OGJ Newsletter

 GENERAL INTEREST Quick Takes

Total cancels deal to acquire Ghana assets from OXY

Citing the market environment, Total SA has decided to end the previously reported deal to acquire Ghana assets from Occidental Petroleum Corp.

In May 2019, Total agreed to an $8.8 billion purchase of assets in Algeria, Ghana, Mozambique, and South Africa that Occidental acquired in its acquisition of Anadarko Petroleum Corp. Total and Occidental have completed sales of the Mozambique and South Africa assets (OGJ Online, Sept. 30, 2019).

The purchase and sale agreement provided that the sale of the Ghana assets was conditional upon the completion of the Algeria assets’ sale. Occidental has informed Total that, as part of an understanding with the Algerian authorities on the transfer of Anadarko’s interests to Occidental, Occidental would not be in a position to sell its interests in Algeria to Total.

In Ghana, the deal would have seen Total acquire 27% participating interest in Jubilee field and 19% participating interest in the TEN fields. These fields represented a gross production of 143,000 b/d in 2018.

Because the purchase and sale agreement expires in September, Total and Occidental have executed a waiver of the obligation to purchase and sell the Ghana assets, so that Occidental can begin marketing the sale of the Ghana assets to other third parties.

Woodside to decommission Echo-Yodel gas field 

Woodside Energy Ltd., Perth, has submitted a plan to the Australian National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) for the decommissioning of Echo-Yodel gas/condensate field in production licences WA-1-L and WA-23-L on the North West Shelf about 140 km northwest of Dampier in Western Australia.

The plan involves the permanent plugging of three wells– the Yodel-3 and Yodel-4 production wells and the nearby Capella-1 exploration well.

Echo-Yodel field was brought on stream in late 2001 and reached the end of its economic life in 2012 with Yodel-4 ceasing production in 2006 and Yodel-3 in 2012. Capella-1 had been left as a suspended gas discovery since it was drilled in 1996.

The decommissioning plan intends that Echo/Yodel subsea infrastructure be left in place so that it can continue to provide hard substrate to maintain marine growth and habitat. This includes the well Christmas trees, 23 km pipeline linking the wells to the Goodwyn A production platform, and umbilical assemblies.

Woodside said the pipeline was cleaned and hydrocarbon freed in 2015/16 and put into a state of preservation. Well tie-in spools were also removed between the pipeline and the wells.

Capella-1, 40 km northwest of the Yodel wells, was not part of Echo-Yodel infrastructure and was suspended just after drilling with a shallow plug. The wellhead was left in place with the original intention of returning to run a drill stem test.

The decommissioning program is scheduled for 2021-2023.

Petronas completes Block 52 farm-out deal with ExxonMobil  

Petronas subsidiary Petronas Suriname Exploration & Production BV (PSEPBV) completed a deal to farm out a 50% interest in Block 52, offshore Surname, to ExxonMobil subsidiary ExxonMobil Exploration and Production Suriname BV, Petronas said in a release May 19.

Block 52, north of the coast of Paramaribo, lies in the prospective Suriname-Guyana basin covering an area of 4,749 sq km with water depths from 50-1,100 m.

PSEPBV is operator of Block 52 with 50%.

Petronas expects to drill one well on the block in this year’s third quarter in addition to acquiring new 3D seismic data, said Emeliana Rice-Oxley, Petronas’s vice-president of exploration.

In 2016, PSEPBV drilled the Roselle-1 well in Block 52 which provided subsurface information and data on the petroleum system of the area. Subsequent detailed analysis carried out by PSEPBV indicated that Block 52 contains multiple geological play types and is within the fairway for hydrocarbon generation and accumulation. 

Exploration & Development Quick Takes 

Genel declares force majeure event at Qara Dagh 

Genel Energy PLC declared a force majeure event impacting work on the Qara Dagh Block in the Kurdistan region of Iraq.

