OGJ Newsletter
GENERAL INTEREST Quick Takes
Questerre to challenge Quebec regulations
Questerre Energy Corp., Calgary, said it will challenge “last-minute restrictions on oil and gas activities and hydraulic fracturing” in regulations implementing 2016 petroleum legislation in Quebec. In a press release, the company welcomed implementation of the Petroleum Resources Act, saying modernization of Quebec hydrocarbon law is essential to Utica shale development in the St. Lawrence Lowlands.
But it said it will challenge specific regulations that it says exceed the government’s authority, contradict scientific studies, and fail to meet consultative requirements.
Other parts of the regulations, it said, “while stricter than other jurisdictions, are generally workable.”
Questerre and Talisman Energy Inc., now Repsol Oil & Gas Canada Inc., suspended a pilot horizontal-drilling program assessing Utica shale discoveries in the St. Lawrence Lowlands in 2010 to await studies underlying the petroleum legislation.
When the government published draft implementation regulations last June, Questerre said they would “have the effect of banning hydraulic fracturing and any meaningful exploitation of natural gas in Quebec.”
Questerre plans to consolidate Repsol Canada’s St. Lawrence Lowlands interests and become operator. Closing of the deal is contingent on the new regulations.
US Energy signs deal for Bakken asset acquisition
US Energy Corp., Denver, plans to acquire oil and natural gas producing properties targeting the Bakken formation of North Dakota form APEG I Partners.
The exclusive, nonbinding memorandum of understanding includes all of APEG’s interest in 67 wells concentrated in Williams and McKenzie counties—assets “highly complementary” to US Energy’s existing portfolio in the state, the company said. Current production is 400 boe/d across 1,600 net acres with 1.1 million boe of proved developed reserves, 79% of which is oil.
US Energy said the deal will create additional opportunities for development and acreage swaps that would permit it to continue consolidating its leasehold position in the area.
Total consideration is $17.8 million—a combination of cash, issuance of common and preferred stock, and the assumption of APEG’s outstanding commodity derivatives. US Energy plans to establish an $8-million revolving credit facility.
Closing is conditioned on debt and equity financing, Nasdaq approval, and stockholder approval at a special meeting scheduled for December.
Court approves Connacher Oil & Gas sale
The acquisition of bankrupt Connacher Oil & Gas Ltd., Calgary, by East River Oil & Gas Ltd. has received court approval.
Connacher on Aug. 2 had named the subsidiary of Changchun Sinoenergy Corp. of China as successful bidder in its investment solicitation under the Companies’ Creditors Arrangement Act (CCAA). Connacher sought creditor protection under the CCAA in May 2016.
East River proposes to buy all Connacher shares for $113.5 million (Can.). The transaction remains subject to other approvals, including by creditors scheduled to meet on Oct. 2.
In the first quarter, Connacher produced a combined average of 12,670 b/d of bitumen from two steam-assisted gravity drainage projects, Pod One and Algar, in the Great Divide area southwest of Fort McMurray, Alta.
The company holds 87,000 acres under lease in the area, where it estimates proved and probable reserves at 441 million bbl. It reported a first-quarter net loss of $57.2 million.
Magnolia to acquire S. Texas assets from Harvest
Magnolia Oil & Gas Corp., Houston, agreed to acquire substantially all of the South Texas assets of Harvest Oil & Gas Corp. in a cash and stock deal worth $191 million.
The deal adds 15 net locations to Magnolia’s core Karnes County inventory and 114,000 net acres to its Giddings field position. The assets produced 4,800 boe/d in the first half of this year—1,400 boe/d in Karnes County (69% oil, 83% liquids) and 3,400 boe/d in Giddings field (27% oil, 53% liquids).
“Harvest represented our largest non-operated working interest owner and the assets are a natural fit for Magnolia,” said Magnolia Chairman and Chief Executive Officer Steve Chazen.
