OGJ Newsletter

Sept. 28, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Total to cut 2016 capital budget by $3 billion

Total SA plans to reduce its capital expenditures to $20-21 billion in 2016 from $23-24 billion in 2015 and a peak of $28 billion in 2013 (OGJ Online, Feb. 12, 2015). The French multinational firm says it then will return to a "sustainable level" of $17-19 billion in 2017 and beyond.

This will be achieved in part by reducing personnel costs by more than $80 million/year, which will result in fewer contractors, according to Total's strategy and outlook presentation delivered at its investor day on Sept. 23. The company also has slashed its global rig fleet nearly in half since 2014 in a move that is "adapting rig count to activity levels," it said.

The spending cuts will result in lower production growth than previously forecast. While the company reported a year-over-year output rise of 11% during this year's first half, it expects growth of just 6-7%/year during 2014-17 and 5%/year when expanding the period to 2014-19.

Production increases largely will be upheld by 20 major startups, eight of which are slated for this year. Total also is targeting more than 1.5 billion boe in its 2016-18 exploration program.

In the US Gulf of Mexico, three appraisal wells are ongoing from the North Platte discovery and an exploration well is scheduled for the Goodfellow prospect. Each is estimated to have 400 million boe in contingent and prospective resources.

Total is also seeing startup of the GLNG, Yamal, and Icthys LNG projects, the latter of which has experienced delays and cost overruns (OGJ Online, Sept. 14, 2015).

Samson latest shale producer to file for bankruptcy

Samson Resources Corp., the Tulsa-based shale producer backed by US multinational private equity firm KKR & Co., filed for bankruptcy on Sept. 16. As part of its restructuring and recapitalization, Samson's second lien lenders, together with the second lien lenders that are backstopping the equity rights offering, will own substantially all of the equity in the reorganized company and all second lien lenders will have the right to participate in the new money investment.

The company also has obtained a commitment from second lien lenders-including Silver Point, Cerberus, and Anschutz-to provide at least $450 million of new capital to increase liquidity post-reorganization and permanently pay down existing first lien debt. This investment may be increased under certain circumstances to $485 million to further bolster liquidity.

Samson filed a series of motions that, pending court approval, will allow the company to operate its business in the ordinary course throughout the Chapter 11 process. The first day motions will allow the company to continue producing oil and gas from its existing operations, pay employee wages, honor existing employee benefit programs, and pay royalties to mineral owners under the current terms of these agreements.

Samson's assets encompass the Haynesville and Bossier shale plays and Cotton Valley reservoir in the East Texas and Northern Louisiana region; Granite Wash and Mississippi Lime, Tonkawa, and Marmato plays in the Midcontinent region; and Williston, Powder River, Green River, and San Juan basins in the Rockies region.

Sabine Oil & Gas Corp. and Quicksilver Resources Inc. are among other notable Chapter 11 filings during the current downturn (OGJ Online, June 15, 2015; Sept. 18, 2015).

Bankrupt Quicksilver Resources seeks sale

Quicksilver Resources Inc., a Ft. Worth independent producer focused on unconventional resources that filed for bankruptcy in March, is for sale (OGJ Online, Mar. 18, 2015).

The company filed a motion with the US Bankruptcy Court for the District of Delaware seeking approval of bidding for all or part of its US and Canadian assets.

According to documents filed in association with the motion, Quicksilver has US proved natural gas-equivalent reserves of 949 bcf in the Barnett shale and West Texas, nearly all in the Barnett, and Canadian proved reserves of 282 bcf in Horseshoe Canyon and the Horn River basin, 80% in Horseshoe Canyon.

The company's Canadian subsidiary, Quicksilver Resources Canada Inc., is working under a forbearance agreement with first-lien secured lenders. Quicksilver and subsidiaries expect to continue normal operations.

