GENERAL INTERESTQuick Takes
ADNOC plans oil-production capacity hike
Abu Dhabi targets self-sufficiency in natural gas and expansion of oil-production capacity to 5 million b/d by 2030 under an expanded budget approved Nov. 4 by the Supreme Petroleum Council (SPC). Announcing capital investment growth of $132.33 billion during 2019-23, SPC reported recent indicated discoveries of 1 tcf of gas in place and 1 billion bbl of oil in place. The emirate is raising oil-production capacity this year to 3.5 million b/d and in its new budget sets an interim target of 4 million b/d by 2020.
Its gas strategy, according to a news release from Abu Dhabi National Oil Corp., “will sustain LNG production to 2040 and allow ADNOC to seize incremental LNG and gas-to-chemicals growth opportunities where they arise.” The country now produces about 3 million b/d of oil and more than 9.8 bcfd of raw gas.
ADNOC said development of offshore Hail, Ghasha, and Dalma sour gas fields will add production of more than 1.5 bcfd of gas (OGJ Online, Jan. 12, 2018).
“ADNOC will also unlock other sources of gas, which include Abu Dhabi’s gas caps and unconventional gas reserves, as well as new natural gas accumulations,” it said.
Its new “integrated gas strategy,” ADNOC said, aims at “potentially transitioning [the emirate] to a net gas exporter.”
Abu Dhabi has been a net gas importer since 2008. Last year’s 5-year budget for ADNOC was about $100 billion.
OMV to sell parts of upstream business in Tunisia
OMV AG has agreed to sell its wholly owned subsidiary OMV Tunisia Upstream GMBH to a subsidiary of Panoro Energy ASA, London, for $65 million, subject to adjustments.
OMV Tunisia Upstream holds 49% interests in the Cercina-Cercina Sud, El Ain-Gremda, El Hajeb-Guebiba, and Rhemoura concessions in Tunisia and half of the shares in Thyna Petroleum Services SA Operating Co. (TPS). The remaining stakes in the concessions and in TPS continue to be held by Tunisian National Oil Co. Average production of the divested assets in 2017 was about 2,000 boe/d, net to OMV.
The agreement will be signed following an equity private placement exercise by Panoro.
OMV will continue the ongoing development of hydrocarbon resources in south Tunisia, in particular the development of the Nawara Concession, involving gas field infrastructure and a pipeline from a central processing plant in the concession to Gabes, 300 km to the north.
TAG to sell New Zealand assets, operations
TAG Oil Ltd., Vancouver, BC, along with certain subsidiaries in New Zealand, has agreed to sell substantially all its Taranaki basin assets and operations in New Zealand to Tamarind Resources Pte. Ltd., Kuala Lumpur, and certain subsidiaries.
The sale would include TAG’s 100% working interests in PMP 38156 (Cheal and Cardiff), PMP 53803 (Sidewinder), PMP 60454 (Supplejack), PEP 51153 (Puka), PEP 57065 (Waitoriki), and TAG’s 70% interest in PMP 60291 (Cheal East) and PEP 54877 (Cheal East).
The agreement calls for TAG to receive a cash payment of $30 million at closing, a 2.5% gross overriding royalty on future production from all the sold assets, and as much as $5 million in event specific payments payable on achieving various milestones—the first being the achieved grant of PMP 60454 (Supplejack) conversion, triggering payment of $500,000 at closing.
The sale puts TAG in a better position to pursue its exploration prospects covering over 275,000 net acres in Australia, including the producing 25,000-acre petroleum mining license in the Surat basin. Completion is expected in first-quarter 2019.
Serica to further lift Keith, Bruce stakes
Serica Energy PLC, London, has entered agreements to further increase its interests in Bruce and Keith natural gas and condensate fields in the UK North Sea.
The company said it has satisfied conditions of a license from the US Office of Foreign Assets Control allowing operations to continue at nearby Rhum field despite a 50% interest subject to renewed US sanctions against Iran held by a subsidiary of National Iranian Oil Co. The license requires benefits accruing to the interest of the subsidiary, Iranian Oil Co. (UK) Ltd., to be held in escrow while sanctions are in effect.