Magnolia was created earlier this year following EnerVest Ltd.’s $2.66-billion sale of South Texas assets to TPG Pace Energy Holdings, an energy-focused special purpose acquisition entity led by Chazen (OGJ Online, Mar. 20, 2018).
The transaction includes $135 million in cash and 4.2 million newly issued shares of stock valued at about $56 million as of the close of trading on Aug. 20. Magnolia will use a combination of cash and borrowings under its revolving credit facility to fund the cash portion of the deal, which is expected to close on Aug. 31.
Pieridae Energy to acquire Ikkuma Resources
Pieridae Energy Ltd. has agreed to acquire Ikkuma Resources Corp. in an exchange of stock estimated in value at $94 million (Can.). Both companies are based in Calgary.
The buyer describes the acquisition as a step toward a final investment decision for its 10 million-tonne/year natural gas liquefaction plant at Goldboro, NS (OGJ Online, Aug. 17, 2015).
Subject to regulatory approvals, Ikkuma before closing will transfer its Cardium light-oil interests into a new private company, ExploreCo, to be owned by Ikkuma shareholders.
In the first quarter this year, Ikkuma produced an average 19,292 boe/d of oil and natural gas from its properties in the central Alberta Foothills. It estimates proved and probable reserves at 107 million boe.
Exploration & DevelopmentQuick Takes
ExxonMobil farms in to block off Namibia
ExxonMobil Namibia (PEL44) Ltd. has agreed to acquire a 30% interest in PEL44 in the Walvis basin offshore Namibia from Azinam Ltd., according to the farmor.
Water depths in the 5,722-sq-km block range from less than 300 m to more than 2,500 m. The deal is subject to government approval and other conditions.
Azinam said it acquired 2,000 sq km of 3D seismic data over the area in 2016. After interpretation, it acquired an additional 1,160 sq km of data now being processed.
Azinam will retain a 12.5% interest. Maurel & Prom of Paris, the operator, has 42.5%. Carried Namibian partners are National Petroleum Corp. of Namibia, 8%; Livingston Mining, 4%; and Frontier Minerals, 3%.
Azinam is part of the Azimuth Group, an offshore exploration and production portfolio management company formed by Seacrest Capital Group, a private equity firm based in Bermuda.
ExxonMobil does not list any Namibian operations on its web site.
Zangeneh: Total has ‘officially left’ Iran
Total SA has “officially left” Iran under threat of US sanctions, according to the Islamic Republic’s oil minister.
Radio Free Europe/Radio Liberty said the minister, Bijan Namdar Zangeneh, told state television the French company had withdrawn from its contract for Phase 11 development of South Pars natural gas field (SP11).
Total earlier this year said it could not remain in the project if sanctions against companies doing business in Iran were not waived. The US began renewing sanctions in August in connection with its May 8 withdrawal from the Joint Comprehensive Plan of Action in Iranian nuclear development (OGJ Online, May 16, 2018).
Sanctions on Iranian oil exports and banking are to be reinstated on Nov. 4.
Planned SP11 production capacity is 400,000 boe/d of natural gas and condensate.
Total had a 50.1% interest in the project with partners China National Petroleum Corp., 30%, and Petropars, 19.9%.
Pertamina finds oil and gas in West Java
A unit of state-owned Pertamina (Persero) of Indonesia is assessing development of an oil and gas discovery named Akasia Maju in the Jatibarang basin of West Java.
The Pertamina EP AMJ-001 1 well, drilled to 2,517 m near Bulak Lor Village, Idramayu Regency, flowed as much as 1,700 b/d of oil on test, Pertamina said. The well flowed natural gas and condensate during other tests.
Well moves field off UK toward development
Siccar Point Energy, Aberdeen, has suspended for use in future development the 204/10a-5 appraisal well in Cambo oil field, 125 km northwest of the Shetland Islands, saying logs and cores confirmed a high-quality reservoir with 23° gravity oil and “petrophysical properties better than anticipated.”
