The journey to sustainable profitability: How to benchmark the efficiency of your investment

K. COUCH, M. GRIFFITHS, J. RITCHIE and P. SRIVASTAVA, Honeywell UOP, Des Plaines, Illinois

Because it provides the energy and materials required for global development, the refining industry is critical to the world economy. At the same time, refiners are under pressure from shareholders, boards, institutional investors and their own management to chart a path for sustained growth and prosperity.

Refinery and petrochemical investments are capital intensive and require careful long-term planning. They must deliver a strong return on investment (ROI) and advance socially and environmentally responsible investment goals.

To develop the most efficient and bankable projects, the authors’ company has identified six critical performance factors to evaluate an investment in a standalone refinery, or one integrated with petrochemicals. This six efficiencies framework^a (FIG. 1) considers carbon, hydrogen, utilities, emissions, water as a scarce resource and capital.

This framework measures how an investment compares to best-in-class benchmarks. It differs from other industry metrics by measuring an investment against the latest technologies available. These benchmarks change annually due to technological innovation, continuously classifying competitiveness against emerging technologies and identifying new opportunities. This model is a planning tool that provides insight into an investment’s profitability, social and environmental impact, and timing.

Quantifying the six critical efficiencies. The model may include a grassroots or brownfield downstream complex, producing fuels or petrochemicals, and is valid for a range of available crudes. This article introduces a methodology for a whole complex, or just individual process technologies, but not the full lifecycle analysis of the net products.

The benchmark for each of the six categories is based on fully optimized configurations for the latest technologies available.¹ Each category is measured and compared to a benchmark configuration with similar objectives, crude quality and product slate.

The framework’s methodology identifies strategies to improve the design and the performance of new and existing complexes, “futureproofing” with best-in-class configuration and infrastructure.

Carbon efficiency. The objective for any complex is to maximize the transformation of carbon into high-value products, directing the right molecules to the right processes, and minimize the work to convert to high-value products.

The effectiveness of the conversion of carbon is determined by the carbon metric for the configuration.^2,3,4 The reference line in FIG. 2 represents benchmark carbon metric performance across the continuum, from fuels to maximum petrochemicals, for an Arabian light crude. Note: the benchmark line never fully achieves 100% petrochemicals. Crude barrels to the complex—not net products—are the basis for the measurement,⁴ accounting for losses such as petroleum coke, fuel gas, sulfur and other lesser contributors.

Comparing the carbon metric for the configuration against the benchmark configuration produces a measurement of carbon efficiency, defined by Eq. 1:

Carbon efficiency, % = 100 * configuration carbon metric/benchmark configuration carbon metric           (Eq. 1)

A carbon metric below the line signals sub-optimized performance with an efficiency of less than 100%. This may indicate the need to re-optimize the configuration or review business objectives as they relate to carbon.

Factors influencing the carbon metric include the quantity of petrochemicals produced, the crude slate and the complexity of the configuration. An optimized configuration restricts carbon rejection technologies and applies more selective technologies, improving molecule management and carbon, hydrogen and capital efficiency.

Hydrogen efficiency. Hydrogen efficiency is highest when hydrogen is used as sparingly as possible to transform molecules into a desired product. Hydrogen is produced from crude as a byproduct of catalytic reforming, steam cracking and propane dehydrogenation. The major consumers of hydrogen are hydrotreating and hydrocracking units. Hydrogen efficiency is improved by reducing the need for external hydrogen, while poor hydrogen management results in waste.

Hydrogen efficiency is calculated directly—rather than by comparison to a benchmark^4,5—using Eq. 2:

Hydrogen efficiency, % = 100 × hydrogen in saleable products/(hydrogen in the feed + hydrogen from the hydrogen plant)                (Eq. 2)

The line in FIG. 3 is an example of hydrogen consumption across the continuum, from fuels to maximum petrochemicals, for an Arabian light crude. A significant amount of hydrogen is required to produce petrochemicals. Efficient recovery of hydrogen from dehydrogenation reactions reduces hydrogen plant size. For example, sending propane to a dehydrogenation unit produces more olefins and less fuel gas than a steam cracker. If co-production of aromatics is desired, hydrogen must be removed. Therefore, an optimal solution will balance hydrogen addition and removal to produce the ideal combination of olefins and aromatics while minimizing hydrogenation and dehydrogenation cycles. Ultimately, hydrogen efficiency is a factor of crude quality, the heavy oil upgrading strategy and the level of petrochemical production. Hydrogen addition lowers this efficiency, while carbon rejection improves it.

