OGJ Newsletter

Jan. 22, 2018
International news for oil and gas professionals


Linn to divest Altamont Bluebell field interest

Linn Energy Inc., Houston, signed an agreement to sell its interest in properties in Altamont Bluebell field in the Uinta basin to an undisclosed buyer for $132 million.

The properties consist of 36,000 net acres in Utah with third-quarter 2017 net production of 1,450 boe/d, proved developed reserves of 5.8 million boe, and proved developed PV-10 of $75 million with field level cash flow of $8.4 million.

The deal has an effective date of Aug. 1 and is expected to close in this year's first quarter.

The deal follows the October 2017 agreements to sell nonoperated Williston basin interest for $285 million and Washakie field interests for $200 million, all part of a noncore divestiture program ongoing since the company's emergence from bankruptcy in February 2017 (OGJ Online, Oct. 23, 2017; Oct. 4, 2017). Linn continues to market its remaining noncore assets in the Permian along with its mature waterfloods in Oklahoma.

Ineos Oil & Gas forms six business units

Ineos Oil & Gas has organized its holdings into six business units. The division of chemical giant Ineos, London, has grown rapidly through acquisitions in the North Sea and UK onshore since 2015. The new units are:

• Ineos Oil & Gas Denmark, with offices and operations in Esbjerg and Gentofte, managing operated and nonoperated properties acquired from DONG Energy. Flemming Horn Nielsen is chief executive officer.

• Ineos Oil & Gas Norway, Stavanger. Sebastian Koks Andreassen is CEO.

• Ineos Oil & Gas UK, London, with David Brooks as CEO. The unit oversees Breagh-area assets in the southern North Sea and properties acquired from DONG Energy, most in the West of Shetlands area.

• Ineos FPS, including the Forties Pipeline System and related properties, including the Kinneil terminal and gas processing plant. Andrew Garnder is CEO.

• Ineos Shale, London, with licenses covering more than 1.3 million acres in England and Scotland. Ron Coyle is CEO.

• Ineos Upstream Services, a new venture based in London that will offer "a broad range" of services to Ineos and others. The unit currently has equipment for onshore seismic surveying, well stimulation, and well testing. Geoff Holmes is chief operating officer.

EIA: Natural gas in storage drops 359 bcf

Natural gas in underground storage across the Lower 48 was 2.767 tcf for the week ended Jan. 5, down 359 bcf from the previous week, the US Energy Information Administration estimated. Storage was 415 bcf less than for the same week last year and 382 bcf below the 5-year average of 3.149 tcf.

Analysts had expected a storage withdrawal of about 318 bcf. The 5-year average for this time of year is a withdrawal of 170 bcf. EIA said the current storage level puts total working gas within the 5-year historical range. Analysts attributed the last draw to winter weather.

Frigid conditions for 2 weeks in the US Northeast have given way to moderate temperatures until at least Jan. 13-14 when colder weather is forecast again.

Nichols named Shell Midstream Partners CEO

Shell Midstream Partners LP reported that after working 38 years with Royal Dutch Shell PLC, John Hollowell will retire as president and chief executive officer of general partner Shell Midstream Partners GP LLC, effective Mar. 31.

Kevin Nichols, vice-president of Shell Pipeline Co. LP, will succeed Hollowell and report to John Abbott, Shell's downstream director.

Nichols joined Shell in 1992 and has held roles with increasing responsibility within Shell's retail business and its downstream strategy group in London.

In 2012, Nichols was named vice-president for Shell responsible for business development, joint ventures, oil movements, and portfolio activity. He was involved with the formation of Shell Midstream Partners and has served as an officer of the master limited partnership since the IPO in 2014.

Exploration & DevelopmentQuick Takes

P'nyang South well confirms PNG field extension

Oil Search Ltd., Port Moresby and Sydney, reported success in its P'nyang South-2 ST1 appraisal well in P'nyang natural gas field in Papua New Guinea's Northwest Highlands.