Those results came in a vertical pilot hole that confirmed an oil column greater than 100 ft with net pay of 58 ft, which exceeded expectations.
After logging and coring, Siccar Point drilled a 1,612-ft horizontal section for an extended well test.
“Initial results are encouraging, indicating excellent reservoir productivity and sustained flow,” the company said.
Discovered in 2002, Cambo field is on UK Continental Shelf licenses P1028 and P1189, 30 km southwest of Rosebank field and 50 km north of Schiehallion field. Siccar Point acquired a 100% operated interest in the field via its January 2017 takeover of OMV (UK) Ltd. (OGJ Online, Nov. 9, 2016). Shell UK farmed in for a 30% interest in May.
Siccar Point describes Cambo as a large basement high with sedimentary sequences draped atop the structure.
Before the latest appraisal, five wells had been drilled in the field, the main reservoir of which is Tertiary Hildasay sandstone of fluvial-deltaic origin. Estimated oil in place exceeds 600 million bbl.
The operator says the Cambo area has potential in undrilled parts of the Hildasay reservoir; the Tertiary Colsay formation at the edges of the structure, which is productive at Rosebank field; and a fractured basement prospect underlying the discovery.
Siccar Point envisions two-phase development with the first phase targeting 90 million boe of oil and gas reserves.
FAR selects Samo-1 location offshore Gambia
FAR Ltd., Perth, has selected its final well location for the forthcoming Samo-1 wildcat on the A2 block off Gambia. The prospect lies immediately south and along trend from large SNE oil field in Senegal waters in which FAR also has an interest.
The wildcat will be in 1,017 m of water about 112 km offshore in the prospective Mauritania-Senegal-Guinea-Bissau-Conakry basin.
FAR will operate Samo-1, which has two main targets—the upper reservoir interval that contained liquid-rich gas at SNE and a lower reservoir that was oil-bearing at SNE.
Good-quality reservoirs have been interpreted at both levels and the well is being directed to the crest of the structure.
Samo-1 is slated to be spudded early in this year’s fourth quarter and is expected to take about 40 days to drill on a trouble-free basis. It is the first well to be drilled off Gambia for 40 years. It will be drilled by the Stena DrillMax dynamic positioning drillship.
Nova Scotia-Morocco research MOU signed
The Offshore Energy Research Association of Nova Scotia and National Office of Hydrocarbons and Mines of Morocco have signed a memorandum of understanding for cooperative research of petroleum resource potential.
The MOU envisions studies comparing recently collected seismic and geochemical data to improve characterization of common geological elements of the Scotian and Moroccan conjugate margins.
Before continental break-up, Nova Scotia and Morocco were joined as one land mass.
Representatives of the groups signed the MOU in Halifax during the biennial Conjugate Margins Conference.
Drilling & ProductionQuick Takes
Partitioned Zone oil restart seen ‘soon’
Oil production from the Partitioned Zone shared by Saudi Arabia and Kuwait, shut in since 2015, will resume “soon,” according to the Kuwaiti oil minister (OGJ Online, Mar. 30, 2017).
“Matters with brothers in Saudi Arabia are going at a steady pace, and we expect the return of production in the divided region soon,” said Bakheet Al-Rashidi, who also is minister of electricity and water, according to the official Kuwait News Agency.
Partitioned Zone fields, offshore Khafji and onshore Wafra, have combined production capacity of 500,000 b/d. Saudi Arabia and Kuwait share the output.
Because of disputes never publicly clarified, Khafji production was suspended in 2014 and Wafra production the following year. Partitioned Zone operations are managed by Al Khafji Joint Operations, owned jointly by national oil company subsidiaries Kuwait Gulf Oil Co. and Aramco Gulf Operations.
The production suspension also halted assessment of the commercial potential of thermal recovery of Wafra heavy oil. A 49-well pilot steamflood began in Wafra field in 2009.