Utilities efficiency. The goal is to use as little energy as possible for feedstock conversion. Utilities efficiency determines the energy demand impact of fuel selection, utility system design, crude quality, facility complexity and the level of petrochemical production. Total energy use is the sum of all utilities.

Process energy consumption typically represents 30%–40% of the operating cost of a best-in-class complex design. In the authors’ company’s framework, utilities are measured in terms of their equivalent consumption of methane, so the objective is to reduce this consumption to lower resource use and operating costs.

The amount of energy consumed by a complex is quantified by the utilities metric.^4,6 The reference line in FIG. 4 shows benchmark performance across the spectrum, from fuels to maximum petrochemicals, for an Arabian light crude using a higher efficiency combined-cycle gas turbine power plant. All the power requirements are provided by a natural gas-fueled turbine generator.

Utilities efficiency measures how effectively the configuration uses energy by comparing it against benchmark performance, calculated using Eq 3:

Utilities efficiency, % = 100 * benchmark configuration utilities metric/configuration utilities metric              (Eq. 3)

Note: Since the category is one where minimization of the configuration metric is desirable, dividing the benchmark value by the configuration value yields a result that increases with improved efficiency.

To minimize the consumption of utilities, the process unit utility requirements and the utility system design must be viewed as a single integrated network.

Emissions efficiency. Emissions efficiency measures greenhouse gas (GHG) emissions with the goal of lowering the carbon dioxide (CO₂) footprint. The model accounts for CO₂ from combustion emissions and as a reaction byproduct. The emissions metric quantifies the CO₂ emitted by a complex.^4,7 The reference line in FIG. 5 is based on an Arabian light crude and represents the benchmark performance across the range of fuels to maximum petrochemicals.

Emissions efficiency measures the reduction of CO₂ and is determined in the same way as utilities efficiency. It accounts for fuel selection, crude quality, complexity of the facility and the level of petrochemical production. The selection of fuel for the utility system is critical. For example, lower heating-value coal will decrease emissions efficiency due to higher emissions relative to the benchmark that uses natural gas. Greater utilities efficiency will improve emissions efficiency.

Water efficiency. Many new projects treat water as a scarce resource, so the framework’s methodology aims for zero discharge. The production of fuels and petrochemicals requires a significant amount of water for heat addition by steam, heat removal by cooling water and hydrogen generation. The objective is to use water sustainably and minimize freshwater makeup.

The water metric measures water consumption.⁴ The reference line in FIG. 6 represents typical performance across the range, from fuels to maximum petrochemicals, for an Arabian light crude. Water efficiency is determined the same way as utilities and emissions (i.e., comparing the use of the primary water source to typical performance). The benchmark line is based on a standard evaporative circulating cooling water system. The use of air-cooled exchangers rather than cooling water exchangers or a closed circulating cooling water system using seawater are possible solutions to reduce water loss. The framework’s methodology adjusts to establish the water metric benchmark specific to crude quality, configuration complexity and the level of petrochemicals being produced.

Capital efficiency. Carbon, hydrogen, utilities, emissions and water are balanced against capital efficiency—the first five determining the sixth. All six criteria may assist or contend with each other, but all can be used to balance the facility’s operational goals with market demand, regulatory restrictions and other factors to develop a bankable project.

Each of the first five efficiencies are essential factors for driving the internal rate of return (IRR), which is a measure of capital efficiency. An increase in one of the five efficiencies may improve or reduce the IRR, so understanding the trade-offs helps a refiner balance the impact of many individual objectives to enable better project decisions.

Within the authors’ company’s model, the IRR is based on standard economic inputs (price, capital and regional impact). The model benchmarks technology-based performance, independent of project-specific execution models and regional variable cost components. As a project moves towards a final investment decision (FID), capital efficiency is used to help a refiner better understand and manage its competitive position in the market.

USE THE FRAMEWORK^a TO DRIVE EFFICIENCY IMPROVEMENTS AND OPTIMIZE ECONOMICS

This section includes a commercial project example where the authors’ company’s framework identified a solution that improved the economics of a customer’s plant configuration. This analysis considered the application of technologies, stream routing and inter/intra technology molecule management. An LP model matched the base case configuration material balance to analyze improvements and establish performance within the framework.