The QD-2 well was on track to spud in this year’s second quarter prior to COVID-19 impacting supply chains and the movement of people in to the region preventing the company from performing its contractual obligations as scheduled, Genel said in a release (OGJ Online, Oct. 28, 2019).

Genel is operator with 40% interest of the Qara Dagh production sharing contract. Partners are Chevron, 40%, and the Kurdistan Regional Government, 20%.

At Sarta oil field in the Kurdistan region of Iraq, where Genel holds 30% working interest, civil construction work is nearing completion, with the facility build ongoing, but first oil has been delayed to this year’s fourth quarter from the third quarter due to delays in the movement of people and equipment caused by the impact of COVID-19 (OGJ Online, Sept. 13, 2019).

DNO discovers Triassic reservoirs in Kurdistan region, Iraq 

DNO ASA has proven three separate Triassic reservoirs in the Kurdistan region of Iraq with data from the Baeshiqa-2 exploration well.

The well was originally spud in February 2019 and drilled to 3,204 m TD (2,549 m TVDSS), encountering 1 km of fractured carbonates with poor to good oil shows. Shallower Jurassic aged reservoirs were encountered and tested; however, the zones were not acid stimulated, and the results were inconclusive.

In November 2019, DNO issued a notice of discovery that hydrocarbons flowed to surface from the upper part of Triassic Kurra Chine B during first phase of testing. The reservoir produced 900-3,500 bo/d with specific gravity of 40-52° API and sour gas of 8.5-15 MMscfd. Following workover and acid stimulation, second phase testing resumed in March 2020 in three separate Triassic aged reservoirs.

During the tests, lower Kurra Chine B produced 600-3,500 bo/d with specific gravity of 47-55° API and sour gas of 4-18 MMcfd. The test demonstrated that upper and lower Kurra Chine B are in communication, proving a hydrocarbon-bearing reservoir interval of about 150 m.

Kurra Chine A flowed 950-3,100 bo/d of 30-34° API and sour gas of 1.8-3.6 MMcfd from a 70 m interval.

Kurra Chine C was the deepest encountered covering 34 m of what is expected to be a thicker 200 m reservoir. The drilled interval has been exposed to significant fracture damage due to pumping of lost circulation material. The reservoir produced 200-1,200 bo/d of 52° API gravity and sour gas of 3.8-6 MMcfd.

The results will determine next steps towards further appraisal and commercial assessment.

Spud of Zartik-1, an exploration well in a separate prospect 15 km southeast on the Baeshiqa license, was expected in May. Site construction was completed late April.

DNO acquired 32% interest and operatorship of Baeshiqa in 2017. Partners include ExxonMobil (32%), Turkish Energy Co. (16%), and the Kurdistan Regional Government (20%).

Premier delays Tolmount first gas 

Premier Oil PLC has pushed the start of gas production at Tolmount field in the southern UK North Sea to second-quarter 2021 from fourth quarter this year (OGJ Online, July 13, 2018). The schedule has been impacted by the COVID-19 pandemic, the company said in a release. Tolmount East is on track for sanction decision by yearend.

Development of Tolmount, expected to produce around 500 bcf of gas (96 MMboe) with peak production of up to 300 MMscfd (58,000 boe/d), was sanctioned in August 2018.

The project entails a minimal facilities platform exporting gas to shore via a new gas pipeline. The EPCIC contract for the platform was awarded to Rosetti Marino. Centrica’s Easington terminal has been selected as the host facility and Saipem as the pipeline EPCI contractor.

Premier is operator with 50%. Dana Petroleum holds the remainder.

Drilling & Production Quick Takes 

Equinor drills dry well near Fram field in North Sea 

Equinor Energy AS will plug well 35/10-6 in the northern part of the North Sea. The well is dry.

Equinor, operator of production license 827 S, concluded drilling the well 20 km northwest of Fram field and about 145 km northwest of Bergen.

