OGJ Newsletter

May 3, 2021


EOG enters Australia with Bonaparte Gulf permit interest

EOG Resources Inc., through a new subsidiary, EOG Australia, has ventured into Australia with an agreement to acquire 100% interest in Bonaparte Gulf permit (WA-488-P), which contains the prospective Beehive structure, from a subsidiary of Melbana Energy Ltd., Melbourne.

The sale to EOG enables Melbana to retain exposure to the upside potential of a Beehive discovery. Melbana will receive an up-front payment of $7.5 million upon satisfaction of conditions precedent, plus $5 million in contingent payments. Of the latter amount, $2.5 million will be payable contingent on EOG entering the final year of the exploration permit which includes the commitment for drilling one well. The other $2.5 million is payable contingent on EOG being awarded a production licence over the permit.

Melbana will also receive future payments of $10 million for each 25 MMboe produced, sold, and delivered by EOG from the permit area.

Included is data from a 700-sq km 3D seismic survey as well as extensive 2D seismic coverage. The 3D survey was acquired in 2019 by previous farminees Total and Santos (OGJ Online, Nov. 5, 2019; Mar. 4, 2020).

An independent study has estimated the Beehive prospect, a large carbonate structure, to hold up to 416 MMboe.

In the meantime, Melbana has retained its adjacent permits WA-544-P and NT/P87 which the company acquired in 2020. These two permits, which lie either side of the marine boundary between Western Australia and the Northern Territory, contain the undeveloped Turtle and Barnett oil discoveries.

Conditions precedent for the sale include regulatory approvals, approval to suspend and extend the remaining permit obligations to allow more time to drill the initial exploration well, and approval of the sale by Australia’s Foreign Investment Review Board.

OPEC+ to keep current plan of gradual production increase

The Organization of the Petroleum Exporting Countries and its allies (OPEC+) met Apr. 27, a day earlier than previously planned, and decided to maintain its current plan to gradually raise production. The news comes amid growing concerns that a surge in COVID-19 cases in India could lead to notable oil demand destruction.

In a statement, OPEC+ said it “decided on the continued implementation of the production adjustment decision” of the Apr. 1 meeting during which the decision was made to gradually lift oil production by 350,000 b/d in May, 350,000 b/d in June, and 441,000 b/d in July. It had been holding back around 8 million b/d of output, including Saudi Arabia’s voluntary cut of 1 million b/d. Saudi Arabia also planned to ease its voluntary cut over the 3-month period. In total, the group agreed to bring 2.1 million b/d back to the market from May to July, easing cuts to 5.8 million b/d.

The OPEC+ group highlighted the continuing recovery in the global economy, but also noted that, even though more than 1 billion COVID-19 vaccine doses had been administered globally, it was concerned that surges in new virus cases in India, Brazil, and Japan might derail recovering demand for crude.

It was decided that the 30th JMMC Meeting and the 17th OPEC and non-OPEC Ministerial Meeting will take place on June 1, 2021.

Mubadala Petroleum signs MoU for Tamar gas field stake

Mubadala Petroleum, Abu Dhabi, has signed a non-binding Memorandum of Understanding (MoU) for Delek Drilling’s 22% non-operated stake in Tamar gas field offshore Israel.

Under an earlier gas framework agreement outlined by the government of Israel, Delek Drilling must sell all holdings in Tamar by end 2021.

Tamar field, 90 km west of Haifa, was discovered in 2009 at an overall depth of 5,000 meters below sea level, and in waters 1,700 m deep. Production began in 2013. Natural gas is extracted through five production wells and flowed through two 140-km pipelines to the primary and main processing plant on the Tamar platform. The gas is then transmitted through a pipeline to the onshore terminal in Ashdod, and into the Israeli market through the INGL national gas pipeline with a portion exported to Jordan and Egypt.

Proven and probable reserves in the lease, after production of more than 69.3 billion cu m (bcm), is estimated at 300 bcm of natural gas and 14 million bbl of condensate, according to a January 2020 Netherland, Sewell & Associates Inc. report.

Chevron operates Tamar with 25% following its acquisition of Noble Energy (OGJ Online, July 20, 2020). Partners are Delek Drilling (22%), Isramco (28.75%), Tamar Petroleum (16.75%), Dor Gas (4%), and Everest (3.5%).

 Exploration & Development Quick Takes

ExxonMobil makes oil discovery offshore Guyana

ExxonMobil made an oil discovery offshore Guyana at the Uaru-2 well in the Stabroek block, adding to block’s gross recoverable resource estimate of more than 9 billion boe.

