GENERAL INTEREST Quick Takes
BHP confirms planned Bass Strait exit
BHP has confirmed that it intends to exit its 50% interest in Bass Strait exploration and production permits offshore Gippsland basin, Victoria.
Chief Executive Officer Mike Henry made the statement in the context of the company’s full 2019-2020 results report Aug. 18.
The company is looking to withdraw from all its later-life assets, including Bass Strait, and will turn its focus on higher value assets, he said.
BHP originally took up the permits in the early 1960s, bringing in Esso Exploration (now ExxonMobil) to be equal 50% interest holder and operator.
The major oil discoveries were made in the latter half of the 1960s into the early 1970s which catapulted Australia into oil self-sufficiency within a few years of being brought on stream. Discoveries also included large gas reserves which transformed Victoria from coal gas to natural gas as an energy source.
BHP’s intention to sell its interest follows a similar move by ExxonMobil in 2019.
Analysts suggest BHP’s stake could be worth up to $3 billion.
Kenya block partners to withdraw notices of force majeure
Joint venture partners on Tullow Oil Kenya BV-operated blocks 10BB and 13T in Kenya have submitted a letter to the Kenyan Ministry of Petroleum and Mining to withdraw the notices of force majeure that were declared May 15, Africa Oil Corp. said in an Aug. 21 release.
Lifting of force majeure notices has been facilitated by the improvement in COVID-19 pandemic restrictions worldwide and the resumption of local and international flights, allowing the restart of the various workstreams under the project, the company said.
The joint venture partners are continuing discussions with the Kenyan government to determine the best way forward for the project.
The partners have proposed that Amosing, Ngamia, and Twiga fields should be developed as a first stage of the South Lokichar development (OGJ Online, July 5, 2012; Jan. 5, 2015). This stage would include a 60,000-80,000 b/d of oil central processing facility and an export pipeline to Lamu.
Final investment decision is expected in this year’s second half.
Lundin Energy appoints Fitzgerald COO
Lundin Energy AB has appointed Daniel Fitzgerald as chief operating officer of Lundin Energy, effective Jan. 1, 2021.
Fitzgerald is currently chief operating officer of International Petroleum Corp. (IPC), a member of the Lundin Group of companies.
He previously held senior management and operational leadership positions with Lundin Petroleum AB.
The appointment follows the decision by Alex Schneiter, president and chief executive officer of Lundin Energy, to step down and the appointment of Nick Walker, Lundin Energy’s current chief operating officer, to succeed him (OGJ Online, Aug. 18, 2020).
William Lundin has been named to succeed Fitzgerald as IPC chief operating officer, effective Dec. 1, 2020. Lundin has worked in the engineering and production operations departments at IPC in Canada and prior to that, worked for BlackPearl Resources Inc., which was acquired by IPC in December 2018.
Exploration & Development Quick Takes
Australia to release new areas for offshore exploration
The Australian government has announced the release of 42 new areas for petroleum exploration in Commonwealth waters. The bulk are offshore northern Australia with three offshore Victoria.
Federal Minister for Resources, Water and Northern Australia Keith Pitt said about 100,000 sq km has been made available across five basins: North Carnarvon basin, Western Australia (19 blocks); Bonaparte basin, Northern Territory (12 blocks); Browse basin, northwest Australia (8 blocks); Gippsland basin, Victoria (2 blocks); and Otway basin, Victoria (1 block).
Pitt acknowledged the impact the COVID-19 pandemic is having on the oil and gas industry, but said the government strongly believes exploration will play a key role in helping the Australian economy recover from the crisis.
All areas in the 2020 release are based on industry nominations and were subject to a comprehensive public consultation process. The areas are available for work-program bidding.
The bidding process will close on June 1, 2021.
Libra Mero consortium launches Phase 3 development
Petrobras and partners have taken the investment decision for the third phase of the Mero project in the ultradeep Libra block offshore Brazil in the Santos basin, 180 km from Rio de Janeiro.
Mero 3 follows investment decisions for Mero 1 (startup expected in 2021) and Mero 2 (startup expected in 2023) FPSOs, both of which have liquid processing capacities of 180,000 b/d .
Petrobras signed a letter of intent with MISC Berhad for FPSO Marechal Duque de Caxias to produce Mero 3 in the southern part of the field. It will have a liquid treatment capacity of 180,000 b/d and is expected to start up by 2024. The project plans to tie back eight oil producers and seven water and gas injectors to the FPSO through rigid production and injection flowlines, flexible service flowlines, and control umbilicals.
The Libra consortium will carry out a pilot test of HISEP in Miro 3—a high-pressure separation technology developed and patented by Petrobras. It consists of CO2 subsea separation and reinjection using centrifugal pumps. This will relieve the oil processing plant in the FPSO and increase oil production, Petrobras said Aug. 17.
