GENERAL INTEREST Quick Takes
Energy Transfer to acquire SemGroup in $5-billion deal
Energy Transfer LP will acquire SemGroup Corp. in a deal valued at $5 billion, the acquiring company reported Sept. 16. The acquisition will increase Energy Transfer’s scale across multiple regions and provide increased connectivity for its crude oil and NGL transportation businesses, the company said.
Assets acquired include the Houston Fuel Oil Terminal (HFOT) on the Houston Ship Channel with 18.2 million bbl of crude oil storage, five deepwater ship docks, and seven barge docks. Energy Transfer plans to build a crude oil pipeline, the Ted Collins pipeline, to connect HFOT to Energy Transfer’s Nederland, Tex., terminal.
Energy Transfer’s acquisition also will add crude oil gathering in the DJ basin in Colorado and the Anadarko basin in Oklahoma and Kansas, as well as crude oil and NGL pipelines connecting both to crude oil terminals in Cushing, Okla. The acquisition likewise will give Energy Transfer a crude oil gathering and transportation presence in western Canada’s Alberta basin. Energy Transfer’s crude oil assets on the Gulf Coast will further benefit from incorporating the Maurepas Pipeline and its connections to the St. James refining complex, the company said.
The multibillion-dollar transaction price, which includes assumption of debt, is based on a unit and cash transaction valued at the $17/share Sept. 13 closing price of Energy Transfer common stock.
The 75-mile, 500,000-b/d Ted Collins pipeline, in conjunction with the combined companies’ other oil transportation assets, will provide immediate access to more than 1 million b/d of crude oil export capacity, with plans to expand to more than 2 million b/d at the Nederland and the HFOT terminals. Energy Transfer anticipates commercial operations to begin in 2021.
Energy Transfer plans to expand its Nederland terminal to handle very large crude carriers.
ExxonMobil to sell upstream assets in Gippsland basin
ExxonMobil Corp. is looking to sell its 50% stake in the Gippsland basin oil and gas development in Australia’s Bass Strait as part of a broader review of its portfolio of assets around the world.
The assets, which ExxonMobil subsidiary Esso Australia owns in a joint venture with BHP Group, include 19 offshore platforms, the Longford and Long Island Point plants, associated infrastructure, and production fields. The joint venture has long been the mainstay oil and gas supplier for southeastern Australia, but output is in decline.
“ExxonMobil putting its entire Gippsland basin upstream portfolio up for sale represents big news for the Australian upstream and gas market,” said Angus Rodger, research director of Wood Mackenzie.
“As a pivotal producer on the east coast, the assets play a key role in supplying gas to Australia’s biggest market. As such, we would expect interest to be strong from domestic players that wish to gain greater exposure to rising gas prices, of which there are a significant number.”
Rodger added, “That said, these are complex, mature assets. We believe this will lead to a far smaller pool of realistic buyers, who will have to get comfortable with the age of the assets, declining production and significant decommissioning liabilities. The fact that a previous effort to offload the Gippsland oil assets failed due to uncertainty over abandonment costs highlights how big an issue it will be, but also suggests any new operator would look to extend and increase production from the portfolio to delay the onset of decommissioning spend.”
DOE to invest in offshore EOR R&D projects
The US Department of Energy will invest nearly $9 million in three offshore enhanced oil recovery research and development projects, DOE’s Fossil Energy Office reported.
FEO said the projects aim to enhance the potential for EOR in offshore settings by advancing promising proof-of-concept technologies to reduce subsea facility complexity, increase control and monitoring, and enable greater tieback distances to production facilities. These projects will focus on maximizing the value of conventional resources in offshore settings, FEO said.
The projects will be executed in two phases, it said. Phase 1 will involve proof-of-concept validation of tools, technologies, and processes in a laboratory or field analog setting. Phase 2 will consist of an integrated full-scale prototype demonstration in a relevant environment to persuade stakeholders to continue developing the technology to the commercialization phase.