Well 35/10-6, the first exploration well in the license, was drilled by the West Hercules drilling facility to a vertical depth of 1,907 m subsea. It was terminated in the Lista formation in the Late Palaeocene. Water depth at the site is 368 m.

The objective of the well was to prove petroleum in Early Eocene and Late Palaeocene reservoir rocks (Intra Balder and Sele formation sandstones). Sandstones were not encountered in the Balder formation. In the Sele formation, sandstones were encountered with a thickness of about 40 m with good to very good reservoir properties.

Data has been collected. The rig will now drill wildcat well 30/2-5 S in production license 878 in the northern North Sea, where Equinor is operator.

Total idles Deepsea Stavanger 

Total South Africa has idled the Odfjell Drilling Deepsea Stavanger semi-submersible drilling rig in Norway for an unspecified time due to ongoing restrictions related to the coronavirus (COVID-19) pandemic. Deepsea Stavanger is on contract with Aker BP and Total to first quarter 2021 with an option to extend until end of 2022. Odfjell will be compensated by Total during the downtime.

Once the idle period is complete, the rig will mobilize to proceed with the multi-exploration program in Total-operated Block 11B/12B.

Lundin lowers production guidance for 2020 

Lundin Energy AB lowered production guidance for full-year 2020 following the Norwegian Government’s production restriction on the Norwegian Continental Shelf. The new guidance will target 157,000 boe/d, which is at top end of the revised 145,000-165,000 boe/d guidance range. Previous guidance had been upgraded to 160,000-170,000 boe/d prior to governmental production cuts.

Production restriction measures will impact the company’s output from June through December 2020, with unrestricted production resuming in 2021. To take advantage of excess production capacity, planned maintenance shutdown on Edvard Grieg, previously deferred from 2020 to 2021, will now take place third quarter 2020.

Due to recently announced increased production capacity at Johan Sverdrup, Lundin is increasing its long-term production guidance to 170,000-180,000 boe/d from 2021 (OGJ Online, Jan. 14, 2020).

PROCESSING Quick Takes 

CNOOC, Shell plan ethylene capacity expansion at Nanhai complex 

Royal Dutch Shell PLC subsidiary Shell Nanhai BV and China National Offshore Oil Corp. (CNOOC) have entered a strategic cooperation agreement to expand ethylene production capacity at their 50-50 joint venture CNOOC & Shell Petrochemicals Co. Ltd.’s (CSPC) petrochemical complex in Daya Bay Economic & Technological Development Zone, Huizhou City, Guangdong Province, China.

The agreement, signed virtually by Shell and CNOOC in an online event on May 17 due to coronavirus travel restrictions, outlines the JV’s plan to build CSPC’s Phase 3 ethylene project at Nanhai, which will include construction of a new 1.5 million-tonnes/year cracker, Shell said in a release on Chinese-language website.

Construction of the grassroots cracker—which will be equipped with Shell’s proprietary advanced linear alpha olefin technology—comes as part of CSPC’s strategy to serve growing customer demand for intermediate and high-performance chemicals in China’s major markets. Alongside ethylene, the proposed expansion also will increase CSPC’s ability to supply styrene monomer and propylene oxide (SMPO), polyether polyols, ethylene glycol, polyethylene, and polypropylene to the market, according to Shell.

Announcement of the CSPC’s Nanhai Phase 3 project—which local media outlets in China reported will require a nearly $6-billion investment—follows an October 2018 memorandum of understanding signed by Shell and CNOOC to explore the possibility of further expanding petrochemical operations at the complex (OGJ Online, Oct. 24, 2018).

CSPC previously commissioned its Phase 2 expansion at Nanhai in May 2018. Alongside a 1.2 million-tpy cracker that more than doubled ethylene capacity of the complex, CSPC also started up several associated derivative units (OGJ, May 2, 2018).

Upon announcing the Phase 3 expansion, Shell also confirmed CSPC is progressing at Nanhai with construction of a second SMPO plant that, once completed, will become China’s largest.