Mero was discovered by the 2-ANP-2A-RJS appraisal well in 2010 and has been in pre-production since 2017 with the 50,000 b/d Pioneiro de Libra FPSO (OGJ Online, Feb. 3, 2020).
The Libra Consortium is led by Petrobras as operator with 40% interest. Partners are Shell and Total, 20% each; and China National Petroleum Corp. and CNOOC Ltd., 10% each. State-owned Pre-Sal Petroleo is contract manager.
Pemex installs Yaxche-C platform
Pemex has installed the jacket and topside for Yaxche-C using Heerema’s Balder deepwater construction vessel (DCV). Yaxche is in Mexico’s Amoca Yaxche blocks, offshore Tabasco state in the Bay of Campeche at water depths of 20-50 m.
Balder arrived on location and started work Aug. 8. Jacket and topside installation were completed Aug. 15.
Engineering, procurement, construction, and installation was awarded to a consortium of Cotemar, Hoc Offshore (Arendal), and Construcciones Mecanicas Monclova (Commsa).
The jacket and platform were fabricated in Tampico, Mexico, by Cotemar. The jacket weighs 700 tonnes, the four skirt piles are 125 tonnes each, and the topside is 850 tonnes. All components left the fabrication yard on one barge to be stored at Dos Bocas before being taken to the Bay of Campeche for installation. Balder will remain in the Gulf of Mexico for more upcoming installation work.
Deltic increases gas estimates at Selene, UK Southern North Sea
Deltic Energy PLC materially increased the estimated volume of gas compared to previous estimates and increased the chance of success in the Selene prospect in the P2437 license area, UK Southern North Sea.
The improvements came from reprocessing existing 3D seismic and utilizing an innovative approach to depth conversion, the company said. The work was performed by a joint Deltic-Shell team after Shell farmed into the license in 2019. Further work was completed on the depositional environment, structural history, gas charge timing, and reservoir quality prediction.
Results from this technical analysis have increased P50 Selene gas initially in place (GIIP) by 44%, to 629 bcf from 437 bcf, while simultaneously improving the geological chance of success (GCoS) by 79%, the company said.
Further work will focus on potential development scenarios, estimation of recovery factors and project economics which are required to support the well investment decision prior to the proposed 2022 drilling activity.
Deltic is operator of the license with 50% interest. Shell holds the remaining 50%.
Drilling & Production Quick Takes
Total spuds Luiperd-1 offshore South Africa
Total SA and partners have spudded Luiperd-1X, the second exploration well on Block 11B/12B offshore South Africa, following the Brulpadda discovery in February 2019.
The well is being drilled by the Odfjell Deepsea Stavanger semisubmersible rig in 1,795 m of water to a total depth of 3,550 m subsea, partner Africa Energy Corp. said Aug. 28. The well will test the oil and gas potential in a mid-Cretaceous aged deep marine sequence where fan sandstone systems are developed within combined stratigraphic-structural closure. Drilling and evaluation of the well is expected to be completed in fourth-quarter 2020.
The block, in Outeniqua basin 175 km off the southern coast, covers an area of some 19,000 sq km in water depths of 200-1,800 m. The Paddavissie Fairway is in the southwest area of the block and includes the Brulpadda discovery, which confirmed the petroleum system. The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data (OGJ Online, Jul 7, 2020).
Total E&P South Africa BV is operator (45%) with partners Qatar Petroleum International Upstream LLC (25%), CNR International (South Africa) Ltd. (20%), and Main Street 1549 Proprietary Ltd. (10%, of which Africa Energy has a 49% stake).
Beach signs new drilling contract for Diamond rig
Beach Energy Ltd. has executed a new offshore drilling agreement with Diamond Offshore General Co. for the use of the semisubmersible Ocean Onyx for a drilling program in the offshore Otway basin in western Victoria.
The agreement provides for the drilling of up to nine wells (six firm and three options) beginning with the Artisan-1 wildcat and followed by a number of development wells in Geographe and Thylacine gas fields.
Artisan-1 is expected to spud between December 2020 and March 2021. The contract includes provisions for COVID-19 related costs and delays.
Beach said that concurrent with this agreement, the two parties also signed a settlement agreement dismissing all current legal proceedings regarding the termination of the previous drilling agreement in March. The termination was sparked by the late arrival of the Ocean Onyx past the original contract start date (OGJ Online, Apr. 28, 2020).
Since that time the semisubmersible has been stacked in Port Phillip Bay near Melbourne, a 1-2-day sail from the Otway region.
Beach said it can move forward with its plans to develop additional gas supplies in the Otway and will work with Diamond during the next months to prepare for campaign startup.
