GENERAL INTERESTQuick Takes
Aramco agrees to buy SABIC for $69 billion
Saudi Aramco and Saudi Basic Industries Corp. (SABIC), already partners in the development of technology to produce chemicals directly from crude oil, will merge.
Aramco signed an agreement under study since last year to buy 70% of the chemical manufacturer from the Public Investment Fund of Saudi Arabia (OGJ Online, July 24, 2018). The private transaction is worth $69.1 billion. Aramco said it has no plans to acquire the remaining 30% of SABIC shares, which are publicly traded.
SABIC operates in more than 50 companies. It produced 75 million tonnes/year of chemicals last year, when it recorded record net income of $5.7 billion, sales of $45 billion, and total assets of $85 billion. Aramco and SABIC agreed in 2017 to collaborate on development of technology to produce chemicals from crude oil. Last year they identified Yanbu, Saudi Arabia, as the site of a 400,000-b/d fully integrated crude-oil-to-chemicals complex (OGJ Online, Nov. 1, 2018).
Aramco seeks to expand its global downstream interests to 8-10 million b/d by 2030 from 4.9 million b/d at present. Of the target capacity, 2-3 million b/d will be for production of petrochemicals, expected to be the main growth segment of future oil demand.
“This downstream portfolio will consume significant quantities of Arabian crude oil,” Aramco said in a press release.
Scotland delays frac policy clarification
Clarification of Scotland’s policy on hydraulic fracturing of oil and gas wells again has been delayed.
In response to a parliamentary question, Energy Minister Paul Wheelhouse announced an 8-week public consultation on the completion method, beginning Apr. 21.
The government earlier said it would inform Parliament of its position during the first quarter of this year.
Wheelhouse in October 2017 had told Parliament a moratorium imposed in 2015 “would remain in place indefinitely” and said notification to local authorities effectively banned development of unconventional oil and gas resources.
When challenged in court, the government said it had not prohibited hydraulic fracturing.
The court ruled last year that Scotland had an “emerging and unfinalized planning policy expressing no support on the part of the Scottish government” for unconventional resource development (OGJ Online, June 19, 2018).
Wheelhouse, according to press reports, told Parliament the final policy would be adopted “as soon as possible” after conclusion of the public consultation.
Mubadala, Uzbekistan enter energy accords
Mubadala Investment Co., Abu Dhabi, and the government of Uzbekistan have entered strategic agreements to cooperate in three energy areas, including oil and natural gas.
Mubadala, Abu Dhabi’s strategic investment and development fund, also will work with the Uzbek government to identify partnership and investment opportunities in conventional power generation and renewable energy.
Mubadala’s international operating company, Mubadala Petroleum, will explore opportunities in production enhancement of oil and gas fields in Uzbekistan and in refining and petrochemicals.
State-owned Uzbekneftegaz recently signed an agreement with Zarubezhneft of Russia to cooperate on enhanced oil recovery at three Uzbek fields (OGJ Online, Mar. 18, 2019).
EPA begins audit program for upstream asset owners
The US Environmental Protection Agency launched a voluntary emissions auditing program on Mar. 29 for new owners of oil and gas exploration and production operations that it said would accelerate the rate at which these entities find, correct, and disclose federal Clean Air Act violations. The program potentially could reduce emissions of significant pollutants significantly and increase environmental protection, it indicated.
“New owners of oil and gas facilities may be particularly well positioned to identify and address emission violations,” EPA Assistant Administrator for Enforcement and Compliance Assurance Susan Bodine said. “This program offers these new owners incentives to ensure their newly-acquired facilities are in, or come into, compliance.”
The program encourages new owners of well sites and associated storage tanks and pollution control systems to participate because it provides regulatory certainty and clearly defined civil penalty mitigation beyond what is offered by the EPA’s existing self-disclosure policies, EPA said.
Under it, new owners will, in most cases, have 9 months from the date of acquisition to notify EPA of their interest in participating, the agency explained. New owners include those who acquired assets in the 12 months preceding the program’s launch. EPA said that it can reject applications if it or a state have already discovered violations at a facility.
EPA said it announced its intention to develop the program on May 4, 2018. It subsequently solicited and received feedback from state and local governments, oil and gas E&P companies and trade associations, and environmental and other non-government organizations. The final program reflects EPA’s efforts to refine the program’s requirements based on stakeholders’ feedback, the agency said.
UK launches oil and gas data repository
The UK Oil and Gas Authority has published 130 terabytes of oil and gas well, geophysical, field, and infrastructure data from the UK Continental Shelf. It called the launch of the country’s first Oil and Gas National Data Repository “what is believed to be one of the largest ever single open releases of data.”
