OGJ Newsletter

April 10, 2017
International news for oil and gas professionals

GOP senators: Restore USGS mineral resources focus

Four Republican US senators asked President Donald J. Trump to refocus the US Geological Survey on its primary mission, which they said is to assess US mineral reserves, and to nominate an economic geologist as the US Department of the Interior agency's next director.

"Despite the clear directives in its Organic Act, the most important charge for the USGS-the surveying of our nation's mineral resource base-is today being severely shortchanged," Sens. Lisa Murkowski (Alas.), John A. Barrasso (Wyo.), James E. Risch (Ida.), and Bill Cassidy (La.) wrote in their Mar. 27 letter to the president.

"After a broad reorganization in 2011, the agency's Mineral Resources Program is now just one part of one of its seven mission areas, and accounted for just 4.6% of its total budget in fiscal 2016," they noted.

Minerals play an important role in modern society, the senators said as they argued that the USGS's lack of focus on its minerals mandate comes at a high price. "We must restore the mineral supply chain in the US, and one of our first steps must be the collection of the basic data needed to give us a true understanding and reliable inventory of the location and extent of America's mineral base," they said.

They urged Trump to choose an economic geologist, who would be trained in earth sciences and understand the economic and strategic value of domestic mineral production, to lead the agency.

"We strongly believe that having an economic geologist at the head of the USGS will embolden the agency to reprioritize its original minerals mandate and thereby allow the US to take much-needed action to restore our mineral security," the senators said.

More time sought to review EPA's RMP amendements

A proposed rule to further delay the effective date of the US Environmental Protection Agency's Risk Management Program (RMP) Amendments was signed by EPA Administrator Scott Pruitt. The rule will give the agency more time to complete its reconsideration of the amendments covering accidental chemical releases, which were issued on Jan. 17.

The proposed rule, which appeared in the Apr. 3 Federal Register, would make the amendments go into effect on Feb. 19, 2019. Comments on it must be received by May 19. EPA also will hold a public hearing on the proposed rule in Washington on Apr. 19.

"We want to prevent regulation created for the sake of regulation by the previous administration," Pruitt said. "Any expansion of the RMP program should make chemical facilities safer, without compromising our national security. Any new RMP requirements also should be developed in accordance with the explicit mandate granted to EPA by Congress."

Pruitt's proposal to further delay the amendments' effective date will give EPA time to evaluate multiple petitioners' objections and consider other issues that may benefit from additional public input, the agency said. It also will use the time to ensure that all of the RMP Amendments' provisions are in accordance with the explicit mandate Congress granted EPA under the 1990 Clean Air Act Amendments.

US Rep. Markwayne Mullin (R-Okla.) introduced Congressional Review Act legislation in early February to revoke EPA's amended risk management programs rule amendments that became final on Jan. 13 and was scheduled to go into effect on Mar. 14 (OGJ Online, Feb. 2, 2017).

He introduced the bill after the American Petroleum Institute, American Fuel & Petrochemical Manufacturers, US Chamber of Commerce, and 18 other business groups asked leaders of the 115th Congress the previous month to use the CRA to disapprove EPA's final risk management practices rule amendments.

PT Medco unit to acquire Inpex Natuna stake

PT Medco Daya Sentosa, a subsidiary of PT Medco Energi Internasional TBK, Jakarta, is acquiring all the remaining shares of Inpex Natuna Ltd., which owns 35% in South Natuna Sea Block B offshore Indonesia. Inpex Natuna is a unit of Inpex Corp., Tokyo.

Block B covers 11,155 sq km about 1,200 km north of Jakarta. Results from Block B in 2016 included 20,000 b/d of crude, 197 MMcfd of natural gas sales, and 6,000 b/d of LPG.

Inpex acquired a participating interest in the block in 1977, with crude oil production beginning in 1979 and natural gas in 2001.

Other interest holders are operator Medco E&P Natuna, 40%, and Chevron Corp., 25%.

