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Apr-2016

Novel processing ideas for a 
condensate refinery

Synergised unit flow schemes for a condensate refinery aim for high value refined products.

DONALD EIZENGA, DAVID SHECTERLE and FRANK ZHU
UOP, a Honeywell Company

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Article Summary

Recent increases in hydraulic fracturing operations have produced a significant amount of condensate liquids, particularly in the US. Conversion of these light liquids into finished products for sale at maximum value is being considered via new units or expansion of existing facilities. The quality of many condensates is such that minimal hydrotreating is required, but significant upgrading of the paraffinic naphtha is required to meet gasoline specifications. A condensate refinery is therefore expected to include reforming and isomerisation of naphtha along with naphtha and diesel hydrotreating. In this article, novel synergised unit flowscheme solutions will be discussed, which consists of three key ideas.

Idea 1
The goal of the alternate condensate fractionation unit (CFU) design was to reduce equipment count and save capital and/or to reduce energy consumption for opex savings, especially when upstream of combined naphtha and diesel hydrotreating (CHT). Typically naphtha and diesel are rigorously separated in the CFU, but they would need to be combined and then re-separated for a CHT unit approach, resulting in redundant fractionation. Innovative designs were considered to overcome the penalty of redundant fractionation. Options to either eliminate a column or to adjust the column operating conditions and draws were considered. Energy benefits were found by optimisation of the columns, and capital cost savings were identified. The energy benefits were not sufficient to overcome the cost of redundant fractionation with a combined hydrotreating approach. The lowest operating costs were achieved when the hydrotreating units are individually optimised and a three-column CFU design is employed, while alternate approaches may provide modest capital cost benefits.

Idea 2
The goal of the combined hydrotreating design was to minimise equipment count and thereby optimise the refinery economics. In the final analysis, the combination of naphtha and diesel in a single hydrotreating unit was found to have limited economic justification. Cost penalties were associated 
with reactor section pressure, catalyst volumes, and redundant fractionation of naphtha. Efficient combinations of shared auxiliary systems and novel combinations were proposed so that each unit could be individually optimised.
   
Idea 3
UOP explored novel solutions for using isomerisation with the UOP Platforming process to determine an economic optimum configuration for gasoline production in the proposed design. A number of options and synergies were evaluated to reduce capital costs and operating costs. Significant capital cost savings were achieved using innovative naphtha complex schemes relative to the base case separated unit configuration. A higher yield case was found to have highest net present value (NPV), while a lower capital approach was evaluated, which may make sense when a customer is severely capital constrained.

The market seeks the technology with minimal capital investment as installation in remote locations could be a significant factor. UOP proposes to handle these issues with construction of modular units, which have been optimised for capital and operating expenses in consideration of the feed properties and product quality targets.

While the various technologies used for hydraulic fracturing of shale to produce natural gas have developed over the last 40 years, the rapidly escalating energy prices through 2014 led to a boom in use of the technology, particularly in the United States. Technology advances significantly reduced the cost for obtaining gas and light condensate oils, which has sustained some production even as crude prices have fallen in 2015. Projections suggest that extraction of such liquids may increase further and they will likely be processed for many years to come. US shale deposits are distributed over a wide range of the country in a number of formations (see Figure 1).

In the process of extracting gas from the wells, condensates and natural gas liquids (NGLs) are also extracted. These liquids include a full range of hydrocarbon constituents from propane to heavy residues that boil at and above 1000°F (540°C). The liquids are therefore similar to other petroleum crudes, but are lighter and generally sweet. For example, crudes are often differentiated by API gravity, with heavy crudes averaging ~15° API, medium at ~25° API, light at ~35° API, and extra light at ~45° API. Condensates average 55° API, but there is a wide range of compositions depending on the source, and the composition may change as the field matures.

The question for gas producers, midstream companies, and refiners is how best to process these liquids. Certainly, adjustment to refinery operation is required, and possibly revamp of existing equipment and/or addition of new process units (for instance, via a modular expansion). Alternatively, new processing facilities could be developed for local markets, which may be placed near the feed sources in remote locations.

Condensate properties
In order to understand how best to process condensate liquids, a good understanding of the properties is required. One key attractive property in the current market environment is that they are relatively low cost and sold at a discount to crudes, in part owing to the major recent increases in fracking. The other key attractive property is that they are light liquids, which makes them ideal for refining into higher margin gasoline and diesel products. Recent estimates have predicted dramatic growth and sustained high levels of production of condensate; however, this has been impacted by the high volatility in crude oil market pricing. Legislation on the sale of ‘crude oil’ and lightly processed condensates from the US is also having further impacts, and in 2015 the US began trading light crude oil for heavy Mexican crudes to the mutual advantage of refiners in both countries.

Condensates may contain up to 10% LPG, and are typically high in both light and heavy naphtha. In fact, a survey of over 100 worldwide condensates showed that LPG + light naphtha + heavy naphtha ranged from 30% up to over 90%, with a median near 60%. The remaining material is mostly in the distillate range, suitable for jet fuel and/or diesel fuel with appropriate processing. Condensates are mostly quite low in the heavy residue range (boiling above 685°F, 360°C).

For the study, a ‘light case’ and ‘heavy case’ feed were considered for a 25000 b/d condensate refinery (see Table 1). The API gravity was 59.4 for the light case and 52.0 for the heavy case. Sulphur was low at 20-30 ppm compared with levels of up to 2% in more contaminated condensates and conventional crudes. Target products for the study included off-gas, which could be used as fuel gas for the complex, LPG, gasoline (or blending component) with an octane target of 87, ultra-low sulphur diesel, and a low sulphur residue (for refinery FCC or hydrocracking feedstock or fuel oil).

Ideas for condensate processing
For the base case of the study, a small hydroskimming style condensate refinery was proposed (see Figure 2). The objective of the study was to analyse opportunities that might optimise the overall complex. The original premise of the study was that reduction of equipment count and minimisation of capital would be the most important objective. Three parts of the study will be summarised:
Idea 1. Efficient CFU design
Idea 2. Combined hydrotreating design
Idea 3. Innovative naphtha complex schemes.


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