• Competitor shuttering. Many regional markets have a delicate balance of supply and demand with the high cost of importing products from other regions. A competitor shuttering its asset may provide the opportunity to serve its abandoned market. • Changing gasoline-to-diesel (G/D ratio). US gasoline demand is expected to decline more rapidly than diesel, whereas in the EU, this is reversed. Sites have some cut point, severity, and catalyst reload flexibility to respond to demand shifts. However, at some point, the spreads get big enough to support a hydrocracking investment in the US and perhaps FCC expansion in the EU. The refiners who are first to market on these opportunities will shore up their competitive positioning, especially if these opportunities can be coupled with a crude expansion to capture the mar- ket as competitors shutter. • Access to advantaged crudes. Regional discounts in crude oils can arise from newer discoveries, pipeline con- straints, or production volumes that limit market access. Many sites have found value in revamping/expanding capa - bilities to process discounted, higher TAN crudes, heavier crudes, or even much lighter, shale-derived crudes, • Access to petchem markets – notably propylene or aro - matics. These can be trickier options for smaller refiners who have never played in these markets. However, there is a need in NA for benzene, and FCC-based propylene is an easy opportunity for sites with pipeline access. Diversifying your product portfolio into higher margin petrochemicals could be an option. Q What incentives and technology are needed to make refinery-based cogeneration of electricity and steam profitable? A Mark Heigold, Department Manager and Associate Process Engineer, Burns & McDonnell, mlheigold@burn- smcd.com The decision to install a cogeneration (cogen) system in a refinery is primarily driven by economics. The key question is whether it is more cost-effective to generate both power and steam on-site or to purchase electricity from the grid while producing steam separately. A refinery investing in a cogen must account for the capital expenditure as well as increased fuel and maintenance costs. However, this is offset by lower direct electricity costs, potential tax credits, and increased efficiency. In North America, government financial incentives are usually linked to achieving a certain level of cogen efficiency. If the efficiency criteria can be met, associated credits can improve project economics. In the US, available investment tax credits (ITC) and Canada’s Class 43.1 heat rate cat - egories encourage cogen adoption. Carbon penalties and fuel market incentives also play a role. Refineries in Canada can avoid carbon taxes through cogen efficiency, while California’s Low Carbon Fuel Standard (LCFS) offers credits for integrating low-carbon fuels like renewable natural gas, hydrogen, or ammonia. These financial mechanisms impact feasibility, making cogen systems more attractive. Energy efficiency is the ultimate goal. Cogen systems
recover waste heat that would otherwise be lost, reduc- ing overall energy consumption. This leads to lower carbon emissions and offers additional benefits such as improved energy security and, in some cases, surplus electricity that can be sold to the grid. The choice of technology for power generation depends on the refinery’s energy demand and fuel availability. Gas turbines with heat recovery steam generators (HRSGs) capture exhaust heat to produce steam, improving fuel utilisation. Steam turbines can be added to utilise high- pressure steam for additional power generation while sup - plying lower-pressure process steam to the facility. An inte - grated gasification combined cycle (IGCC) facility gasifies refinery residues to produce syngas, which fuels a gas tur - bine combined-cycle system for electricity and steam pro- duction. Each option must be evaluated based on fuel costs, efficiency, and integration with existing refinery operations. Installing a cogen system will impact existing infrastruc - ture. With a gas turbine-based system, fuel consumption will increase since a portion of the turbine fuel is used for power generation, with the remainder credited to steam production. The electrical system must also be able to handle ‘behind-the-fence’ self-generation as well as switch back to grid supply when the turbine(s) are down for main - tenance. Refineries with existing infrastructure that can handle these requirements will find installation more eco - nomical than those requiring significant updates. A full lifecycle analysis will help determine whether a cogen provides a financial advantage over grid electricity and separate steam production. While project justification is primarily financial, regulatory benefits, reduced emis - sions, and the ability to incorporate low-carbon fuels fur- ther strengthen the case. If a cogen system can produce electricity and steam at a lower cost than grid power and standalone boilers, and incentives improve ROI, it presents a compelling economic option. A Joe Jacobs, Manager, Strategic Business Development, Becht, jjacobs@becht.com Refiners face competitive market pressures to lower pro - duction costs. Coproducing electricity and steam is a proven way to improve cycle efficiency for a refinery site. Improved energy efficiency will mean lower costs for the refiner. Electricity producers also face demand issues for the grid, with alternative energy sources having cyclical production and needing a swing supply. Building new power plants is one option to stabilise the grid; however, cost pressures are not unique to petroleum refiners. Currently, refiners nominally receive some cost incen - tives to produce electricity. These agreements have ele - ments for the refinery site to maintain electrical production at peak times as well as during electrical infrastructure maintenance periods. These agreements have tradition - ally been from opposite sides of the table where the par- ticipation is based on the transaction: electricity bought and sold. Perhaps the time is coming for more integrated arrange - ments like partnerships that allow the replacement of anti- quated fired boiler technology in a refinery for a baseload
7
PTQ Q2 2025
www.digitalrefining.com
Powered by FlippingBook