The well, drilled in retention license PRL3, reached a total depth of 2,725 m and encountered gas in good-quality Toro and Digimu sandstone reservoirs. However, the underlying Emuk sands were largely water-bearing. Oil Search, as drilling operator, was pleased with the results, which confirm the extension of the large P'nyang field to the southeast.

Peter Botten, Oil Search managing director, said the company and its joint venture partners are now evaluating the well results, including the implications for 1C and 2C contingent gas resource volumes in the field.

Oil Search is confident that the drilling program's primary objective-to migrate 2C contingent resources to the 1C category in this area-will be met and support marketing and financing the expansion of the Papua New Guinea LNG project.

A recertification of the field's gas resources by an independent expert is under way. Results should be completed during this year's second quarter.

The JV also is working with the Papua New Guinea department of petroleum to progress the offer of a petroleum development licence (APDL 13) over P'nyang field. Work is also continuing to select an optimal development concept for the field.

Oil Search has a 38.5% interest, with ExxonMobil Corp. holding 49% and Japan's JX Nippon holding 12.5%.

Penguins field redevelopment marks North Sea upswing

Royal Dutch Shell PLC will install its first manned platform in the northern North Sea in almost 30 years with final investment decision to redevelop Penguins oil and gas field.

Penguins field lies in 165 m of water 150 miles northeast of the Shetland Islands. Discovered in 1974, the field was first developed in 2002 and is a 50% joint venture of operator Shell and ExxonMobil Corp. (OGJ Online, Sept. 4, 2001).

Shell's investment decision authorizes construction of a floating production, storage, and offloading vessel that will replace the retiring Brent Charlie platform. Oil and gas is processed through four existing drill centers tied back to Brent Charlie. The Sevan 400 FPSO was chosen as the development option for the field, which will add an additional eight wells.

Shell said its breakeven price on the redevelopment was below $40/bbl, and the FPSO is expected to have a peak production of about 45,000 boe/d. Oil will be transported via tanker to refineries and gas will be transported via the FLAGS pipeline to the St. Fergus gas terminal in northeast Scotland, Shell said.

Global engineering and construction company Fluor has been let the FPSO engineering, procurement, and construction contract. Sevan Marine ASA will provide the technology under license agreement for the circular FPSO and will provide technical support during the design phase of the project.

Wood Mackenzie Senior Research Analyst Fiona Legate said the Penguins expansion in early 2018 is a positive marker for the North Sea, ending "a cautious era during the downturn." The Penguins redevelopment is expected to produce about 80 MMboe. "This is the largest FID since Culzean in August 2015," Legate said (OGJ Online, July 21, 2017). WoodMac expects as many as 14 UK FIDs in 2018, and "Penguins is the second-largest by reserves," Legate said.

Octanex follows Eni in Exmouth Plateau withdraw

Octanex Ltd., Melbourne, has decided to withdraw from Exmouth Plateau permits WA-362-P and WA-363-P following the earlier withdrawal of operator Eni SPA from the permits and the joint operating agreements.

The two blocks are on the northern margin of the plateau some 300-400 km northwest of the Western Australian coastline. They contain the Gawain-1 and Galahad-1 wells drilled in 2011. The permits are in the third year of the first renewed exploration period.

Octanex said the work program for the fourth and fifth years require a new 1,000-sq-km 3D seismic survey and an exploration well in each permit. With Eni advising of its withdrawal, Octanex said it would no longer have been carried through all the coming exploration activity.

The company reviewed its position and its capacity to fund the program's fourth year, including the likelihood of finding another farminee within the required time period.

Following this review, Octanex has decided to withdraw completely and has provided Eni with its consent to surrender the permits.

Beach finds gas fields in Cooper drilling program

Beach Energy Ltd., Adelaide, has ended its first phase of fiscal year 2017-18 Western Flank Cooper-Eromanga basin drilling program on a high with four exploration successes from six wells, including the discovery of two natural gas fields.

