Adapt, survive and thrive: IMO 2020

By Mark Cudmore, Wood plc

To prepare for IMO 2020, adaptations being made by oil refineries, including configuration, debottlenecking and rapid, low-cost preparation
To prepare for IMO 2020, adaptations being made by oil refineries, including configuration, debottlenecking and rapid, low-cost preparation (photo: Wood plc)

IMO 2020 is just around the corner. The updated emissions regulations mean that maritime vessels need to slash sulphur emissions by 1st January 2020. Announced only three years ago, the deadline for the change is now looming large.

There has been much wrangling in oil products circles since the International Maritime Organisation (IMO) announced the change in late 2016. To ensure compliance, the marine sector will have to reduce sulphur emissions from 3.5 weight per cent (wt%) to 0.5 wt%.

At the time, research stated that by 2020 there would be enough compliant fuel to supply the global fleet. Latest figures suggest this may now be a challenge.

One of the primary assumptions behind this forecast was that by the end of 2019, just under 4,000 scrubbers, systems designed to remove sulphur from vessel emissions, would be installed across the world’s vessels. Although initially deemed an obvious solution, many organisations have resisted scrubber installation due to the capital investment required and the cost of taking ships to dry dock while this work is completed. By the end of May 2018, it was thought that less than 1,000 units had been installed which is significantly behind schedule.

So now, as the deadline for change approaches, with just months until enforcement, the focus has shifted towards the supply chain to come up with the solutions.

In this paper we discuss the current state of the market, the adaptations being made by oil refineries, including configuration, debottlenecking and rapid, low-cost preparation.

Where does that leave the refining industry?
With limited time left, and with potentially huge investment required in order to modify its product qualities, the industry has found itself at a crossroads in terms of what comes next.

The onus is now firmly on refiners to evolve their outputs to low sulphur fuels; however, with no convergence on how the industry is to adapt, the risk for any investment is still deemed to be very high. High-sulphur fuel oil has traditionally been used by the shipping industry as bunker fuel. It has become a convenient way high-sulphur material, often residues from the production of higher value products, can be cost effectively sold by refineries. In 2017, global demand for high-sulphur fuel oil stood at over 70% of overall bunker fuels.

Shipping companies will also have to consider a switch to alternative fuels, such as Very Low Sulphur Fuel Oil (VLSFO) or marine gas oil (MGO), which are more complex to produce.

Refineries are now faced with how to adapt, survive and thrive in the new operating conditions. This likely means upgrading, reconfiguring or adapting their current operations, and there are three main ways in which they could choose to do this, in order of descending time and capital requirement:

1.         Reconfiguration

2.         Debottlenecking/Repurposing

3.         Rapid, low cost preparation

1. Major reconfiguration
A further complicating factor is the impact IMO 2020 will have on feed and product prices. For major projects, investors require a clear projection of likely future economics. Unfortunately, even at this late stage, predictions of the impact on pricing remain varied and highly uncertain. This leads to a wide range of scenarios to include in economic modelling and significant risk in relying on IMO 2020-specific price trends.

The most significant, targeted reconfigurations seen so far will cost billions of dollars and involved the construction of whole new complexes, including the installation of residue destruction and/or treatment technologies (see table 1).

Table 1. Comparison between residue upgrading technologies.
Table 1. Comparison between residue upgrading technologies. (illustrations: Wood plc)

One might have expected that one technology, whether residue hydrocracking, residue hydrotreating, coking or RFCC, would have started to emerge as the front runner for an accepted view of IMO 2020 pricing. However, no clear trend has emerged. Drivers for choosing a reconfiguration option are still very much strategic and specific to each facility, as shown in Figure 1.

Figure 1. Major reconfiguration technology choice is based on a number of factors.
Figure 1. Major reconfiguration technology choice is based on a number of factors.

Strategic planning and positioning are crucial factors in making this decision. One key differentiator is focus on different product markets. For example, production of petrochemicals is favoured by RFCC technology whilst residue hydrocracking investment tends to rely on the market for diesel. Residue hydrotreating is even more specific to demand projections as this relies on a strong low sulphur bunker premium, and the time this will persist for.

Another important differentiator driving the decision is the company’s view on the availability of disposal routes for the remaining residue, which can vary from standard petroleum coke to high-metal content pitch depending on the technology.

The expected return on capital employed (ROCE) has underpinned configuration decisions, but this has been shown to be very close in many cases despite widely varying technology options.

The reality is that current “Bottom of the Barrel” upgrading projects have selected a variety of technology options globally. Cokers are still a popular choice for new investments, as well as new residue hydrocrackers and solvent deasphalting additions.

There remains a fundamental barrier to these options, which is the availability of time. In terms of major configuration projects, it has not been possible to build much of this upgrading capacity between the IMO’s announcement and 1st January 2020.