Shell, however, disclosed no specific timelines for either development of the Nanhai Phase 3 expansion or commissioning of the complex’s second SMPO plant.

PKN Orlen lets contract for new petrochemical unit at Plock complex 

Polski Koncern Naftowy SA (PKN Orlen) has let a contract to Badger Licensing LLC to provide technology for a new unit to be included as part of a project to expand phenol production capacities at its 327,300-b/d integrated refining and petrochemical complex in Plock, Poland (OGJ Online, Dec. 2, 2019).

As part of the May 12 contract, Badger Licensing will deliver the basic engineering design package as well as licensing of its proprietary technology to make isopropanol from acetone for a grassroots isopropanol unit, PKN Orlen said.

Basic engineering design work and launch of the selection process for a general contractor on the proposed project—which, if approved, would include the isopropanol unit as well as associated systems and infrastructure—are scheduled to start in the coming months, the operator said.

The project to expand Plock’s phenol and acetone value chain is one of four included in PKN Orlen’s Petrochemicals Development Programme (PDP), which aims to position the company to take full advantage of its potential in petrochemicals by adding some 30% to the operator’s existing capacity while ensuring a marked improvement in Poland’s overall trade balance in petrochemicals.

The proposed isopropanol unit also would have the additional advantage of making Poland more secure in the event of an epidemic, as isopropyl alcohol—a less expensive substitute for ethanol or methanol—has antiviral properties and is used in the production of antiseptic fluids, according to Obajtek.

Launched in 2018 and requiring an estimated investment of about 8.3 billion zloty, the PDP—which alongside the isopropanol unit also includes plans to build an aromatic derivatives plant—will be implemented through yearend 2023.

PKN Orlen previously let contracts to add a new visbreaking unit, increase production of ethylene and aromatics, and improve flexibility of gasoline production as part of the Plock petrochemicals expansion (OGJ Online, Feb. 27, 2020; Sept. 13, 2019).

Advanced Petrochemical lets contract for Jubail PDH-PP complex 

Advanced Global Investment Co. (AGIC), a subsidiary of Advanced Petrochemical Co. (APC), has let a contract to Fluor Corp. to provide project management consulting (PMC) for the operator’s proposed propane dehydrogenation (PDH) and polypropylene (PP) complex at APC’s existing operations in Jubail Industrial City, on Saudi Arabia’s eastern coast.

As part of the contract, Fluor will deliver PMC services for front-end engineering design, detailed engineering, procurement, and construction phases of the project, including associated utilities and off sites, Fluor said on May 14.

Once completed, AGIC’s complex will produce 843,000 tonnes/year of propylene and 800,000 tpy of PP that will be used for production of specialty polymers by manufacturers in the face mask, automotive, pipes, food packaging, and textiles industries, according to the service provider.

Fluor, which booked its portion of the undisclosed contract value in first-quarter 2020, said it will execute the project from its offices in Farnborough, UK, and Al Kobar, Saudi Arabia, with support from the firm’s global network.

Award of the PMC contract follows AGIC’s Mar. 27 signing of a shareholders agreement with SK Gas Co. Ltd. subsidiary SK Gas Petrochemical Pte. Ltd. (SKGP) to establish a joint venture named Advanced Polyolefins Co. (APC JV) for construction and operation of the proposed PDH-PP complex, according to a Mar. 29 release from APC.

At a total estimated cost of about $1.8 billion, the planned PDH-PP project will be financed 25% by equity of shareholders, while APC JV will finance the remaining 75% via borrowing from lenders, APC said. AGIC will hold 85% interest in APC JV, with SKGP to hold the remaining 15% stake.

APC also confirmed AGIC has already awarded a series of contracts for technology to be implemented at the proposed PDH-PP complex. Lummus Technology LLC will deliver licensing for its proprietary CATOFIN technology for the PDH plant, while LyondellBasell Industries NV subsidiary Basell Poliolefine Italia SRL will license its proprietary Spherizone and Spheripol technologies for the complex’s two PP plants, each of which will have a capacity of 400,000 tpy, APC said.