Wexpro, Piceance Energy form JV for gas development

Wexpro Co., a subsidiary of Questar Corp., Salt Lake City, has entered into a joint venture with Laramie Energy II LLC subsidiary Piceance Energy LLC to develop natural gas-producing assets in western Colorado's Piceance basin.

Wexpro expects to spend $60-70 million on an 80-well drilling program targeting the Mesaverde formation. The partners will begin drilling in the Collbran Valley in Mesa County in early October, and continue through early 2017.

The joint-development agreement also provides Wexpro options to acquire development rights for deeper formations and, with mutual consent, to extend and expand the drilling program by as many as 300 wells, contingent on commodity prices.

Energy minister appointed for Northern Australia

New Australian Prime Minister Malcolm Turnbull has unveiled his new cabinet, appointing former Assistant Treasurer Josh Frydenberg as federal minister for resources, energy, and Northern Australia.

The move resurrects a dedicated energy and resources portfolio that was absent from the cabinet of recently deposed Prime Minister Tony Abbott. Instead Abbott incorporated the role in the industry portfolio, although the minister concerned, Ian Macfarlane, was a long-time resources industry minister and opposition energy spokesman in previous governments.

Frydenberg is a former lawyer and policy advisor to former Liberal Party leaders John Howard and Alexander Downer. His appointment to the resources and energy portfolio is seen as heralding a new era and significant change in the sector.

His task ahead will be in progressing reforms, particularly in regard to the transition to cleaner energy systems.

With much of the accent in Australian projects on LNG, Frydenberg is described as having the economic credentials to take the gas industry and gas market in particular through the next challenging phase of development.

Exploration & DevelopmentQuick Takes

MOL reports discovery in northern Pakistan

MOL Group reported a second discovery of crude oil, natural gas, and condensate on the Karak Block in Punjab Province of northern Pakistan.

The operator, Mari Petroleum Co. Ltd., tested hydrocarbons in three formations in the Kalabagh-1A ST1 well, which was drilled to 3,003 m.

The Lower Jurassic Datta flowed 618 boe/d of gas and 160 b/d of condensate. The Middle Jurassic Samana Suk flowed 877 boe/d of gas and 180 b/d of condensate. And the Paleocene Lockhart flowed 500 b/d of crude oil.

Also on the block, which is on the border with Khyber Pakhtoonkhwa Province, the joint venture found oil in the Halini well in 2011.

Drilled to 5,350 m, the Halini well flowed on test at an average rate of 1,700 b/d of 26° gravity crude through a 32/64-in. choke.

Drilling continues on Lithuanian Raseiniai license

Tethys Oil AB reported the completion of drilling of the Tidikas-1 exploration well on the Raseiniai license onshore Lithuania. The Tidikas-1 well, which was drilled vertically to the Cambrian sandstone at a measured depth of 1,412 m, found a combined oil column of nearly 50 m in two different limestone formations. Cores also were taken from Silurian and Ordovician limestones, marl, and dolomites.

The well flowed oil to surface during drillstem tests and will be put on a long-term production test.

Tidikas-1 was the second well drilled this year on the Raseiniai license. The Bedugnis-1 well, which was completed in August, was drilled vertically to a total measured depth of 1,067 m and recorded oil shows while drilling, but no oil flowed to surface (OGJ Online, June 17, 2015). Both wells were targeting Silurian reefs and carbonate features mapped by an 80-sq km 3D seismic study completed in 2014.

"There are now clear indications that an active petroleum system exists within the Raseiniai license," said Magnus Nordin, Tethys Oil managing director.

The Raseiniai license covers 1,535 sq km onshore Lithuania. Tethys Oil has a 30% indirect interest in the license.

Drilling & ProductionQuick Takes

NEB: Canadian natural gas exports to US have declined

Canada's National Energy Board says exports of Canadian natural gas exports to the US have declined in recent years because of increased US gas production.