ROK Resources increases production in Glen Ewen, Saskatchewan
ROK Resources Inc. began a well repair and reactivation program to increase production and improve environmental protection systems in its recently acquired Glen Ewen properties in Saskatchewan. The company produced about 170 boe/d in July, and following workovers on two wells, production increased to about 210 boe/d for the first 14 days in August.
Following the Glen Ewen asset acquisition, ROK holds 6,072 net acres within the Glen Ewen and Florence area. The land lies within a larger area of historical production for both the Midale and Frobisher beds. The new acreage position allows for the drilling of up to 12 1-mile long fractured horizontal wells targeting the Midale beds and six half-mile long horizontal wells targeting the Frobisher beds. As oil prices recover, six of these 18 locations are expected to be drilled to assess reserves and to allow for the development of production infrastructure.
Recent hydraulic fracture stimulation within Glen Ewen has created an opportunity to apply similar completion techniques to the Midale beds throughout Glen Ewen and Florence project areas, the company said. While the Midale formation has historically been produced within the Florence area, the interbedded nature of the rock suggests that better results would be achieved using horizontal fracturing technology. In addition, the company plans to target the Halbrite and Huntoon cycles of the Frobisher beds. The Frobisher shoaling events create high permeability reservoirs which can provide high initial productive rates and favorable short-term economics with payouts in less than a year, the company said.
With an investment in 2 miles of gathering pipelines, the ROK expects to have sufficient capacity to process emulsion, dispose water, and conserve gas for development of the land bases. The recently acquired 9-23-2-1W2 facility is underutilized and capable of processing 4,500 bbl of fluid/day. Conversion of an additional well to saltwater disposal should further expand capacity of the facility, ROK said. Historical capacity was 6,000 bbl fluid and 1,000 bbl sales oil.
PROCESSING Quick Takes
No timeframe for restart of Keyera’s Wapiti gas plant
Keyera Corp. has indefinitely extended the timeframe of a recently announced unplanned outage at its Wapiti natural sour gas processing and liquid stabilization plant about 60 km south of Grand Prairie, Alta. (OGJ Online, Aug. 25, 2020).
Keyera informed Pipestone Energy Corp. on Aug. 27 that the issue relating to the Wapiti plant’s waste heat recovery system that led to the outage is more widespread than previously indicated, with the total scope of the problem and root cause of the outage still yet to be determined, Pipestone Energy—which has secured long-term natural gas gathering, compression, and processing capacity at the plant—said on Aug. 28.
As a result, the original estimate provided by Keyera to repair the plant and return to operations by the week ending Sept. 4 is no longer valid, with Keyera currently unable to provide a definitive indication for the anticipated duration of the plant’s outage, according to Pipestone Energy.
Based on this new development, Pipestone Energy has formally suspended its 2020 production and cash flow guidance released on Aug. 5 of 16,000-17,000 boe/d and $40 million at the midpoint, respectively, due to the timing uncertainty for the Wapiti plant’s return to normal operations.
Pipestone Energy reiterated its contingent business interruption insurance—which includes coverage on the Wapiti plant—has a 30-day waiting period but should cover any net financial losses incurred by the company, if necessary, should the outage extend beyond Sept. 16.
Pipestone Energy previously said both itself and Keyera are performing maintenance and installation activities that otherwise would have resulted in planned downtime during late third-quarter and early fourth-quarter 2020 during the ongoing plant outage.
Keyera commissioned Phase 1 of the Wapiti gas plant in May 2019 with gas processing capacity of 150 MMcfd and condensate handling capacity of 25,000 b/sd, and also has approved a second phase of the Wapiti plant scheduled for commissioning in fourth-quarter 2020 that will add another 150 MMcfd of gas processing capacity at the site (OGJ Online, May 31, 2018).
TurkmenGaz’s Kiyanly chemical complex achieves full production rates
State-owned TurkmenGaz increased production of export-bound polymer products during January-July 2020 amid reaching full production capacity at its Kiyanly gas chemical complex in the Turkmenbashi district of Balkan Province in western Turkmenistan.
Initially commissioned in October 2018, the Kiyanly gas chemical complex—the largest in the region—during first-half 2020 ramped up production of polyethylene and polypropylene to full capacity rates of 381,000 tonnes/year (tpy) and 81,000 tpy, respectively, Turkmen state media said on Aug. 27.
Full commissioning of the Kiyanly complex helped increase the country’s overall polyethylene production by 140.0% (to 1.374 million tonnes) and polypropylene by 40.5% (to 711,000 tonnes) between January-July 2020, according to data from the State Statistics Committee of Turkmenistan.
