GENERAL INTERESTQuick Takes
Bahrain to create $1 billion energy fund
Bahrain plans to raise $1 billion for energy investments in a fund the government calls unique among Gulf Cooperation Council countries.
Investments will include development of Bahrain Petroleum Co.’s recent offshore discovery in an unconventional reservoir, estimated to hold 80 billion bbl of oil in place (OGJ Online, Apr. 4, 2018).
Funds also will be used for other upstream work as well as downstream projects.
The Bahrain Energy Fund will be backed by the government, which seeks to raise funds from financial institutions in the kingdom.
In a related move, the Bahrain Development Bank announced a venture capital initiative, the $100 million Al Waha Fund of Funds, to attract investment firms to the island nation and support business start-ups.
US JCPOA exit pushes Total to drop South Pars plans
France’s Total SA has dropped plans for South Pars 11 (SP11), a gas development project to supply gas within Iran following US President Donald Trump’s May 8 announcement that the US will withdraw from the Joint Comprehensive Plan of Action (JCPOA) and reinstate sanctions. PetroChina was a partner on the project (OGJ Online, July 3, 2017).
The company will not be in a position to continue the project and will have to unwind all related operations before Nov. 4 unless it is granted a specific project waiver by US authorities with the support of the French and European authorities.
Such a waiver must include protection from any secondary sanction, the company said, as it cannot afford exposure that might include the loss of financing in dollars by US banks for its worldwide operations (US banks are involved in more than 90% of Total’s financing operations), the loss of its US shareholders (US shareholders represent more than 30% of Total’s shareholding), or the inability to continue its US operations (US assets represent more than $10 billion of capital employed).
In accordance with its contractual commitments vis a vis the Iranian authorities, the company is engaging with the French and US authorities to examine the possibility of a project waiver.
Actual spending to date with respect to the contract is less than €40 million in group share and withdrawal would not impact the company’s production growth target of 5% CAGR between 2016 and 2022, the company said.
South Pars has an estimated 21 tcf of gas in place, and Wood Mackenzie estimates SP11 could recover more than 10 tcf of sweetened gas with 450 million bbl of condensate.
ADNOC, OCP consider fertilizer venture
Abu Dhabi National Oil Co. and OCP Group of Morocco have agreed to consider forming a global fertilizers joint venture exploiting ADNOC’s sulfur production and experience with ammonia and natural gas in combination with OCP’s large phosphate resources and fertilizer expertise.
The venture would have production centers in the United Arab Emirates and Morocco. It extends a partnership formed last December based on a sulfur offtake agreement.
ADNOC expects its sulfur production to rise by at least 50% from current levels of 7 million tons/year as output of sour gas increases.
Talos Energy starts business after merger
Talos Energy Inc., Houston, has begun business after the stock-swap merger of Talos Energy LLC and Stone Energy Corp. (OGJ Online, Nov. 21, 2017).
The company has interests in the Gulf of Mexico and on the Gulf Coast. It estimates yearend 2017 proved and probable oil and gas reserves at 205 million boe, 80% liquids and 150 million boe proved.
Exploration & DevelopmentQuick Takes
Scotland hedges hydraulic fracturing stance
Prohibition of hydraulic fracturing in Scotland might not be policy, after all.
Taken to court over the issue by Ineos Shale, holder of two exploration licenses between Glasgow and Edinburgh, the government is hedging its position (OGJ Online, Jan. 20, 2018).
“The concept of an effective ban is a gloss,” government attorney James Mure said during the first day of judicial review, according to The Scotsman. “It is the language of a press statement.”
In October, Energy Minister Paul Wheelhouse told the Scottish Parliament hydraulic fracturing “cannot and will not take place in Scotland (OGJ Online, Oct. 3, 2017).”
He was announcing a decision to extend indefinitely a moratorium in place since 2015.
Parliament endorsed the decision in a 91-28 vote later that month.
Tom Pickering, Ineos Shale operations director, said Mure’s statement in court represented “a staggering U-turn on the policy direction” announced last October.
He said it casts “further uncertainty and ambiguity across the policy framework for onshore unconventional oil and gas development in Scotland.”
Norway plans offshore licensing round
Norway is planning a new licensing round for offshore oil and gas fields in the North Sea, Norwegian Sea, and Barents Sea. The licensing for mature, already open areas will expand available exploration acreage, the Norway Energy Ministry said.
An invitation to apply for petroleum production licenses, an updated map of the announced blocks, regulatory requirements and more information was posted on the Norwegian Petroleum Directorate web site.