DOE’s National Energy Technology Laboratory will manage the three projects, which involve:
- Improving EOR’s efficiency and capability in offshore wells through a $5.25-million Project ULTRA which uses underwater laser telecommunications and remote access technology.
- Enhancing offshore EOR by enabling longer, safer, and cheaper subsea well tiebacks in Houston-based Subsea Shuttle LLC’s $5-million project to which DOE is contributing nearly $2.9 million.
- Developing an advanced multidimensional capacitance sensors-based subsea multiphase mass flow meter to measure and monitor offshore EOR systems.
Exploration & Development Quick Takes
ExxonMobil reports oil discovery off Guyana
ExxonMobil Corp. reported making an oil discovery offshore Guyana with the Tripletail-1 well in the Turbot area on the Stabroek block, adding to an estimated recoverable resource of 6 billion boe. Tripletail-1, drilled in 6,572 ft of water 3 miles northeast of the Longtail discovery, encountered 108 ft of a high-quality oil-bearing sandstone reservoir. After completion of operations at Tripletail, the Noble Tom Madden drillship will drill the Uaru-1 well 6 miles east of Liza field.
“This discovery helps to further inform the development of the Turbot area,” said Mike Cousins, senior vice-president of exploration and new ventures at ExxonMobil.
Exploration and development are moving forward elsewhere on the Stabroek block. The Stena Carron drillship is currently drilling the Ranger-2 well and upon completion will conduct a well test at Yellowtail-1. The Noble Bob Douglas drillship is currently completing development drilling for the Liza Phase 1 project. ExxonMobil will add a fourth drillship, the Noble Don Taylor, in October.
The Liza Phase 1 development is on schedule to start up by early 2020. It will produce as much as 120,000 b/d of oil utilizing the Liza Destiny floating production, storage, and offloading vessel, which arrived in Guyana on Aug. 29 (OGJ Online, Aug. 29, 2019).
ExxonMobil approved funding for the Liza Phase 2 development after it received government and regulatory approvals in May (OGJ Online, May 3, 2019). Expected to startup by mid-2022, the project plans to use the Liza Unity FPSO to produce as much as 220,000 b/d of oil. A third development, Payara, could see startup as early as 2023 with production up to an estimated 220,000 b/d of oil pending government approvals.
Stabroek block is 6.6 million acres. Esso E&P Guyana is operator with 45% interest. Hess Guyana Exploration holds 30% interest and CNOOC Petroleum Guyana holds 25% interest.
Tullow reports oil discovery opens play off Guyana
Tullow Oil PLC reported that a recent oil discovery has opened a new Upper Tertiary oil play in the Guyana basin.
The Joe-1 exploration well, drilled by the Stena Forth drillship to a 2,175 m TD in 780 m of water, encountered 14 m of net oil pay in high-quality oil-bearing sandstone reservoirs of Upper Tertiary age. On completion of operations, the drill ship will return to Ghana.
Joe is the first oil discovery to be made in the Upper Tertiary and derisks the petroleum system in the western area of the Orinduik block, where a number of Tertiary and Cretaceous-age prospects have been identified, the company said.
Tullow and its partners will evaluate data from the discovery along with data from the August Jethro-1 discovery and wait for data on the Carapa well to determine the optimal follow-on exploration and appraisal program, Tullow said (OGJ Online, Aug. 12, 2019). Additional thinner sands above and below the main pay at Joe-1 are being evaluated for possible incremental pay, said Africa Oil in a separate press statement.
The Repsol Exploracion Guyana-operated Carapa-1 well (Tullow, 37.5%) on the Kanuku license, scheduled to begin drilling in late September with the Rowan EXL II jack up rig, will test the Cretaceous oil play.
Tullow Guyana is operator of the Orinduik block with 60%. Total E&P Guyana holds 25%. Eco (Atlantic) Guyana holds the remaining 15%. Africa Oil holds 18.8% equity interest in Eco.
Equinor makes gas discovery with Orn well
Equinor and its partners will evaluate a natural gas discovery made with the Orn well southwest of Marulk field in the Norwegian Sea. The group will now clarify the need for delineation.