Exploration & DevelopmentQuick Takes
Indian combine to explore Abu Dhabi block
A combine of state-owned Bharat Petroleum Corp. Ltd. and Indian Oil Corp. Ltd. will invest as much as $170 million to explore and appraise conventional resources of onshore Block 1 in Abu Dhabi. Abu Dhabi National Oil Co. awarded exploration rights to the combine to close its first competitive bid round (OGJ Online, Mar. 18, 2019).
The BPCL-IOCL combine will hold a 100% interest during the exploration phase and may develop and produce any discoveries. ADNOC has the option to take 60% interest during the production phase. The agreement term is 35 years.
Block 1 covers the Ruwais Unconventional Gas Concession under which Total SA and ADNOC target tight-gas potential of the Upper Jurassic Diyab formation (OGJ Online, Nov. 12, 2018).
Aker submits PDO for Tano-Cape Three Points
Aker Energy Ghana Ltd. has submitted an integrated plan of development and operations (PDO) to Ghanaian authorities for the Deepwater Tano-Cape Three Points block offshore Ghana.
Aker is the operator. Partners are Ghana National Petroleum Corp., Lukoil Overseas Ghana Tano Ltd., and Fueltrade Ltd.
The PDO calls for development of Pecan field as a firm Phase 1. Pecan field is the largest of several area discoveries.
Upon approval from Ghana, the partners will initiate the process to make a final investment decision. Pecan field is scheduled to come on stream 35 months after the FID.
The main Pecan field in 2,400-2,700 m of water is about 115 km offshore Ghana. Plans call for it to be developed using a floating production, storage, and offloading vessel and a subsea production system. Up to 26 subsea wells are expected to be drilled of which 14 would be advanced, horizontal oil wells and 12 would be injectors with alternating water and gas injection, and the use of multiphase pumps as artificial lift, to maximize oil production.
Pecan field reserves are estimated at 334 million bbl of oil with plateau production estimated at 110,000 b/d. Production is expected to last for more than 25 years. The total investments to develop these reserves are estimated at $4.4 billion, excluding the charter rate for a leased FPSO.
Gran Tierra obtains three Ecuador blocks
Gran Tierra Energy Inc., Calgary, announced it obtained three blocks in Ecuador’s Orientie basin, marking the firm’s entry into Ecuador, pending regulatory approvals and finalization of participation contracts.
Gran Tierra bid for three blocks covering 140,000 acres, creating a contiguous acreage position extending from Gran Tierra’s assets in Colombia’s Putumayo basin.
The Ecuador blocks will consolidate Gran Tierra’s position in a conventional oil fairway. Ecuador’s Napo formation is believed equivalent to the Villeta formation in Putumayo basin. Both formations are believed to contain multizone potential in the same carbonate and sandstone reservoirs.
Once finalized, Gran Tierra is expected to hold 100% working interest and operatorship in Charapa block, Chanangue block, and Iguana block, which increases Gran Tierra’s gross acreage in the conventional resource plays in Ecuador and Colombia to more than 1.3 million acres.
Gran Tierra’s winning bids consisted of a work program bid by block, including plans to drill 14 exploration wells in 4 years across the blocks. The company’s share of revenues is tied to the Oriente oil blend price and to production volumes.
Drilling & ProductionQuick Takes
Noble Energy sanctions Alen gas development
Noble Energy Inc. has sanctioned the Alen natural gas development project offshore Equatorial Guinea with the start of production expected in first-half 2021 (OGJ Online, May 10, 2018).
Gas will be processed through Alba Plant LLC’s liquefied petroleum gas plant and EGLNG’s LNG plant at Punta Europa, Bioko Island—both onshore and Marathon Oil-operated.
The field, on Blocks O and I offshore Equatorial Guinea, holds total estimated gross recoverable resources of 600 bcf of gas equivalent and has been producing gas condensate since 2013. The gas has been reinjected into the reservoir to enhance liquids recovery (OGJ Online, Jan. 12, 2011).
Primary condensate will continue to be produced and transported to Aseng field production, storage, and offloading vessel for sales. The Alen project will utilize the existing three high-capacity production wells on the platform, with minor modifications necessary to deliver sales gas from the platform. A 24-in., 950 MMcfed capacity pipeline will be constructed to transport all gas processed through the Alen platform some 70 km to the onshore facilities.
Gas sales of 200-300 MMcfed gross (75-115 MMcfed net to Noble) are expected at start-up. The wet gas stream will be tolled through the Alba plant for additional liquids recovery before converting dry gas into LNG via the EGLNG facility. Gas sales are expected to grow modestly as open capacity in the EGLNG plant increases due to declining Alba field production.