Acquisition of the license was a condition of Serica’s November 2017 agreement to acquire BP PLC’s 50% interest in the field in a deal that also covers BP’s Bruce and Keith interests.
Serica now has agreed to buy a 16% interest in Bruce field and a 31.83% interest in Keith field from BHP Billiton Petroleum Great Britain Ltd. for an initial cash payment of £1 million, to be adjusted for working capital and 40% of post-tax cash flows from the effective date of Jan. 1, 2018. BHP retains liability for the costs of decommissioning facilities and wells now in place, subject to adjustments.
Last August, Serica agreed to acquire Total SA’s interest in Bruce and Keith fields, subject to completion of the BP deal.
Separately, Serica on Nov. 6 said it had agreed to acquire a 3.75% interest in Bruce field and an 8.33% interest in Keith field from Marubeni Oil & Gas (UK) Ltd.
Unlike the earlier transactions, the Marubeni deal transfers decommissioning obligations to Serica, which will receive a cash consideration from Marubeni with no deferred or contingent consideration. The Marubeni transaction depends on completion of the BP acquisition.
Completion of all the transactions will make Serica’s interests 98% in Bruce field and 100% in Keith field. It will operate those fields as well as Rhum.
Lukoil, Eni to share three Mexican blocks
Lukoil and Eni have agreed to become partners in three shallow-water production-sharing blocks in Mexico through farmouts.
Lukoil will transfer a 40% stake in Block 12 to Eni, retaining 60% and remaining operator.
Eni will assign 20% interests each in Blocks 10 and 14 and remain operator. It will hold 80% of Area 10 and 40% of Area 14, in which Citla holds the other 40%.
The blocks, awarded in Mexico’s Round 2.1 in 2017, are in the Sureste basin.
The transfers are subject to approval by the National Hydrocarbons Commission.
The companies also are partners in Sureste basin Block 28, awarded in licensing Round 3.1. Eni holds 75% of Block 28 and is operator, and Lukoil holds the remainder.
Exploration & DevelopmentQuick Takes
Israel launches Eastern Mediterranean bid round
Israel has launched its previously announced bid round to grant offshore exploration licenses for gas and oil in the Eastern Mediterranean (OGJ Online, June 18, 2018). The round follows an earlier one that began 2 years ago and granted six licenses.
Bids for the new round are to be submitted by June 2019 with announcement of the winners scheduled for July 2019. Details are posted on the Energy Ministry web site.
Yuval Steinitz, Israeli energy minister, said, “This bid is intended to continue the development of the natural gas market in Israel, increase competition by the entry of new international energy companies, and broaden Israel’s energy security.”
Licenses for 19 blocks will be issued in five zones. Each block measures up to 400 sq km and each zone, consisting of multiple blocks, can be as large as 1,600 sq km.
The zones are in the Israel’s southern waters, which is an area already partially licensed and where there has been some seismic research and limited exploration activity.
The Israeli Energy Ministry is limiting to eight the number of licenses granted to any one party. In addition, any licensee holding more than 20% of a producing oil lease will not be able to participate in the current bid round. Required guarantees for bid round participation call for $2.5 million for the first block licensed in a zone. Each additional block in the same zone will require another $500,000. The maximum guarantee required for four consecutive blocks will be $4 million.
Before drilling, a licensee will be required to place an additional guarantee of $5 million. An exploration license initially will be granted for 3 years. The licensee can request up to two 2-year license extensions provided they fulfill certain conditions. Officials said they designed the extension schedule to give a licensee time to study the area.
Five areas draw bids in NL license round
The Canada-Newfoundland and Labrador Offshore Petroleum Board received high bids totaling nearly $1.4 billion (Can.) for exploration licenses covering four areas in the Eastern Newfoundland Region and one area in the Jeanne d’Arc Region in a round of scheduled bidding that ended Nov. 7.