Recoverable resources are estimated at 50-88 million boe. The well has been permanently plugged.
Exploration well 6507/2-5, S, the first in production license 942, was drilled 12 km southwest of Marulk field, 38 km southwest of Norne field, and 20 km northwest of Skarv by the West Phoenix drilling rig to a vertical depth of 4,147 m subsea. The well was concluded in the Tilje formation in Early Jurassic rocks. Water depth in the area is 332 m.
The objective of the well was to prove petroleum in Middle Jurassic reservoir rocks (the Garn and Ile formations). In addition, reservoir and fluid data were to be collected from the Lysing formation in the Upper Cretaceous.
The well encountered a total gas column of 40 m in the Garn and Not formations, of which 30 m of sandstones mainly of moderate reservoir quality in the Garn formation and tight sandstones in the Not formation.
The Ile formation is tight and aquiferous. The gas-water contact was not encountered. As expected, the Lysing formation is aquiferous, and data was collected as planned.
Equinor is operator with 40%. Partners are Aker BP 30% and Wellesley 30%.
Talos gets nod for more exploration offshore Mexico
Talos Energy Inc. received a 2-year contract extension and regulatory approvals for additional exploration activities on Block 7 offshore Mexico in the Sureste basin. Talos operates Block 7. Its partners include Sierra Oil & Gas, a Wintershall DEA company, and Premier Oil PLC.
The consortium identified multiple potential oil exploration targets on Block 7, including the Xlapak and Pok-A-Tok prospects.
The National Hydrocarbons Commission of Mexico approved a modified Block 7 exploration plan in which the consortium retains the acreage coverall all its exploration targets. Typically, the Block 7 production-sharing contract requires the consortium to relinquish half the acreage but not in this case.
In July the consortium announced the Zama-1 discovery on Block 7. The Zama-1 well was the first offshore exploration well drilled by the private sector in Mexico’s history. Premier holds a 25% interest.
Drilling & Production Quick Takes
Vaalco well to appraise deeper Etame zone
Vaalco Energy Inc., Houston, has started a drilling program in Etame oil field offshore Gabon that will include appraisal of a reservoir below existing production.
It has spudded the Etame 9P appraisal well to test the Lower Cretaceous Dentale formation, which underlies the producing Gamba sandstone of the same age.
Vaalco says the Dentale formation, penetrated by earlier wells, presents “a number of targets in a sand-shale sequence with favorable reservoir properties.”
It estimates the formation holds as much as 4.6 million bbl of recoverable oil.
After drilling the Etame 9P, the Vantage Drilling International Topaz jack up will drill the Etame 9H horizontal development well targeting the Gamba formation.
The 2019-20 drilling program includes a total of two appraisal wells and as many as three development wells.
Vaalco and partners produced an average of 13,550 b/d of oil during the second quarter in the Etame Marine license area. Production is from two wells in the Etame platform, three wells each in the SEENT and Avouma platforms, one well in the Ebouri platform, and three subsea wells flowing into a floating production, storage, and offloading vessel.
Hurricane well flows 9,800 b/d off UK
Hurricane Energy PLC has suspended for possible completion as an oil producer its 205/26b-14 Lincoln Crestal well in the West of Shetlands area offshore the UK (OGJ Online, July 2, 2019).
The well flowed on tests with an electric submersible pump at a maximum stable rate of 9,800 stock-tank b/d of 43º gravity oil with no formation water.
It flowed naturally at an average rate of 4,682 stock-tank b/d.
The Transocean Leader semisubmersible rig drilled the Greater Warwick area well to 1,780 m TVD subsea with a 720 m horizontal section in fractured basement.
It’s the second of three wells planned in 2019. The next will be the 204/30b-A Warwick West well.
Subject to regulatory approval, the operator will suspend the Lincoln Crestal well with long-term gauges installed to test interference with future Greater Warwick wells.
If completion is approved by regulators and partners and warranted by further technical evaluations, the well will be tied back to the Aoka Mizu floating production, storage, and offloading vessel next year on Lancaster field to the north. Lancaster early production started in June (OGJ Online, June 19, 2019).