Drilling at Uaru-2 encountered 120 ft (36.7 m) of high-quality oil-bearing reservoirs including newly identified intervals below the original Uaru-1 discovery. The well was drilled in 5,659 ft (1,725 m) of water and lies some 6.8 miles (11 km) south of the Uaru-1 well.

In January 2020, ExxonMobil Uaru-1 marked the 16th discovery in the block. The well encountered 94 feet (29 m) of high-quality oil-bearing sandstone reservoir and was drilled in 6,342 ft (1,933 m) of water (OGJ Online, Jan. 27, 2020).

In March 2021, ExxonMobil secured a sixth drillship, the Noble Sam Croft, for exploration and evaluation drilling activities offshore Guyana. A fourth project, Yellowtail, has been identified within the block with anticipated start up in late 2025 pending government approvals and project sanctioning. This project will develop the Yellowtail and Redtail fields, which lie about 19 miles (30 km) southeast of the Liza developments (OGJ Online, Sept. 8, 2020).

ExxonMobil anticipates at least six projects online by 2027 and sees potential for up to 10 FPSOs to develop its current recoverable resource balance.

Start-up of Liza Phase 2 remains on target for 2022, as the Liza Unity FPSO prepares for sail away from Singapore later this year. The Unity FPSO has a production capacity of 220,000 b/d of oil at peak rates. The hull for the Prosperity FPSO, the third project at Payara field, is complete, and topsides construction activities have commenced in Singapore with a startup target of 2024.

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator of the 6.6-million-acre Stabroek block with 45% interest. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. holds 25%. 

Neptune begins final phase of Duva development

Neptune Energy began drilling four production wells on Duva field on PL 636 in the Norwegian sector of the North Sea about 14 km northeast of Gjøa field. 

The wells are being drilled by Odjfell Drilling’s Deepsea Yantai semi-submersible rig in 360 m of water. All four wells were pre-drilled and cased off at a depth of 2,500 m prior to starting the final drilling campaign. The rig is set to drill the reservoir sections, install the lower completions, and execute well clean-up activities. Drilling is estimated to take 110 days.

Duva is a fast-track project being developed as a subsea installation with three oil producers and one gas producer and tied back to the Neptune-operated Gjøa semi-submersible platform. The drilling begins the final phase of development. Subsea works were completed in 2020, with the four subsea trees installed in March 2021. Duva is scheduled to come online third-quarter 2021 and add about 25,000 boe/d to the Gjøa platform. 

Neptune Energy is operator with 30%. Partners are Idemitsu Petroleum Norge (30%), PGNiG Upstream Norway (30%), and Sval Energi (10%).

Equinor to develop Askeladd Vest

Equinor Energy AS and partners will develop Askeladd Vest in the southern Barents Sea. At a cost of 3.2-billion kroner and part of the multi-phased Snøhvit development, the project is expected to provide 134 MMboe, extending plateau production at the Hammerfest LNG plant by 2 years. Production is expected to begin in first-half 2024.

The subsea template on Askeladd Vest will be tied back to Askeladd field through a pipeline and an umbilical. The distance from the onshore production plant at Melkøya to the subsea field is 195 km—the longest distance ever to a field development.

A contract valued at 460 million kroner for the subsea production facility was let to Aker Solutions and comprises a subsea template and two Christmas trees with associated components. Fabrication will take place in Sandnessjøen and Egersund, and project management and engineering will take place at Tranby.

In the summer of 2020, TechnipFMC was awarded a letter of intent for pipelaying and subsea installation services for the project.

Pipes for the project have been supplied by the German manufacturer Butting. These pipes have been manufactured and are stored in Orkanger.

Nexans has been awarded a letter of intent for fabrication of umbilicals. It will fabricate fiber-optic cables and power cables in Rognan.

Equinor is operator of Askeladd Vest with 36.79%. Partners are Petoro AS (30.00%), Total E&P Norge AS (18.40%), Neptune Energy Norge AS (12.00%), and Wintershall Dea Norge AS (2.81%).

 Drilling & Production Quick Takes

Eni starts gas production at Merakes, offshore Indonesia

Eni SPA started gas production from the Merakes project in the East Sepinggan block in the Makassar Strait, offshore East Kalimantan, Indonesia.

The project is a deepwater gas field development at Kutei basin in about 1,500 m water depth. Five wells guarantee 450 MMscfd production, equivalent to 85,000 boe/d, Eni said in a release Apr. 26. The field has been connected to ENI’s operated 750 MMscfd Jangkrik floating production unit (FPU), 45 km from Merakes field.

Production will be combined with gas flowing from Jangkrik gas field. After processing, gas is exported to onshore receiving infrastructure in Senipah via existing Jangkrik pipelines and will be partially sold to the domestic market. Gas also will contribute to the life extension of Bontang LNG plant that supplies LNG to domestic and export markets.

