OGJ Newsletter

Aug. 7, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.

GENERAL INTEREST Quick Takes

Natural gas deliveries to US LNG export plants set record

Natural gas deliveries through pipelines to US LNG export plants ( LNG feed gas) averaged 12.8 bcfd in first-half 2023, according to data by S&P Global Commodity Insights and the US Energy Information Administration (EIA). This increase was attributed to the Freeport LNG plant returning to service. Over this period, the average LNG feed gas was 8%, or 1 bcfd, more than the 2022 annual average, and 4%, or 0.5 bcfd, more than the same 6-month period in 2022.

April 2023 marked a monthly record for LNG feed gas at 14 bcfd, driven by strong international demand for US LNG exports, particularly in Europe. However, there was a slight decline in May and June, with averages of 13 bcfd and 11.5 bcfd, respectively, mainly due to maintenance work at various US LNG export plants, including Sabine Pass and Cameron.

LNG feed gas levels are typically higher than LNG export levels because some of the feed gas is used by LNG export plants for on-site liquefaction equipment operation. Freeport LNG is unique in the US as it employs electric motors instead of natural gas turbines to drive refrigerant compressors, resulting in most of its feed gas being converted into LNG.

According to EIA’s estimates, about 14% of LNG feed gas is used for liquefaction processes, mostly to operate on-site liquefaction equipment.

EIA forecasts US LNG exports to average 12 bcfd in 2023 and 13.3 bcfd in 2024 as new LNG liquefaction projects, including Golden Pass and Plaquemines, are expected to come online. The global economic conditions and demand for natural gas in Europe and Asia will influence the forecast. Moreover, the replacement of Russia’s natural gas exports by pipeline to Europe with LNG is anticipated to support higher US LNG exports. Limited growth in global LNG export capacity in the next 2 years may increase demand for destination-flexible LNG supplies, primarily from the US, according to EIA.

Strathcona to acquire Pipestone to create large public Canadian oil and gas producer

Strathcona Resources Ltd. has agreed to acquire Pipestone Energy Corp. in an all-share deal that would create the fifth largest liquids producer in Canada measured by production and reserves.

The combined company, which will continue as Strathcona Resources Ltd., will become a public reporting issuer with three core areas, each with meaningful scale and inventory, and a balance of heavy oil, condensate and NGLs, and natural gas production, the companies said in a joint release Aug. 1.

The combine will hold current production of about 185,000 boe/d (70% oil/condensate, 78% total liquids), across three concentrated areas: Cold Lake Thermal (55,000 b/d), Lloydminster Heavy Oil (55,000 b/d), and Montney (75,000 boe/d).

Viking, Acorn North Sea CCS projects advance

Harbour Energy PLC, operator of the Humber, UK-based Viking CO2 transportation and storage network and partner in the Acorn carbon capture and storage (CCS) project in northeast Scotland, won Track 2 status for both projects as part of the UK Government’s CCS cluster sequencing process. The change in status allows both projects to move into front end engineering and design (FEED) and discussions with the government over the terms of economic licenses, ahead of final investment decisions (FID).

Viking has the potential to transport and store up to 10 million tonnes/year (tpy) of CO2 by 2030 and 15 million tpy by 2035, with independently verified storage capacity of 300 million tonnes of CO2 across the depleted Viking gas fields. Harbour describes the project as transformational for the Humber region, potentially unlocking up to £7 billion of investment across the full CO2 capture, transport, and storage value chain between 2025 and 2035.

Harbour says Viking can also enable, through the company’s work with Associated British Ports at the Port of Immingham, the potential for shipped CO2 from emitters elsewhere in the UK and internationally to be transported for permanent storage in the Viking fields, creating a new industry for the UK.

Viking, which stopped production in 2018, lies under the southern North Sea off the coast of Lincolnshire, UK. Harbour and bp share an interest in the 120 km, 36-in OD Lincolnshire Offshore Gas Gathering System pipeline which will be repurposed and lengthened by 20 km to connect to Viking.

Acorn CCS is a CO2 transportation and storage system which reuses legacy oil and gas infrastructure to transport emissions from the Scottish Cluster to permanent storage under the North Sea. Acorn’s partners describe the Scottish Cluster as a collection of industrial, power, and hydrogen businesses in central and northeast Scotland.

Harbour is Viking’s operator with a 60% interest and is partnered with bp PLC which has a 40% non-operated share. Harbour has a 30% non-operated interest in Acorn CCS, which lead developer Storegga operates. Shell UK and North Sea Midstream Partners Ltd. our also part of the Acorn joint venture.

Exploration & Development Quick Takes

Woodside confirms FID for Julimar-Brunello Phase 3

Woodside Energy will move ahead with development of the Julimar-Brunello Phase 3 project offshore Western Australia.