Transfer of 30.361 million shares to Medco for $167 million is scheduled for the end of May (OGJ Online, Apr. 4, 2016).

Exploration & DevelopmentQuick Takes

ExxonMobil makes third oil discovery off Guyana

ExxonMobil Corp. affiliate Esso Exploration & Production Guyana Ltd. encountered 82 ft of high-quality, oil-bearing sandstone reservoirs while drilling the Snoek well on the Stabroek block offshore Guyana.

The well reached 16,978 ft in 5,128 ft of water and targeted similar aged reservoirs as encountered in previous discoveries at Liza and Payara. Snoek is in the southern portion of the 6.6 million-acre block, 5 miles southeast of the 2015 Liza-1 discovery (OGJ Online, May 20, 2015).

ExxonMobil earlier this year said it encountered more than 95 ft of oil-bearing sandstone in its Payara-1 well, which was drilled about 10 miles northwest of the Liza-1 discovery (OGJ Online, Jan. 12, 2017).

Following completion of the Snoek well, the Stena Carron drillship has moved back to the Liza area to drill the Liza-4 well.

Esso E&P Guyana is operator and holds 45% interest in Stabroek. Hess Guyana Exploration Ltd. holds 30% and CNOOC Nexen Petroleum Guyana Ltd. holds 25%.

Beach ends Cooper basin gas program with discovery

Beach Energy Ltd., Adelaide, has concluded its four-well gas exploration and appraisal program in South Australia's Cooper basin with a discovery in its wholly owned permit ex-PEL 91.

The Mokami-1 wildcat tested a western extension of the Permian-age southwest Patchawarra gas fairway and intersected 10.1 m of net pay across a 19.2-m gross section in the Patchawarra formation. The best drillstem test result flowed 8.6 MMcfd of gas along with a liquids content of 93 bbl/MMcf.

The well has been cased and suspended as a future producer.

Beach counted the overall program a success, notching three liquids-rich gas discoveries from the four wells. The Canunda-3 appraisal well and the Crocker-1 wildcat had been discoveries earlier in the drilling campaign.

Beach said Canunda-3 and Crockery-1 reinforced the potential for additional stratigraphically trapped gas in the southwest Patchawarra play, while the Mokami-1 step-out bodes well for future drilling in the frontier Permian 'Edge' play.

Planning for an expanded gas drilling program in the next financial year is under way.

On the Western Flank oil front, in permit PEL 182 where Senex Energy Ltd. is operator with 57% interest and Beach has 43%, the combine found oil with the Hoplite-1 well, which intersected a 17-m gross section with oil shows in the upper Birkhead formation in the Eromanga basin, but a drillstem test indicated subcommercial flow. Better reservoir with more oil shows was found with a sidetrack into the middle Birkhead, but again, not sufficient for a commercial development.

Nevertheless, the presence of oil in the Birkhead is deemed encouraging for a northern extension of the Western Flank play fairway in this permit.

In permit ex-PEL 91, the Pennington-5 appraisal well intersected 2.2 m of net oil pay in the Namur Sandstone and 1.8 m in the McKinlay Member as well as shows in the Birkhead. The well will be cased and suspended as a future producer. Beach has now spudded Pennington-6 in a continuation of the oil campaign.

Firms begin drilling in Russia's Krasnoyarsk region

Rosneft has started drilling the Tsentraino-Olginskaya-1 well in the Khatangsky license area on the Russian Arctic shelf. It is the first well drilled under the Laptev Sea, where water depth reaches 32 m.

The rig is on the shore of Khatanga Bay in the northern part of the Krasnoyarsk region.

Rosneft said geological exploration and 21 km of seismic studies revealed 114 oil and gas-bearing structures that were considered "promising." Preliminary estimates suggest that the Laptev Sea's potential geological resources could reach 9.5 billion tons of oil equivalent.