2. Debottlenecking
Medium scale projects have been a popular option for many refiners as a means to take advantage of the increased upgrading margin. For the purposes of this paper, these are classed as ranging in cost from USD 200 million to around USD 5 million (Figure 2). They provide a less risky option in terms of timescale too, realistically being implemented within two years from start-to-finish.

Figure 2. Debottlenecking in context.
Figure 2. Debottlenecking in context.

There are still opportunities to debottleneck existing units. Hydrotreating of high sulphur streams is a clear target of debottlenecking activities to take advantage of the wide low-high sulphur differential expected.

There can be economic benefits in penalising yields to enable throughput increase in the disrupted market environment.

In simple terms, this could mean that refiners end up revamping units or having flexibility to make more marine gas oil at the expense of diesel. Pushing more through the units could mean that companies might, for example, do more gas oil runs rather than diesel runs through hydrotreaters. If the shipping industry utilises diesel-range material to replace current high-sulphur bunkers, then the projected price difference between road diesel and marine gas oil could well reduce.

Low-cost debottlenecking of primary distillation, i.e. crude distillation, vacuum distillation, as well as sulphur treatment and amine, has been successful across many refineries already in support of debottlenecking hydrotreating or conversion units.

Repurposing has been shown to be a viable option too (see Figure 3). Existing or shutdown units such as visbreakers, thermal crackers and old lubricant hydrotreaters, for example, may be able to be used to successfully hydrotreat material.

Figure 3. Repurposing.
Figure 3. Repurposing.

Solvent deasphalting (SDA) units are also being added for comparatively moderate capital expenditure (see Figure 4). Simultaneously revamping the hydrocracker can help to reduce HSFO production by almost 50%, increase middle distillates yield and improve crude flexibility.

Solvent deasphalting (SDA) units are also being added for comparatively moderate capital expenditure (Figure 4). Simultaneously revamping the hydrocracker can help to reduce HSFO production by almost 50%, increase middle distillates yield and improve crude flexibility.

Figure 4. Mid Term Repurposing example: This example of a delayed coker (DCU) revamp project aimed to increase vacuum residue processing from 3.7 MMTA to 4.6 MMTA. Addition of an SDA resulted in far higher liquid yields versus the standard DCU throughput revamp.
Figure 4. Mid Term Repurposing example: This example of a delayed coker (DCU) revamp project aimed to increase vacuum residue processing from 3.7 MMTA to 4.6 MMTA. Addition of an SDA resulted in far higher liquid yields versus the standard DCU throughput revamp.

The combination of SDA and deasphalted oil hydrocracking, and thermal conversion, has a crucial advantage: it retains high levels of crude flexibility. This is becoming an increasingly important profitability driver for refiners. In turn, this creates an opportunity to further increase margins by including lower-priced, opportunity or niche crudes within a refinery’s portfolio.

The combination of SDA and deasphalted oil hydrocracking, and thermal conversion, has a crucial advantage: it retains high levels of crude flexibility. This is becoming an increasingly important profitability driver for refiners. In turn, this creates an opportunity to further increase margins by including lower-priced, opportunity or niche crudes within a refinery’s portfolio.

3. Low Cost Preparation
Refiners have also been preparing their existing operations. Notable examples so far include investment in flexibility in logistics such as blending, high pour or total acid number.

Leading companies had already implemented their preparations by the end of 2018 for the large market changes expected towards the end of 2019. There is still time as these measures can be implemented quickly once determined.

Market study input is required to provide a credible range of market scenarios to respond to. These scenarios must include both limitations on quantity and price changes and must also be specific to the individual refining asset and the available markets (Figure 5).

Figure 5. IMO 2020: Steps for robust planning.
Figure 5. IMO 2020: Steps for robust planning.

Studies to examine how to respond to the market changes have included the following, with the aim of optimising preparations across the scenarios:

  • New feeds including minor modifications and investigations for enabling new crudes.
  • New product grades.
  • Yield and operational changes including equipment rating and performance prediction.
  • Logistics flexibility including assessment of jetty and tank farm operations loading, repurposing and minor modifications.
  • Compatibility of new components in residues or crude mixtures.

Implementation of these measures may take the form of minor projects/MoCs, but also of critical importance is the preparedness of trading and marketing functions as well as refinery production planning. Updates to the planning tools such as Linear Programmes (LPs) will be required ahead of the market changes to enable refining economics to be optimised.

What’s next?
So far, the industry has been observed implementing a range of options, with each facility identifying its own future opportunities and aligning any investment accordingly.

As well as offering strong payback to any site, the short- and medium-term modifications and preparations have the potential to allow highly exposed and marginal refiners to stay in business past the initial disruptive period, allowing time for long-term strategic positioning.

What ties each approach together is the need for a firm grasp of risk in the market, particularly related to future price fluctuations of each product. It is this combined with the strategic flexibility to maximise opportunity and resilience in an environment of great uncertainty that will give refiners the best chance of survival once the new regulations come into force.

Mark Cudmore, Manager, Asset Consultancy at Wood plc
Mark Cudmore, Manager, Asset Consultancy at Wood plc