In its second-quarter 2023 report dated July 18, the company confirmed a positive final investment decision was made on the project—which will provide a new supply of gas to the Chevron-operated Wheatstone LNG plant—in April, said Woodside chief executive officer Meg O’Neill.

KUFPEC, which holds a 35% interest in Julimar-Brunello fields, noted the decision in mid-June.

Both fields supply about 20% of the total raw gas demand to the Wheatstone project, KUFPEC said at the time. The remaining gas is provided by Chevron-operated Wheatstone and Iago fields.

The Julimar-Brunello development project has been split into multiple development phases. To date, two phases, comprising eight wells, have been completed and are producing.

In June, Woodside Energy Julimar Pty. Ltd. awarded TechnipFMC a contract to engineer, procure, construct, and install (EPCI) flexible pipes and umbilicals for its Julimar Phase 3 development.

Woodside Energy Group delivered quarterly production of 44.5 MMboe in second-quarter 2023, down 5% from this year’s first quarter due to planned turnaround and maintenance activities. Full-year production guidance remains unchanged at 180-190 MMboe.

The company has total revenue of $3.08 billion for the quarter, down 29% from this year’s first quarter due to lower realized prices and lower production.

Ithaca Energy discovers hydrocarbons at K2 prospect

Ithaca Energy (UK) Ltd. discovered hydrocarbons at the K2 prospect in license P2382, Block 22/14c, Central North Sea. The operator will perform an appraisal sidetrack in the main bore.

Upon entering the reservoir, Ithaca discovered 45 ft net thickness of hydrocarbons in the Forties Member sandstones. Logs were acquired to establish reservoir quality and further analysis of the well results will be performed to determine future activity and the recoverable resources estimate.

Water depth at the site is 294 ft (90 m). Drilling targeted the Forties Member sandstones.

Ithaca Energy is operator at K2 (50%) with partner Dana Petroleum (50%).

Petronas Carigali makes multiple gas discoveries offshore Sarawak

Petronas Carigali Sdn. Bhd. made six oil and gas discoveries in five blocks off the coast of Sarawak, Malaysia.

Wells from new and existing oil fields include the Gedombak well in Block SK306 and the Mirdanga well in Block SK411 (Balingian province), the Sinsing well in Block SK313, the Machinchang and Pangkin wells in Block SK301B, and the Kalung Emas well in Block SK315 (West Luconia province). The wells exhibited low levels of contaminants, the company said.

The discoveries came from a domestic exploration drilling campaign which began in late 2022 and led to the oil discovery that year of Nahara-1 in Block SK306 (OGJ Online, Dec. 7, 2022). The company attributes the discoveries to its clustered exploration approach which is suited for highly matured geological provinces.

Drilling & Production Quick Takes

Diamondback previews slight production increase for 2024

Diamondback Energy Inc. drilled a record number of new wells and topped its production estimates for the second quarter but will slow down its growth in the second half of this year. Executives also are forecasting low-single-digit output increases for 2024.

Diamondback averaged oil production of a little more than 263,000 b/d in the 3 months ended June 30, which was an increase of 19% from the same period in 2022. Daily combined volumes climbed 18% year over year to nearly 450,000 boe/d. The company’s teams drilled 86 wells in the Midland basin as well as 12 in the Delaware basin. Full-year 2023 guidance for gross wells drilled has been increased to 335-350 from 325-345.

Production is expected to be flat to up slightly from the last 3 months and rise only marginally from there late this year and in 2024.

The relative slowdown also will translate into less capital spending: After spending $711 million in the second quarter, Diamondback is forecasting capex to shrink about 5% this quarter and then dip further in the fourth quarter to about $600 million—which also is the early assumption for spending in 2024. Those declines are based both on lower activity forecasts and drops in the prices of raw materials and other categories.

Diamondback produced net income of $586 million in the second quarter, a drop from a bumper profit of more than $1.4 billion in the same period of 2022. Total revenues fell to $1.9 billion from nearly $2.8 billion and operating profits were cut in half to $1.0 billion as the company’s combined average price fell to $46.31/boe from nearly $80.

Neptune starts gas production at Adorf Z18 well

Neptune Energy started production from the Adorf Z18 gas well in Adorf Carboniferous gas field, Georgsdorf, northwestern Germany.

The well is in the Carboniferous formation and is expected to increase production from the Adorf license by about 1,900 boe/d to about 8,200 boe/d.

Adorf gas field was discovered in 2020 and the first well, Adorf Z15, was brought into production in the same year. A second well, Adorf Z16, started production at the beginning of 2022. A third well, Adorf Z17, increased Neptune’s production from the license to around 6,300 boe/d (OGJ Online, May 25, 2023).

