Author: Tom Young

ConocoPhillips advanced its LNG strategy in the first half of 2023, completing the acquisition of an equity interest in Qatar’s North Field South project, agreeing to an offtake deal with the planned Saguaro LNG export facility in Mexico and securing regasification capacity at the Gate LNG Terminal in the Netherlands.

At its analyst and investor meeting in April, the company said it sees robust LNG demand growth well into the middle of the century, led by Asian importers. It aims to expand its LNG supply portfolio from six million metric tonnes per annum (mtpa) currently to over 12 mtpa by 2028.

Qatar acquisition

ConocoPhillips completed a deal making it one of three international partners, alongside TotalEnergies SE and Shell plc, in QatarEnergy’s North Field South (NFS) expansion project. The NFS project is two liquefied natural gas (LNG) trains with a combined capacity of 16 mtpa.

ConocoPhillips will have an effective net participating interest of 6.25 per cent in the NFS project, in addition to its existing 3.125 per cent stake in the 32 mtpa North Field East project.

Source: Evaluate Energy

QatarEnergy and ConocoPhillips will deliver LNG to Germany from the region in 2026, with the company also announcing it has secured 2.8 mtpa of regasification capacity at a planned terminal in Germany.

“That supports our two mtpa offtake from our LNG SPAs with Qatar and leaves 0.8 million mtpa to be supplied by our commercial LNG business,” said chief financial officer William Bullock.

Mexican waves

ConocoPhillips has also signed a 2.2 mtpa offtake agreement from the proposed Saguaro LNG terminal on the west coast of Mexico, which is well placed to supply Asian markets by avoiding Panama Canal fees. The project has yet to take FID.

“From a supply perspective, it really does complement our offtake from Port Arthur very nicely, creating some excellent optimization opportunities,” said Bullock.

The company has 5 mtpa of LNG supply from Phase 1 of Port Arthur LNG on the Gulf Coast, with FID already taken and startup slated in 2027. It also has access to excess uncontracted volumes from Phase 1 of the project and options for equity and offtake on future phases.

The company is planning a mix of long-term contracts, short-term contracts and spot sales across its portfolio to optimize pricing.

“We are actively developing placement into Europe. We’re developing long-term deliberate opportunities into Asia. And we’re considering some sales FOB at the facilities that are in the money right now,” said Bullock.

ConocoPhillips also has a partnership with Origin Energy Limited for Australia Pacific LNG (APLNG). It is comprised of a coalbed methane development operated by Origin Energy and an LNG production project operated by ConocoPhillips.

 

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A corporate culture focused on driving down costs while driving up well productivity is allowing Permian oil producer Diamondback Energy, Inc. to drill more wells faster while keeping a lid on capital expenditures, chief executive officer Travis Stice said at the company’s second quarter 2023 conference call.

The improved cycle times resulted in Diamondback drilling 98 wells in the second quarter of 2023, a record for the company, and almost twice the 52 wells drilled in the year-ago quarter, as it integrated two large Permian acquisitions into its operations.

Source: Evaluate Energy Company Performance Data

At that pace, Diamondback would drill 400 wells this year, significantly higher than its annual guidance of ~340.

“We’re slowing down the drilling pace in the second half of the year and building a few DUCs,” said Stice. “If this was 2017 or 2018, we’d be stepping on the accelerator and spending more capital, but instead we’re focused on generating more free cash flow in the second half of the year and returning that cash to shareholders.”

The drilling productivity improvements are the result of a corporate culture focused on continuous incremental productivity gains, said Stice.

“I wish I could say it was one individual piece of technology that’s transferable across our entire rig fleet, but it’s much more subtle than that,” he explained. “It’s the culture that we have that has an extreme focus on cost control and efficiencies.”

“And it’s not one or two items, it’s thousands of items that are decided upon [by] every one of these rigs,” he added. “They measure how long it takes to physically screw pipe together for 300 times for every trip that they make — that measurement of just simply screwing pipe together in five minutes versus the next rig over that was six minutes, you think it doesn’t matter, but when you do that several bit trips, bit runs, per well, it adds up. And that’s the level that our organization focuses on efficiency.”

Measuring operational metrics

“What it boils down to is the teams measuring every little thing they can on the rig and measuring which way those operational metrics are trending,” said chief operating officer Danny Wesson. “When a metric is not trending in the right direction, they attack it with a fervor that is unlike anything I’ve ever seen. And that continues to [produce] year-over-year improvements in execution.”

