Future of Refinery: Complexity, Sustainability and Cost Optimization...

As firms work to understand their vision of how they need to connect with the market across the energy progress, executing those plans requires a speculation system that is all the while bankable, adaptable, and economical. In a business where speculation open doors are lined up with three-to-five-year support circle back plans, potential open doors length from more modest, exceptionally strategic ventures to longer-term procedures. While more modest ventures can be financed out of income, bolder ventures frequently expect admittance to outer funding. These undertakings face expanded difficulties to get the money expected to connect the energy change. Essentially answering to changes in the commercial center dangers being past the point of no return and an powerlessness to contribute quickly enough to keep a going concern. The key test is to put resources into productive ventures lined up with society's rising spotlight on ecological, social and administration (ESG) objectives.

Healing a fractured business model:

Please, get rid of transfer pricing. Whether a firm operates a basic oil refinery or the most highly integrated refinery and petrochemicals complex, entitlements are pervasive in the form of transfer pricing between internal lines of business. These can be west-side vs east-side, conversion units vs others, and refinery vs aromatics vs olefins, to name a few. As the industry looks to drive efficiencies via connected and digital, we learn more about the inefficiencies associated with such entitlements. Connected and digital themselves do not fix inefficient business models. As China has been the world leader in integrated R&P complexes, it drives step-change higher efficiency in the ‘Chairman’s Model’, in which each internal business is driven towards the same goal: the best overall profitability of the firm, not just their domain.

Any digital or connected approach will simply mirror the inefficiencies of a fractured business model. Several major firms are realizing this fundamental inefficiency and have started their journey to improvement – leadership structures are being modified, incentives are being realigned, and benefits are being realized. The first step in creating a future-forward refinery is to ensure the organizational structure reflects an integrated business model approach. When we consider decarbonization and driving efficiencies, it is imperative to consider the whole operation.

Efficient integration with molecular precision:

As we look at ways to increase a plant’s efficiency, we start at the macro level, but very quickly dig deeper into what is happening at the most micro level. It is no longer good enough to talk about boiling ranges of feedstocks or even individual carbon numbers. Strategies for molecule management have matured to one of true molecular precision. Latest technology advancements manage operating efficiency at the level of individual isomers as we drive to minimize the work intensity for each component. As engineers and chemists, we can take almost any molecule and convert it into almost any other molecule. But certain molecules want to be certain things. For example, by exerting energy (work) and capital, we can convert propane all the way to BTX. But what should we convert it into? The answer is: the thing that creates the highest value with the least amount of work and capital. To do that, we need to integrate efficiently across the entire enterprise. Less efficient operations are systematically losing their right to participate in future markets.

How to measure efficiency?:

There are total six different efficiency metrics. The main metric is CAPITAL, which is surrounded by five other metrics like Carbon, Hydrogen, Utilities, Emissions and Water. Whether a firm or an investor is focused on financial or ESG measures, doing this well, aligned with each firm’s goals, is critical in securing access to the cash required to realize their vision.

With carbon, we want to put the right molecules in the right place. This can be the right process unit or separating the right product pool. With hydrogen, we want to optimize the sources and uses – put it on to do good things, take it off to do good things, and do that as few times as possible. With utilities, we want to do more with less and minimize utility usage. When we are successful with utilities, emissions also come down. But emissions can also be favorably reduced when we employ the proper molecular management and drive towards smaller equipment to carry out the objectives.

Water is critical. We want to treat water as a scarce resource because it is. There is a growing competition for water between civil, social, societal, agricultural, and other industrial uses. We need to minimize new water consumption and strive for zero water discharge.

Finally, it must be noted that the approach to securing capital has shifted dramatically over the past few years. Large banks have shifted their lending profiles towards green projects. Financial portfolio management is extending beyond traditional measures, such as net present value (NPV), internal rate of return (IRR), and debt service coverage ratio (DSCR), and increasingly focusing on sustainability measures, such as CO2 per tonne of product and CO2 per dollar invested. Boards of directors are also driving this proliferation. As this communication cascades down organizations, project managers at the individual site level are increasingly asking us to help them achieve the financial measures, but also the ESG measures.

Scope 1, 2 and 3 emissions:

Scope 1 emissions, commonly known as direct emissions, are produced as part of day-to-day business. These include emissions exiting process units and heater stacks, emissions from on-site generation of utilities, fugitive emissions from flanges and valves, and company vehicle emissions.

Scope 2 emissions frequently are referred to as indirect emissions. These are associated with the generation of energy needed to run a facility that is produced by and purchased from someone else.

Scope 3 emissions arise primarily from the ultimate combustion of fuels that a refinery produces and sells. Scope 3 also includes emissions associated with disposing of waste streams and emissions generated when others fabricate, manufacture, and deliver such things as catalyst, specialty equipment, vessels, exchangers, and pumps on the facility’s behalf. Scope 3 encompasses everything upstream and downstream of the facility, making this the largest component of its carbon footprint.

There are several ways an existing enterprise can reduce emissions. These range from low-cost tactical ‘just go do’ activities to the most strategic shifts, such as pivoting from fuel to petrochemicals production.

No- or low-cost solutions include reducing slops reprocessing, reducing or eliminating flaring, and avoiding over-refluxing columns. These can often be solved through visualization tools to quantify processes and understand how to get the most out of their assets every day, across every shift.