The program in the company's wholly owned ex PEL106 and ex PEL91 found fields with the Lowry-1 and most recently with the Largs-1 DW1 sidetrack wells, while the Crawford-1 and Naiko-1 wells proved extensions of existing fields.

The gas exploration and appraisal campaign focused on Cooper basin's Southwest Patchawarra and Permian Edge play fairways in South Australia.

The most recent discovery-Largs-1 DW1-is in the Southwest Patchawarra play immediately south of Beach's Middleton gas facility. It targeted stratigraphically trapped gas in the mid-to-lower intervals of the Permian age Patchawarra formation.

The well first intersected reservoir sands of subcommercial quality but was then sidetracked to the northwest where it intersected three gas pay zones totalling 12 m of net pay across a 19.2 m gross interval.

Pressure data confirmed the shallowest gas sand to be a field discovery. Beach said further testing was not required and the well was cased and suspended as a future producer. The other three wells also were cased and suspended. All will be brought on stream progressively during the early part of FY 2018-19.

Meanwhile, Beach's drilling program in the permits will now move north to the Stunsail and Kalladeina fields in ex PEL91 where an oil appraisal and development campaign will be undertaken over the next 3 months.

Maverick basin well finds oil, gas in S. Texas

US Energy Corp. said it may take an increased working interest for up to four additional wells Dimmit County, Tex., after announcing positive results at it Beeler Ranch No. 1H in neighboring Zavala County.

The Beeler Ranch No. 1H, a 26,000-ft total measured depth dual-lateral well, produced 1,046 bbl of oil and 1,085 Mcf of natural gas during a 24-hr production test. The well had a flowing tubing pressure 1,118 psi on a 22/64-in. choke. where up to four additional wells may be drilled at an increased working interest for US Energy. The targeted the Georgetown formation and produced a cumulative 7,300 boe/d with an 81% oil cut during the first 8 days. According to US Energy, these results were in line with some of the upper-tier wells recently completed in the Georgetown formation.

US Energy holds adjacent acreage in Dimmit and Zavala counties. The Beeler Ranch well is operated by CML Exploration LLC, which operates 70 single and multilateral horizontal wells in the Maverick basin. Targets for the region include naturally fractured carbonates of the Austin Chalk, Buda, and deeper reservoirs in Zavala and Dimmit counties.

Deep Ravenspurn gas test plugged off UK

A well testing deep gas potential in the Ravenspurn area of the southern UK North Sea has been plugged, reports Premier Oil (OGJ Online, Dec. 7, 2016).

Before drilling, BP, with 85% equity interest, had said the Ravenspurn North Deep well would test the potential for a new gas play in Carboniferous strata "several hundred meters" below pay at the Ravenspurn ST2 platform operated by Perenco.

Perenco, with a 10% interest, operated the deep test during drilling and testing. Premier, with 5%, said the Rowan Gorilla VII jack up has been moved off location.

Drilling & ProductionQuick Takes

Tullow hires rig to restart TEN drilling

Tullow Oil PLC will restart development drilling in the TEN oil fields offshore Ghana with the Maersk Venturer drillship, for which it has signed a contract for up to 4 years.

It also will use the ship for drilling in Jubilee oil field.

Drilling in the TEN development area was suspended by a border dispute between Ghana and Ivory Coast, which was settled in the International Tribunal of the Law of the Sea last September (OGJ Online, Sept. 25, 2017).

The first well in the revived TEN program will be a production well in Ntomme field. It will be followed by a Jubilee production well. The rest of the schedule is under development.

Tullow said it and partners are considering use of a second rig. The other TEN fields are Tweneboa and Enyenra.

Tullow expects the TEN fields to produce an average 64,000 b/d gross this year.

In the fourth quarter of 2017, Tullow signed an agreement with the government of Ghana to sell associated gas from the fields. It expects gross gas sales of 4,200 boe/d this year.

Partners in the TEN development area are Kosmos, Anadarko, Ghana National Petroleum Corp., and Petro SA.