The Lincoln Crestal well offsets the inclined 205/26b-12 discovery well drilled in 2016, which penetrated more than 800 m of basement with an extensive oil column. Lincoln and Lancaster fracture networks and oil properties are similar.
The Brynhild Fault Zone separates Lincoln from Lancaster. Water depth in the area is about 160 m.
Hurricane and Spirit Energy hold 50% interests each in the Lincoln Crestal well.
PROCESSING Quick Takes
Aramco completes Sasref refining JV buyout
Saudi Aramco has completed a deal to acquire Royal Dutch Shell PLC’s share of the partners’ 50-50 joint venture Saudi Aramco Shell Refinery Co. (Sasref), which operates the 305,000-b/d refinery at Jubail, Saudi Arabia (OGJ Online, Apr. 22, 2019).
As part of the deal, Aramco purchased Shell’s 50% interest in the JV for $631 million in a transaction that closed on Sept. 18, Aramco and Shell said in a joint release.
The acquisition supports Aramco’s plan to increase the complexity and capacity of its refineries as part of its long-term downstream growth strategy.
For Shell, the Sasref sale came as part of an ongoing effort to focus its refining portfolio to further integrate with Shell Trading hubs and chemicals, the operator said.
SABIC, ExxonMobil break ground on GCGV project
A joint venture of Saudi Arabian Basic Industries Corp. (SABIC) and ExxonMobil Corp. has started construction of the JV’s Gulf Coast Growth Ventures (GCGV) project, a 1.8 million-tonne/year ethane cracking complex in San Patricio County, Tex., near Corpus Christi (OGJ Online, July 25, 2016).
A groundbreaking ceremony for the proposed project took place at the Texas construction site on Sept. 13, SABIC said on official Facebook account.
The ExxonMobil-SABIC JV received final environmental regulatory approval in June to proceed with construction of the GCGV project, which—alongside the ethane steam cracker and two polyethylene units—also will include a 1.1 million-tpy monoethylene glycol unit (OGJ Online, June 13, 2019).
Upon announcing regulatory approval, the JV also confirmed it has let engineering, procurement, and construction contracts for the GCGV project to John Wood Group PLC as well as a consortium of McDermott International Inc. and Turner Industries Group LLC (OGJ Online, Aug. 22, 2019; June 19, 2019).
Project approval follows ExxonMobil and SABIC’s 2018 formation of the 50-50 GCGV JV—under which ExxonMobil will act as site operator—and the April 2017 selection of the San Patricio County site, which will allow ExxonMobil and SABIC to take advantage of the region’s existing infrastructure to capture competitive pricing for US natural gas feedstock as well as access to rising demand for ethylene-based products in overseas export markets.
Alongside forming part of SABIC’s growth strategy to build petrochemical installations in key markets—including the Americas—to address industry demand and achieve the company’s 2025 strategy, the proposed multibillion GCGV project also is one of the developments included as part of ExxonMobil’s 10-year, $20-billion “Growing the Gulf” expansion initiative announced in early 2017.
Gazprom Neft advances Omsk delayed coking project
PJSC Gazprom Neft has completed installation of the main section for its project to expand delayed coking capacity at its 430,000-b/d Omsk refinery in Western Siberia as part of the operator’s second phase of its ongoing modernization program to reduce environmental impacts and improve processing capacities, conversion rates, energy efficiency, and production qualities at the site (OGJ Online, Feb. 15, 2018).
A reinforced concrete frame construction standing more than 28 m high and supporting main equipment—including two coking ovens weighing 1,200 tonnes—for the future 40,000-b/d coking complex has now been installed, Gazprom Neft said.
The revamped coking complex, which will reduce environmental impacts and improve refining efficiency at the site, is scheduled to be commissioned in 2021.
Once in operation, the reconstructed delayed coking unit will enable full processing of heavy oil fractions to increase gasoline and diesel production at the refinery, as well as produce 38,700 tonnes/year of needle coke, the operator said.