It had offered exploration licenses for 16 parcels totaling 3,941,046 hectares in the Eastern Newfoundland Region and one in the Jeanne d’Arc Region.
The sole bidding criterion was commitment to exploration spending during the first period of the 9-year license.
The board received no bids for production licenses offered in the Jeanne d’Arc Region.
In the Eastern Newfoundland Region:
• BHP Billiton Petroleum (New Ventures Corp.), bidding alone, submitted a record-high bid of $621.02 million for Parcel 8 covering 269,799 hectares.
• BHP Billiton also submitted the successful bid of $201.02 million for 273,579-hectare Parcel 12, again bidding alone.
• A combine of Equinor Canada Ltd. (70%) and Husky Oil Operations Ltd. (30%) made the successful bid of $32.23 million for Parcel 14, covering 159,036 hectares.
• Equinor Canada (60%) and Suncor Energy Offshore Exploration Partnership (40%) bid high with $480 million for 253,608-hectare Parcel 15.
In the Jeanne d’Arc Region, Suncor (40%), Husky (30%), and Equinor Canada (30%) made the successful bid of $52 million for Parcel 1, covering 142,448 hectares.
Companies partner for exploration off Algeria
Executives of Italy’s Eni SPA, France’ Total SA, and Algeria’s Sonatrach have signed two agreements that include an exclusive partnership for exploration offshore Algeria in a virtually unexplored geological province.
Eni and Total also will pursue obtaining exploration permits that will allow for the completion of the hydrocarbon potential assessment, the companies said.
Eni CEO Claudio Descalzi said, “Together with Sonatrach and Total, we will have the opportunity to explore the deep waters of the Algerian offshore, a virtually unexplored geological province where Eni will be able to contribute by leveraging its experience in the Eastern Mediterranean and its inventory of advanced exploration technologies.”
Eni has been present in Algeria since 1981 and currently participates in 32 mining permits with an equity production in the country of 90,000 boe/d.
Santos moves to Stage 3 of Amadeus basin farm-in
Santos Ltd. has completed the acquisition of 1,337 km of seismic data in Amadeus basin permits EP82, EP112, and EP125 in the Northern Territory as part of Stage 2 of its farm-in to the acreage held by Central Petroleum Ltd., Brisbane.
The results of the seismic program have induced Santos to proceed to Stage 3 of the farm-in arrangement, which includes the drilling of a well in EP112 to earn a 70% interest in that permit. Santos is expected to drill the Dukas prospect during first-quarter 2019, carrying Central’s cost as part of the deal.
The prospect has the potential to hold multiple trillion cubic feet of gas. Two earlier wells in this southern part of the Amadeus (Mt. Kitty and Magee) have indicated the presence of a hydrocarbon system. The presence of helium and hydrogen in the earlier wells has the potential to add further value to any success at Dukas.
Santos has elected to remain at a 40% interest in EP82, EP105, and EP106 with no further farmout work to be completed. Central will retain 60% interest in these permits.
Drilling & ProductionQuick Takes
Colorado voters defeat Proposition 112
Colorado voters on Nov. 6 defeated Proposition 112, which would have increased oil and gas well setbacks from homes and businesses. The proposition would have required most new oil and gas wells be at least 2,500 ft from homes and other occupied buildings statewide except for federal land in Colorado.
The Colorado Oil & Gas Association had opposed Proposition 112. COGA issued a statement thanking Coloradans who “stood with the energy sector to oppose this measure.”
Imperial to develop Aspen SA-SAGD project
Imperial Oil Ltd. expects production to begin in 2020 from its Aspen oil sands development 45 km northeast of Fort McMurray, Alta., where it will use thermal recovery with water consumption and greenhouse-gas emissions as much as 25% lower than those of standard steam-assisted methods.
Production will reach 75,000 b/d of bitumen and can be doubled with later development, Imperial said in an announcement of its final investment decision.
The $2.6-billion (Can.) project will use solvent-assisted, steam-assisted gravity drainage (SA-SAGD), in which light hydrocarbons such as propane and butane are injected with steam to mobilize bitumen. Construction is to begin this quarter.