ADNOC lets FEED contracts for sour gas project

Abu Dhabi National Oil Co. (ADNOC) has awarded two front-end engineering and design contracts for ADNOC's offshore sour gas project involving Hail, Ghasha, and Dalma fields in the Arab formation.

ADNOC let the Hail and Ghasha FEED contract to Bechtel (UK) and let the Dalma FEED contract to TechnipFMC (UAE). It is estimated that the sour gas project could meet 20% of UAE's gas demand by the second half of the next decade.

Sultan Ahmed Al Jaber, UAE minister of state and ADNOC Group chief executive officer, said the contracts are part of a long-term strategy to develop UAE gas resources.

The ADNOC 2030 strategy envision higher oil production and enhanced gas development (OGJ Online, July 10, 2017).

Baker Hughes: Global rig count rises 32 in December

The global count of active drilling rigs increased by 32 month-over-month in December 2017 to average 2,089, according to Baker Hughes data. The count is up 317 compared with the December 2016 average.

Latin America gained 14 units in December to 195, up 11 year-over-year. Venezuela gained 10 units to 50. Colombia was up 1 unit to 25. Mexico gained 6 units to 15. Brazil declined 2 units to 14. Bolivia remained unchanged at 3 units.

In North America, the US was up 19 units to 930, a rally of sorts, as it marked the first increase in average monthly rigs running since July 2017. Canada was up 1 unit to 205. The US remained up 296 year-over-year, while Canada was down 4 units year-over-year.

The Asia-Pacific region dropped 4 units during the month to 217 but was up 25 rigs compared with its December 2016 average. India was up 2 units to 116. Indonesia remained unchanged at 34. Brunei Darussalam gained 1 rig to 2 units. China Offshore gained 1 unit to 32. Malaysia gained 1 unit to 7. Thailand increased 1 unit to 7. Japan remained unchanged at 1 unit. No data were reported for Myanmar.

Africa declined 8 units during the month to 77, down 1 year-over-year. Algeria decreased 5 units to 50. Seven countries remained unchanged, namely Angola, 2; Chad, 1; Congo, 2; Gabon, 2; Kenya, 8; Libya, 1; and Mozambique, 1.

Europe gained 2 units in December to 87, down 12 units year-over-year. Turkey lost 4 units to 18. Offshore UK declined 1 unit to 4.

Offshore producer Norway gained 3 units to 16. The Netherlands gained 2 units to 4. Germany gained 1 unit to 3. Italy gained 1 unit to 4.

The Middle East remained unchanged month-over-month at 378, up 29 from its December 2016 average. Iraq climbed 2 units to 54. Pakistan gained 1 unit to 20.

Saudi Arabia declined 4 rigs to 111.

Contracts let for Azeri Central East platform

Azerbaijan International Oil Co. has let two separate front-end engineering and design contracts to the SOCAR-KBR LLC joint venture for a production platform with drilling quarters, the Azeri Central East platform, for Azeri-Chirag-Gunashli (ACG) field in the Caspian Sea.

The contracts cover FEED services for the new platform along with associated tie-ins to existing platforms in ACG field and a separate contract for the subsea services FEED. The contracts' values were not disclosed.

SOCAR-KBR was formed in 2015 to advance Azerbaijan's efforts to create an Azerbaijan-based engineering firm.


Motiva lets hydrogen contract for Port Arthur refinery

Motiva Enterprises LLC, a wholly owned unit of Saudi Aramco's Saudi Refining Inc. (SRI), has let a new contract to Praxair Inc., Danbury, Conn., to supply additional hydrogen to its 600,000-b/d Port Arthur, Tex., refinery, the largest in the US.

Under the agreement, Praxair will increase the amount of hydrogen it delivers to the refinery to support capacity expansions of a hydrocracker and diesel hydrotreater Motiva completed at the site in 2016 to increase production of ultralow-sulfur diesel and other clean transportation fuels, Praxair said.

Expanded hydrogen supply under the contract will also support other unidentified, ongoing needs of the refinery.

