OGJ Newsletter

Aug. 9, 2021


ConocoPhillips adjusted earnings up quarter-on-quarter

ConocoPhillips reported second-quarter 2021 earnings of $2.1 billion, compared with second-quarter 2020 earnings of $300 million and first-quarter 2021 earnings of $1.0 billion. Excluding special items, second-quarter 2021 adjusted earnings were $1.7 billion, compared with a second-quarter 2020 adjusted loss of $1.0 billion and first-quarter 2021 adjusted earnings of $900 million. Special items for the current quarter included a gain on Cenovus Energy shares and a contingent payment from Cenovus associated with the 2017 Canadian disposition, partially offset by corporate expenses.

Production excluding Libya for second-quarter 2021 was 1.547 MMboe/d, an increase of 566,000 boe/d from the same period a year ago. After adjusting for closed acquisitions and dispositions as well as impacts from the 2020 curtailment program, second-quarter 2021 production increased 46,000 boe/d or 3% from the same period a year ago. The increase was primarily due to new production from the Lower 48 and other development programs across the portfolio, partially offset by normal field decline. Production from Libya averaged 41,000 boe/d.

In the Lower 48, production averaged 794,000 boe/d, including 435,000 boe/d from the Permian basin, 227,000 boe/d from the Eagle Ford, and 95,000 boe/d from the Bakken. In Alaska, drilling commenced at GMT2 and the first Fiord West well spudded from the CD2 pad. In Norway, the Tor II project was completed with the remaining three wells of the eight-well program brought online.

Earnings increased from second-quarter 2020 due to higher realized prices and volumes, partially offset by the absence of the second-quarter 2020 gain following completion of the Australia-West divestiture, as well as higher depreciation expense associated with the higher volumes. Excluding special items, adjusted earnings were higher compared with second-quarter 2020 due to higher realized prices and higher volumes, partially offset by increased depreciation expense associated with the higher volumes.

Third-quarter 2021 production is expected to be 1.48-1.52 MMboe/d, reflecting seasonal turnarounds planned in Alaska and the Asia Pacific region. Guidance excludes Libya and assumes that previously announced divestitures close during third-quarter 2021.

TC Energy Q2 net income falls 24%

TC Energy Corp. had net income for second-quarter 2021 of $982 million, compared with net income of $1.3 billion for the same period in 2020. It attributed the drop in income to the impact of common shares issued for the acquisition of TC Pipelines LP in first-quarter 2021.

The company had recorded a $2.2-billion after-tax asset impairment charge in its first-quarter 2021 earnings, related to termination of the Keystone XL crude oil pipeline project and shared with the Government of Alberta, but is advancing $21 billion in other capital projects.

In its earnings report, TC Energy noted that due to scope changes, permit delays, and impacts from COVID-19, it continues to expect costs of its 420-mile, 2.1-bcfd Coastal GasLink natural gas pipeline project, delivering Alberta production to the 14-million tonne/year LNG Canada liquefaction plant in Kitimat, BC, to increase significantly and the project itself to be delayed. Coastal GasLink is in a dispute with LNG Canada with respect to certain costs and the impacts on schedule. If a resolution is not reached in the near term, TC Energy said that Coastal GasLink may be required to suspend certain key construction activities but would continue with work required for safety reasons and regulatory compliance.

The company has sanctioned the VR enhancement project on its Columbia Gas Transmission system in the US. The project is intended to improve reliability and lower emissions at a cost of $700 million and is targeted to enter service second-half 2025.

Construction of TC Energy’s 261-mile, 886-MMcfd Villa de Reyes gas pipeline in Mexico is ongoing but has been delayed by COVID-19 contingency measures. The company expects to reach partial in-service by end-2021, with the remainder of construction completed during first-half 2022.

3R Petroleum signs deal for Papa-Terra interests

3R Petroleum Offshore SA has agreed to acquire participation interests in Papa-Terra heavy oil field in the Campos basin offshore Brazil from Petrobras for $105.6 million.

