is subject to necessary government and regulatory approvals and customary post-closing adjustments.

The effective date of the sale is Oct. 1, 2014.

Williams to buy more of Utica East

Williams Partners LP agreed to buy an additional 21% interest in Utica East Ohio Midstream LLC from EV Energy Partners LP for $575 million.

Once the deal closes, which is expected by July 15, Williams Partners of Tulsa will hold a 70% interest in the company. Utica East is a natural gas midstream business in eastern Ohio's Utica shale region. The deal is expected to add to Williams' earnings this year.

Acquiring these cash-generating assets supports our strategy to grow our natural gas midstream position in key basins, Williams Partners CEO Alan Armstrong said, adding the assets being acquired have attractive growth opportunities.

Williams Partners, which waived $43 million of general partner incentive distribution rights from 2015-17, said it will finance the transaction through equity and debt, including revolver borrowings.

ASX begins trading in natural gas futures

The Australian Securities Exchange (ASX), in conjunction with the Australian Energy Market Operator, has begun trading the ASX Wallumbilla natural gas futures.

The launch Apr. 7 took place a year after the AEMO established Australia's first voluntary gas supply hub in Wallumbilla near Roma in Queensland.

The Wallumbilla end-of-day benchmark price will be used as the reference price for the ASX's new gas futures contract.

The new market will help gas industry participants to manage their forward price risk and also will provide greater price transparency. Matt Zema, AEMO managing director, said the establishment of the new market in gas futures is an important step towards competition in Australia's growing eastern and south-eastern gas markets.

The benchmark price can be used as a basis price for gas contracts and the development of a derivatives market will provide a risk management tool for forward pricing and planning.

The AEMO has held regular consultations with industry to refine its benchmark price methodology so that it is in keeping with industry needs and expectations.

Exploration & DevelopmentQuick Takes

Statoil strikes oil in Gulf of Mexico's Yeti prospect

Statoil ASA has made an oil discovery in the Miocene Yeti prospect of Walker Ridge Block 160 in the Gulf of Mexico.

The Yeti discovery expands the proven subsalt Miocene play further south and west of the Big Foot field, explained Jez Averty, Statoil senior vice-president, exploration, North America. We are analyzing data to determine the size of the discovery in order to consider future appraisal options.

The discovery, 9 miles south of Big Foot field and 7 miles from Cascade field, was drilled by the Maersk Developer drilling rig, a sixth generation semisubmersible.

Statoil says its drilling efficiency on Yeti was among the best of any well drilled in Walker Ridge, achieving a rate of 400 ft/day. The rig has since moved to drill Statoil's Thorvald prospect on Mississippi Canyon Block 814.

Statoil operates Yeti with 50% interest. Partners are Anadarko Petroleum Corp. 37.5% and Samson Offshore LLC 12.5%.

Woodside finds gas near Pluto field

Woodside Petroleum Ltd. has made a natural gas discovery with its Pyxis-1 wildcat 15 km from its Pluto field production facilities in WA-34-L offshore Western Australia. The well intersected about 18.5 m of net gas pay within the Jurassic sandstone target reservoir.

Wireline logs have confirmed the discovery and gas samples have been brought to the surface. Woodside has not quantified the find, but observers suggest a resource of several hundred billion cubic feet.

Pyxis offers future tie-back potential to the existing Pluto infrastructure, including the onshore One-train LNG plant on the Burrup Peninsula. The well was drilled by Transocean Ltd.'s Deepwater Millennium ultradeepwater drillship.

JX Nippon-led group makes oil find off Malaysia

Santos Ltd., a recent member of the JX Nippon Oil & Gas Exploration-led group in deepwater Block R offshore Sabah, Malaysia, has reported an oil discovery in the permit with the drilling of the Bestari-1 wildcat. Preliminary findings from the well indicate a 70-m column of oil-bearing sands across multiple horizons, Santos said.

Santos acquired a 20% interest in the permit in February by taking 10% from each of Nippon and Inpex (OGJ Online, Feb. 2, 2015). The block lies close to Murphy Oil's existing Kikeh oil field and Shell's Gumusut-Kakap oil field. Bestari-1 is the first of three wildcats planned for the permit early this year.