Canadian exports to the US East decreased by more than 65% in 2007-14, said NEB, citing 2.82 bcfd in 2007 and 0.95 bcfd in 2014. Exports to the US Midwest declined to 3.9 bcfd in 2014 from 5 bcfd in 2011.

NEB said production in the US Marcellus region has increased to more than 16 bcfd from less than 2 bcfd in 2007 (OGJ Online, Feb. 2, 2015).

"Increased natural gas production in the US has also led to pipeline modifications that have affected Canadian exports," said NEB, noting that the Rockies Express Pipeline (REX) used to transport up to 1.8 bcfd eastward from production in the US Rockies to markets in the Midwest (OGJ Online, Aug. 13, 2015).

"However, as production of natural gas in the US East increased, the REX was modified and now also moves natural gas westward from Ohio to Midwest markets," said NEB. "This pipeline modification has further increased competition in the Midwest for Canadian exports."

Statoil brings first subsea gas compression plant online

Statoil ASA has brought the first subsea gas compression plant online at Aasgard field in the Norwegian Sea. The firm says the technology will add 306 million boe over the life of the field.

Compression closer to the well increases recovery as well pressure decreases over time. Traditionally, compression plants are installed on platforms or onshore. The Aasgard subsea plant is on the ocean floor in 300 m of water close to the wellhead.

Statoil says that moving gas compression from the platform to the wellhead increases recovery rates and the life of a field. Prior to gas compression, gas and liquids are separated out and, after pressure boosting, recombined and sent by pipeline about 40 km to Aasgard B.

Recovery from the Midgard reservoir on Aasgard will increase to 87% from 67%, and to 84% from 59% in the Mikkel reservoir, the company said. Siri Espedal Kindem, senior vice-president for Statoil's Aasgard operations, said that the life of both reservoirs will be extended to 2032.

Statoil's subsea gas compression project cost about 19 billion kroner and took more than 5 years to complete (OGJ Online Nov. 10, 2010).

Statoil Brazil lets contract for Peregrino development

Statoil Brazil, on behalf of its partners in the Peregrino field license, has let a contract to Wood Group to provide 4-year operations and maintenance for the Alpha and Bravo wellhead platforms as well as modification services for both units and the Peregrino floating production, storage, and offloading vessel.

Peregrino field lies 85 km offshore Brazil in the Campos basin in 100 m of water in the BMC-7 and BMC-47 licenses. Statoil holds 60% ownership and operates the field; Sinochem holds the remaining interest. Earlier this year, the companies submitted a plan of development for the $3.5-billion second phase of the field to Brazil's National Agency of Petroleum, Natural Gas, and Biofuels (OGJ Online, Feb. 27, 2015).

The field, which is Statoil's first and largest operatorship outside the Norwegian Continental Shelf, started production on April 2011 and produces about 90,000 b/d of oil. Peregrino has produced more than 90 million bbl of oil since start of production (OGJ Online, Apr. 11, 2011).

The contract's scope includes offshore services and covers all production processes and equipment except drilling services and introduces a new operating model for the field.

Wood Group has been operating the two wellhead platforms since 2009 and has supported the Peregrino project throughout its development.

Woodside lets contract for Laverda, Cimatti fields

Woodside Petroleum Ltd. has let a front-end engineering and design contract to Norway's Aibel Singapore for a proposed subsea tie-back of Laverda and Cimatti oil fields to the Ngujima-Yin floating production, storage, and offloading vessel stationed on nearby Vincent oil field offshore Western Australia.

The move has come as a result of continuing studies by Woodside on the aggregation of undeveloped oil resources in the Exmouth subbasin with maximum use of existing systems.

The Ngujima-Yin FPSO will undergo modifications to its topsides, hull, and turret to accommodate the new fields. Aidel's work includes management, engineering, and provision of procurement services for the FEED contract, which also contains an option for execution of the development phase. Final investment decision is expected during second-quarter 2016.

Laverda and Cimatti are referred to as a Greater Enfield development project, which plans to access 70 million boe from the two fields.