Papa-Terra field is part of the BC-20 concession. It lies in water depth of 1,200 m. The field began production in 2013. Average 2021 oil and gas production until June was 17,900 boe/d through two platforms, the P-61 tension-leg platform and P-63 FPSO (OGJ Online, Mar. 16, 2015).

Consideration includes $6 million paid, $9.6 million to be paid at closing, and $90 million in contingent payments related to production levels and future oil prices.

Closing is subject to conditions including approval by the National Agency of Petroleum, Natural Gas and Biofuels.

Petrobras is operator with 62.5%. Chevron holds 37.5%.

 Exploration & Development Quick Takes

TotalEnergies confirms oil encounter offshore Surniname

TotalEnergies SE confirmed a single, blocky sand that is full to base with black oil in Block 58, offshore Suriname.

Sapakara South-1, an appraisal well on the eastern edge of the Sapakara area, encountered about 30 m (98 ft) of net black oil pay in a single zone of high-quality Campano-Maastrichtian reservoir.

A second appraisal well encountered two thin intervals of black oil above water in the Campano-Maastrichtian at Kwaskwasi, impacting a small portion of the eastern edge of Kwaskwasi. The Campano-Maastrichtian intervals at Kwaskwasi and the Sapakara South-1 discovery are separate and unrelated.

The Maersk Valiant drillship will soon mobilize to the next exploration prospect at Bonboni, about 45 km to the north, before returning later in the year to flow test Sapakara South-1.

TotalEnergies is operator at Block 58 (50%) with APA Suriname Corp. holding the remaining 50% working interest.

Eni discovers oil offshore Mexico

Eni has encountered oil in Upper Miocene sequences on the Sayulita exploration prospect in Block 10 in the mid-deep water of Cuenca Salina Sureste basin, offshore Mexico. Preliminary estimates put the discovery at a possible 150,000-200,000 boe in place.

Sayulita-1 EXP is the seventh successful well drilled by Eni offshore Mexico in basin and the second commitment well of Block 10. The well was drilled by the Valaris 8505 semisubmersible rig in water depth of 325 m, reaching a total depth of 1758 m ssl. It lies about 70 km off the coast and 15 km from the Saasken oil discovery that will be appraised near yearend.

Sayulita-1 EXP found 55 m of net pay of good quality oil in the Upper Miocene sequences. The reservoirs show excellent petrophysical properties. Data collection has been carried out and the data acquired indicate a production capacity for the well of up to 3,000 b/d of oil.

The discovery, along with that of Saasken, confirm the value of the asset and open the potential commercial outcome of the block as other nearby prospects may be clustered for development, the operator said.

The Block 10 joint venture is operated by Eni with 65% interest. Partners are Lukoil (20%) and Capricorn, a wholly owned subsidiary of Cairn Energy PLC (15%).

Eni is currently producing more than 20,000 boe/d from Mexico’s Area 1 on an early production configuration and expects to ramp-up to 65,000 boe/d in 2022 and reach a plateau of 90,000 boe/d in 2025. Eni holds rights in eight exploration and production blocks (six as operator), all in the Gulf of Mexico’s Sureste basin, where it is carrying out an exploration and appraisal campaign.

Petro Rio completes Campos basin tieback

Petro Rio SA completed the tieback between Polvo field and the Bravo FPSO in Tubarão Martelo field (TBMT) in Campos basin, offshore Brazil.

The tieback is 11 km long with 22 km of installed lines between the flowline and electric umbilical. Two scheduled shutdowns were carried out during the project’s final phase lasting 10 days in Polvo and 7 days in TBMT for adjustments to the electric system, production lines, and oil and water processing facilities. The tieback was completed in 11 months.