JX Nippon and Inpex now have 27.5% each, with Petronas 25% and Santos 20%.

Gazprom Neft, PetroVietnam further Arctic collaboration

Further to its exclusive talks on possible cooperation, JSC Gazprom Neft and PetroVietnam have set October as a tentative deadline for prioritizing terms for their partnership at Dolginskoye field and the Severo-Zapadnyi (North West) blocks in Russia's Pechora Sea (OGJ Online, Nov. 26, 2014).

The agreements, signed on Apr. 6, include the formation of a dedicated working group and a list of priority oil and gas fields for the two blocks along with the establish of basic terms for future joint exploration efforts.

Dolginskoye oil field lies 120 km south of the Novaya Zemlya archipelago and 110 km north of Russia's mainland. Discovered in 1999, the field has seen four exploration wells-three in the north and one in the south. The North West license block is near Dolginskoye and Prirazlomnoye shelves where Gazprom Neft also operates.

The company said seismic work includes more than 11,000 line-km of 2D and 1,600 sq km of 3D seismic.

Dolginskoye field was discovered in 1999. Three exploration wells have been drilled, two in the north and one in the south. Gazprom Neft holds a total of five licenses for the blocks on the Arctic shelf.

Drilling & ProductionQuick Takes

AWE starts oil production from Pateke-4H

AWE Ltd. has completed its subsea tie-back and installation project to connect the Pateke-4H development well to the Tui area oil fields gathering system.

Flow testing is under way to determine the optimal well settings. The well recorded an initial unstabilized flow rate of 34,000 b/d through a 67% choke with a 48% water cut, which is in line with field modelling.

AWE plans to test various facility parameters, including choke settings, before establishing a much lower stabilized flow rate for long-term production. The company forecasts oil production from the well will then decline relative to the increasing water cut in the well.

The Pateke-4H development well is performing as expected and will boost near-term production and cash flow without additional operating costs, said Bruce Clement, AWE managing director, adding that the well represents the final stage of development for the Tui project.

The subsea tie-back and installation project involved the installation of 1,312 m of flexible flow line, a gas lift umbilical and production manifold, integrated controls and ancillary equipment in 124 m of water.

The Tui area oil fields and the Umuroa floating production, storage, and offloading vessel were shut in for the duration of the tie-back project (OGJ Online, Apr. 24, 2007). During the shut-in period, a planned program of facility inspections and maintenance was conducted.

The Tui area oil fields comprises Tui, Amokura, and Pateke fields 50 km off Taranaki, New Zealand, in PMP 38158 (OGJ Online, Oct. 29, 2004). Production from each field is fed into the Tui field gathering system and then into the Umuroa FPSO.

AWE operates PMP 38158 with 57.5% interest. Partners are New Zealand Oil & Gas subsidiaries 27.5% and Pan Pacific Petroleum subsidiaries 15%.

COS report finds US offshore operations safer

The US offshore oil and gas industry is safer than ever, though there is still room to improve, according to the first annual performance report released Apr. 8 by the Center for Offshore Safety (COS).

The report, which is based on 2013 operations data collected from COS members, highlights metrics for conducting scheduled maintenance and inspections, as well as completing safety and environmental audits. Notably, COS found that there were zero fatalities or losses of well control in the deepwater Gulf of Mexico during more than 42 million work-hr in 2013.

This is the first report off its kind to be published by US regulators or industry, said COS Executive Director Charlie Williams. America's offshore oil and natural gas industry is even safer than before, but our goal will always be zero accidents and zero spills.

Williams said that sharing data and lessons learned throughout the industry is fundamental to COS achieving its mission of enhancing safety. As long as there is room for improvement, the consortium's work will not be complete.

The top three areas for improvement cited in the inaugural safety performance report are: safe mechanical lifting, such as with cranes and hoists; process safety, with emphasis on risk management, maintenance, inspection, and testing; and adherence to operating procedures and safe-work practices.

COS will use the report's findings as a baseline for year-to-year comparisons to track improvement or regression. The 2015 report is available on the COS web site.

