GENERAL INTERESTQuick Takes
ExxonMobil, PAA to build Permian crude pipeline
ExxonMobil Corp. and Plains All American Pipeline LP (PAA) have signed a letter of intent to build a common-carrier pipeline to transport more than 1 million b/d of crude oil and condensate from multiple locations in the Permian basin to the Texas Gulf Coast.
The pipeline would feature loading points in both Wink and Midland, Tex. and delivery points in Webster, Baytown, and Beaumont, Tex. The companies said existing pipeline corridors would be used when possible, to limit potential community and environmental disruptions.
PAA earlier this year concluded an open season to build its 585,000-b/d Cactus II crude oil pipeline system between the Permian basin and Corpus Christi-Ingleside, Tex., with 545,000 b/d fully committed under long-term third-party shipper agreements. The company expects Cactus II, which also has an origin point in Wink, to enter service in third-quarter 2019.
Canada retains Carruthers for pipeline work
The Canadian government has retained the former head of a pipeline project it rejected to assess the Trans Mountain oil pipeline and to advise a new crown corporation that will manage system expansion. Under contract to the Canada Development Investment Corp., John Carruthers will conduct due diligence on the system connecting Edmonton, Alta., with Burnaby, BC, according to press reports.
As president of Northern Gateway Pipelines, Carruthers oversaw Enbridge’s proposal for a twin pipeline between Alberta and northern British Colombia.
The federal government rejected that proposal in November 2016 while approving Kinder Morgan’s Trans Mountain expansion and Enbridge’s Line 3 replacement between Alberta and the US (OGJ Online, Nov. 30, 2016).
The government last month agreed to acquire Trans Mountain to ensure completion of the expansion project after Kinder Morgan said it was stymied by opposition of the British Colombia and local governments and suspended work.
Nelson: Keep eastern gulf off-limits until 2027
US Sen. Bill Nelson (D-Fla.) filed an amendment to the annual national defense bill aimed at keeping oil exploration and production out of the eastern Gulf of Mexico for an additional 5 years. He made the June 7 move as a senior Armed Services Committee member a day after the American Petroleum Institute formally launched its Explore Offshore coalition to build support for oil and gas activity in US offshore areas which are off-limits currently (OGJ Online, June 7, 2018).
“Here we go,” Nelson tweeted in response to reports on June 6 that API had formed the coalition. “Like us, Big Oil doesn’t believe Florida is really ‘off the table’ to new drilling—despite what [Florida Gov. Rick] Scott and the Trump administration keep saying—and now they are making a new push to drill closer to Florida’s shores. We can’t let that happen!”
Scott, a Republican, announced on May 31 that he is running to defeat Nelson in November, when the senator up for reelection to a fourth term.
Nelson’s amendment would extend until 2027 the eastern gulf oil and gas moratorium, which is scheduled to expire in 2022. By making it an amendment instead of stand-alone legislation, he made it possible to require only 50 votes to be approved and added into the broader bill. Typically, 60 votes are required to get a stand-alone bill through the chamber, an official on his staff noted.
Exploration & DevelopmentQuick Takes
ExxonMobil advances Liza Phase 1 development
ExxonMobil Corp. has started drilling the first of 17 planned wells of Liza Phase 1 development offshore Guyana with production startup expected in 2020 (OGJ Online, Jun. 16, 2017).
Development drilling on Liza field on the 6-million-acre Stabroek block began in May. The company and its coventurers have so far discovered estimated recoverable resources of more than 3.2 billion boe on the block.
The Liza Phase 1 development includes a subsea production system and a floating production, storage, and offloading vessel, the Liza Destiny, designed to produce as much as 120,000 b/d of oil (OGJ Online, Jun. 22, 2017). Four subsea drill centers with 17 production wells are planned. Construction of the FPSO and subsea equipment is under way. A second FPSO with a capacity of 220,000 b/d is planned as part of Phase 2, and a third is under consideration for the Payara development. Together they will produce more than 500,000 boe/d.
Shell makes sixth find in Norphlet deepwater play
Shell Offshore Inc. reported its sixth oil discovery in the Norphlet geologic play in the deepwater US Gulf of Mexico.
Drilled to a total vertical depth of 29,000 ft, the Dover well encountered 800 net ft of pay in the Jurassic Norphlet. The well is in 7,500 ft of water about 170 miles offshore southeast of New Orleans on Mississippi Canyon Block 612.
The discovery lies 13 miles from the Appomattox host platform and is considered an attractive potential tieback, the company said. The Appomattox host platform is on location in the gulf and is expected to start production before yearend 2019.
Shell’s major deepwater hubs are positioned for production expansion through near-field exploration and additional subsea tiebacks. The company expects its global, deepwater production to exceed 900,000 boe/d by 2020, from already discovered, established areas.