Capital expenditure (CAPEX) for the project was $45 million. The tieback will reduce operating expenses (OPEX) to $70 million/year from $120 million/yr, the company said, accounting for the FPSO lease (currently chartered to the field and operated by BW Offshore Ltd.), maintenance, and diesel expenses. This cost reduction is expected to increase field recovery by extending the production period, Petro Rio continued.

The cluster has economic life until 2037 (considering 1P reserves), representing a 10-year extension for Polvo and 12 years for TBMT. The tieback will reduce the cluster’s emissions to 13.7 kg CO2/bbl from 18.6 to 13.7 kg CO2/bbl.

In July, Petro Rio’s production team was expected to adjust and stabilize Polvo field’s production at the Bravo FPSO. In parallel with the tieback project, the Kingmaker rig is finishing the TBMT-8H well workover and will begin completion of well TBMT-10HP, which is to be concluded in September.

Petro Rio holds rights to 95% of the Polvo and TBMT oil until the first 30 million cumulative bbl oil produced and 96% of the cluster’s oil thereafter. PetroRio is responsible for 100% of the OPEX, CAPEX, and field abandonment costs.

 Drilling & Production Quick Takes

Petrofac brings offshore Malaysia field online

Petrofac (Malaysia) Ltd. brought its East Cendor oilfield onstream in Block PM 304 on the western flank of Malay basin, about 140 km offshore Peninsular Malaysia.

East Cendor, the fourth field to be exploited on the block following Cendor, West Desaru, and Irama, comprises a single new wellhead platform and a new 6.3-km pipeline linking the field to the Cendor floating production, storage, and offloading (FPSO) vessel.

First oil was on Jun. 23, 2021. The field is expected to peak at more than 7,000 b/d.

Petrofac is operator at Block PM 304 with partners Kuwait Foreign Petroleum Exploration Co. (Kufpec) and Petronas Carigali Sdn Bhd.

Kuwait Energy tests well in Abu Sennan license

Kuwait Energy Egypt drilled and tested the Al Jahraa-8 (AJ-8) development well in the Abu Sennan license, 12 km to the northeast of producing Al Jahraa field in Egypt’s Western Desert, partner United Oil & Gas PLC said in an Aug. 2 release.

The AJ-8 well was spudded on May 2, targeting the Abu Roash (AR) and Bahariya reservoirs in an undrained portion of Al Jahraa field (OGJ Online, Apr. 6, 2021). The original hole was sidetracked after encountering poor hole conditions in the highly deviated well.

Preliminary interpretations indicate that the sidetrack encountered net pay in AR-E, and over 30 m net pay across Upper Bahariya and Lower Bahariya Upper reservoirs. Due to hole conditions in the sidetrack, a decision was made to run liner at 4,314 m MD and TD the well without reaching the Lower Bahariya Lower reservoir that had been a pre-drill target.

The well has been successfully tested from Lower Bahariya. Preliminary testing was carried out over a 17-hour period on several choke sizes. Results indicate a maximum flow rate of 2,093 b/d and 3.63 MMscfd on a 64/64-in. choke and a rate of 1,189 b/d and 1.22 MMscfd on a more constrained 26/64-in. choke.

The well will be completed and brought onstream from the Lower Bahariya reservoir. Hydrocarbon-bearing zones that were encountered in the Upper Bahariya and AR-E will be later tested and brought onstream.

After completing AJ-8, the EDC-50 rig will move about 7 km north of Al Jahraa field to drill the ASX-1X exploration well, expected to spud in the coming days. This is expected to be the final well of the 2021 campaign. Longer-term plans for the Abu Sennan license are under discussion.

Abu Sennan is operated by Kuwait Energy Egypt (25%). Joint venture partners are United Oil & Gas PLC (22%), Global Connect Ltd. (25%), and Dover Investments (28%).

CNOOC begins production at Liuhua 21-2

CNOOC Ltd. has started production of Liuhua 21-2 oil field in the eastern South China Sea in water depth of 437 m.