Based in Houston, COS was formed in 2012 to enhance safety in the deepwater US gulf. The association is open to all companies that operate in deepwater exploration and production. Its focus is based on API's Recommended Practice 75, covering safety and environmental management systems that have been implemented into US federal offshore regulations (OGJ Online, Mar. 27, 2012).

Cairn India seeks to triple gas production from RJ block

Cairn India Ltd. is seeking to triple natural gas production from the RJ block in Rajasthan by drilling a minimum of 42 wells in the next 3 years.

Cairn foresees gas production of 3 million cu m/day from the block, formally known as RJ-ON-90/1. Current capacity from 30 existing wells is 1 million cu m/day, Cairn said. Fields in the RJ block include Raageshwari Deep Gas (RDG), Mangala, Bhagyam, and Aishwarya (OGJ Online, Mar. 25, 2013).

Cairn has filed a proposal with the Petroleum and Natural Gas Regulatory Board for a 24-in., 194-km pipeline from the proposed RDG Terminal to the Gujarat Gas Grid. First gas from the RDG Terminal is expected in 2017, subject to approval of the pipeline.

PROCESSINGQuick Takes

Shell wraps upgrade of Singapore ethylene cracker

Royal Dutch Shell PLC has concluded a long-planned upgrade and expansion of its ethylene cracker complex (ECC) on Bukom Island, Singapore, which along with the nearby 462,000-b/d Pulau Bukom refinery and 750,000-tonne/year monoethylene glycol (MEG) plant on Jurong Island, forms part of the company's fully integrated Shell Eastern Petrochemicals Complex (SEPC) (OGJ Online, July 1, 2013; July 27, 2006).

In addition to reducing the ECC's energy consumption and carbon dioxide emissions by about 7% and 11%, respectively, the debottlenecking and expansion project has boosted the plant's ethylene production capacity by more than 20% from its previous 800,000-b/d capacity, Shell said.

While the company did not immediately disclose a precise figure for the plant's expanded production capability, a Shell spokesperson told OGJ via e-mail that the upgraded ECC now has a new capacity of more than 1 million tpy.

The expansion and upgrading project was completed ahead of schedule, within budget, and without lost-time injury, according to Huck Poh, general manager for Shell's Pulau Bukom manufacting site.

The ECC upgrade, which included installation of new furnaces, heat exchangers, and heating coils to make the conversion process more efficient, involved the use of 100 new and modified pieces of equipment, nearly 2,000 tonnes of steel, more than 200 km of cables, and 40 km of piping, Shell said in a project description posted to the company's web site.

Following with Shell's strategy to maximize integration of its Singapore refining and petrochemical operations to meet growing regional demand, increased production from the ECC will 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, the company said.

A final cost of the upgrading project was not disclosed.

Gazprom Neft inks deal for stake in Vietnamese refinery

Russia's JSC Gazprom Neft has entered an agreement with Vietnam National Oil & Gas Group (PetroVietnam) to purchase a 49% interest in the 6.5 million-tonne/year Dung Quat refinery.

The agreement, signed on Apr. 6, grants Gazprom Neft exclusive rights to negotiate its acquisition of PetroVietnam's shares in the refinery, which is owned and operated by PetroVietnam subsidiary Binh Son Refining & Petrochemical Co. Ltd. (BSR), Gazrpom Neft said.

This latest contract follows previous agreements between Gazprom Neft and PetroVietnam to increase collaboration on joint oil and gas ventures as part of a strategic partnership formed in 2009 (OGJ Online, Nov. 26, 2014; Nov. 12, 2013).

Gazprom Neft's share of investment in the previously announced expansion and modernization of Dung Quat, which was commissioned in 2009 and remains Vietnam's only operating refinery, will be proportionate to its share in the plant, the Russian company said.

In addition to improving the efficiency of Dung Quat's technological processes to enable production of Euro 5-standard motor fuels, the planned modernization project will boost the refinery's crude oil processing capacity to 8.5 million tpy.

Gazprom Neft disclosed neither a timeline nor price for the acquisition of its minority interest in the refinery.