Commercial example. As summarized in TABLE 1, the customer asked if it was possible to increase the profitably of the base configuration and simultaneously increase production of petrochemicals from a deeply integrated configuration. The following modifications demonstrate examples of the molecular management practices needed to develop an optimized configuration:

1. Routed steam cracker pyrolysis gasoline to the aromatics complex: Gasoline production was reduced, paraxylene (PX) production was maintained and surplus naphtha was redirected to the steam cracker to increase olefin production.
2. Added a vacuum gasoil (VGO) hydrocracker and eliminated the VGO hydrotreater and high propylene fluidized catalytic cracking unit (FCCU). FCC coke production decreased by 31%, making additional material available for olefins production. Capital cost and complexity were reduced, as well.
3. Routed C₄/C₅ olefins from the steam cracker and remaining FCC gasoline to the olefins cracking process (OCP) for light olefins production. This avoided C₄/C₅ stream hydrotreatment and recycle back to the steam cracker, minimized hydrogen addition/removal cycles and backfilled freed steam cracker capacity with naphtha. Additional net olefins were produced from the OCP, which is more efficient in converting the C₄ and C₅ olefins to propylene and ethylene. Deeper integration into petrochemicals inherently results in the production of more fuel gas. In this case, improved steam cracker feed and more selective conversion in the OCP minimized the increase in fuel gas production.

The optimized configuration is shown in FIG. 7. The proposed configuration increased petrochemicals production from 60 wt% to 68 wt%, while fuels production fell from 21 wt% to 13 wt% on crude and other raw materials. TABLE 2 summarizes carbon, hydrogen, utilities, emissions, water and capital in terms of the framework.

Strategies adopted for improving efficiencies include:

1. Carbon: A reduction in FCC capacity and optimal routing of olefins streams to the OCP; better management of molecules between the steam cracker and the aromatics complex.
2. Hydrogen: The removal of the VGO hydrotreater, a reduction of steam cracker recycle hydrotreater capacity and the elimination of high-severity FCC , reducing hydrogen loss in FCC coke.
3. Utilities: Increasing petrochemicals production requires more energy consumption; however, the optimized configuration improved utilities efficiency despite this higher petrochemicals production.
4. Emissions: Coal as a fuel source lowers emissions efficiency. More efficient use of energy increases emissions efficiency.
5. Water: The reduction in FCC capacity reduced reactor system requirements, reduced steam for driving the wet gas compressor and main air blower turbines, reduced cooling water, reduced boiler feed water by 3,520 tpy and cooling water load by 1,340 MMm³/yr, thus avoiding 27 MMm³/yr in water losses.

Capital efficiency aggregates the preceding five efficiencies. The impact of these gains was visible in capital efficiency improvement. Increasing the production of petrochemicals at better efficiencies strengthened the profitability of the project. With only a 1% capital cost increase, the modifications grew net cash margins by $6/bbl or $890 MM/yr. The IRR increased from 24% to 25.8%, and NPV grew by $5.2 B (FIG. 8 and TABLE 3).

Takeaway. The authors’ company’s framework^a is a future-forward decision-making methodology that provides a data-driven approach to more profitable performance and growth. The methodology shows how a new or existing facility compares to the latest technology benchmark for each of the constrained resources. The framework’s methodology aligns a firm’s needs, wants and budget to identify a strategy to improve the performance of new or existing assets. HP

NOTES

^a Honeywell UOP’s E6 Framework

1. The optimization of configurations was performed utilizing Aspen PIMS Linear Programming (LP) planning software.
2. Configuration carbon metric, % = 100 * carbon in high-value products/carbon in the feed.
3. High-value products do not include materials that are combusted within the complex for energy (e.g., FCC coke or fuel gas), and they do not include low-value byproducts, such as coke from the delayed coking unit.
4. The feed to the complex includes crude oil and any other raw materials converted to products (e.g., methanol, vacuum gasoil), but excludes any raw materials combusted as a fuel (e.g., purchased natural gas, crude oil as fuel).
5. Saleable products do not include materials that are combusted within the complex for energy (e.g., FCC coke or fuel gas).
6. The utility requirements for each individual unit are combined into a total requirement for each utility (net usage of electrical power, steam and fuel gas, among others). Each total utility consumption is converted to an equivalent methane requirement. This conversion step is included in the LP model scope, and the amount of equivalent methane consumption is provided as an output.
7. CO₂ emissions include process releases (e.g., hydrogen plant byproduct) and combustion emissions. Combustion emissions are determined from the total utility needs converted to an equivalent methane consumption requirement (reference note 6)