This summer the company drilled two record wells with 7,500-foot (2,300 metres) laterals in under five days, said Wesson. “Those results are remarkable, and we don’t talk about individual well results a lot, but those are the things that we continue to do in the day to day of the company that continue to drive our execution downward.”

“We have a healthy competition among our rigs and completion crews that we incentivize monetarily for efficiency and cost control measures,” added Stice.

Diamondback completed and turned 89 wells to operation in the quarter compared to 62 in the year-ago quarter, a number that Stice said was likely to come down to around 80 for the next two quarters. It expects to complete 330-345 gross wells during the year. The company is running four simulfrac crews which can complete about 80 wells each a year.

The average lateral length for wells completed during the first six months of 2023 was 10,889 feet.

“In this new business model of capital efficiency and profitable value over volumes, we’re focused on running the most efficient plan possible,” said president and chief financial officer Kaes Van’t Hof. “Absent a major change in commodity price, that’s the plan and that allows the teams to plan their business and also allows us to execute at the lowest cost from a capex perspective, so kind of that 15-ish rigs and four simulfrac crews feels like a really good baseline for us.”

Source: Evaluate Energy Company Performance Data

Net production guidance for 2023 has been increased slightly from 430,000–440,000 boe/d to 435,000–445,000boe/d, due to production outperformance year-to-date.

Diamondback had Q2 net income of US$556 million, down from US$1.42 billion in the year-ago quarter, on lower commodity prices.

 

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The U.S.’s largest natural gas producer, EQT Corporation, says it is on track to achieve its goal of net-zero Scope 1 and Scope 2 greenhouse gas (GHG) emissions in its production segment by 2025.

EQT plans to achieve the goal largely through operational improvements, rather than the use of offsets. The company made noteworthy progress in 2022, reducing Scope 1 and 2 emissions by 19.8 per cent on 2021 levels to 433,450 tonnes of CO2e, according to Evaluate Energy data.

These figures do not include emissions from the assets acquired in the third quarter of 2021 from Alta Resources Development, LLC, which EQT is reporting separately this year.

EQT has overseen a steady reduction in Scope 1 and 2 production-segment emissions since 2018 (see chart below), despite acquiring some Chevron Corporation upstream and midstream oil and gas assets in the fourth quarter of 2020, which are included in its performance towards the 2025 target.

During 2022 the firm completed a $28-million initiative to replace 9,000 natural gas-powered pneumatic devices in its production operations with electric units. These devices set thresholds and manage liquid levels in vessels such as separators, scrubbers and filters and accounted for 47 per cent of EQT’s Scope 1 production segment GHG emissions in 2021.

The replacement program took two years, but the benefits will not be fully realized in its emissions inventory until EQT reports its 2023 data due to the way emissions from pneumatic devices are calculated under the EPA’s reporting rules, meaning it expects to report further emissions reductions in 2023.

EQT has published a whitepaper highlighting its learnings from the program so that other operators can leverage its experience and implement the processes in their own operations.

Alta assets

The pneumatic drive replacement program was also carried out across the acquired Alta assets, although again the full benefits have not yet been reflected in emissions reporting data.

Production segment Scope 1 and Scope 2 GHG emissions from the Alta assets were cut year-on-year by just two per cent to 107,901 tonnes of CO2e in 2022, far less than the 19.8 per cent cut in the historical assets.

A change in the way emissions from pneumatic devices were reported in the Alta assets following the purchase — from an assumption-based model to a full inventory — led to a year-on-year increase in emissions in the division in 2022. As with the historical assets, the benefits of the replacement program on emissions will not be seen until 2023, when the firm expects a significant reduction below both 2021 and 2022 levels.

Methane emissions intensity

EQT also has a goal to reduce its Scope 1 methane emissions intensity to below 0.02 per cent by 2025.

Between 2018 and 2021 it made good progress on cutting methane emissions intensity (see chart below) due to its combo-development strategy. This strategy focuses on developing multiple multi-well pads simultaneously, reducing infrastructure and therefore opportunities for methane loss.

In 2022 the firm achieved a figure of 0.038 per cent, only a marginal improvement on the 0.039 per cent figure reported in 2021, but EQT expects this figure to improve in 2023, again thanks to realizing the ongoing benefits of the pneumatic device replacement program, and maintains confidence in hitting its 2025 goal.