Noble plans to sign offtake agreements to sell the LNG in global markets. Cumulative capital expenditure for the project in 2019-20 is $330 million gross ($165 million net to Noble).
Noble operates Alen field with 45% working interest and holds a 28% non-operated working interest in the Alba plant.
Total starts full production from Kaombo
Total SA has started production on Kaombo Sul, the second floating production, storage, and offloading vessel of the Kaombo oil development offshore Angola. Operated by Total E&P Angola, the project lies on Block 32 in 1,400-2,000 m of water about 260 km offshore Luanda.
Kaombo Sul will add 115,000 b/d of oil to Kaombo Norte, the first FPSO brought on stream in July 2018 (OGJ Online, July 27, 2018). Total production is expected to reach 230,000 b/d at peak, equivalent to about 15% of the country’s production. Associated gas will be exported to the Angola LNG plant.
A total of 59 wells—more than 60% already drilled—will be connected to the two FPSOs, which were converted from very large crude carriers to develop the resources of Gengibre, Gindungo, Caril, Canela, Mostarda, and Louro over an 800-sq-km area in the central and southern part of the block.
Gengibre, Gindungo, and Caril were connected to the Kaombo Norte FPSO, while Mostarda, Canela, and Louro, have now been connected to Kaombo Sul.
Total operates Block 32 with 30% participating interest, along with Sonangol P&P 30%, Sonangol Sinopec International 32 Ltd. 20%, Esso Exploration & Production Angola (Overseas) Ltd. 15%, and Galp Energia Overseas Block 32 BV 5%.
In addition to the Block 32, Total operates Block 17 (40%) in Angola where investment decisions were taken in 2018 to launch three new satellite projects: Zinia 2, Clov 2, and Dalia 3 (OGJ Online, Nov. 12, 2018).
Total is a partner in Blocks 0 (10%), 14 (20%), 14K (36.75%) and 16/06 (65%), as well as in Angola LNG (13.6%), and in different exploration licenses. In 2018, the Group signed a risk service agreement with Sonangol for the deepwater Block 48 exploration license, which Total will operate (OGJ Online, May, 29, 2018).
Neptune lets contract for Norwegian North Sea wells
Neptune Energy Norge AS has let a drilling contract to CIMC Offshore AS to drill six wells in the Norwegian North Sea using the newbuild Beacon Atlantic semisubmersible rig, which will be managed by Odfjell Drilling AS.
Designed for harsh environments, the Beacon Atlantic semi will drill three development wells in Duva field (formerly Cara) starting late this year. In addition, it might drill another three development wells in Gjoa field’s P1 segment. Duva field is 6 km northeast of Gjoa field.
Neptune Energy Norge has options to use the rig for additional development or exploration wells.
Odin Estensen, Neptune Energy managing director, said Duva production is expected by late 2020 and Gjoa P1 production is expected in early 2021.
The Beacon Atlantic is scheduled to arrive at the first drill site in the fourth quarter. Currently, the semi awaits final commissioning and sea trials at CIMC Raffles yard in Yantai, China.
Nepture Energy Norge operates Duva field with 30% interest. Duva partners are Idemitsu Petroleum Norge AS 30%, Pandion Energy AS 20%, and Wellesley Petroleum AS 20%.
Gjoa field production started in 2010. The P1 segment is in northern Gjoa field. Neptune Energy Norge holds 30% and operates Gjoa. Partners are Petoro AS 30%, Wintershall Norge AS 20%, OKEA 12%, and DEA Norge AS 8%.
Fifth Eridu well in Iraq flows oil
Lukoil reported the fifth well in Eridu oil field on Block 10 in southern Iraq flowed more than 9,000 b/d of oil from Middle Cretaceous Mishrif pay (OGJ Online, Jan. 24, 2019).
It plans further appraisal drilling and acquisition of 3D seismic data over the field and 2D seismic data over the southern and central parts of the 5,800-sq-km block, which is 150 km west of Basra.
PROCESSINGQuick Takes
Gazprom, partner advance LNG-chemical plan
Gazprom and RusGasDobycha have begun implementing plans for a large natural gas liquefaction and processing complex on the Gulf of Finland near Ust-Luga, Russia.
The companies decided on final configuration of the complex, which will process 45 billion cu m/year of gas and yield 13 million tonnes/year of LNG, as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG.
LNG and LPG are to be exported. Ethane will feed a chemical plant planned by RusGasDobycha through its Baltic Chemical Complex special-purpose entity. Target output of the complex is more than 3 million tpy of polymers.
For the joint LNG-processing complex, Gazprom will supply wet natural gas produced from Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula.
About 20 billion cu m/year of residual gas will flow into Gazprom’s gas transmission system.