Along with utilizing existing infrastructure, the project included construction of an underwater production system with 8 development wells planned in total.

The project is expected to reach peak production of 15,070 b/d of crude oil in 2023. The field recovers associated gas through the light hydrocarbon recovery system to reduce methane emissions, the operator said.

CNOOC is operator with 100% interest.


Lukoil breaks ground on new petrochemical unit

PJSC Lukoil is starting construction on its previously announced project to add a grassroots petrochemical unit at subsidiary LLC Lukoil Nizhegorodnefteorgsintez’s (NNOS) 17-million tonnes/year (tpy) Kstovo refinery in central Russia’s Nizhny Novgorod region.

In a July 21 ceremony, NNOS laid the foundation stone for construction of the planned polypropylene complex that, once in operation, will process a feedstock of propylene supplied by the refinery’s two existing catalytic crackers to produce 500,000-tpy of product for other plastic manufacturers in the region, Lukoil said.

The polypropylene project comes as part of a plan to monetize anticipated increases in production from Nizhny Novgorod’s two 2-million tpy catalytic crackers, both of which are currently undergoing modernization works, according to the operator.

Lukoil also is undertaking a project to install a similar polypropylene unit at subsidiary’s Lukoil Neftochim Burgas AD’s 7-million tpy refinery along the Black Sea coast in Bulgaria.

The July 21 groundbreaking ceremony took place alongside a separate event celebrating NNOS’s commissioning of a 150,000-tpy polymer-bitumen binders production unit at the refinery, which will supply specialty bitumen products to help extend lifetime of roadway pavement, Lukoil said.

The new bitumen unit follows NNOS’s startup of the refinery’s new bitumen terminal in 2020, which is equipped to accommodate loading of 200 bitumen trucks daily as part of Lukoil’s broader program to further expand its bitumen business.

NNOS’s polypropylene and bitumen projects follow the operator’s recent mechanical completion of its long-planned deep conversion, delayed coking complex, which will enable the Nizhny Novgorod refinery to slash its production of fuel oil by 2.6 million tpy and increase annual output of Russian Class 5 (equivalent to Euro 5)-quality diesel fuel by 700,000 tpy.

Scheduled for full commissioning in this year’s fourth-quarter, the new delayed coking complex will include a 2.11-million tpy delayed coker; a 1.5-million tpy combined diesel fuel and gasoline hydrotreater; a 50,000-cu m/hr hydrogen production unit; a 425,000-tpy gas fractionator; and an 81,000-tpy combined elemental sulfur-sulfuric acid production unit.

Brooge advances refining, storage project at Fujairah

Brooge Energy Ltd., through its subsidiaries Brooge Petroleum and Gas Investment Co. FZE (BPIC) and Brooge Petroleum and Gas Investment Company Phase III FZE (BPGIC III) is moving forward with construction of its proposed Phase 3 refinery and storage expansion at its existing terminal operations in Fujairah, UAE, outside the Strait of Hormuz, adjacent to the East coast port of Fujairah on the Gulf of Oman (OGJ Online, Aug. 6, 2020).

With results of a recently completed feasibility study supporting financial viability of the project, Brooge looks forward to potentially starting the anticipated 2-year construction period for Phase 3 as early as second-half 2021 for a targeted commissioning date sometime in 2023, Nicolaas L. Paardenkooper, CEO of Brooge Energy and BPGIC, said on July 28.

Completion of the feasibility study by Ernst & Young follows the 2020 conclusion of front-end engineering design and start of preconstruction work—including the soil investigation and environmental impact assessment report—for Phase 3.

Alongside adding up to 3.5 million cu m—or 22 million bbl—of fresh oil storage capacity to make Brooge Energy the Port of Fujairah’s largest independent oil storage and service provider, Phase 3 also will include a new 25,000-b/d modular refinery to produce very low-sulfur fuel oil, as well as construction of a 180,000-b/d conventional crude oil refinery, according to the operator.