Imperial has tested the process for 7 years at its Cold Lake thermal project 170 km southeast of Fort McMurray, which produces 160,000 b/d of bitumen. It proposes an expansion of Cold Lake that would use SA-SAGD (OGJ Online, Aug. 29, 2018).
Imperial’s Aspen application calls for 370 well pairs drilled from 50 pads for both phases.
PROCESSINGQuick Takes
ExxonMobil commissions Antwerp refinery’s coker
ExxonMobil Petroleum & Chemical BVBA has commissioned a delayed coker at its 320,000-b/d Antwerp refinery in Belgium.
Designed to convert heavy, higher-sulfur residual oils into transportation fuels such as marine gas oil and diesel, the 50,000-b/d coker will expand the refinery’s capacity to meet demand for cleaner transportation fuels throughout northwest Europe, as well as help the refinery meet anticipated demand for lower-sulfur fuel oil to comply with International Maritime Organization standards scheduled to take effect in 2020, ExxonMobil said.
Part of a $2-billion investment the company has made in the Antwerp refinery over the last 10 years, the coker joins other completed projects at the site, including a 130-Mw cogeneration unit to reduce greenhouse gas emissions, as well as a diesel hydrotreater, which has increased the refinery’s production capacity for low-sulfur diesel to enable modern diesel engines to achieve lower emissions standards.
ExxonMobil said the newly commissioned delayed coker is the first of several expansion projects designed to strengthen the competitiveness of its European business.
The company is currently constructing a hydrocracker at subsidiary Esso Nederland BV’s 191,000-b/d refinery in Rotterdam that will upgrade heavier hydrocarbon byproducts into cleaner, higher-value finished products such as EHCTM Group II base stocks and ultralow-sulfur diesel (OGJ Online, June 24, 2016).
ExxonMobil also is considering an expansion project at subsidiary Esso Petroleum Co.’s 270,000-b/d Fawley refinery near Southampton, UK, that would include a hydrotreater unit and associated hydrogen plant to increase domestic diesel production and reduce reliance on imported fuel.
Petrotrin proceeds as planned with refinery closure
Petroleum Co. of Trinidad & Tobago Ltd. (Petrotrin) is progressing with its previously announced plan to end refining operations at the company’s 165,000-b/d Pointe-a-Pierre refinery.
Refining operations are continuing to wind down at the facility, with operations as of Nov. 1 shifting seamlessly away from refining crude to importing refined fuels and exporting existing crude reserves, Petrotrin said.
On Oct. 27, the operator received the first of 16 shipments of refined fuels to be delivered during the next 4 months under an agreement with BP PLC’s Latin America integrated sales and trading group. On Oct. 30, the company said it also loaded its first shipment of oil for export, which included about 500,000 bbl of medium-octane, low-octane crude to buyer Trafigura Oil Traders Ltd. Because of the imported fuel volumes, motorists in Trinidad and Tobago currently remain unaffected by the refinery closure, the operator said. While Petrotrin previously confirmed the phased shutdown would begin on Oct. 1, the operator has yet to reveal a definitive timeline for when cessation of operations at Pointe-a-Pierre would be completed.
Petrotrin said the decision to exit the refining business comes amid a lack of domestically produced crude oil to serve as feedstock for the manufacturing site as well as the operator’s plans to entirely redesign its exploration and production business, with the restructuring exercise geared to curtail the company’s losses and usher it on a path to sustainable profitability.
EPP to expand Mont Belvieu NGL fractionation
Enterprise Products Partners LP (EPP) is planning an additional incremental 150,000-b/d expansion to its existing NGL fractionation complex in Mont Belvieu, Tex.
To become the eleventh NGL fractionator at the site, this new unit would increase EPP’s NGL fractionation capacity to 1 million b/d in the Mont Belvieu area and about 1.5 million b/d companywide once service begins, the company said.