During summer navigation in 2016, more than 8,000 tons of cargo were delivered from the seaport of Arkhangelsk to the drilling site. Cargo included the drilling rig, other equipment and materials for drilling, and accommodation modules. A year-round research based is near the drilling site.

The drilling is performed by RN-Burenie, Rosneft's in-house service company.

Separately, PJSC Lukoil began drilling a well in the Vostochno-Taymyrsky license area, also in Krasnoyarsk. Lukoil said No. 1P is a vertical six-string well that will tap Lower Cambrian strata in a drilling effort expected to last a year.

Lukoil won the subsoil use rights for the license area in August 2015, and has completed a 2D seismic survey of 2,501 km that began in early 2016.

More than 20,000 tons of material and equipment required for drilling were delivered to the drill site via the Northern Sea route.

Drilling & ProductionQuick Takes

Elusive Taq Taq reserves cut by two thirds

The partnership operating Taq Taq oil field in the Kurdistan region of Iraq is drilling a well to test the northern reach of the free-water level after an independent study cut proved and probable reserves by two thirds (OGJ Online, Mar. 13, 2013).

Depending on results of the TT-29z well, a similar well might be drilled to test the southern extension, according to Genel Energy PLC, London. Genel holds 55% of the TTOPCO partnership with Addax Petroleum Corp., Houston, part of the Sinopec Group. Genel's working interest is 44%.

The study, by McDaniel & Associates, lowered Taq Taq reserves to 59 million bbl from a yearend 2015 estimate of 172 million bbl.

Genel said the change follows reassessment of the gross rock volume above the oil-water contact and fracture porosity of the undrained Cretaceous Shiranish reservoir.

The study noted "significant uncertainty" in Taq Taq reserves, dependent on Shiranish fracture porosity in the unswept part of the reservoir. The factor is difficult to estimate.

Production has dropped to 19,000 b/d from 36,000 b/d at the end of 2016. Water breakthrough has accelerated production declines of key wells, Genel said. Taq Taq has produced 207.9 million bbl.

The company expects results of the TT-29z well by midyear.

Eni to drill two subsea wells in Goliat field

Eni Norge AS plans to drill two subsea wells in Goliat field to start production from the Snadd discovery in the Barents Sea offshore Norway. The Snadd reservoir lies between the Realgrunnen and Kobbe reservoirs, which already are producing.

The Norwegian Petroleum Directorate (NPD) estimates this will increase Goliat's oil reserves 7.5 million bbl to about 200 million bbl. Snadd was mentioned in Goliat's plan for development and operation (PDO). NPD has approved Eni's application for a PDO exemption.

Eni Norge plans to drill a production well and a water-injection well in Snadd, with start-up anticipated later this year. The wells will be drilled from the subsea equipment on Goliat.

Goliat was the first oil field to start production in the Barents Sea. Eni developed it by using a floating cylindrical production and storage vessel with a capacity of 1 million bbl.

Statoil gets okay for Trestakk PDO in Norwegian Sea

Norway's Ministry of Petroleum and Energy has approved the plan for development and operation (PDO) of the Statoil ASA-operated Trestakk discovery on the Halten Bank in the Norwegian Sea.

Field development comprises a subsea template and a tied-in satellite well. Three production wells and two gas injection wells also will be drilled. Statoil estimates that the field has recoverable volumes of 76 million boe, most of which is oil. Tied in to the Asgard A production vessel, Trestakk is expected to come on stream in 2019.

"The Trestakk volumes are an important contributor in maintaining profitable operation of the Asgard A vessel up to 2030," explained Siri Espedal Kindem, Statoil head of operations, north cluster. "It also enables us to extract more of the original Asgard field volumes."

Statoil says project investment is calculated at about $640 million, almost half of the original estimate, as a result of concept choice, simplification, and optimized scope. The firm also says it expects to recover more oil than originally expected.

"This is a good example of what we are able to achieve in collaboration with our license partners and suppliers by innovative thinking and spending enough time on maturing the best concept choice," said Torger Rod, Statoil head of project development.