Unlike the Scope 1 and Scope 2 emissions figures, the methane emissions intensity figure does include emissions and production from the Alta assets.

In November 2022, the Oil and Gas Methane Partnership 2.0 (OGMP) — a multi-stakeholder initiative launched by the United Nations Environment Programme — awarded EQT a “Gold Standard” rating, the highest reporting level under the initiative, in recognition of its reduction targets and commitment to accurately measuring, reporting and reducing methane emissions.

EQT was among 14 upstream companies globally qualifying for the Gold Standard for 2022.

LNG production argument

In recent months EQT has been advancing a climate-centric argument for leveraging U.S. natural gas to replace international coal. For more on EQT’s LNG plans, click here.

“We believe this to be one of most important initiatives available to the world in addressing climate change,” says chief executive officer Toby Rice.

“We’ve got a plan to reshape the world’s energy mix by increasing U.S. LNG exports to connect our affordable, reliable and clean natural gas to the world’s coal consumers.”

The firm says a quadrupling of U.S. LNG capacity to 55 bcf/d by 2030 to replace overseas coal use would reduce global emissions by 1.1 billion tonnes CO2 per year.

 

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EQT Corporation, the biggest independent U.S. natural gas producer, is dipping its toes in the LNG export market.

EQT has signed a non-binding preliminary agreement with Energy Transfer to sell one million metric tonnes per annum of LNG via the proposed Lake Charles terminal in Louisiana.

The 15-year tolling agreement was signed after EQT spent 18 months evaluating the best way to reach international gas markets.

“This strategy allows us to creatively structure deals with downside price protection, obtain visibility into global downstream markets, and interact with a wide array of potential customers,” said EQT president and CEO Toby Rice during the company’s second quarter conference call.

EQT delivers 1.2 bcf/d, or around 25 per cent of its production, to the Gulf Coast. Around 135 mmcf/d would go to supply the Lake Charles LNG deal.

“We’ve spent the last year and a half studying the nuances of LNG export opportunities and believe the strategy we are pursuing provides the best combination of upside exposure with downside risk mitigation relative to the netback structures that are commonly being signed,” said Rice.

The exact structure of the deal wasn’t revealed but it will give EQT some exposure to international LNG prices rather than selling on a Henry Hub basis, where prices have historically been much lower.

Source: Evaluate Energy Company Performance Data – find out more here.

Getting the deal in place with Lake Charles is the first stage in the process of selling to international buyers. The second stage is to sign a sales and purchase agreement (SPA) with the buyers themselves, where the firm will also seek 15-year deals to match the tolling agreement.

“We plan to pursue signing one or more SPA with prospective international buyers and have additional opportunities to increase our tolling exposure,” said Rice. Talks with buyers are already underway and EQT is seeking a deal with a price floor and ceiling to provide “energy security” to prospective customers, he added.

LNG Facility Investments

The firm initially considered taking an equity investment in an East Coast LNG facility as the best way to gain exposure to international markets, but eventually decided that a tolling agreement was a better option. However, it did not rule out an equity stake in the future.

“We’re not looking to make investments … but there could be opportunities where, from a risk mitigation perspective, it makes sense for us to make a small investment in an LNG facility,” said Rice.

EQT has not set any targets on the proportion of its gas it will sell via LNG but aims to be opportunistic with deals depending on market conditions. In his concluding remarks Rice said the Lake Charles deal represented an “initial step” in EQT’s LNG strategy.

Earlier this year the firm launched a campaign calling for the U.S. to quadruple its LNG export capacity to 55 bcf/d by 2030 to replace overseas coal use. Modelling by the firm showed such a scenario would reduce international CO2 emissions by 1.1 billion metric tonnes per year.

Lake Charles Developments

Energy Transfer signed two other agreements for Lake Charles earlier this month.

• Under the first deal a Japanese consortium would purchase 1.6 million metric tonnes per annum for a 20-year term.
• Under the second deal Chesapeake Energy Corporation would supply one million metric tonnes per annum to Lake Charles for 15 years, which trading house Gunvor would purchase at a price indexed to the Japan Korea Marker (JKM).

Lake Charles has an authorization from the Department of Energy (DoE) to start non-FTA LNG exports by December 2025.

In April this year, the DoE declined a request from Energy Transfer to extend the deadline to start exports to December 2028, and last month declined a rehearing request.

Energy Transfer has not yet made a final investment decision (FID) on the Lake Charles project.