The project concept comprises as many as 14 wells tied back to the Ngujima-Yin vessel via a 16-in. rigid production flowline and a 10-in. flexible production riser.

Modifications to the FPSO include the addition of a low-salinity water treatment plant, injection pumps, and turbine drivers. There also will be new inhibitor injection facilities, multiphase pumps, variable speed drives and control system, plus a subsea control system for the additional wells and brownfield modifications to the vessel and turret to facilitate the changes.

Suncor to add 10% interest in Fort Hills oil sands project

Suncor Energy Inc., Calgary, has agreed to acquire 10% working interest in the Fort Hills oil sands project from Total E&P Canada Ltd. for $310 million (Can.), or $230 million (US). The deal is expected to close by yearend.

The $15-billion, 180,000-b/d project is in Alberta's Athabasca region, 90 km north of Fort McMurray. Construction activities are 40% complete, and start-up is expected by yearend 2017.

Suncor also will acquire a further proportionate interest in Fort Hills related logistics, including pipelines, storage terminals, and third-party pipeline capacity agreements.

As a result of the deal, Suncor's incremental capital increase to Fort Hills is estimated at just more than $1 billion, of which $700 million is remaining project spend.

Suncor says the acquisition of the additional working interest also presents an opportunity for the company to lower its capital cost per barrel and enhance its projected return on the Fort Hills project.

Meanwhile, Arnaud Breuillac, Total's exploration and production president, commented on the deal from his company's perspective, "As a result of a full comparative analysis of its global asset portfolio in the context of lower oil prices, Total has decided to reduce its exposure to Canadian oil sands projects.

"Following the suspension of the Joslyn project at the beginning of 2015, the sale of this minority interest will reduce our capex outlay in the Fort Hills project by over $700 million [(Can.)]-about $530 million [(US)]-from now until end-2017, and help us deliver on our global capex reduction target," Breuillac said.

Following completion of the deal, Fort Hills Energy LP's partners will comprise Suncor with 50.8% working interest, Total E&P Canada Ltd. 29.2%, and Teck Resources Ltd. 20.0%. Suncor is the developer and operator of the Fort Hills project through an operating services contract.

PROCESSINGQuick Takes

Neste advances reconfiguration of Finnish refinery

Neste Corp. has let a contract to Neste Jacobs Oy to provide engineering, procurement, and construction management (EPCM) services related to the reconfiguration of its 3 million-tonne/year Naantali refinery in Finland (OGJ Online, Oct. 7, 2014).

The Naantali reconfiguration comes as part of Neste's October 2014 decision to improve the competitiveness of its overall refining operations by integrating its Naantali refinery with its 9.8 million-tpy Porvoo refinery so that the sites will operate as a single Finnish refining system, Neste and Neste Jacobs said.

While a precise value of the contract was not disclosed, Neste earlier said it would invest €60 million into Naantali's reconfiguration, which is to involve various utility-related enhancements intended to simply the refinery's structure and improve its processing efficiency ahead of its integration with Porvoo (OGJ Online, Apr. 20, 2015).

Following its reconfiguration, the Naantali will continue to produce diesel and specialty products, including solvents and bitumen, and maintain an important role in producing feedstocks, such as vacuum gas oil, for production lines in Porvoo.

Additionally, gasoline components produced at Naantali will be refined into finished products at Porvoo, with Naantali's terminal capacity to be used for distributing Porvoo's gasoline production.

Consolidation of the two Finnish refineries also will enable Neste to increase diesel output alongside a simultaneous reduction in heavy fuel oil production from the integrated unit.

With the €500-million refining consolidation and integration program proceeding as planned to date, the new Naantali-Porvoo operating model remains on schedule to be fully commissioned by mid-2017, Neste said.

Neste also previously let a contract to Neste Jacobs to provide EPCM services for a €200-million solvent deasphalt (SDA) feedstock pretreatment unit to be built at Porvoo as part of the integration project (OGJ Online, Aug. 5, 2015).