Discovered in 1986 by the 6406/3-2 well, Trestakk lies in 300 m of water 20 km south of Asgard (OGJ Online, Nov. 1, 2016). FMC Technologies Inc. and Technip Norge AS are slated to jointly handle engineering, procurement, construction, and installation, and Aker Solutions ASA will handle topside work at Asgard A (OGJ Online, Nov. 4, 2016).

Statoil holds 59.1% interest in Trestakk. Partners are ExxonMobil Exploration & Production Norway AS 33% and Eni Norge AS 7.9%.

Oil production begins from Flyndre field in North Sea

Maersk Oil has started production from Flyndre field in the UK and Norwegian North Sea. Oil is traveling 25 km via pipeline to the Repsol Sinopec Resources-operated Clyde platform.

Production from Flyndre field is expected to peak at 10,000 bo/d and last until at least 2023. The field, discovered in 1974, lies 293 km southeast of Aberdeen on Blocks 30/13 and 30/14 in the UK North Sea and 325 km west-southwest of Stavanger on Block 1/5 (PL018C) in the Norwegian North Sea.

Flyndre is developed as a subsea tie-back to the Clyde platform with a single production well. The export route takes production from the platform via the Repsol Sinopec-operated Fulmar platform and onwards to Teesside via the Norpipe system.

Partners in the Flyndre field development are Maersk Oil UK Ltd. with 65.941% interest, Repsol Sinopec Resources UK Ltd. 22.739%, Repsol Sinopec North Sea Ltd. 4.24%, Maersk Oil Norway AS 6.255%, Statoil Petroleum AS 0.471%, and Petoro AS 0.354%.


Dow close to startup of Freeport ethylene plant

Dow Chemical Co. has completed construction of the previously announced 1.5 million-tonne/year ethylene production expansion and upgrade project at its petrochemicals manufacturing complex in Freeport, Tex. (OGJ Online, June 26, 2014; Oct. 29, 2012).

With construction activities wrapped, the new unit is now progressing through the commissioning phase for planned startup by midyear, Dow said.

A foundational element of Dow's $6-billion US Gulf Coast investment program to utilize low-cost and advantaged US shale gas feedstock, the TX-9 cracker raises total olefins capacity at the Freeport site to more than 4 million tpy, the company said.

Once fully commissioned, the new unit will feed a series of Dow's other investments in Texas and Louisiana to increase specialty derivatives capacity, all of which are slated for startup between 2017-18.

Last year, Dow also fully commissioned a 750,000-tpy propane dehydrogenation unit at Freeport as part of the Gulf Coast ethylene and derivatives investment program (OGJ Online, Mar. 9, 2016).

Total's Port Arthur ethane cracker contract detailed

CB&I, Houston, has confirmed a previously announced contract award from Total SA's Houston-based subsidiary Total Petrochemicals & Refining USA Inc. (TPRI) to provide engineering, procurement, and construction services for a 1 million-tonne/year ethane cracker to be built at TPRI's refining and petrochemical manufacturing site in Port Arthur, Tex. (OGJ Online, Mar. 27, 2017).

The EPC contract, valued at about $1.3 billion, follows Total's earlier award to CB&I for front-end engineering and design services and ethylene technology licensing for the proposed Port Arthur cracker project (OGJ Online, Sept. 24, 2015), CB&I said.

Originally licensed to use seven of CB&I's highly selective Short Residence Time (SRT) cracking heaters, the new cracker now will use six SRT-III pyrolysis heaters, the service provider said.

CB&I's confirmation of the EPC contract follows a Mar. 27 announcement from Total, Nova Chemicals Corp., and Borealis AG that the three have entered a preliminary partnership agreement to build the grassroots steam cracker at TPRI's Port Arthur operations, which alongside Total's 178,000-b/d refinery, also hosts BASF Corp. (60%)-TPRI (40%) jointly owned BASF Total Petrochemicals LCC's more than 1 million-tpy ethylene plant (OGJ Online, June 4, 2015).