Praxair, which began delivering hydrogen to the Port Arthur refinery in 1992, disclosed neither a value of the contract nor the increased volume of hydrogen to be delivered under the agreement.

Chinese operator starts up second PTA line

Tongkun Group Co. Ltd. subsidiary Jiaxing Petrochemical Co. Ltd. (JPCL) has commissioned a second purified terephthalic acid (PTA) unit at its petrochemical production plant at Zhejiang Zhapu Industrial Park in Jiaxing Port Area, Zhejiang Province, China.

Equipped with Invista Performance Technologies' (IPT) latest P8 proprietary PTA process technology, the first reaction train of the new PTA line reached its fully designed rate in 10 days after introduction of first feedstock, IPT said.

While IPT did not specify capacity of the new line, the new PTA plant previously was slated to have a nameplate capacity of 1.2 million tonnes/year, Tongkun said in a 2013 regulatory filing on the project.

In addition to the new PTA plant, JPCL operates a 1.67 million-tpy PTA line at the site that, commissioned in 2012, also is equipped with IPT's process technology, according to a PTA reference list posted to the service company's web site.

Borealis lets Belgian PDH FEED-study pact

Borealis AG, Vienna, has let a contract to Jacobs Engineering Group Inc., Dallas, to complete a front-end engineering design (FEED) study for its proposed propane dehydrogenation (PDH) plant at the operator's existing production site in Kallo, Belgium (OGJ Online, Feb. 2, 2017).

As part of the FEED study, Jacobs will deliver the basic design package for the inside and outside-battery limit areas of the planned PDH plant, the service provider said.

Jacobs, which completed a feasibility study for the proposed plant in June 2017, said it expects to complete its scope of work on the FEED phase of the project by mid-2018.

A value of the contract was not disclosed.

Borealis previously let a contract to Honeywell UOP LLC to provide licensing of its proprietary C3 Oleflex technology, basic engineering design, as well as services, equipment, catalysts, and adsorbents for the proposed Kallo PDH plant that, once in operation, would produce a targeted 740,000 tonnes/year of on-purpose, polymer-grade propylene.

If approved, the PDH plant is tentatively scheduled for start-up during second-half 2021.

Borealis plans to reach a final investment decision on the PDH project by yearend 2018, the company said in a late-September 2017 release.

Sinopec lets contract for Eni slurry technology

China Petrochemical Corp. (Sinopec) has let a contract to Eni SPA to provide technology licensing and basic engineering for a grassroots bottom-of-the-barrel upgrading plant to be built at Sinopec subsidiary Maoming Petrochemical Co. Ltd.'s more than 470,000-b/d Maoming integrated refining complex in Guangdong Province, China.

Alongside technology licensing for its proprietary Eni slurry technology (EST), Eni's scope of work under the contract will include delivery of the process design package and other services, including operational and technical training, as well as assistance during the development, implementation of detailed engineering, precommissioning, and startup phases of the plant, Eni said.

With a design capacity of 46,000 b/d (310 tonnes/hr) for refining heavy residue, the new unit will replace the refinery's existing petcoke production line to produce more environmentally friendly fuels in compliance with the International Maritime Organization's impending regulations requiring lower sulfur content in bunker fuels beginning in 2020 (OGJ, Jan. 1, 2018, p. 48; OGJ Online, Aug. 28, 2017).

Sinopec will be responsible for detailed engineering and construction of the project, Eni said.

To be the first full-scale, commercial use EST, Maoming's plant is scheduled to be completed by 2020.

Eni did not disclose of a value of the contract.

In October 2013, the Italian operator commissioned the first 23,000-b/d EST conversion plant for production of Euro 5-quality diesel and other high-quality streams at its 200,000-b/d Sannazzaro de' Burgondi refinery near Pavia, in Po Valley, Italy, following extensive testing of the slurry hydrocracking process technology at a 1,200-b/sd EST demonstration plant at the company's 120,000-b/d Taranto refinery.