Applications are due by Sept. 4. The ministry plans to award licenses in early 2019.
The latest licensing round was expanded to 103 blocks total compared with 2017 offerings of 47 Norwegian Sea blocks and 56 Barents Sea blocks.
India sets second small-field bid round
India’s Directorate General of Hydrocarbons has published documents for a second round of bidding for licenses containing discovered small fields (DSFs).
It will launch DSF Bid Round II in June, offering 26 contract areas on which 60 small fields have been discovered.
The areas, 15 onshore and 11 in the shallow offshore, cover a total of 3,100 sq km in eight sedimentary basins with estimated total hydrocarbons in place of 1.4 billion boe of oil and natural gas.
DGH hopes to sign revenue-sharing contracts by November. It will open data rooms in June and bidding via a portal on its web site in July. Bidding closes in September.
It will score bids 20% based on work program and 80% based on government revenue share.
DGH awarded 30 contract areas in its DSF Bid Round I, in which India made its first use of the revenue-sharing contract (OGJ Online, Mar. 28, 2017).
Lukoil signs new plan for West Qurna-2 field
Lukoil has signed a new development plan for West Qurna-2 oil field in Iraq with Basra Oil Co.
The plan calls for an increase in production to a plateau rate of 800,000 b/d in 2025 from current flow of 480,000 b/d.
The plateau target is lower than that of Lukoil’s earlier service contract, which called for early production from the Late Cretaceous Mishrif formation of 400,000 b/d and full-field Mishrif output of 550,000 b/d.
Production was to have risen to a plateau rate of 1.2 million b/d with development of the Early Cretaceous Yamana formation (OGJ Online, Mar. 31, 2014).
SDX makes gas discovery in Morocco
SDX Energy Inc., London, discovered conventional natural gas in its LMS-2 exploration well on the Lalla Mimouna permit in Morocco.
The operator is completing the well for production in the Miocene H-9 sand interval, a shallow marine deposit not previously tested in the area.
Drilled to 1,158 m TD, the well encountered 16.4 m of net gas pay with average porosity of 32% in an overpressured section and had liquid hydrocarbon shows.
The company plans an extensive test.
The well was the last of SDX’s nine-well drilling program in Morocco and the seventh successful well (OGJ Online, Sept. 21, 2017).
SDX holds 75% of the Lalla Mimouna permit. The National Office of Hydrocarbons and Mines (ONHYM) holds 25%.
Drilling & ProductionQuick Takes
Shell-Total combine to develop Omani gas
A combine of Shell and Total plans initial production of 500 MMcfd of natural gas from several discoveries to be developed in the Greater Barik area of onshore Block 6 in Oman, Total reports.
Production later might reach 1 bcfd, Total said as it announced the signing of a memorandum of understanding with the Omani government.
Shell is operator. Interests are 75% Shell and 25% Total, subject to a government back-in.
Total said it would use its equity gas entitlement as feedstock to develop a regional LNG bunkering service in Oman.
It plans to build a liquefaction train at Sohar with 1 million tonnes/year of capacity.
The plant could be expanded if warranted by expansion of the market for LNG as ship fuel.
Third Zohr production unit on production
Eni SPA and partners have started the third production unit, designated T-2, in deepwater Zohr natural gas field offshore Egypt, raising field capacity to 1.2 bcfd.
They had doubled capacity to 800 MMcfd at the end of April with start-up of the second unit, T-1 (OGJ Online, Apr. 30, 2018).
Production, which began last December, is to reach 2 bcfd by the end of 2018 and a plateau rate of 2.7 bcfd next year.
Zohr is in 1,500 m of water on the Shorouk Block, in which Eni holds a 60% interest, Rosneft 30%, and BP 10%.
Provisional contract let for Troll Phase 3
Equinor, formerly Statoil, has exercised an option for delivery of a processing module to be installed on the Troll A platform in the Norwegian North Sea if Phase 3 development proceeds at Troll oil and gas field.
Award of the $160-million engineering, procurement, construction, and installation contract to Aker Solutions ASA depends on a final investment decision and submission of a plan for development and production in the third quarter.
Phase 3 development targets natural gas reserves in the Troll West structure 25 km northwest of the Troll A platform.
It will use two subsea templates in 330 m of water, from each of which four production wells will be drilled for tie-back to Troll A. The platform handles gas from reserves developed in the eastern part of the field under Phase 1 development.
Phase 2 developed oil reserves from the Troll West structure. It included installation of the Troll B and C platforms.
