Gas 2025 Issue

when feeding NGL to a steam cracker, such as steam ratio and coke reduction, product quenching, and the use of dual feedstock crackers that can switch between NGLs and naphtha to optimise production, will be discussed in future issues of PTQ . Associated process gas With crude oil production, there are opportunities to mon- etise co-produced gas or associated process gas (APG). Technically, a number of options exist for handling APG, including preparing it as fuel in various forms, such as dried pipeline gas or liquefied petroleum gas (LPG), and export - ing it via pipeline. It can then be re-injected for later recov- ery, such as processing it as LNG or LPG and exporting it via tankers for converting it to petrochemical feedstock. Modular or portable gas-powered engines driving elec- trical generators (Gensets) can turn APG into power for onsite electricity, eliminating the cost of diesel deliveries to remote areas and reducing CO₂ emissions that otherwise might result from diesel fuel consumption or previous vent- ing or flaring practices. As with other gas sources, there are challenges to its commercialisation, such as the need for gas desulphurisation at relatively high H₂S concentra - tions, but cleaning this fuel makes it valuable, especially in remote areas with limited fuel sources. In addition, the waste heat from the Gensets can also be used for onsite heating purposes. Stranded gas While natural gas or well-gas-driven gensets may cost more to rent than a diesel generator, long-term fuel cost savings make natural gas generators more economical when also factoring in Tier 4 emissions compliance require- ments. According to feedback from industry experts, the diesel engine is normally 40% of the genset’s component cost (engine + generator), so when the cost of the engine increases by 80 to 100% (for technology needed to meet more stringent emissions compliance), the overall cost for diesel generators becomes significantly more expensive than gas generators, invalidating the industry paradigm that diesel generators are typically the lowest capital option. In addition, a payback of greater than 10-to-1 may be real- ised with discounted gas as diesel prices increase in response to the IMO 2020 global 0.5% sulphur cap for marine bunker fuels (against the current 3.5% limit). The sulphur cap will require blending diesel into bunker fuels to meet the 0.5% sulphur spec that cannot be met by the heavier distillates and high sulphur fuel oils (HSFOs) currently in use. Incentives Multiple proposed US projects, including Venture Global’s CP2 LNG facility, Commonwealth LNG, Rio Grande Phase 2, Port Arthur Phase 2, and Lake Charles LNG, may be able to make significant strides this year towards reaching the market. Additionally, the new US Administration provides a tailwind for facilities with non-free trade agreement (FTA) approvals that are set to expire within the next four years, such as Cameron LNG Phase 2, Woodside Louisiana LNG, and Texas LNG. Collectively, these eight facilities total

around 15 Bcf/d of nameplate capacity and would nearly double current US LNG capacity. Although not necessary to move forwards with an LNG project, Department of Energy (DOE) non-FTA authorisation is important for new LNG projects, as it allows access to critical demand centres, making it more attractive for securing offtakers and financ - ing and ultimately paving a path for a facility to achieve a positive final investment decision (FID). Elsewhere, the first train of LNG Canada, a 1.8 Bcf/d facility, is expected to be fully in service in mid-2025. The project will be the first major export project in the country. Additionally, Western LNG, with the Nisga’a Nation and Rockies LNG, is looking to achieve a positive FID on its Ksi Lisims LNG project in 2025, a proposed 1.5 Bcf/d facility, after it received a significant investment from Blackstone Energy Transition Partners. BTU Analytics had previously identified the growing Canadian LNG industry as a risk to US gas markets in the August 2024 edition of the Gas Basis Outlook . However, the same can be said of other projects in the Western Hemisphere. According to a recent report from Energy Capital and Power, several significant LNG projects are in develop - ment in Africa. The first phase of the 2.3 million tons LNG Greater Tortue Ahmeyim (GTA) project between Senegal and Mauritania is nearing completion and commissioning. Other major projects are on track in other parts of Africa. Gas-based projects in The Middle East, such as the 1.0 mmtpa Marsa LNG project located within SOHAR Port and Freezone, will provide maritime energy solutions in the Middle East with a cleaner fuel alternative for global ship- ping while facilitating Oman’s economic diversification. Another project of high interest due to its unique status of making it one of the world’s lowest carbon intensity LNG plants is the Ruwais LNG project in the United Arab Emirates. It will include the construction of two liquefaction trains, each with a capacity of 4.8 mmtpa. This new capac- ity, totalling 9.6 mmtpa, will more than double ADNOC’s current UAE LNG production, bringing it to approximately 15 mmtpa as the company expands its international LNG portfolio. Located in Al Ruwais Industrial City in the Al Dhafra region of Abu Dhabi, the project will be the first LNG export facility in the Middle East and North Africa (MENA) region to operate on clean power. Vision According to the most recent Shell LNG Outlook , global LNG demand for liquefied natural gas (LNG) is forecast to rise by around 60% by 2040, and more than 170 million tonnes of new LNG supply are set to be available by 2030. A few of the drivers for the expanding gas industry have been discussed, not the least of which is leveraging clean gas to heat and power homes, businesses, and industries throughout the world. Take, for example, the development of natural gas fields in and around relatively remote Trinidad and Tobago and conversion to LNG and NGLs through liq- uefaction facilities on those Caribbean islands. The reve- nues earned contribute to GDP in that area, allowing for a higher standard of living for many in that region while reducing the need for coal, diesel, and heavy oils.

Gas 2025