 

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U.S. natural gas giant EQT Corporation continues finding ways to drive drilling and completions productivity levels higher at its Marcellus and Utica shale gas development.

A benchmarking exercise carried out by EQT during the quarter found the company’s recent southwest Appalachian wells were being drilled 68 per cent faster than the average of its peers, the company reported at its second quarter conference call.

Source: EQT Q2 Results Presenation. For more on Evaluate Energy Documents, watch a short video here or click here for more information. 

“A horizontal EQT rig drilled roughly 300,000 more lateral feet per year relative to our peer average,” said EQT president and CEO Toby Rice.

One rig crew set a new world record by drilling 12,318 feet in 24 hours on a well in Greene County, Pa., Rice added. Meanwhile EQT’s completions team stimulated a record 20,880 lateral feet on a separate well.

“At nearly four miles this is one of the longest completed laterals in the history of U.S. shale development and an internal record,” said Rice, noting that completion efficiency was up 20 per cent against the year-ago quarter.

The drilling and completions performance helped EQT achieve a total sales volume of 471 bcfe during the second quarter, towards the top end of its 425–475 bcfe production guidance, according to Evaluate Energy data.

The achievement came despite lower-than-expected liquids volume from downtime at a Shell plc ethane cracker and other third-party issues which negatively impacted production by 12 bcfe compared to the forecast.

Back on track

EQT production is on track to return a 500 bcfe quarterly rate in the third quarter as third-party issues are resolved and drilling and completions continue apace. The company has maintained its expectation of 1,900–2,000 bcfe total sales volume for 2023.

It also hopes to complete its US$5.2 billion acquisition of the Tug Hill and XcL Midstream assets in the third quarter, following Federal Trade Commission (FTC) approval in the next month.

The assets will add an estimated 800 mmcfe/d to EQT’s production in the Appalachian region, as well as 95 miles of midstream gathering systems connected to long-haul interstate pipelines in southwest Appalachia.

The deal was initially announced in 2022 and has been under FTC review since then. Our review of the deal can be found here.

“It’s been a long process, but we see light at the end of the tunnel,” said Rice. “One of the guiding principles for us as we were going through this process is to make sure that we preserve the economics of the deal that we signed off, and I feel like we’re going to be able to deliver that and also preserve strategic flexibility going forward.”

The assets are expected to lower EQT’s pro forma corporate free cash flow breakeven price by approximately $0.15/mmBtu until 2027.

EQT’s production guidance does not include the impact of the Tug Hill and XcL Midstream acquisitions.

 

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U.S. supermajor Chevron Corporation will only take equity stakes in LNG liquefaction terminals when necessary to get its gas to market, CEO Mike Wirth said on the firm’s second quarter results call.

Wirth noted that the midstream part of the value chain had the potential to be very capital intensive and deliver low returns.

“We’re really looking to drive high returns, not necessarily to own assets for the sake of control, unless it creates a differentiated value proposition,” he said.

In the U.S., Chevron signed two deals last year with LNG developers Cheniere Energy, Inc. and Venture Global LNG for a combined four million metric tonnes per annum (mtpa) that will provide an outlet for natural gas flowing from its Permian Basin shale holdings in West Texas and New Mexico, without it having to take a stake in terminals.

Because it has its own shipping portfolio Chevron can lift the cargoes on a FOB basis and sell them into international gas markets.

Outside the U.S., Chevron has some stakes in LNG projects — notably in Angola and Australia. It is also evaluating a floating LNG project offshore Israel that would process gas from the Leviathan field.

“In places where you’ve got remote gas where you need to be in the entire value chain and you can create an economic model that supports the investments, we’ve done that,” said Wirth. “In other locations where you’ve got other people that will put capital into the midstream assets … that’s certainly a model that helps us support our aspiration to drive higher returns.”

Chevron has experienced several challenges with its Gorgon LNG liquefaction facility offshore Australia. It was licensed to build the export plant on the condition it would inject at least 80 per cent of the CO2 it emitted. But it injected just a third of the CO2 it produced in the 2021-2022 financial year due to issues with its water management system. Chevron was required to purchase a significant volume of carbon offsets to make up the shortfall.

Chevron’s Angola LNG has also suffered technical issues and was shut down for more than three years from 2015 to 2019.

Mixed strategies

New types of contracts have allowed some gas producers to get exposure to international gas prices without having to take equity stakes in liquefaction projects.