Total seeks interest in Block 8 off Cyprus
Total SA is seeking an interest in a block off Cyprus west of where Turkish military vessels in February blocked drilling planned by Eni SPA (OGJ Online, Mar. 27, 2018).
Stephane Michel, president, Middle East and North Africa of Total Exploration & Production, told reporters after a meeting with Cypriot President Nicos Anastasiades that the company had applied for an interest in Block 8.
Eni holds 100% of the block, which is directly south of the island. Total and Eni are partners in Block 6, where Eni, the operator, early this year reported a natural gas discovery in its 1 Calypso NFW well (OGJ Online, Feb. 9, 2018).
The Saipem 12000 drillship was moving from the Calypso well to Block 3 in the northeastern part of the Cyprus Exclusive Economic Zone when it was turned away by Turkish ships.
Turkey disputes Cyprus’s offshore territorial claims, which it long has argued shouldn’t be addressed until unification of the island nation now divided between Greek and Turkish sectors.
Turkish Petroleum Corp., meanwhile, is preparing to drill off Cyprus with the Deep Sea Metro II drillship, which it acquired in 2016 in a liquidation auction.
Turkish President Recep Tayyip Erdogan confirmed the plans in a March summit with European Union leaders in Varna, Bulgaria. He said Turkish Cypriots would receive a share of any revenue from the production of hydrocarbons.
Iraq awards border-field rehab contracts
Iraqi Minister of Oil Jabbar Ali Al-Luiebi said he expects production to reach 500,000 bo/d from six fields to be rehabilitated under contracts awarded this month after a recent bid round.
Five of 11 blocks offered near the Iranian and Kuwaiti borders received no bids. In a last-minute change, the government assessed bids on the basis of net revenue-share. The contracts remain subject to final approvals.
Crescent Petroleum of Sharjah will receive contracts covering Klabat-Gumar and Khashm Al-Ahmar-Injana fields in Diala governate and Khudr Al-Mai field in Basra governate.
Contracts awarded to Geo-Jade Petroleum of China cover Naft Khana field in Diala governate and Howaiza field in Maysan governate. And United Energy Group of China will receive a contract for Sindbad field in Basra governate.
Equinor finds oil near gas strike off Norway
Equinor and partners have found oil in the Utsira High area of the Norwegian North Sea in a well that also confirmed the 2004 Verdandi natural gas discovery on license PL 167.
Calling the find commercial, Equinor estimated the 16/1-29 S “Lille Prinsen” well found 15-35 million boe of recoverable oil in its main target.
It also found oil in a shallower layer “with very good reservoir quality” but did not evaluate quantity.
The Odfjell Drilling Deepsea Bergen semisubmersible rig drilled the 16/1-29 S well to 1,987 m vertical depth, 2,001 m measured depth below sea surface, terminating in basement rock, according to the Norwegian Petroleum Directorate. Water depth is 114 m.
The well is northeast of Ivar Aasen oil field, about 2 km south of the Verdandi discovery well.
It encountered an oil column of 95 m total, with 17 m of efficient reservoir in clastic rocks with moderate to good reservoir quality. The oil-water contact is at 1,947 m below sea surface.
The shallower, unevaluated discovery, according to NPD, is in thin Eocene Grid sandstone layers totaling 10 m in an interval of about 30 m. About 5 m of pay was gas and 5 m oil.
Pressure data indicated depths below sea surface of 1,436 m for the gas-oil contact and 1,472 m for the oil-water contact.
The well cut 15 m of gas pay in Paleocene Heimdal and did not encounter the gas-water contact.
Equinor operates PL 167 with a 60% interest. Lundin Norway AS and Spirit Energy Norge AS hold 20% interests each.
Corridor suspends Old Harry work in Canada
Corridor Resources Inc., Halifax, has suspended exploration of a large structure in the Gulf of St. Lawrence, citing unexpected complexity of the geology and its failure to find a partner.
The 43,000-acre Old Harry structure is in 470 m of water straddling the Newfoundland-Quebec border. It’s one of the largest undrilled structures in eastern Canada.
Corridor Resources said it purchased a licensed copy of a controlled-source electromagnetic survey conducted over the Newfoundland side of the structure in 2017 and performed an integrated geotechnical review with 762 km of reprocessed 2D seismic data acquired in 1998 and 2002.
The review indicated more complexity than previous analysis had suggested.
“This has led us to believe the play could be more gas-prone than oil-prone and the overall hydrocarbon accumulation could be less than originally estimated,” the company said in a press release.
It said a 3D seismic survey over the whole structure would be needed to support drilling of an exploratory well. Without a partner, it can’t complete the work before expiration of the exploration license on the Newfoundland side in January 21.
“We reached this conclusion with the knowledge that the timelines for regulatory approvals for offshore projects are lengthy and are becoming increasingly challenging,” it said.