Equinor expects Phase 3 development to extend Troll’s plateau gas production by 7 years. Last year, the field produced an average 783,000 boe/d of oil, gas, and condensate, of which 81% was gas, the Norwegian Petroleum Directorate said.
Troll field production comes from Late Jurassic Sognefjord and Middle Jurassic Fensfjord sandstone encountered at 1,300-1,400 m below sea level.
Equinor, operator, holds a 30.58% interest. Other interests are Petoro, 56%; Norske Shell, 8.10%; Total E&P Norge, 3.69%; and ConocoPhillips Scandinavia, 1.62%.
Verus to buy Babbage stake from Premier
Verus Petroleum UK Ltd., Aberdeen, will gain 2,400 boe/d of natural gas production through the purchase of interests in the southern UK North Sea from Premier Oil PLC, London.
The operators have agreed to an $88.1-million deal covering Premier’s 47% operated interest in Babbage gas field along with 50% operated interests in three adjacent licenses: P2212, P2290, and P2301.
Verus will pay $64.3 million in cash and assume exploration commitments valued at $23.8 million. It will make further cash payments of as much as $7.7 million if a discovery designated Cobra is developed.
Verus said it will drill a well 10 km from Babbage field in 2019.
Wintershall submits Nova oil development plan
The Norwegian Petroleum Directorate said Wintershall Nova AS and its partners submitted a plan for development and operation for the North Sea Nova oil field, previously called Skarfjell. Plans call for production from the subsea development starting in September 2021.
Reserves are estimated at 12.2 million standard cu m of oil equivalent (77 million bbl). Nova will be tied in to the Gjoa complex via pipelines. Neptune operates Gjoa. Nova is 17 km southwest of Gjoa.
The development involves two subsea templates with three production wells and three water injection wells. Wintershall plans to develop Nova with the flexibility so it could accommodate one additional subsea template with four wells.
The development includes a new module on Gjoa, already prepared to accommodate a third-party tie-in. Gjoa also will deliver lift gas to the field and water injection for pressure support. Nova will obtain electric power from Gjoa platform, which will get the power from shore.
Nova reserves were proved in 2012. The production license was awarded in 2007. The licensees in Nova production license 418 are Wintershall as operator with 35%, Spirit 20%, Capricorn Norge AS 20%, Edison Norge AS 15%, and DEA 10%. Capicorn is part of Cairn Energy.
NPD did its own studies, advocating water injection on Nova to ensure optimal utilization of resources.
Rosneft advances development off Vietnam
Rosneft Vietnam BV is advancing development of natural gas and condensate reserves on Block 06.1 in the Nam Con Son basin offshore Vietnam.
The Japan Drilling Co. Hakuryu-5 semisubmersible has spudded the LD-3P production well in 160 m of water in Lan Do (Red Orchid) field, which produces from two existing wells.
Rosneft plans a subsea completion tied back to the platform on Lan Tay (West Orchid) field.
Target depth of the LD-3P well is 1,200 m along the wellbore.
Lan Do and Lan Tay were discovered by BP.
Rosneft plans later this year to sidetrack its PLD-1P exploration well for production in Phong Lan Dai (Wild Orchid) field (OGJ Online, Mar. 9, 2016). The Hakuryu-5 rig will drill the sidetrack.
Production will flow to the Lan Tay platform, on which related construction is under way.
Rosneft Vietnam holds a 35% interest in the production sharing agreement for Block 06.1. Other interests are ONGC Videsh Ltd., 45%, and Petrovietnam, 20%.
PROCESSINGQuick Takes
API official sees questions after ethanol meeting
A May 8 White House meeting which tried to address some refiners’ problems with meeting quotas under the Renewable Fuel Standard apparently did not offer adequate solutions to the regulation’s problems, an American Petroleum Institute official suggested on May 14.
Allowing ethanol exports to be counted as Renewable Identification Numbers, which supposedly would put downward pressure on high prices for the renewable fuel credits and promising to authorize year-round sales of gasoline with a 15% ethanol blend won’t do the job, Frank J. Macchiarola, API Downstream and Industry Operations Group Director Frank J. Macchiarola told OGJ.
“On the E15 waiver, EPA has said it doesn’t have legal authority. It would require legislation to do this,” he explained. API also is concerned that about 75% of the cars on the road today are not built to run on E15, and cars are still manufactured that aren’t warranted for it, Macchiarola said. “We also believe the administration does not have the regulatory authority to allow for year-round E15 sales,” he indicated.