The new NGL fractionator is scheduled to be completed in second-quarter 2020, the operator said. Announcement of this latest Mont Belvieu expansion follows EPP’s earlier announced plan for a separate 150,000-b/d NGL fractionator, now under construction, which is scheduled to be completed during first-quarter 2020. Both projects are supported by long-term, fee-based contracts, EPP said.
“The demand for NGL fractionation capacity continues to expand as producers in domestic shale plays like the Permian basin, the Eagle Ford, and DJ basin seek market access and end users require supply assurance,” said A.J. Teague, chief executive officer of EPP’s general partner.
“With the completion of our new fractionators, [EPP] will have essentially doubled its fractionation capacity in response to the shale revolution of the past decade,” Teague added, noting that the new fractionation units also will supply NGL products for the expanding petrochemical industry on the US Gulf Coast as well as growing global demand for US NGLs.
Sonatrach lets contract for Arzew refinery
Sonatrach has let a contract to Honeywell UOP LLC to provide a suite of its proprietary technologies for production of 200,000 tonnes/year of methyl tertiary butyl ether (MTBE) at its 80,000-b/d refinery in Arzew, Algeria.
As part of the contract, Honeywell UOP will deliver technology licensing, design services, key equipment, catalysts, and adsorbents for the project, the service provider said.
Alongside UOP’s Butamer technology, which isomerizes normal butane into isobutane, the technology package also includes a UOP C4 Oleflex unit to dehydrogenate isobutane into isobutylene, as well as a UOP Ethermax unit to convert isobutylene and methanol into a high-octane MTBE blending agent that contains no benzene or aromatics.
The technologies will enable Sonatrach to supply MTBE to the region’s refineries to produce fuels that meet increasingly strict specifications, including Euro 5-quality fuels, according to Bryan Glover, vice-president and general manager of Honeywell UOP’s process technology and equipment business.
This latest contract follows Sonatrach’s previous award of a €5.17-million, 18-month contract to Amec Foster Wheeler PLC to provide preliminary engineering works for construction of a the Arzew MTBE plant (OGJ Online, Dec. 20, 2016).
Designed to treat 75,000-tpy of methanol from Sonatrach’s Arzew CP1Z methanol and derivatives complex as well as 150,000 tpy of butane from its Arzew GP1Z LPG separation complex, the MTBE installation would help to improve octane quality of fuels produced at the company’s refineries.
TRANSPORTATIONQuick Takes
Gas supply limited despite Enbridge line repair
Enbridge has restored partial service to customers of its BC Pipeline following the Oct. 9 rupture of a natural gas transmission pipeline 13½ km north of Prince George, BC, but supply is still limited, and retail customers are being asked to continue to conserve throughout the winter, said British Colombia electric power and gas distribution and retail company FortisBC.
Repairs to BP Pipeline’s 36-in. line are complete and the line expected to be in operation at about 55% operating pressure, gradually ramping up to 80% through this month.
The Enbridge-owned and operated BC Pipeline comprises two parallel lines, one 36-in. and the other 30-in., that move gas into the US Pacific Northwest. Until both pipelines are back at full operating pressure, there is not enough gas to support the typical winter consumption of the FortisBC customer base.
TransCanada to expand NGTL pipeline system
TransCanada Corp. will expand its Nova Gas Transmission Ltd. (NGTL) System to connect existing and new supply to incremental intra-basin demand. The expansion consists of about 197 km (122 miles) of large-diameter pipeline, three compression units, meter stations, and associated infrastructure.
The company expects to file applications to build and operate the expansion with Canada’s National Energy Board in second-quarter 2019. Pending approvals, construction will start as early as third-quarter 2020.
The project is underpinned by 1.1 bcfd of new firm service contracts. Shippers have executed commercial agreements for 754 MMcfd of incremental firm delivery services starting in April 2022, supplying Alberta power generation, oil sand extraction, petrochemical, industrial, and utilities segments. Shippers also executed 377 MMcfd of firm receipt services from November 2021 connecting incremental Montney and Deep basin production to the system. The contracts have terms of 8 to 20 years.
TransCanada estimates cost of the expansion at $1.5 billion, with most of the capital investment to occur in 2021-22.