The SDA unit, which aims to improve the refinery's production structure as well as optimize its crude slate, is scheduled for start-up in 2017.

Second fire within a month hits Pemex's Tula refinery

Mexico's Petroleos Mexicanos (Pemex) has extinguished the second fire within a 2-week period at its 315,000-b/d Miguel Hidalgo refinery in Tula, Hidalgo state.

The latest fire, which occurred on Sept. 21 at 10:35 a.m. local time following a leak of an unidentified substance in heater BA-701 of the U-700-1 diesel hydrotreater, has been completely controlled, with one injury reported as a result of the incident, Pemex said.

Repair work to ruptured coils in the impacted equipment is scheduled to begin shortly, and other units at the refinery continue to operate normally, the company said.

Pemex did not disclose further details regarding the incident, including either its impact to production at the site or the potential cause of the fire.

A timeline for repairs to the affected unit remains unavailable.

On Sept. 9, Pemex extinguished a fire which broke out in the area of the refinery's burners following a leak of an unidentified substance from a fractured vent line (OGJ Online, Sept. 11, 2015).

Earlier in the year, a fire occurred in a leaking hydrogen compressor at the refinery's resid hydrodesulfurization, resulting in minor damages and only a brief interruption to production (OGJ Online, Mar. 9, 2015).

TRANSPORTATIONQuick Takes

Enterprise brings Rancho II oil pipeline into service

Enterprise Products Partners LP (EPP), Houston, reported its 88-mile, 36-in. Rancho II crude oil pipeline is now online and able to transport supplies between Sealy, Tex., and the company's Enterprise Crude Houston (Echo) storage terminal in southeast Houston (OGJ Online, Nov. 2, 2012).

The line, which will transport various grades of crude, condensate, and processed condensate, will link existing Eagle Ford assets and the recently announced 400-mile Midland-to-Sealy pipeline-expected in service by second-quarter 2017-with the larger Gulf Coast crude oil network (OGJ Online, May 1, 2015).

The Midland-Sealy line, with capacity of 540,000 b/d, will connect the company's Midland terminal with storage at Sealy. It will receive oil by truck and pipeline and deliver it to Sealy in as many as four segregated batches. It will carry West Texas Sour, West Texas Intermediate, and Light West Texas Intermediate crude as well as condensate.

Atlantic Coast applies to FERC for nod to build

Atlantic Coast Pipeline LLC applied to the US Federal Energy Regulatory Commission for permission to build its 564-mile interstate natural gas transmission pipeline.

The pipeline-owned by Dominion 45%, Duke Energy 40%, Piedmont Natural Gas 10%, and AGL Resources 5%-will transport as much as 1.5 bcfd southeast from Harrison County, W.Va., to Chesapeake, Va., and Robeson County, NC.

Dominion expects construction to begin in second-half 2016, pending regulatory approvals, for a fourth-quarter 2018 in-service date. The company estimates Atlantic Coast Pipeline will cost $5 billion.

Utility subsidiaries and affiliates of all four companies plus PSNC Energy have signed on as customers of the pipeline, subscribing 96% of the pipeline's capacity. Dominion and Duke Energy, for example, are building multiple natural gas-fired power stations and closing coal-fired ones.

Virginia Natural Gas, AGL's subsidiary in Hampton Roads, Va., said it needs more natural gas to meet peak customer demand in Chesapeake and Virginia Beach.

Dominion has completed surveying about 85% of a proposed route. Atlantic will file supplemental information with FERC when surveying is completed and propose the final route. The comment period for alternative routes ended Sept. 4 (OGJ Online, Aug. 6, 2015).

Dominion Transmission Inc. applied simultaneously to FERC for permission to build its Supply Header Project, including 38 miles of gas pipeline and modified existing compressor stations in West Virginia and Pennsylvania. The company expects the project to cost $500 million.