Khalimov gets E&P position at Tatneft
Rustam Khalimov was appointed first deputy general director for exploration and production of oil and gas at Tatneft Co., Almetyevsk, Tatarstan.
A Tatneft employee since 1987, he most recently served as deputy general director for development and production of oil and gas.
Drilling & ProductionQuick Takes
Permits sought for Chaveroo horizontal wells
Ridgeway Arizona Oil Corp., a wholly owned subsidiary of Hunter Oil Corp., Houston, has applied for permits to drill five horizontal wells to begin redevelopment of Chaveroo oil field in Roosevelt County, NM (OGJ Online, Aug. 12, 2016).
The wells will target fractured Permian-Guadalupian San Andres dolomite at about 4,500 ft with mile-long laterals.
Hunter Oil plans to drill as many as 84 horizontal wells in Chaveroo field, a 1960 discovery in which it holds a 100% working interest in about 16,000 acres.
Chaveroo has produced over 25 million bbl of crude oil from vertical wells drilled on 40-acre spacing. Hunter Oil estimates Chaveroo net reserves at 8.4 million boe proved and undeveloped, 3.4 million boe probable, and 10.2 million boe possible.
The firm also plans to redevelop nearby Milnesand field, a 1959 discovery, with horizontal wells. Milnesand, in which Hunter Oil holds a 100% interest in 7,400 acres, has produced 12 million bbl of oil from vertical wells on 40-acre spacing. Net reserves are estimated at 4.1 million boe proved and undeveloped, 1.8 million boe probable, and 4.3 million boe possible.
Borr Drilling buys 5 jack up rigs from Keppel
Keppel Corp. Ltd., a wholly owned subsidiary of Keppel Offshore & Marine Ltd., has sold five jack up rigs to Borr Drilling Ltd. for $745 million. One rig is scheduled to be delivered in late-2019 with four rigs to be delivered during 2020.
Two of the rigs, the Cantarell V and Paraiso II, were built for Grupo R and one for Falcon Energy Group. Keppel FELS has terminated the contracts. The other two rigs were being built in anticipation of demand.
PROCESSINGQuick Takes
Phillips 66 to expand Sweeny fractionation capacity
Phillips 66 is proceeding with an expansion of existing midstream operations at Phillips 66 Partners LP’s Sweeny hub in Old Ocean, Tex.
The project includes construction of two new 150,000-b/d NGL fractionators in Old Ocean, additional NGL storage capacity, and associated pipeline infrastructure, Phillips 66 said.
Scheduled to begin commercial operations in late 2020, the estimated $1.5-billion expansion project will increase overall NGL fractionation capacity at Sweeny to 400,000 b/d and enable access to 15 million bbl of total storage capacity, according to the operator.
The Sweeny hub currently has 100,000 b/d of fractionation capacity through Phillips 66 Partners’ Sweeny Fractionator One, 200,000 b/d of LPG export capability, and access to 9 million barrels of gross NGL storage capacity at nearby Phillips 66 Partners’ Clemens Caverns (OGJ Online, Feb. 18, 2016).
“We are pleased to move forward with the Sweeny hub expansion, a key part of our midstream growth strategy that further optimizes our integrated NGL value chain,” said Greg Garland, Phillip 66’s chairman and chief executive officer.
“The Sweeny hub is strategically positioned to provide fractionation capacity for rapidly growing Permian basin NGL production and access to US Gulf Coast petrochemical, fuels, and LPG export markets,” Garland added.
Alongside the planned expansion, Phillips 66 said it also has secured supply agreements for Y-grade NGL feedstock, including an agreement with DCP Midstream LP. which has an option to acquire up to a 30% ownership interest in the new fractionators.
The combination of DCP’s gathering, processing, and pipeline services with Phillips 66’s fractionation, storage, and export capabilities will offer Permian producers a full-service, wellhead-to-market solution, according to Garland.
Keyera approves Phase 2 of Wapiti gas complex
Keyera Corp. is proceeding with Phase 2 of its Wapiti natural gas gathering and processing project south of Grand Prairie, Alta. Phase 2 of the Wapiti gas plant will add another 150 MMcfd of sour gas processing to the 150-MMcfd Phase 1 of the plant currently under construction, Keyera said.
At an estimated cost of about $150 million, Phase 2 of the Wapiti plant is scheduled to be completed in mid-2020.
Alongside construction of Phase 2, Keyera said it also is expanding the Wapiti gathering system and the North Wapiti pipeline system—the two gathering systems that will deliver natural gas volumes to the Wapiti plant—by adding additional compression to each system.
The expansion of the Wapiti gathering system is supported by Paramount Resources Ltd.’s initial volume commitment on Phase 1 of the Wapiti gas plant, while the expansion on the North Wapiti Pipeline System is supported by incremental volume commitments from Pipestone Oil Corp.
