OGJ Newsletter

Jan. 9, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Chevron plans 25% increase in organic capital spend in 2023

Chevron Corp. plans to increase its organic capital expenditure in 2023 by 25% from 2022, while slightly decreasing its affiliate spend.

The company is budgeting $14 billion capex, excluding acquisitions, and $3 billion for equity affiliates.

Chevron’s 2023 organic capex includes $11.5 billion in upstream spending ($8 billion US, $3.5 billion international) and $1.9 billion in downstream capex ($1.5 billion US, $300 million international) and affiliate capex budgets of $1.9 billion upstream and $1.1 billion downstream.

Upstream capex includes more than $4 billion for Permian basin development and roughly $2 billion for other shale and tight assets. More than 20% of upstream capex is for projects in the Gulf of Mexico.

Nearly half of affiliate capex is for Tengizchevroil’s Future Growth Project-Wellhead Pressure Management Project (FGP-WPMP) in Kazakhstan and about a third is for Chevron Phillips Chemical Co., including the US Gulf Coast II petrochemical project.

The budgets include about $2 billion in lower carbon capex, more than double the 2022 budget, including $500 million to lower the carbon intensity of Chevron’s traditional operations and about $1 billion to increase renewable fuels production capacity, the company said.

Chevron’s 2023 capex budget assumes cost inflation that averages in the mid-single digits with certain areas higher, such as the Permian basin that assumes low double-digit cost inflation.

Australian government’s proposed price caps alarm gas industry

The Australian natural gas industry expressed concern over federal government’s decision to place temporary price caps on gas as a way of easing the financial burden on the country’s gas consumers.

Prime Minister Anthony Albanese said late last week that the Australian government will partner state governments to “shield Australian families and businesses from the worst impact of predicted energy price spikes.”

The proposal is to set a 12-month gas price cap of $12 (Aus.) per gigajoule on new wholesale gas sales by producers in the East Coast market covering Queensland, New South Wales, and Victoria.

Substantial gas price increases have occurred in those states in recent months due in part to the unreliability of other energy supplies as well as the fall-out from pressure on global energy markets attributed to the Russian invasion of Ukraine.

Australian Petroleum Production & Exploration Association (APPEA) chief executive Samantha McCulloch said a price cap on gas will force prices higher for consumers because it will kill investment confidence and reduce future supply.

“This heavy-handed radical intervention has been conducted with no prior consultation with industry to consider specific measures and warn of potential risks to Australia,” she said.

Woodside Energy Ltd. chief executive officer Meg O’Neill, who is also APPEA chair, said the government’s policy will not address falling domestic gas supply and the increasingly important role of gas in providing dispatchable power.

“These are the primary factors that are driving higher energy prices in the east coast gas market, rather than solely the impact of the tragic war in Ukraine,” O’Neill said.

“No one wants to see energy shortages and gas rationing. We must develop a comprehensive longer-term solution that addresses gas supply and reliability, the overall energy mix and infrastructure, without undermining the market-based economy,” she added.

Edvard Grieg, Ivar Aasen now powered from shore

Aker BP expects to reduce CO2 emissions from Edvard Grieg and Ivar Aasen production platforms by 200,000 tonnes/year (tpy) now that the two North Sea Utsira High area platforms are operated with electric power from shore.

Two gas fired turbines have been shut down, thus reducing greenhouse gas emissions by 3.6 million tonnes over the life of the field as well as reducing operating costs as the company no longer operates its own power plant on the platform, said Kari Nielsen, asset manager Edvard Grieg and Ivar Aasen, Aker BP, in a release Dec. 7.

Gas-powered turbines on the Edvard Grieg platform have supplied both fields with the necessary power and heat since start-up in 2015 and 2016, respectively.

Edvard Grieg was prepared to receive electricity from shore from the construction phase in 2012 to fulfill requirements from authorities. In 2014, Parliament decided that a solution for power supply from shore should be developed for Johan Sverdrup, and the other installations in the Utsira High area should be connected in conjunction with phase two of Johan Sverdrup development.

The project has been carried out as two sub-projects—one for seabed cable installation between Johan Sverdrup and Edvard Grieg, and one for development and installation of a solution with electric boilers for heat required in the process plant (OGJ Online, Sept. 29, 2020).

Petroleum Sarawak acquires Shell’s stake in Malaysian assets

Petroleum Sarawak Exploration & Production Sdn. Bhd. (PSEP) has acquired Sarawak Shell Bhd.’s stake in two offshore production sharing contracts (PSC) in Malaysia’s Baram Delta.

PSEP will gain 40% non-operated interests in the Amended 2011 Baram Delta EOR PSC and 50% interest in the SK307 PSC for base consideration of $475 million, with additional payments of up to $50 million contingent on commodity prices.