While PetroVietnam confirmed in a Dec. 17, 2014, release that BSR continues to actively carry out activities related to the modernization and revamp of Dung Quat, the company said it does not expect to commission the fully expanded and upgraded refinery until 2022 (OGJ Online, Jan. 26, 2015).

Lukoil restarts ethylene production at Stavrolen complex

Lukoil has resumed production of ethylene and propylene at its 350,000-tonne/year Stavrolen petrochemical complex in Budennovsk, Russia, following a February 2014 fire that broke out in the plant's ethylene production unit gas separation area (OGJ Online, Feb. 27, 2014).

As part of the repair and maintenance work, which was completed according to the approved schedule, Lukoil also carried out a project to expand the ethylene unit's capacity to process straight-run naphtha and LPG feedstock supplied to Stavrolen via rail from the company's Russian refineries and gas processing plants, Lukoil said.

The upgrading project included reconstruction of cracking furnaces, fuel gas skids, gas feedstock evaporation complexes, and water-flush columns, the company said.

Lukoil said it resumed polypropylene production at Stavrolen using imported feedstock as far back as October 2014.

The company, however, did not disclose current ethylene production rates at the complex.

In 2012, Lukoil announced project plans for the Stavrolen industrial site designed to equip the complex to process gas produced in the northern Caspian (OGJ Online, Sept. 25, 2012).

In addition to the modernization of existing ethylene and polyethylene units at the Stavrolen complex, the first stage of a 2 billion cu m/year gas processing plant also was scheduled to be commissioned this year, Lukoil has said.

TRANSPORTATIONQuick Takes

Enterprise expands HSC LPG-export terminal

Enterprise Products Partners LP (EPP) has expanded its LPG export terminal at the Houston Ship Channel (HSC) by 1.5 million bbl/month (2,500 bbl/hr) to 9 million bbl/month of fully refrigerated, low-ethane propane. The expansion will allow EPP to accommodate three additional ships per month.

The company also is making progress on a refrigeration train that will increase loading rates by another 11,000 bbl/hr by the fourth quarter. Once this final expansion phase is complete EPP will be able to load up to 16 million bbl/month, or roughly 29 vessels. To help ensure adequate supply to the docks, the partnership is completing a dedicated 30-in. OD LPG pipeline from Mont Belvieu, Tex., to the terminal.

Kinder Morgan Energy Partners LP also is expanding its HSC terminals, in its case to provide additional refined product storage and dock services (OGJ Online, Oct. 14, 2014).

TransCanada to change Energy East route

TransCanada Corp., responding to new concern about Beluga whales and community comments, will change the destination end of its proposed Energy East pipeline (OGJ Online, Oct. 30, 2014).

The company said it won't build a marine terminal and associated tanks at Cacouna, Que., as originally planned.

The Energy East project, a combination of reconfiguration of 1,864 miles of existing natural gas pipeline and 990 miles of construction, is to be able to carry 1.1 million b/d of crude oil from Alberta and Saskatchewan to eastern Canada.

This decision is the result of the recommended change in status of the Beluga whales to endangered and ongoing discussions we have had with communities and key stakeholders, TransCanada Pres. and CEO Russ Girling said.

The company is reviewing alternative terminal sites. It said refineries in Quebec and New Brunswick still will be directly connected to the pipeline.

Tamar gas exports to Jordan get key okays

The export to Jordan of natural gas from Tamar field offshore Israel has received key approvals (OGJ Online, Feb. 20, 2014).

Subsidiaries of Delek Group, a Tamar partner, said Israel authorities granted the approval for sale to NBL Eastern Mediterranean Marketing Ltd. of fixed quantities of gas under an agreement signed in February 2014.

The agreement covered total supply of 66 bcf over 15 years. Delek said other approvals are needed from Israel and Jordan.

Noble Energy Inc. operates Tamar field.

US industry scoreboard - 4/13

4 wk. 4 wk. avg. Change, YTD YTD avg. Change,

Latest week 3/27 average year ago1 % average1 year ago1 %

Product supplied, 1,000 b/d

Latest Previous Same week Change,

Latest week 3/27 week week1 Change year ago1 Change %

Stocks, 1,000 bbl

More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles
View Oil and Gas Articles on PennEnergy.com