EQT said in its second quarter results that it would not look to take stakes in U.S. liquefaction but would gain exposure to international gas markets via a tolling agreement with Energy Transfer’s Lake Charles project. Chesapeake Energy Corporation similarly has agreed to supply trading house Gunvor with two million mtpa LNG at JKM-linked prices without yet specifying which terminal will be used.

But other producers continue taking equity stakes in the U.S.

ConocoPhillips has a 30 per cent stake in the Port Arthur LNG project it is developing with Sempra Infrastructure, and Exxon Mobil Corporation has a 30 per cent stake in Golden Pass export terminal.

Devon Energy Corp. also has a preliminary agreement in place to help finance Delfin Midstream’s first floating LNG vessel.

Outside the U.S. firms, TotalEnergies SE has a stake in Cameron LNG and Rio Grande LNG.

For more on Evaluate Energy’s company performance data, click here. 

 

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BP plc is one of the few oil majors to set an absolute Scope 3 emissions reduction target — meaning it has a goal to reduce the emissions from the combustion of the fossil fuels it produces, as well as the emissions it takes to produce them.

Of the majors, only BP and Shell plc have net zero Scope 3 targets for 2050. BP set a baseline of 361 million tonnes of CO2e for its Scope 3 emissions in 2019, and initially set a target to reduce this by 20 per cent by 2025 and by 35-40 per cent by 2030. That equates to achieving annual emissions of 289 million tonnes of CO2e or lower in 2025 and 216-234 million tonnes of CO2e or lower in 2030.

As of 2021 the firm had achieved a 15.8 per cent reduction with Scope 3 emissions of 304 million tonnes of CO2e (see chart below), Evaluate Energy data shows.

But earlier this year the firm downgraded the 2025 target from 20 per cent reduction to a 10-15 per cent reduction and the 2030 target from a 35-40 per cent reduction to a 20-30 per cent reduction. The move illustrates that the company’s emissions reduction targets are not binding and can be adjusted depending on global energy security concerns.

This downgrading gave BP leeway to increase emissions over the next few years and still hit its targets. Emissions in 2022 have already increased slightly year-on-year to 307 million tonnes of CO2e — a 15 per cent reduction on the baseline — as fossil fuel production increased 1.6 per cent year-on-year to 2.253 million boe/d.

Between now and 2025 BP expects emissions to grow further due to major project start-ups, deferred divestments of existing production, and further production growth — suggesting it is likely to hit the lower end of the downgraded 10-15 per cent reduction target. But in its latest sustainability report it restated its confidence to hit the mid-range of the 2030 target with a 25 per cent reduction on the baseline, thanks to the anticipated base decline of existing fields and to new low carbon projects coming online after 2025.

BP’s fossil fuel exploration and production capital expenditure has declined from a peak of $4.6 billion in 2010 to around $500 million in 2022, but again it has indicated this figure could grow in the next three years.

Earlier this year BP adjusted upwards its overall capital expenditure expectations from $14-16 billion per year to $14-18 billion per year out to 2030. Of the midpoint $16-billion annual investment between now and 2030, $8 billion will go into transition technologies and $8 billion into fossil fuels.

“We are growing our investment into our transition and, at the same time, growing investment into today’s energy system,” said CEO Bernard Looney, announcing the extra investment.

After 2030, the firm is looking to reduce Scope 3 emissions through two key strategies. The first is producing blue hydrogen using carbon capture and storage (CCS). In April BP signed an agreement to take a 40 per cent stake in the Viking carbon capture and storage (CCS) project in the North Sea.

The second is generating more renewable electricity from its power portfolio.

Renewable generation capacity

By 2030, BP aims to have developed 50 GW of renewable generating capacity, with an interim target of 20 GW by 2025. Apart from Norway’s Equinor, few oil and gas firms have adopted the strategy, preferring instead to focus on hydrogen or CCS.

By the end of first quarter in 2023 the firm had brought 5.9 GW of renewables to FID, and had 38.8 GW in the pipeline, including 10.3 GW relating to the Australian Renewable Energy Hub green hydrogen project and 1.5 GW relating to its Morven offshore wind project in Scotland, in which it was awarded a lease option in January 2022 in partnership with EnBW.

In 2022 the company progressed its offshore U.S. Empire Wind 1 and 2 projects with Equinor and development work continued on its Beacon Wind project. In March 2022 BP partnered with Marubeni Corporation to explore an offshore wind development opportunity in Japan.