The first train is due onstream in the second half of 2023. RusKhimAlyans, a 50-50 special-purpose venture of Gazprom and RusGazDobycha, will operate the project.
Ineos to double capacity of USGC EO-EOD plant
Ineos AG, Rolle, Switzerland, is planning to double the size of subsidiary Ineos Oxide’s proposed ethylene oxide (EO) and ethylene oxide derivatives (EOD) plant to be built somewhere along the US Gulf Coast.
Part of Ineos’ plan to address a fast-growing EO merchant market as well as the operator’s own requirements, the new plant—which will now produce 520,000 tonnes/year of EO—is slated to be operational sometime in 2023, Ineos said.
In addition to installing its own on-site ethoxylate derivative capacity and infrastructure to supply customers by rail, Ineos said it plans to allow interested third parties to colocate on site and consume EO by pipeline.
The operator, which said it is considering several sites along the USGC for the new plant, has yet to disclose a precise location for the project.
HollyFrontier wraps maintenance at El Dorado refinery
HollyFrontier Corp. has completed unplanned maintenance during this year’s first quarter at subsidiary HollyFrontier El Dorado Refining LLC’s 135,000-b/sd refinery in El Dorado, Kan.
As of Mar. 26, the crude unit was back online, and the refinery remained in the process of restarting all downstream units, the operator said. Due to planned and unplanned maintenance during the period, HollyFrontier said it expects overall first-quarter crude oil throughputs for its system to average 395,000-405,000 b/d.
TRANSPORTATIONQuick Takes
Qatar Petroleum advancing LNG expansion
Qatar Petroleum will solicit tenders for engineering, procurement, and construction of onshore facilities in its expansion of natural gas liquefaction capacity later this month, according to a project report by Saad Sherida Al-Kaabi, minister of state for energy affairs and QP president and chief executive officer.
Al-Kaabi told the International Conference & Exhibition on Liquefied National Gas in Shanghai on Apr. 2 that Chiyoda Corp. would complete front-end engineering and design of onshore facilities “in the next few days.”
QP is expanding liquefaction capacity at Ras Laffan Industrial City to 110 million tonnes/year from 77 million tpy through the addition of four trains with capacities of 8 million tpy each (OGJ Online, Sept. 26, 2018).
Lake Charles LNG project agreement signed
Energy Transfer and Shell US LNG have moved toward a final investment decision on the conversion of Energy Transfer’s regasification terminal at Lake Charles, La., into a 16.45 million-tonne/year natural gas liquefaction plant (OGJ Online, June 30, 2017).
The companies signed a framework agreement designating Shell project lead before the companies reach FID and as construction manager and operator of Lake Charles LNG if the project is sanctioned. Energy Transfer will be site manager and project coordinator prior to FID. The 50-50 project partners also said they will invite tenders from LNG engineering, procurement, and construction companies “in the weeks ahead.”
The FID will depend on the outcome of EPC bidding, project competitiveness, and market conditions, they said.
Prelude FLNG project ships first condensate cargos
Shell Australia’s Prelude floating LNG facilities in the Browse basin offshore Western Australia have produced and shipped their first cargo of condensate. The 116,000-dwt tanker Advantage Atom loaded the cargo last month.
There is no indication yet when the LNG shipments will begin from the FLNG vessel moored 475 km north-northeast of Broome and 155 km off Western Australia in 248 m of water.
The facilities entered the start-up and ramp-up phase at yearend 2018—an initial phase of production where gas and condensate is produced and moved through the facility.
Once fully operational, Prelude will produce 3.6 million tonnes/year of LNG, 1.3 million tpy of condensate, and 400,000 tpy of LPG. LNG and LPG will be offloaded via a side-by-side vessel configuration with specially designed cryogenic loading arms. The condensate is being offloaded from the rear of the facility using a floating hose mechanism.
Three stern thrusters enable the Prelude floating facility to maintain an optimum heading for offtake operations.
Shell said the focus continues to be on providing a controlled environment to ensure Prelude will operate reliably and safely now and into the future.
PNG-LNG project signs another midterm sales deal
The ExxonMobil-led PNG-LNG project in Papua New Guinea has made a midterm LNG sale agreement with Unipec Singapore for the supply of about 450,000 tonnes/year of LNG over 4 years. Unipec is a wholly owned unit of Sinopec, one of PNG-LNG’s original long-term customers. The new deal follows similar agreements with PetroChina and BP last year.
The midterm agreements add to the 6.6 million tpy from the project committed under long-term contracts to JERA, Osaka Gas, Sinopec, and CPC and take the total contracted volumes of LNG from PNG-LNG to about 7.9 million tpy.