Remaining interests in both PSCs are held by operator Petronas Carigali Sdn. Bhd.

The Baram Delta EOR PSC comprises Bokor, Baronia, Fairley Baram, Bakau, and Siwa oil fields and Tukau Timur and Baronia gas fields. The SK307 PSC currently produces from Baronia Barat oil field (Online, March 15, 2021).

The transaction is targeted to be completed in early 2023, subject to conditions including consent and regulatory approval from Petronas.

 Exploration & Development Quick Takes

Eni makes another gas discovery offshore Cyprus

Eni has made a gas discovery offshore Cyprus with the well Zeus-1, drilled in Block 6, 162 km off the coastline in 2,300 m of water depth.

Zeus-1 is the third consecutive discovery in Block 6. It follows Cronos-1 and Calypso-1 discoveries in the block in 2018 and August 2022, respectively. Zeus-1 encountered 105 m of net gas pay in a carbonate reservoir sequence, the operator said in a release Dec. 21. The gas in place associated to this reservoir is preliminarily estimated at 2-3 tcf, Eni said.

Zeus-1 well was drilled and successfully tested with the Tungsten Explorer drill ship. Results of the test are being incorporated in the evaluation of the discoveries cluster that will drive subsequent studies and operations targeting a fast-track development of the block.

Eni Cyprus is operator of Block 6 with 50% interest. TotalEnergies holds the remaining 50%.

OGDCL discovers oil and gas in Pakistan’s Sindh Province

Oil and Gas Development Co. Ltd. (OGDCL) has discovered oil and gas at the Kot Nawab-1 exploration well in Sinjhoro block in Sanghar district of Sindh province in Pakistan.

Kot Nawab-1, the 11th discovery in the block, was spudded on June 3, 2022. The well was drilled down 3,000 m. Based on wireline logs interpretation, drill stem test-1 in the Basal sand has tested 125 bo/d, 0.483 MMscfd gas, and 400 b/d water through a 28/64-in. choke at 150 psi well head flowing pressure.

OGDCL is operator of Sinjhoro block (76%) with partners Orient Petroleum Inc. (19%) and Government Holdings (Private) Ltd. (5%).

ExxonMobil lets contract for UARU development offshore Guyana

ExxonMobil has let a subsea contract to Saipem SPA for Uaru oil field development in Stabroek block, offshore Guyana.

The contract includes design, fabrication, and installation of subsea structures, risers, flowlines, and umbilicals for a large subsea production installation. Saipem was previously awarded four subsea contracts by ExxonMobil Guyana for prior developments in Liza Phase 1 and 2, Payara, and Yellowtail, and will perform operations by using its vessels, including FDS2 and Constellation.

Uaru, in the eastern portion of the block at a water depth of around 2,000 m, will target 1.319 billion boe and is expected to come online end-2026 (OGJ Online, Oct. 26, 2022).

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%.

OMV submits subsea tieback plan for Berling

OMV (Norge) AS submitted a plan for development and operation (PDO) to the Norwegian Ministry of Petroleum and Energy for the Berling (previously Iris Hades) gas and condensate discovery in production license (PL) 644 on Haltenbanken in the Norwegian Sea.

The recommended development concept for Berling field is a 4-slot subsea production template tied back via a 24-km pipeline to Equinor-operated Åsgard B platform.

The rich gas will be processed on Åsgard B and transported via the Åsgard Transport System for further processing at Kårstø gas processing plant. The condensate will be transferred to Åsgard and co-mingled with other Åsgard production for storage and export by shuttle tankers to the market. Recoverable resources are estimated to be about 45 MMboe.

The development cost is estimated at NOK 9.1 billion.

OMV (Norge) AS is the operator for the development and operations with 30% working interest. The license partners are Equinor Energy AS (40%), DNO Norge AS (20%) and Sval Energi AS (10%).

In December, DNO agreed to acquire Sval Energi’s stake in the field. Share transfer awaits government approval.

 Drilling & Production Quick Takes

Petrobras starts production at Itapu field

The P-71 floating production, storage, and offloading vessel started production from Petroleo Brasileiro SA-operated Itapu field in the presalt area of Santos basin offshore Brazil.

The FPSO can process up to 150,000 bbl oil and 6 million cu m/d gas in addition to storing up to 1.6 million bbl of oil. Positioned in a water depth of 2,010 m, the FPSO will be the only one to produce Itapu field. Petrobras expects the unit to reach its maximum production capacity in 2023.

The P-71 is the sixth and last of the series of replicant platforms operated by Petrobras.

Gazprom begins commercial production from Semakovskoye field

Gazprom and RusGazDobycha began production at Semakovskoye gas field in the Yamal-Nenets Autonomous Area of Russia.