Neptune Energy is operator and 100% owner of the field.

PTTEP increases natural gas production from G1/G6 Gulf of Thailand project

PTT Exploration and Production Public Co. Ltd. (PTTEP) has increased natural gas production from its G1/61 project (Erawan, Platong, Satun, and Funan fields) in the Gulf of Thailand as targeted.

Production at the project reached 400 MMscfd at the end of second-quarter 2023, up from 210 MMscfd.

PTTEP is producing natural gas, condensate, and crude oil at the project, and is in the process of drilling additional wells with plans to install four additional wellhead platforms by end-2023 to further increase production to 800 MMscfd by April 2024.

PTTEP became operator of the project in 2022. At transfer, natural gas production at G1/61 was 376 MMscfd.

Magnolia increases production volumes 10% y-o-y

Magnolia Oil & Gas Corp. grew production volumes 10% in second-quarter 2023 compared with the prior-year quarter and 3% sequentially.

The operator’s second-quarter 2023 production volumes averaged 81,900 boe/d, higher than guidance due to well performance from Giddings oil field in South Texas, the company said in an earnings report Aug. 1. Magnolia expects total oil and gas production in third-quarter 2023 to be similar to second-quarter levels but raised its full-year production growth to 7-8% from 5-7%, also due to Giddings performance.

Magnolia will maintain the current 2-rig program throughout the year. One rig will continue to drill multi-well development pads in the Giddings area. The second rig will drill a mix of wells in both the Karnes and Giddings areas, including appraisal wells at Giddings.

For full-year 2023 at Giddings, Magnolia expects to average about 4 wells per pad with average lateral lengths of about 8,000 ft. In late July, the company completed a small, bolt-on asset purchase outside of its core development area in Giddings for $40 million.

Total drilling and completions capital for 2023 of $425-440 million, lower than previous guidance of $440-460 million, is expected.

Second-quarter 2023 capital spending was $86.1 million, about 15% below earlier guidance, partially due to lower oilfield services and material costs, the company said.

PROCESSING Quick Takes

Taiyo Oil launches study for renewable fuels project

Taiyo Oil Co. Ltd. is considering producing renewable fuels at subsidiary Nansei Sekiyu KK’s oil and petroleum products storage and marine terminal—home to a now-idled 100,000-b/d refinery—on Japan’s southwestern island of Okinawa in Nishihara, Nakagami District, Okinawa Prefecture.

Taiyo Oil and partner Mitsui & Co. Ltd. (MCL) have initiated a feasibility study for a project that could produce sustainable aviation fuel (SAF) and renewable diesel, Taiyo Oil said on July 26.

The proposed renewables plant would use an alcohol-to-jet (ATJ) process technology to produce up to 220,000 kl/year of SAF and renewable diesel from a feedstock of cost-competitive ethanol supplies imported to the site’s marine terminal via large tankers.

In a separate release, MCL confirmed the plant would be equipped with LanzaJet Inc.’s ATJ technology.

Pending the outcome of the feasibility study, Taiyo Oil said the renewables plant would become operational and begin initial production of SAF and renewable diesel sometime in fiscal-year 2028.

Alongside supplying Japan’s domestic demand for renewable fuels, Taiyo Oil said it also expects the proposed plant’s location in the center of East Asia will enable exports to destinations elsewhere in the Asia Pacific.

According to its website, Nansei Sekiyu officially became part of Taiyo Oil in late-December 2016 following the latter’s $129.3-million acquisition of Nansei Sekiyu’s storage and marine terminal assets—including the idled Nishihara refinery, which shuttered in April 2015—from Brazil’s state-owned Petroleo Brasileiro SA.

MPLX net income up 6.6%, adding seventh Permian gas processing plant

MPLX LP had second-quarter 2023 net income of $933 million, compared with $875 million for second-quarter 2022. Adjusted earnings before interest, taxes, depreciation, and amortization (EBITDA) rose in both its logistics and storage (L&S) and gathering and processing (G&P) segments. L&S was up 5.8% at $1.022 billion and G&P 3.7% at $509 million.

Total liquids pipeline throughputs of 6 million b/d increased 1% from second-quarter 2022. Gas gathering volumes averaged 6.2 bcfd, up 9% year-on-year. Processed volumes averaged 8.9 bcfd, a 6% increase versus second-quarter 2022. Fractionated volumes averaged 583,000 b/d, up 9%.

In the L&S segment, MPLX is expanding its natural gas and NGL long-haul and crude gathering pipelines supporting the Permian and Bakken basins. Specifically in the Permian, working with its partners, MPLX is expanding both the Whistler crude pipeline, to 2.5 bcfd from 2 bcfd, and its Agua Dulce Corpus Christi pipeline lateral, targeting September 2023 startup. MPLX is also boosting capacity on its Belvieu Alternative NGL (BANGL) joint venture pipeline to 200,000 b/d, with expected completion in first-half 2025.