Together with other projects forming the second phase of the Omsk refinery’s modernization project, the revamped coking complex will increase the site’s conversion rate to 97% and increase light-product yield to 80%, Gazprom Neft said.
Gazprom Neft—which confirmed it already has completed installation of three major coking ovens, each 28.5 m long and weighing 197 tonnes—said it also will replace process heaters and secondary refining columns, as well as add an additional tank farm and automated control system, as part of the coking reconstruction project.
The company said its current investment in the project stands at 5.2 billion rubles. As part of its first and second-phase modernization works at the site that started in 2008, Gazprom Neft has, to date, invested a total of 300 billion rubles at the Omsk refinery (OGJ Online, July 26, 2017; July 12, 2017).
Sonatrach-Total JV lets contract for C3 Oleflex unit
Sonatrach Total Entreprise Polymeres (STEP), a 51-49% joint venture of Sonatrach SPA and Total SA, has let a contract to Honeywell UOP LLC to provide its proprietary C3 Oleflex technology for a grassroots 565,000-tonne/year polymer-grade propylene plant in Arzew, Algeria (OGJ Online, Oct. 8, 2018).
Alongside technology licensing, Honeywell UOP also will provide basic engineering design, services, equipment, catalysts, and adsorbents for the proposed plant, the service provider said.
In addition to converting domestically produced propane into propylene, STEP will further convert the propylene into polypropylene plastic to supply customers in Algeria, along the Mediterranean, and in other markets like Europe, according to Bryan Glover, vice-president and general manager of Honeywell UOP’s petrochemicals and refining technologies business.
TRANSPORTATION Quick Takes
Cheniere, EOG sign long-term gas supply agreements
Cheniere Energy Inc. subsidiaries Corpus Christi Liquefaction and Cheniere Corpus Christi Liquefaction Stage III have entered into long-term gas supply agreements with EOG Resources Inc. EOG has agreed to sell gas to Cheniere over 15 years starting in early 2020. The quantity will start at 140,000 MMbtu/day and increase to 440,000 MMbtu/day. The LNG associated with 140,000 MMbtu/day will be owned and marketed by Cheniere. EOG will receive a price based on the Platts Japan Korea Marker. The remaining 300,000 MMbtu/day will be sold by EOG to Cheniere at a price indexed to Henry Hub.
A portion of the deal is subject to certain conditions, including a positive final investment decision on Cheniere’s Corpus Christi Stage III project, which is being developed to include up to seven midscale liquefaction trains with a total expected aggregate nominal production capacity of 9.5 million tonnes/year. The project received a positive environmental assessment from the US Federal Energy Regulatory Commission in March. All remaining regulatory approvals are expected by yearend.
Taproot plans extension of DJ basin midstream
Taproot Rockies Midstream executed a long-term acreage dedication for crude oil transportation from Bonanza Creek Energy Operating Co. In conjunction with Bonanza Creek’s dedication of nearly 70,000 gross acres (subject to Bonanza Creek’s preexisting dedications), Taproot will extend its existing multiservice midstream system (the Baja system) some 35 miles south (the Rattlesnake extension) to transport Bonanza Creek’s crude oil to Taproot’s Baja system for redelivery at Tallgrass Energy Partners’ Buckingham terminal, with ultimate delivery to Cushing. Delivery to the Buckingham terminal is expected to provide shipper customers premium pricing for “Niobrara–spec” crude oil barrels (42° gravity and below), the company said. The in-service date for the expansion project is expected in second-quarter 2020.
The agreement increases the total acreage dedicated to Taproot’s Baja system to nearly 175,000 gross acres. In addition to the Rattlesnake extension, Taproot intends to construct a truck unloading and storage facility to provide customers with a crude oil delivery point in Weld County, Colo. The Rattlesnake extension gives the opportunity to become the first independent pipeline solution in the northeast Wattenberg area to provide producers with direct pipeline access to the Buckingham terminal, said Taproot CEO Kevin Sullivan.