Semakovskoye field contains recoverable gas reserves of more than 320 billion cu m (bcm), Gazprom said in September 2020 upon construction completion of the field’s first production well. Reserves are concentrated in the waters of Taz Bay of the Kara Sea (OGJ Online, Sept. 2, 2020).

First phase development includes 19 wells with horizontal lengths up to 4,200 m, a 7.5-bcmy gas treatment plant, and a 122-km pipeline from the field to the Unified Gas Transmission System.

Sonatrach starts up Algerian gas field

Algerian state-owned Sonatrach SPA (100%) has started production from Tinrhert gas field in block Ohanet II, onshore southeastern Algeria in the Illizi province.

The project connects 36 gas wells from Tinrhert to new inlet separation and compression equipment in nearby Ohanet field.

Commissioning completion of the surface infrastructure has led to a production of 4.5 MMcmd of gas, 500 tonnes/day of LPG, and 800 tons/day of condensate, exceeding expected forecasts for the project.

The field is expected to recover 1,059 MMboe, comprised of 6,355 bcf of natural gas reserves.

Norway production down in November, NPD says

Norway’s production averaged 1.946 million in November, the Norwegian Petroleum Directorate (NPD) reported. The figure is down from the 1.950 million b/d produced in October.

Average daily liquids production in November consists of 1.740 million b/o, 187,000 bbl of NGL, and 19,000 bbl of condensate. Oil production in November was 8.7% lower than the NPD’s forecast.


Shandong Yulong Petrochemicals lets contract for integrated megacomplex

Nanshan Holdings Co. Ltd.’s majority held Shandong Yulong Petrochemical Co. Ltd. has let a contract to Chevron Lummus Global LLC (CLG)—a joint venture of Chevron Corp.’s Chevron USA Inc. and Lummus Technology LLC—to deliver process technology for a new hydrocracking unit at the operator’s grassroots 20-million tonne/year (tpy) integrated refining and petrochemical complex under construction as part of the Yulong Island Refining and Chemical Integrating Project at Yulong Petrochemical Industrial Park, Yantai City, Shandong Province, China.

Under the contract, CLG, as licensor, will provide technology licensing, engineering, proprietary reactor internals, and catalyst supply for a slurry residue hydrocracking unit equipped with Eni Slurry Technology, CLG said on Dec. 21.

Shandong Yulong Petrochemical will use the new EST hydrocracking unit—which, once operable, will become one of the world’s largest—to convert 3 million tpy of high-sulfur residue into naphtha, diesel, and vacuum gas oil that will provide low-sulfur transportation fuels to the consumer market as well as petrochemical feedstock to downstream units at the Yulong complex, according to the service provider.

The contract follows Shandong Yulong Petrochemical’s earlier award to CLG’s JV owner Chevron Lummus to deliver licensing of its proprietary CDAlky technology to outfit a new 400,000-tpy alkylation unit that will produce very high-octane, gasoline-blending alkylate to improve fuel efficiency and reduce environmental impacts of finished gasoline product at the complex.

The operator also previously contracted Lummus to license proprietary technologies to be implemented at the complex’s two mixed-feed crackers, an ethylbenzene-styrene monomer plant, and two polypropylene plants.

In January 2022, Shaanxi Chemical Construction Engineering Co. Ltd. confirmed it received a nearly 2-billion yuan contract award from Shandong Yulong Petrochemical in late 2021 to deliver engineering and construction on two sections of Phase 1 of the project’s main complex, as well as construction of the refinery’s light hydrocarbon tank farm project.

Scientific Design Co. Inc.—owned by Saudi Basic Industries Corp. and Clariant Ltd.—confirmed its contract award from Shandong Yulong Petrochemical for licensing of Scientific Design’s proprietary ethylene oxide-ethylene glycol technology for the complex’s planned 1.02-million tpy monoethylene glycol plant.

Phase 1 of Shandong Yulong Petrochemical’s planned complex seemingly remains on schedule for startup in June 2023.

S-Oil lets contract for petrochemical expansion at Ulsan integrated complex

Saudi Aramco’s majority owned S-Oil Corp. has let a contract to Lummus Technology LLC to deliver the first commercial deployment of a new crude-to-chemicals process technology for a massive petrochemical expansion at the operator’s 669,000-b/d integrated refining complex in Ulsan, South Korea.

As part of the Dec. 16 contract, Lummus will license its TC2C thermal crude-to-chemicals technology—jointly developed by Lummus, Saudi Aramco Technologies Co., and Chevron Lummus Global (CLG)—for a new steam cracker to be built as part of S-Oil’s recently approved Shaheen project, the service provider said.