At a slightly higher cost, operators can consider using higher activity catalysts. These reduce reactor temperatures, leading to a reduction in the amount of fuel used and a subsequent reduction in the CO2 footprint. Operators can optimize pump efficiencies by properly sizing impellers and control valves or improving the compressor anti-surge control system hardware, software, and programming.

Moderate- to high-cost options might include adding to the heat exchanger network, optimizing hydrogen and electrification networks, monitoring and mitigating fugitive emissions, and replacing exchangers with higher efficiency systems.

When we engage with the customer to start this journey, we start with a Concept Development Workshop – effectively a voice-of-the-customer exercise where we align our listening skill set to understand where the firm wants to transition or improve across time. It helps us identify the right ideas to assess. Then, working with the current value of carbon in the global region, we create a carbon abatement curve for the customer, in which carbon reduction opportunities and their CO2 impact are paired with the cost per tonne of CO2 reduced. This provides a roadmap through which a firm can plan its journey.

Cost of hydrogen production drives regional technology selections:

The cost to produce hydrogen varies from region to region around the globe and has a profound impact on the types of technologies employed and market participation. For example, the cost of hydrogen in China out of a steam methane reformer (SMR) is approximately $2,000/t compared to $750/t in the Middle East. As a result, China drives crude oil to aromatics projects; when they search for olefins projects, they end up importing propane (effectively as a hydrogen source) to feed their propane dehydrogenation units.

Lower energy prices result in a cost advantage for producing light olefins in the US, the Middle East, and places that have a similar cost structure, while places that have a high hydrogen cost structure (China, SEA, India) are looking more towards aromatics production and/or imported feedstocks.

How does this impact the ways in which we try to improve carbon efficiencies and operations costs? It means there is a huge argument for capturing the hydrogen that refiners have already made.

Capturing stray hydrogen:

A survey of operating sites showed that many facilities operate in the range of 30-50 mol% H2 in their fuel gas headers; some even higher. This is due in large part to solution losses. The higher the operating pressure of a unit, such as a hydrocracker, the higher the solution and purge losses into the fuel gas. If one assumes 30 mol% H2 in the fuel gas in a region with a (low) cost of $5 per million BTUs with no CO2 credit, you can see that hydrogen recovery can lead to a 12% IRR). If the hydrogen content in the fuel gas is 50 mol% at the same cost of $5, you see an IRR of 26% by recovering this grey hydrogen that is otherwise lost to fuel.

When you move to Europe and Asia, where you typically see fuel costs closer to $20 per million BTUs, you start to see IRRs in the range of 69-73%, depending on the amount of CO2 credit available. In a typical 100K b/d refinery, the investment to recover the hydrogen you have already made is $15- $18M. The chemical value of the hydrogen so far exceeds the fuel value of the hydrogen. It is clearly worth recovering, given the IRRs previously discussed.

Reducing emissions through carbon capture:

Another way firms can reduce emissions is to implement carbon capture, sequestration, and utilization. To address CO2 capture, Honeywell UOP offers an Advanced Solvent for Carbon Capture (ASCC) system.

An advanced solvent allows for a higher mass transfer rate, which enables regeneration at a higher pressure, delivering CO2 at 5-6 bar(g) instead of just 1 bar(g). As a result, the unit is smaller for lower Capex, while the higher pressure substantially reduces Opex – up to $10-15 per tonne captured.

Adding an advanced solvent for carbon capture to the four key stacks in a refinery that produce 93% of the CO2 emissions for the entire complex, we were able to reduce net CO2 by 81%. The economics behind CCUS are dramatically impacted by government policy. It is important to understand the regional tax benefits, carbon credits, and traded carbon market values associated with carbon capture.

Another way to improve the CO2 footprint for many refiners is to bury the petroleum coke (petcoke) produced rather than reselling it as a high-carbon fuel. Petcoke traditionally competes with coal in the fuel market. In a decarbonizing world, governments will set coal policy. Refiners can only impact what they control, and that is the decision of whether to sell petcoke as a fuel, or to sequester that carbon in solid form. This avoids the high Scope 3 CO2 footprint created when the eventual end user burns it and has a net cost of CO2 avoidance of $10-40 per tonne.

Pivoting from refined fuel products toward petrochemicals:

Finally, an effective strategy to increase the internal rate of return of a facility and reduce Scope 3 emissions is to consider a pivot from refined fuel products toward petrochemicals. It is not a question of immediately and forever getting out of fuels; it is simply considering a migration across time that may align with the business plan of your firm.

The production of petrochemicals centres around the mixed feed steam cracker, or naphtha cracker, commonly the heart of an integrated facility’s operation. One can feed a broad range of hydrocarbons into a steam cracker, with the preferred output being ethylene. All other products, while useful, are not the primary aim of this process. In fact, while heavier products (propylene, butadiene, benzene, and mixed aromatics) have some potentially attractive market value, there are much more efficient and clean ways of achieving those particular products. Recall the discussion on molecular precision and management. The least useful products, fuel gas and pyrolysis oil (pyoil), are generally to be avoided.

Conclusion:

Today’s refiners can achieve bankable, ESG-aligned goals by managing feedstocks to meet their target product objectives. As an industry, we must start thinking and acting differently to survive in a decarbonising world across the energy transition. Through efficient use of molecular precision across an entire integrated refining and petrochemical operation, leveraging the economic value of CO2, operating firms can create the best roadmap to meet their changing objectives and become the refinery of the future today.