Eni is operator of the block (65%) through its affiliate, Eni East Sepinggan Ltd. Partners are Neptune Energy East Sepinggan BV (20%) and PT Pertamina Hulu Energi (15%).

BP begins gas production from West Nile Delta’s Raven field

BP has started gas production from Raven, the fifth field of the offshore West Nile Delta project off the Mediterranean coast in Egypt.

The $9-billion development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. BP and its partners, working with the Ministry of Petroleum, have developed the project in three stages. The first, Taurus-Libra, began production in March 2017; the second, Giza-Fayoum, began production in February 2019. In total, the project involves 25 wells and three long distance subsea tiebacks to shore. All gas produced is fed into Egypt’s national grid.

Currently, Raven’s gross production is 600 million std cu ft/d of gas (MMscfd). At its peak, Raven field is expected to deliver gross production of 900 MMscfd and 30,000 b/d of condensate (gross production).

BP is operator of the West Nile Delta project with 82.75%. Wintershall Dea holds 17.25%.

Reliance starts Satellite Cluster gas production

Reliance Industries Ltd. (RIL) started production from Satellite Cluster gas field in Block KG D6 off the east coast of India. The field lies 60 km from the existing onshore terminal at Kakinada in water depths up to 1,850 m.

Satellite Cluster is the second of the three developments to come onstream, following start-up of R-Cluster in December 2020 (OGJ Online, Dec. 22, 2020). Originally scheduled to start production in mid-2021, the field will produce gas from four reservoirs using a total of five wells. It is expected to produce up to 6 million std cu m/d.

Combined with MJ, the third deepwater gas development in the block, some 30 million std cu m/d total production is expected by 2023, meeting up to 15% of India’s gas demand. The developments will each use existing hub infrastructure in the block. MJ is expected to come onstream near second-half 2022.

RIL is operator of the block with 66.67% interest. BP holds the remainder.


Sinopec refineries start up new alkylation units

China Petroleum & Chemical Corp. (Sinopec) has commissioned new alkylation units to two of its subsidiaries’ refineries in China (OGJ Online, Dec. 5, 2017).

E.I. DuPont de Nemours & Co.’s DuPont Clean Technologies has completed performance tests certifying two of its proprietary STRATCO alkylation units recently installed at Sinopec Yangzi Petrochemical Co. Ltd.’s (YPC) 281,151-b/d refinery at Nanjing, Jiangsu Province and Sinopec Zhenhai Refining & Chemical Co.’s (ZPCC) 461,890-b/d refinery at Ningbo City, Zhejiang Province are meeting performance guarantees, the service provider said on Apr. 20.

Designed to enable the two refineries to produce low-sulfur, high-octane, low-rvp alkylate that helps ensure quality of their fuel production complies with China VI (equivalent to Euro 6) emission standards, the YPC and ZRCC alkylation units—which process methyl tertiary butyl ether (MTBE) feeds—have alkylate production capacities of 7,700 b/sd 7,500 b/sd, respectively, DuPont said.

Both units have completed startup and are currently in operation, according to Kevin Bockwinkel, DuPont’s global business manager of STRATCO alkylation technology.

First announced in 2017, the YPC and ZPCC alkylation units follow DuPont’s delivery of five earlier STRATCO units to Sinopec refineries (OGJ Online, Nov. 10, 2017; Aug. 25, 2017; Jan. 26, 2017).

APC subsidiary lets contract for Jubail PDH-PP complex

Advanced Global Investment Co. (AGIC), a subsidiary of Advanced Petrochemical Co. (APC), has let a contract to Maire Tecnimont SPA subsidiaries Tecnimont SPA and Tecnimont Arabia Ltd. to deliver engineering, procurement, and construction (EPC) on two polypropylene (PP) units for a grassroots integrated propane dehydrogenation (PDH) and PP complex to be built at APC’s existing operations in Jubail Industrial City II, Saudi Arabia (OGJ Online, May 15, 2020).

Tecnimont will provide complete engineering services, equipment, and out-of-kingdom material supply for the PP units, with Tecnimont Arabia to deliver in-kingdom material supply, erection, and construction activities up to startup and performance of guarantee test run.

To be located inside the integrated PDH-PP complex, the two PP units—each of which will have a capacity of 400,000-tonnes/year—are scheduled to be completed by second-quarter 2024.

This latest contract for the PDH-PP complex follows AGIC’s May 2020 award to Fluor Corp. for delivery of project management consulting on the development, as well as awards to Lummus Technology LLC for licensing of its proprietary CATOFIN technology for the PDH plant and LyondellBasell Industries NV’s subsidiary Basell Poliolefine Italia SRL for licensing of its Spherizone and Spheripol technologies for the complex’s two PP plants.