MPLX remains focused on the Permian and Marcellus basins in its G&P segment. In the Permian’s Delaware basin, MPLX is progressing construction of its sixth natural gas processing plant, the 200-MMcfd Preakness ll, which is expected online first-half 2024. MPLX is also planning to build the 200-MMcfd Secretariat, its seventh processing plant in the basin, with expected startup in second-half 2025. These new plants will bring MPLX processing capacity in Delaware basin to 1.4 bcfd. In the Marcellus, MPLX is progressing construction of its 200-MMcfd Harmon Creek ll processing plant, expected online first-half 2024.

Matador weighs Delaware basin gas processing expansion

Matador Resources Co. is considering options to expand its cryogenic natural gas processing capacity in northern Lea County, NM.

To increase flow assurance for rising gas volumes in the county—including assets gained through the $1.6-billion acquisition of Advance Energy Partners Holdings LLC—and regional third-party producers, Matador plans to expand its local gas processing capacity by another 200 MMcfd.

The expansion could involve independent construction of a new gas plant or a new gas plant built as part of a potential partnership, the company said in a July 26 earnings call.

While Matador confirmed it is currently evaluating whether to include a partner for the proposed plant, the project could also involve an expansion of San Mateo Midstream LLC’s 460-MMcfd Black River processing plant in the county, said Joe Foran, Matador’s chairman and chief executive officer.

The Black River plant—which Matador (51%) owns alongside joint-venture partner Five Point Energy LLC (49%)—previously completed a 200-MMcfd expansion to its current capacity in 2020.

Follwing completion of its Advance acquisition, Matador, through subsidiary Pronto Midstream LLC, owns the Marlan gathering and processing system in Lea and Eddy Counties, NM, which includes the 60-MMcfd Marlan gas plant.

Glenn Stetson, Matador’s executive vice-president of production, said the company also believes the Marlan plant—which received increased throughputs during second-quarter 2023 via its direct connection to 15 of Matador’s operated wells—will be full by yearend, further supporting proposed capacity expansion plans.

While planning is under way, Matador said its primary objective is to protect its balance sheet and that adding that a partner could make the proposition more appealing.

TRANSPORTATION Quick Takes

Equitrans to begin construction of Ohio Valley Connector expansion project

Equitrans LP expects construction of the 350-MMcfd Ohio Valley Connector expansion (OVCX) project to begin soon, on target for incremental capacity in-service by first-half 2024.

The company provided the update as part of its second-quarter report on Aug. 1.

On June 15, Equitrans received from the US Federal Energy Regulatory Commission (FERC) a certificate of public convenience and necessity for expansion project, and on July 27, the US Army Corps of Engineers issued the project’s last outstanding approval. On July 31, FERC issued the Notice to Proceed. 

OVCX will increase deliverability on ETRN’s Ohio Valley Connector pipeline and is designed to meet growing demand in markets in the mid-continent and Gulf Coast through existing interconnects with long-haul pipelines in Clarington, Ohio (OGJ Online, Jan. 24, 2023). The 37-mile Ohio Valley Connector’s current capacity is 850 MMcfd.

Equitrans expects to invest about $160 million in the project, which is primarily supported by a long-term firm capacity commitment of 330 MMcfd. 

Shell signs term LNG capacity agreements with PipeChina

Shell (China) Ltd. has signed medium- and long-term agreements with China Oil & Gas Pipeline Network Corp. (PipeChina) for use of the latter’s LNG terminals. Details regarding the timing and volume of the leases were not provided.

Shell last year signed two terminal-use agreements with PipeChina subsidiary PipeChina LNG Terminal Management. Included in the deal were the 4.2-million tonne/year (tpy) Yuedong LNG terminal and 3-million tpy Beihai LNG.

PipeChina formed in 2019 to consolidate operation of China’s LNG terminal and pipelines. PipeChina LNG operates seven terminals and is building three more, one each in Shandong (6.5-million tpy), Fujian (3-million tpy), and Shenzen.

Phase 1 of PipeChina’s Shandong Longkou terminal is expected to enter service in October 2023. Phase 2 would raise capacity to 12 million tpy. Shenzhen Diefubei is slated for 2025 startup.

bp, OMV sign a 10-year LNG supply agreement

bp signed an agreement to provide OMV with up to 1 million tonnes/year (tpy) of LNG for 10 years from 2026.

bp will provide the LNG from across its portfolio, which will be received and regasified through the Gate LNG terminal in Rotterdam, The Netherlands, where OMV holds regasification capacity, or other terminals in Europe for supply to European customers.

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