Floating wind power studied for platforms
Equinor and its partners in Gullfaks and Snorre oil fields in the Norwegian North Sea are considering the use of floating wind turbines to supply electrical power to the platforms.
Equinor said a study of the concept identified the Tampen-area fields as the most promising on the Norwegian Continental Shelf for application of a concept it calls Hywind.
Due further study is a wind farm comprising 11 turbines atop vertical spars with total output of 88 Mw.
Equinor estimates the system could meet 35% of the annual needs of the Snorre A and B and Gullfaks A, B, and C platforms, lowering emissions of carbon dioxide by more than 200,000 tonnes/year.
It estimates preliminary capital and development expenditures at 5 billion kroner ($600 million) and says a final investment decision is possible in 2019.
Equinor’s Gullfaks partners are Petoro AS and OMV (Norge) AS. Its Snorre partners are Petoro, ExxonMobil Exploration & Production Norway AS, Idemitsu Petroleum Norge AS, DEA Norge AS, and Point Resources AS.
Equinor submits Johan Sverdrup second-phase PDO
Equinor and partners associated with Johan Sverdrup oil field in the North Sea submitted the project’s Phase 2 plan for development and operation (PDO) to the Norwegian Ministry of Petroleum and Energy.
Partners said the project has higher estimated resources and lower investment costs than initially believed (OGJ Online, Aug. 29, 2016).
“The Johan Sverdrup field is the largest field development on the Norwegian shelf since the 1980s,” said Equinor CEO Eldar Satre. “At plateau, the field will produce up to 660,000 b/d with a break-even price of less than $20/bbl.”
Since the Phase 1 PDO in 2015, partners have reduced the total estimated investment for Johan Sverdrup full field development by more than 80 billion kroner.
The PDO for Johan Sverdrup Phase 2 also includes measures to use power from shore to the Utsira High by 2022 as outlined in the Phase 1 PDO.
Emission savings from the Johan Sverdrup field are estimated at 460,000 tonnes/year of carbon dioxide.
The updated investment estimate for Phase 1 is now 86 billion kroner (nominal kroner, project exchange rate), a 30% reduction since submission of the Phase 1 PDO.
In the Phase 2 PDO, partners reduced the investment estimate to 41 billion kroner, and the breakeven price for Phase 2 is now less than $25/bbl.
Phase 2 is scheduled to come on stream in late 2022.
FPSO sails out for Egina field off Nigeria
One of the world’s largest floating production, storage, and offloading vessels has sailed away from a fabrication and integration yard in Lagos for installation on ultradeepwater Egina oil field offshore Nigeria.
The field, on the OML 130 license operated by Total Upstream Nigeria Ltd., will produce 200,000 b/d of crude oil from 44 wells in 1,400-1,700 m of water 130 km offshore.
Samsung Heavy Industries Nigeria Ltd. (SHI) built the FPSO at its Goeje yard in South Korea and moved it to Lagos late last year (OGJ Online, Nov. 2, 2017). It built the SHI-MCI yard there in a joint venture with a local company, completing the facility in October 2016.
The FPSO is 330 m long, 61 m wide, and 34 m tall. It weighs 220,000 tonnes, with topsides weighing 60,000 tonnes. Storage capacity is 2.3 million bbl.
PROCESSINGQuick Takes
Petrobras updates Replan refinery status after fire
Processing activities at Petroleo Brasileiro SA (Petrobras) remained partially suspended on Aug. 27 following a fire that broke out Aug. 20 at its 415,000-b/d Replan refinery in Paulínia, Sao Paulo, Brazil (OGJ Online, Aug. 23, 2018).
The temporary closure follows notification to Petrobras from Brazil’s National Petroleum, Natural Gas, and Biofuels Agency (ANP) on Aug. 24 for a continued partial shutdown of the Replan facility as a precautionary measure, Petrobras said.
Despite the halt on processing activities, however, utilities, tankage, and product-delivery operations at the refinery continue, the company said.