APC said APC JV expects to begin construction in 2021 on the new PDH-PP complex—which will receive its main feedstock of propane from Saudi Aramco under a long-term contract—for a targeted start-up of operations by second-half 2024.

APC currently produces 455,000 tpy of propylene and 450,000 tpy of PP at its existing Jubail Industrial City plants, according to the company’s website.

TRANSPORTATION Quick Takes 

API: Liquids pipeline incidents affecting people, environment down 36% 

Total liquids pipeline incidents impacting people or the environment decreased 36% over the last 5 years, while total pipeline incidents were down 17%, according the American Petroleum Institute (API) and Association of Oil Pipe Lines (AOPL). The organizations’ 2019 Performance Report & 2020-2022 Strategic Plan also reported that pipeline incidents impacting people or the environment caused by corrosion, cracking, or weld failure decreased 50% over the last 5 years. Corrosion-based failures dropped 45%

The performance data presented by this report is government-collected data on pipeline incidents made publicly available by the US Pipeline and Hazardous Materials Safety Administration (PHMSA). Each year, API and AOPL download PHMSA incident data to analyze where pipeline operators are making progress and to focus upcoming industry-wide safety improvement efforts.

Pipeline incidents impacting people or the environment caused by equipment failure were down 15% over the last 5 years. Incidents related to installing and maintaining pipeline equipment or operating the pipeline and its valves or pumps were down 13% over the last 5 years in areas impacting people or the environment. In these areas, incidents caused by incorrect operations decreased by 11% while equipment failure decreased 15% from 2015 to 2019, API and AOPL said.

Over the last 5 years, only 7% of crude oil incidents were larger than 500 bbl. Crude oil incidents greater than 50 bbl have decreased 26%, from 42 to 31 incidents, according to the organizations. Over the same timeframe, liquid pipeline mileage has increased nearly 10%, including a 20% increase in crude oil pipelines, while total barrels delivered increased 35% from 2014.

Williams places Phase II Hillabee Transco expansion in service 

Williams has placed in service Phase II of its Hillabee expansion project, a Transco expansion that provides natural gas to Florida’s power generation market. The incremental expansion provides firm capacity to Sabal Trail Transmission via a capacity lease arrangement, enabling direct access from the Station 85 pooling point in Choctaw County, Ala., to natural gas markets in Florida.

Phase I of the Hillabee expansion project entered service in July 2017. Phase II of the project included the construction of 11 miles of pipeline looping, a new compressor at Station 95, and modifications to a compressor at Station 100. The Phase II expansion increases Transco system capacity by almost 270 MMcfd. Together, Phases I and II increased Transco’s capacity by more than 1 bcfd.

Williams began work on the project in 2016.

Woodside awards Pluto-Karratha interconnector project contract 

Woodside Petroleum Ltd. has let a supply and fabrication contract for the planned Pluto-Karratha gas plant interconnector project on the Burrup Peninsula of northwest Western Australia to Civmec Construction and Engineering.

The work involves Civmec fabricating the structural steel, piping, a module and skids within the Pluto LNG plant which will be used to support the interconnector project. Construction is expected to take 7 months, beginning this year.

The interconnector is proposed to transport gas from the Pluto facility to the North West Shelf project’s LNG plant via a 5 km pipeline to be built along the existing Dampier to Bunbury natural gas trunkline corridor.

A final investment decision on the pipeline component of the interconnector was made in November 2019 and DDG Operations Pty Ltd. (part of the Australian Gas Infrastructure Group) was contracted to construct the pipeline as well as its ongoing operation and maintenance.

The interconnector will create opportunities to take advantage of future excess capacity at the Karratha gas plant. It also has the potential to accelerate future developments of Pluto field gas reserves as well as third party resources.

The on-stream date is scheduled for 2022.