An integrated process that combines Lummus’ ethylene technology, Aramco’s separation and catalyst technologies, and CLG’s hydroprocessing catalysts and reactor technologies, TC2C will equip the new steam cracker to treat the Ulsan refinery’s by-products of naphtha, offgas, and other feedstocks for production of up to 3.2 million tonnes/year of petrochemicals, including ethylene, propylene, butadiene, benzene, and other basic chemicals, according to S-Oil and Lummus.

The new plant also will produce polyethylene to be used as feedstock for making plastics and other synthetic materials.

Scheduled to begin construction in 2023, the expansion at Ulsan is slated for completion in 2026.

S-Oil took final investment decision (FID) to proceed with the planned $7-billion Shaheen project in November 2022.

Alongside enabling S-Oil’s goal of operating more efficiently by recovering and recycling waste heat from the steam cracker and improving Ulsan’s overall energy efficiency, the new Shaheen cracker’s use of TC2C technology also provides potential for reducing carbon emissions at the site while supporting a stable supply of petrochemical feedstock.

Upon completing Shaheen, S-Oil said its volume-based chemical yield will more than double to 25% from 12%.

S-Oil confirmed awarding a contract for engineering, procurement, and construction to a consortium of Hyundai Engineering & Construction Co. Ltd., Hyundai Engineering Co., and Lotte Engineering & Construction Co. Ltd.

Shaheen comes as the second-phase petrochemical expansion at the Ulsan complex, the first phase of which was completed in 2018 and fully commissioned in 2019 at a total investment of $4 billion.


First LNG cargo arrives at Germany’s terminal in Wilhelmshaven

Uniper SE brought Germany’s first full load of LNG to the new Uniper-operated, 7-8 billion cu m/year (bcmy) LNG terminal in Wilhelmshaven (OGJ Online, Mar. 2, 2022). The Maria Energy LNG vessel, owned by Tsakos Energy Navigation, was loaded at Venture Global LLC’s 10-million tonne/year Calcasieu Pass liquefaction plant in Cameron Parish, Louisiana, on Dec. 19, 2022.

The Maria Energy is fully charged with some 170,000 cu m of LNG.

The cargo is part of the commissioning process at the Wilhelmshaven terminal. Commercial operations are expected to start in mid-January 2023. Through the Höegh Esperanza floating storage and regasification unit, about 5 bcmy of natural gas can be offloaded in Germany.

Gazprom starts 1.8-tcm Kovyktinskoye natural gas field, Power of Siberia leg

PJSC Gazprom has started natural gas production from 1.8-trillion cu m Kovyktinskoye field and placed the 804-km Koykta-Chayanda leg of the Power of Siberia pipeline into service, Russian-state Interfax reported. Production from Kovyktinskoye will be transported on Power of Siberia to both Russian consumers and China.

Drilling of production wells at the field started in July 2019, according to Interfax, with startup and commissioning of the associated comprehensive gas-treatment unit (CGTU-2) following in October 2022. Gazprom had drilled four exploratory wells at Kovyktinskoye the year before and acquired 3D seismic data across 2,460 sq km of the field.

The company plans to bring several more CGTU online in its efforts to produce 27 billion cu m/year from Kovyktinskoye, the press agency said.

“The launch of [Kovyktinskoye] field, including CGTU-2 and the Kovykta-Chayanda section, will promote the development of gas supplies to the eastern regions of Russia and the reliable fulfillment of obligations for the supply of Russian gas via the Eastern Route for export to China,” Interfax concluded.

ONEOK files for Saguaro Connector natural gas pipeline border crossing

ONEOK Inc. has filed a Presidential Permit application with the US Federal Energy Regulatory Commission for its Saguaro Connector natural gas pipeline subsidiary to build and operate a new border crossing into Mexico from Hudspeth County, Tex.

The proposed 2.8-bcfd Saguaro Connector would use 155 miles of 48-in. OD pipe to transport Permian basin gas carried by ONEOKs existing 777-MMcfd WesTex intrastate pipeline and other sources to Mexico. A pipeline being developed on the Mexican side of the border will carry the gas to the west coast for liquefaction and export.

ONEOK expects to take final investment decision on Saguaro Connector by mid-2023.

Targa Resources to pay $1 billion to own 100% interest in Grand Prix NGL pipeline

Targa Resources Corp., Houston, has agreed to acquire Blackstone Energy Partners’ 25% interest in Targa’s Grand Prix NGL pipeline for $1.05 billion. Targa will own 100% of Grand Prix upon closing, which is expected in this year’s first quarter.

Grand Prix has capacity to transport up to 1 million b/d of NGL to the Mont Belvieu, Tex. hub. It connects Targa’s gathering and processing positions in the Permian basin, North Texas, and Southern Oklahoma to Targa’s fractionation and storage complex at Mont Belvieu.