Funded by export credit agencies and built by a consortium of Toyo Engineering Corp., Hyundai Engineering Co. Ltd., Hyundai Engineering & Construction Co. Ltd., and LG International Corp., the Kiyanly gas chemical complex originally was to use technology from Lummus Technology and W.R. Grace & Co. to produce 400,000 tpy of ethylene and high-density polyethylene, as well as 80,000 tpy of polypropylene, for export to markets mainly in the Asia Pacific, Europe, and Turkey using gas sourced from shelf of the Caspian Sea (OGJ Online, Apr. 29, 2016; Apr. 20, 2015).
The complex also was to house a planned 5-billion cu m/year gas separation unit equipped with Toyo’s Coreflux technology to enhance recovery of ethane and LPG, with BASF SE’s Oase technology to enable acid gas removal (OGJ Online, May 12, 2014).
TRANSPORTATION Quick Takes
Mountain Valley pipeline requests 2-year extension from FERC
Mountain Valley Pipeline (MVP) LLC has requested a 2-year extension from the US Federal Energy Regulatory Commission (FERC) for completion of its 303-mile, 2-bcfd Appalachian natural gas pipeline. The company, headed by EQM Midstream Partners LP, cited “unforeseen litigation and permitting delays” in requesting the extension.
The company has installed 253 miles of pipeline and restored 153 miles of right-of-way, according to its request, describing it as 92% complete. Construction of the project’s three compressor stations is also complete. MVP was to have been completed by October 2020 based on the FERC certificate issued October 2017.
MVP expects to receive outstanding permits and opinions from the US Fish and Wildlife Service, the US Forest Service, the National Park Service, and the US Army Corps of Engineers by end 2020. The company cited efforts by opposition groups to delay permit issuance as among the factors prompting its request.
The North Carolina Department of Environmental Quality earlier in August denied a Clean Water Act approval for MVP’s 75-mile Southgate extension (OGJ Online, Aug. 11, 2020).
EQM’s partners in MVP are NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream, and RGC Midstream LLC.
KMI gets FERC permission to start Elba Island Train 10
Kinder Morgan Inc. (KMI) received US Federal Energy Regulatory Commission permission to put Train 10 of its Elba Island LNG plant near Savannah, Ga., in service, bringing total capacity to about 2.5 million tonnes/year. KMI earlier in August had begun Train 9 operations.
The company started Train 1 fourth-quarter 2019 (OGJ Online, Oct. 4, 2019).
The Elba Island project is owned 51% by KMI and 49% by EIG Global Energy Partners, supported by a 20-year offtake agreement with Royal Dutch Shell PLC.
Delta Offshore awards subsea pipeline FEED to McDermott
Delta Offshore Energy awarded McDermott International Ltd. a contract to provide front-end engineering design (FEED) services for a 22-mile subsea gas pipeline. The pipeline is part of an integrated LNG-to-power project and will connect a regasification platform to the planned 3,200-Mw combined-cycle power plant in Bac Lieu Province, Vietnam.
McDermott also won the pre-engineering geotechnical and geophysical survey services being carried out as a part of the FEED scope. Three months before the award, McDermott began a feasibility study for the project, which was converted into the FEED.
McDermott anticipates the FEED contract will be converted into an engineering, procurement, construction, and installation contract first-quarter 2021.
Alaska LNG gets non-FTA export authorization
The Alaska LNG Project LLC (Alaska LNG) has received US Department of Energy (DOE) authorization to export domestically produced LNG from its proposed liquefaction terminal in Nikiski, Alas. Alaska LNG plans to build an 800-mile pipeline connecting the 20-million tonne/year liquefaction plant to natural gas reserves on the North Slope. The Federal Energy Regulatory Commission authorized the siting, construction, and operation of Alaska LNG and the 42-in. OD pipeline earlier this year (OGJ Online, May 21, 2020).
Under terms of the DOE authorization, as much as 2.55 bcfd of natural gas can be exported as LNG from the plant and export terminal on the Kenai Peninsula over a 30-year term to any country with which the US does not have a free trade agreement (non-FTA countries), and with which trade is not prohibited by US law or policy. At full capacity the plant is expected to liquefy about 3.5 bcfd.
Alaska LNG is the twentieth large-scale export project to have final long-term DOE authorization to export LNG to non-FTA countries, and the second on the West Coast after the July approval of Pembina Pipeline Corp.’s Jordan Cove project in Oregon (OGJ Online, July 6, 2020).
State-owned Alaska Gasline Development Corp. has led the project since 2016. DOE conditionally approved exports from Alaska LNG to non-FTA countries in 2015 and to FTA countries in 2014.
If built to its authorized capacity, Alaska LNG, including the pipeline, is expected to cost more than $38 billion.