The precautionary suspension of processing operations at the site stems from the Aug. 20 fire, whose origin was an explosion in a tank of one of the acidic water units associated with the U-220A catalytic cracking unit, which also impacted one of the refinery’s atmospheric distillation units (U-200).
Petrobras—which currently is compiling documents and information required by the ANP attesting to appropriate safety conditions for safely resuming operations of processing units not impacted by the incident—said it expects to restart production processes during the next few days following the ANP’s lifting of the precautionary shutdown measure.
The company disclosed no details regarding the severity of the incident’s impact to the U-200 and U-220A units.
EPP, AMP evaluate gas processing combine
Enterprise Products Partners LP (EPP) and American Midstream Partners LP (AMP) have entered an agreement under which AMP may purchase a 25% interest in EPP’s 1-bcfd natural gas processing plant in Pascagoula, Miss.
The purchase option remains subject to certain conditions, including AMP completing modifications to certain installations on its High Point pipeline system that would provide incremental gas volumes with access to the Pascagoula plant, EPP said.
The High Point pipeline system currently delivers offshore gas production to the EPP-operated 300-MMcfd Toca gas processing plant in St. Bernard Parish, La.
Due to pending modifications to the High Point system’s installations, EPP, along with other owners of the Toca plant, voted to idle operations of the plant to use existing processing capacity at the more efficient Pascagoula plant, EPP said.
Customers of the Toca plant, however, will have the option to enter into similar processing arrangements with the Pascagoula plant, which should provide customers with higher netbacks in the form of improved NGL recoveries and reduced energy costs, EPP said.
TRANSPORTATIONQuick Takes
Enbridge acquires outstanding shares of Spectra’s MLP
Enbridge Inc. and Spectra Energy Partners LP (SEP) have entered into a definitive agreement under which Enbridge will acquire all outstanding public common units of SEP at a ratio of 1.111 common shares of Enbridge for each common unit of SEP. The ratio is a 9.8% increase to the exchange ratio offered by Enbridge on May 17. The transaction is valued at $3.3 billion.
The companies explained that a significant weakening of US master limited partnership (MLP) capital markets had adversely affected SEP’s growth opportunities. If SEP were to continue as a stand-alone entity it would need to transition to a self-funding model using internally generated cash flow, limiting future distribution growth.
The merger will give Enbridge all 81.9 million public outstanding common units of SEP. In aggregate, based on the agreed exchange ratio, Enbridge would issue an estimated 91 million Enbridge common shares in connection with the transaction, or about 5% of the total number of Enbridge common shares outstanding.
The companies expect the transaction to close fourth-quarter 2018, subject to customary conditions. Enbridge Inc. and Spectra Corp. merged late 2016 (OGJ Online, Sept. 6, 2016).
AIE lets contract for FSRU for Port Kembla terminal
Australian Industrial Energy (AIE) has let a contract to Norwegian group Hoegh LNG to provide the floating storage and regasification unit (FSRU) for its planned LNG import terminal at Port Kembla on the New South Wales coast south of Sydney.
AIE and Hoegh have signed an exclusivity agreement whereby AIE has the right to lease one of Hoegh’s state-of-the-art 300-m, 170,000-cu m capacity FSRUs for the project that proposes to supply imported gas to Australian east coast industrial customers from the first quarter of 2020.
The FSRU is to be permanently moored at Berth 101 in Port Kembla’s inner harbor for the duration of the time charter party contract.
The FSRU will regasify LNG that can then be injected into a pipeline from the berth to the existing east coast gas transmission network that lies about 10 km away.
AIE says the FSRU will form part of the final port infrastructure design plans that will also address the New South Wales government’s planning assessment and development approval requirements, which were provided to AIE last week.
AIE was formed in 2017 by a consortium comprising Squadron Energy, which is led by Australian industrialist Andrew Forrest, major Japanese trading and investment group Marubeni Corp., and Japan’s JERA Co.