AGIC previously signed a shareholders’ agreement with SK Gas Co. Ltd. subsidiary SK Gas Petrochemical Pte. Ltd. (SKGP) in March 2020 to establish a JV named Advanced Polyolefins Co. (APC JV) for construction and operation of the proposed PDH-PP complex.

Once in operation, AGIC’s complex will produce 843,000 tpy of propylene and 800,000 tpy of PP for production of specialty polymers by manufacturers in various industries.

In addition to the planned complex, APC quietly announced in March that Saudi Arabia’s Ministry of Energy approved allocating requisite volumes of feedstock for AGIC to set up a grassroots petrochemicals complex, also to be built in Jubail Industrial City II.

To be based on a “cracking technology” yet to be identified, the proposed complex will produce 1.15 million tpy of ethylene, 850,000 tpy of propylene, and 400,000 tpy of aromatics, fuels, and their derivatives, APC said in a Mar. 10 filing to the Saudi Stock Exchange (Tadawul).

APC said startup of all units to be included in the newly announced complex will be in fourth-quarter 2025.


Total declares force majeure on Mozambique LNG project

Total SE has declared force majeure on its 12-million tonne/year Mozambique LNG project, citing the declining security situation in northern Cabo Delgado province, and withdrawn all project personnel from the Afungi site.

The company expressed “its solidarity with the government and people of Mozambique and wishes that the actions carried out by the government of Mozambique and its regional and international partners will enable the restoration of security and stability in Cabo Delgado province in a sustained manner.” It had hoped to begin production at the site in 2024.

Total last year awarded Siemens Energy a contract to supply power generation and compression equipment for Mozambique LNG. It suspended work on the project Mar. 27, 2021.

Total E&P Mozambique Area 1 Ltda., a wholly owned subsidiary of Total SE, operates Mozambique LNG with a 26.5% participating interest alongside ENH Rovuma Área Um SA (15%), Mitsui E&P Mozambique Area 1 Ltd. (20%), ONGC Videsh Rovuma Ltd. (10%), Beas Rovuma Energy Mozambique Ltd. (10%), BPRL Ventures Mozambique BV (10%), and PTTEP Mozambique Area 1 Ltd. (8.5%).

Trans Mountain ordered to stop expansion work

Canada’s Trans Mountain crude pipeline received orders from the country’s Ministry of Environment and Climate Change to halt work on the system’s expansion in an area near Burnaby, BC, until Aug. 20, the end of the current bird nesting season. Work encompassed includes tree felling and other use of chainsaws, bulldozers, or heavy equipment.

Citizen complaints prompted enforcement officer visits which prompted the orders. A number of birds in the area are protected under Canada’s Migratory Birds Convention Act.

The expansion is set to increase the pipeline’s capacity to 890,000 b/d from 300,000 b/d and be complete late 2022.

The Canadian government bought Trans Mountain from Kinder Morgan in 2018 (OGJ Online, May 29, 2018).

Total, CNOOC sign agreements to build Uganda-Tanzania crude pipeline

Total SE, China National Offshore Oil Corp. (CNOOC), Uganda National Oil Co. (UNOC), and Tanzania Petroleum Development Corp., have concluded final agreements needed to begin work on the heated 897-mile, 24-in. OD East African Crude Oil Pipeline (EACOP) and the Lake Albert rift basin development project. EACOP will run from western Uganda to the Indian Ocean port of Tanga in Tanzania, delivering as much as 300,000 b/d.

First oil exports are planned for early 2025. EACOP will include six pump stations and a heat tracing system to maintain a minimum internal temperature of 50° C.

Lake Albert development comprises Tilenga and Kingfisher discovery areas in Uganda. Upstream ownership is divided among Total (56.67%), CNOOC (28.33%), and UNOC (15%). Total operates Tilenga and CNOOC Kingfisher, with Total estimating combined plateau production of the two fields at 230,000 b/d.

Tilenga is in the Buliisa and Nwoya districts and includes development of six fields and drilling more than 400 wells from 31 sites. Wells planned include 200 water-injections wells, 196 production wells, two polymer-pilot wells, and 28 reference wells.

Production will be delivered through 160 km of buried flowlines to a 190,000-b/d treatment plant in Kasenyi, Uganda. All produced water will be reinjected into the fields, according to Total, and the gas will be used to power the treatment plant. Surplus electricity will be exported to the pipeline and the Ugandan grid.

One of the fields developed is inside Murchison Falls Park. The others are outside the park, south of the Victoria Nile in sparsely populated rural areas and agricultural areas.

The company last year acquired Tullow Oil PLC’s Ugandan assets for $575 million.