Further capital investments in the Wapiti plant’s gathering systems are covered under existing agreements with Paramount and Pipestone, both of which include take-or-pay commitments, Keyera said.
Additional compression on the Wapiti gathering system is estimated to cost about $85 million with a target completion date in mid-2020. Including this compression expansion, the total cost of both phases of the Wapiti gas plant is estimated at about $705 million, the operator said.
Keyera said it expects additional compression on the North Wapiti pipeline system to add about $40 million to the cost of that project, bringing its total to $160 million.
Assuming timely receipt of all regulatory approvals and permits, the North Wapiti pipeline system is scheduled to be completed during second-half 2019.
First approved in May 2017, the Wapiti gas project is designed to serve producers in the liquids-rich Montney regions of northwestern Alberta (OGJ Online, June 14, 2017).
PDMI of Oman lets contract for petchem plant
Projects Development & Management International LLC (PDMI) of Oman has let a contract to SNC-Lavalin Group Inc., Montreal, to design and deliver a greenfield chloralkali polyvinyl chloride plant about 150 km southeast of the Omani capital of Muscat.
As part of the long-term contract, SNC-Lavalin will provide concept development to commissioning, including execution of initial engineering, master planning, and process technology evaluation and selection to support project financial investment decision approvals, the service provider said.
SNC-Lavalin said it expects to receive the subsequent engineering, procurement, and construction management contract for the project in first-quarter 2019, under which it will carry out the complete design and delivery, working alongside Omani contractors to maximize in-country value.
The service provider also will support operations and maintenance of the plant once completed.
At an overall capital cost of about $1.5 billion, the project will produce about 225,000 tonnes/year of PVC destined for the Asia Pacific, as well as about 140,000 tpy of sodium hydroxide that will support local industries.
SNC-Lavalin disclosed no further details regarding either the proposed petrochemical plant or the specific value of the contract award.
TRANSPORTATIONQuick Takes
AGL executes key deals for Victorian LNG jetty
AGL Energy Ltd., Sydney, has executed two key agreements for its proposed LNG import jetty at Crib Point on the west Gippsland coast of Victoria.
Firstly, AGL has made development and gas transportation agreements with APA Group for the development and construction of the Crib Point-Packenham gas pipeline and the ongoing transportation of gas from the proposed LNG jetty to the domestic market.
Under this agreement APA will source long lead-time items for the proposed pipeline. Construction and operation of the line is still subject to regulatory approvals, the granting of a pipeline license, and a final investment decision by AGL.
Secondly, AGL has made work, lease, and berthing and jetty agreements with the Port of Hastings Development Authority for the long-term use of the Crib Point jetty berth No. 2. The PHDA will begin jetty remediation work to prepare for AGL’s exclusive occupation of the berth No. 2 for the continuous mooring of a floating storage and regasification unit (FSRU). Again, the agreement is subject to regulatory approvals and an FID by AGL.
AGL says it hopes to reach FID for the project during the 2019 fiscal year and aims to start gas deliveries into the Victorian and other southern states domestic market during the 2021 fiscal year.
The company is progressing its environmental approvals and licensing requirements and continues to negotiate other key commercial arrangements for LNG supply and for long-term charter of the FSRU.
AGL is also working closely with the local community in its development plans for the Western Port region.
The plan to use Crib Point has the merit of an existing deepwater jetty that currently functions as a petrol import point. Selection of another location would require construction of a new jetty and significant excavation of the bay floor.
Gladstone LNG ships 200th cargo from Curtis Island
The Gladstone LNG (GLNG) project led by Santos Ltd., Adelaide, has successfully delivered its 200th cargo of LNG from its Curtis Island plant near Gladstone on Queensland’s east coast.
The YK Sovereign LNG carrier docked at the Incheon reception terminal in South Korea with the cargo last week.
The two-train Curtis Island plant has a capacity to produce a total of 7.8 million tonnes/year of LNG. Much of its gas supply is coal seam gas (CSG) derived from fields in the Surat and Bowen basins of southeast Queensland.
The first train was brought on stream in September 2015 and the first cargo shipped a month later.
The second LNG train was brought on stream in May 2016.
The GLNG project is currently investing $900 million (Aus.) in upstream production systems this year, including the drilling of 300 CSG wells, which will help maintain gas feedstock for the plant.
Last month GLNG reported a final investment decision had been reached for the $400-million (Aus.), 137-well Arcadia CSG project in the Bowen basin of southeast Queensland (OGJ Online, May 31, 2018).
The initial phase of the Arcadia development will deliver a peak of more than 75 terajoules/day of gas to supply the GLNG plant as well as the domestic gas market in eastern Australia.
Arcadia is expected to be brought on stream late in 2019 and produce a total of 27 petajoules of CSG by 2022.
Santos is operator of GLNG with 30%. Total has 27.5%, Petronas 27.5%, and Kogas 15%.