In 2022, BP’s transition technology investment doubled year-on-year to $4.9 billion, forming around 30 per cent of total capital expenditures for the year, up from around three per cent in 2019 (see chart above). It sees this figure reaching $6-8 billion in 2025 and $7-9 billion in 2030, meaning a cumulative investment over 2023-2030 of around $55-65 billion.

BP does not provide guidance for oil and gas investment that far out, but this transition spending would leave a remaining cumulative non-transition capital expenditure budget of $73-79 billion over the same time period.

 

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Chinese oil and petrochemicals product supplier Sinopec made progress towards its goal of creating a full value-chain for hydrogen during 2022, advancing production, refuelling stations, fuel cells and storage technologies, according to the company’s latest sustainability report.

Sinopec is accelerating the development of hydrogen energy as a core business of its new energy portfolio, with an initial focus on supplying the refining and transportation sectors.

“We are actively promoting the development of the domestic hydrogen energy industrial chain, ranking the first globally in terms of hydrogen refuelling stations in operation and under construction,” said chairman Ma Yongsheng.

Sinopec has an interim target to install 1,000 hydrogen refuelling station by 2025, supplied with 120,000 tonnes a year of low-carbon hydrogen. Sinopec is allocating 30 billion yuan (US$4.6 billion) to the project.

By the end of 2022 it had built 98 hydrogen refuelling stations to provide high-purity hydrogen for fuel cells, with a total delivery capacity of 16,500 tonnes a year, Evaluate Energy data shows.

Sinopec is already China’s largest grey hydrogen producer, manufacturing 3.5 million tonnes in 2021, accounting for 14 per cent of China’s total output.

It wants to leverage this position to increase its production of low-carbon green and blue hydrogen. By 2050 it has a stated goal to develop a nationwide low-carbon transportation energy supply net-work and operate the largest number of low-carbon hydrogen refuelling stations in the country.

In the midstream, Sinopec has finished construction of nine hydrogen supply centres and completed its first short-pipeline hydrogen transmission station in Jiaxing City, in the eastern Zhejiang province. It has also been developing a suite of hydrogen purification technologies for fuel cells, which require higher purity hydrogen than industrial applications.

And it has undertaken engineering and technical research on high-strength, high-pressure hydrogen storage materials and equipment, as well as a large double-shell vacuum insulated liquid hydrogen spherical tank with a view to deployment in the next few years.

During 2022 Sinopec announced a 100,000 tonne-per-year hydrogen pipeline stretching 400 kilometres from Inner Mongolia — where it is planning a 30,000 tonne-per-year green hydrogen production plant — to the capital Beijing.

CCUS

Sinopec captured 1.53 million tonnes of CO2 in 2022, its highest level ever. The bulk of the CO2 was captured from the firm’s ammonia production processes. During the year the firm used 657,000 metric tonnes of this CO2 for enhanced oil recovery in 36 separate projects.

Sinopec does not yet provide figures for how much CO2 it has injected into storage but says that by 2023 it will have the capability to store 300,000 tonnes.

During 2022 Sinopec began operation of the Qilu-Shengli Oilfield CCUS project, which has the capability to capture one million tonnes of CO2 every year, some of which will be injected into reservoirs for oil production and some of which will be injected into storage.

“This achievement has made Sinopec a technology company with a complete carbon-related industrial chain,” said Yongsheng.

Sinopec says it will build another similar sized CCUS demonstration project in partnership with Sinopec Nanjing Chemical Industries before 2025, as well as constructing a CCUS research and development facility. The firm wants to combine its CCUS and hydrogen expertise to create a blue hydrogen value chain across China.

It is also conducting a joint study with Shell plc, German chemical company BASF, and Chinese steel manufacturer Baowu to develop a CCUS-as-a-service model to transport emissions from third-party industrial facilities in the eastern region of China to offshore reservoirs for injection.

The firm has continued to increase investment in CCUS technology research and development, pioneering its own capture process and high-efficiency solvents, including a new high-efficiency ionic liquid capture solvent that it says could reduce capture costs by about 20 per cent.

In a demonstration project for industrial partners the company built a capture unit that achieved a 96 per cent capture rate. Most available technologies currently can achieve a capture rate of around 90 per cent.

Sinopec says its goal is to reach an emissions peak by 2030 and become carbon neutral by 2050.

 

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