As part of the proposed partnership, the three companies also would jointly build and own a 625,000-tpy polyethylene (PE) production plant based on Borealis' proprietary Borstar PE process at Total's petrochemical production site in Bayport, Tex.

With final investment decision on the projects due by yearend, the $1.7-billion ethane cracker and Borstar PE unit, if approved, would reach startup in late 2020, according to Total, which plans to hold 50% ownership interest in the proposed partnership.

Gazprom lets contract for Amur gas plant

PJSC Gazprom, through its general contractor partner NIPIgazpererabotka (Nipigaz), has let a contract to China National Petroleum Corp. affiliate China Petroleum Engineering & Construction Corp. (CPECC), to provide related engineering, procurement, and construction services for its now 42 billion-cu m/year grassroots Amur natural gas processing plant under construction near Svobodny in Russia's far-east Amur region (OGJ Online, July 29, 2015).

CPECC will participate in design, manufacturing, and delivery of equipment and construction of compressor stations as well as gas drying, purification, and fractionation plants for the project, Gazprom said.

A value of the soon-to-be-signed EPC contract between CPEEC and Nipigaz was not disclosed.

Previously planned at a capacity of 49 billion cu m/year, the Amur gas processing plant-which also will include a 60 million-cu m/year helium plant and connect to PSJC Sibur Holding's long-planned integrated ethylene, polyethylene, and polypropylene production complex under construction at Tobolsk in Western Siberia's Tyumen region-is scheduled to begin operation of its first process train sometime in 2018 (OGJ Online, Jan. 21, 2016).


Total-led group outlines Papua LNG project timeline

The Total Papua New Guinea-led group at the proposed Elk-Antelope natural gas field development known as Papua LNG has outlined an expected timeline for the project.

Philippe Blanchard, Total Papua New Guinea's managing director, says the joint venture expects to start its front-end engineering design work by yearend or early 2018.

All being well, this will lead to a final investment decision at about yearend 2018 or the beginning of 2019.

The JV is currently completing an appraisal program at the fields and finalizing design aspects.

Elk-Antelope fields are held in retention lease PRL-15 in the Eastern Highlands.

The overall plan is a pipeline to the coast feeding into an LNG facility nearby-or integrated with-the ExxonMobil Corp.-led group's Papua New Guinea-LNG plant at Caution Bay near Port Moresby.

The upstream central processing facility will be built close to the Purari River west of the Herd Base, which serves Elk-Antelope field operations.

There will be about 75 km of onshore pipeline corridor descending from the Eastern Highlands processing plant south to the Purari River delta area to west of Kerema and then 265 km of offshore pipeline corridor roughly following the coastline to Caution Bay. There will be two separate lines: one for gas and one for condensate.

ETP launches supplemental open season for Bakken line

Dakota Access LLC and Energy Transfer Crude Oil Co. LLC (ETCO), units of Energy Transfer Partners LP (ETP), have launched a binding supplemental open season to solicit shipper commitments for transportation service for Bakken-Three Forks production to reach multiple markets through their respective pipeline systems.

Dakota Access and ETCO, the entities responsible for developing, owning, and operating the Bakken pipeline, each anticipate that incremental transport capacity for Bakken-Three Forks production will be determined based on committed subscriptions made by shippers during the supplemental open season, which commenced on Mar. 29.

The supplemental open season includes local tariff service on the Dakota Access pipeline from Bakken-Three Forks to Patoka, Ill. It also provides interested parties with the opportunity for joint tariff service from Bakken-Three Forks to Nederland, Tex., through a commitment to both the Dakota Access and ETCO pipeline systems.

ETP early in February received from the US Army Corps of Engineers the final easement necessary to complete the Dakota Access project (OGJ Online, Feb. 9, 2017).