Confirmation of Phase 3’s ongoing development follows BPGIC’s early July agreement with an unidentified oil trading company for the project’s planned modular refinery.

As part of the modular refinery agreement, BPGIC will sublease land to the oil trader, which will be responsible for building and paying all construction costs for the refinery, for which BPGIC will act as operator, earning revenue from tolling fees on a take-or-pay basis, according to a July 9 release from Brooge.

The agreement between BPGIC and the oil trader includes a 20-year tolling contract consisting of a 5-year contract beginning upon completion of the refinery’s construction and three 5-year renewal periods, Brooge said.


Whistler Pipeline placed in service

Whistler Pipeline LLC started full commercial service on the Whistler natural gas pipeline on July 1, providing some 2.0 bcfd of incremental natural gas transport capacity to the Texas Gulf Coast markets from the Permian basin. Delivery points in the Agua Dulce provide shippers with access to Gulf Coast industrial and export markets including LNG.

Whistler consists of a 450-mile, 42-in. OD transmission line running between the Waha hub and Agua Dulce and a 50-mile, 36-in. OD lateral providing Waha connectivity to Midland basin gas processors.

Whistler is owned by MPLX LP, WhiteWater Midstream, and a joint venture of Stonepeak Infrastructure Partners and West Texas Gas Inc.

PGNiG increases North American LNG volumes, cuts Port Arthur LNG

Polish Oil & Gas Co. SA (PGNiG) has agreed with Venture Global Calcasieu Pass LLC and Venture Global Plaquemines LLC to purchase another 2 million tonnes/year (tpy) of LNG for 20 years, bringing the total volume of LNG contracted from Venture Global LNG by PGNiG to 5.5 million tpy.

The agreements increase volumes contracted in 2018 and 2019. Instead of 1 million tpy, PGNiG intends to purchase 1.5 million tpy from the under-construction 10-million tpy Calcasieu Pass plant, while the volume contract from Plaquemines (20 million tpy) will increase to 4 million tpy from 2.5 million tpy. Cargoes will be sold on a free on-board basis.

PGNiG expects Calcasieu Pass to begin commercial deliveries in early 2023.

PGNiG also entered an MOU with Sempra LNG for the potential purchase of 2 million tpy of LNG from Sempra’s North American liquefaction plants. The MOU is nonbinding and coincides with the termination of the parties’ 2018 agreement for 2 million tpy to be delivered from Sempra’s 11-million tpy Port Arthur LNG project, which has experienced delays.

Sempra LNG owns a 50.2% interest in 12-million tpy Cameron LNG in Hackberry, La., and is considering with its partners a proposed expansion of the plant through adding a third 6-million tpy train. Partners in Cameron LNG include Mitsui & Co., Mitsubishi Corp., TotalEnergies, and NYK Line.

Sempra LNG, its IEnova subsidiary, and TotalEnergies are also building the 3-million tpy Energia Costa Azul LNG plant in Baja California, Mexico. Phase 1 of the project is under construction and first production is expected by end-2024. A potential expansion of the plant is in the early stages of development.

Tellurian to supply Shell with LNG

Tellurian Inc. has finalized LNG sales agreements with Shell NA LNG. Agreements are on a free on-board basis at Driftwood LNG for a combination of 3 million tonnes/year (tpy) for a 10-year period, indexed to a combination of two indices: the Japan Korea Marker and the Dutch Title Transfer Facility, each netted back for transportation charges.

The agreements mark the third deal Tellurian has finalized in 10 weeks, totaling 9-million tpy and nearly all the capacity of Driftwood LNG’s first two trains.

Tellurian said it will now focus on financing Driftwood, with a focus on beginning construction early-2022.

Bechtel Oil, Gas, & Chemicals Inc. is Driftwood’s engineering, procurement, and construction contractor. The plant is being built in Carlyss, La., on the west bank of the Calcasieu River.