API also is concerned that counting ethanol exports to as RIN credits is contrary to the RFS and would not be able to withstand legal scrutiny, he continued. “Frankly, we think the entire process that is currently being undertaken about trying to find a regulatory fix is a perfect example of how the RFS is broken and needs comprehensive legislative reform. Any part of that should include a sunset provision,” Macchiarola said.
“We oppose the reallocation of volumes and believe that small refiner exemptions are evidence that the RFS is broken and comprehensive legislative reforms, including a sunset of the program, are needed,” he added.
Total, Sonatrach plan PDH-propylene complex
Total and state-owned Sonatrach of Algeria have agreed to start engineering studies for a propane dehydrogenation and propylene complex in Arzew.
The $1.4-billion project, owned 51% by Sonatrach and 49% by Total, would have output capacity of 550,000 tonnes/year of polypropylene. The partners plan to start front-end engineering and design this summer, subject to approvals.
The companies formed a comprehensive partnership last year.
TRANSPORTATIONQuick Takes
Shell Midstream to buy Amberjack pipeline interests
Shell Midstream Partners LP, Houston, has agreed to acquire Shell’s ownership interest in Amberjack Pipeline Company LLC, which is comprised of 75% of Amberjack Series A and 50% of Amberjack Series B for $1.22 billion (OGJ Online, Feb. 23, 2011).
The pipeline currently transports 300,000 b/d “due to the success of Jack St. Malo and Tahiti,” the company said, and is forecasted to transport approximately 400,000 b/d by the end of 2019 from continued in-field development, as well as new projects expected to come online.
The pipeline has “exceptional connectivity” in the Gulf of Mexico with delivery options along the Texas and Louisiana Gulf Coast, and shippers can deliver into multiple pipelines allowing for the transportation of four different crude grades.
Shell Midstream Partners plans to fund the acquisition with borrowings under existing credit facilities.
The acquisition is expected to close on or around May 11, subject to closing conditions.
Report: Canadian pipeline stasis costly
A regional crude price deeply discounted by pipeline congestion might cost energy companies in Canada $15.8 billion (Can.) this year, according to a new report.
A Fraser Institute bulletin by analysts Elmira Aliakbari and Ashley Stedman noted that the average price differential between Western Canadian Select (WCS) and West Texas Intermediate (WTI) crudes in the first quarter this year was $26.30/bbl (US).
The analysts estimated the “natural spread,” based on quality differences and transportation costs, at $11.80/bbl.
The WCS-WTI differential is widening as production of bitumen and heavy oil in Alberta and Saskatchewan increases while growth in pipeline takeaway capacity faces political opposition.
“As no major pipelines will be entering service till at least the latter half of 2019, we expect the WTI-WCS differential to remain elevated in 2018,” the analysts said.
They applied the expected WCS-WTI differential less the natural spread to projected heavy crude exports to calculate their estimate for lost revenue this year. Their figure was near that of a similar study by Scotiabank in February (OGJ Online, Feb. 21, 2018).
Aliakbari and Stedman made similar calculations for each year’s revenue loss during 2013-17 and estimated total revenue loss for all 5 years at $20.7 billion (Can.).
The annual loss was highest in 2013 at $9.88 billion (Can.) and lowest last year at $1.09 billion.
Kingfisher to build oil pipeline to serve STACK area
Kingfisher Midstream LLC, Oklahoma City, a wholly owned subsidiary of Alta Mesa Resources Inc., Blueknight Energy Partners LP (BKEP), and affiliates of Ergon Inc., will construct a crude oil pipeline serving STACK producers in central Oklahoma through newly-formed Cimarron Express Pipeline LLC.
BKEP will construct and operate the 65-mile, 16-in. crude oil pipeline extending from northeastern Kingfisher County, Okla., to BKEP’s Cushing, Okla., crude oil terminal, which it will continue to operate. The pipeline will have an initial capacity of 90,000 b/d, expandable to over 175,000 b/d. Completion is expected in mid-2019.
Cimarron Express will be owned 50/50 by Kingfisher Midstream and Ergon. Ergon, owner of the general partner of BKEP, will hold its ownership through a new wholly owned subsidiary, ERGON—Oklahoma Pipeline LLC (Devco). Both Ergon and BKEP have rights concerning the purchase or sale of Devco, subject to certain terms and conditions.
Concurrent with the formation of Cimarron Express, Alta Mesa executed a long-term acreage dedication and transportation agreement with Cimarron Express, which incorporates 120,000 net acres in Kingfisher and Garfield counties.
The receipt terminal for the pipeline will be Kingfisher’s crude oil storage facility in northeastern Kingfisher County and will connect to Kingfisher’s crude oil gathering system and truck unloading terminal.
