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HYDROCRACKING AND HYDROGEN PRODUCTION, PURIFICATION, AND RECOVERY (QUARTERLY ISSUES)
Publication date:3Q 2011
Hydrocracking and Hydrogen Production, Purification, and RecoveryHydrocracking
Hydrocracking (HC) is utilized in refineries to upgrade a variety of feeds that range from coker naphtha to various gas oils and residual fractions into lighter molecules that have higher average volatility and improved economic value. Hydrocracking works to improve the quality of the initial feedstock by removing N and S and increasing the hydrogen-to-carbon ratio. As the world economy continues to stabilize following a period of recovery from the widespread economic crisis that began in 2008, refiners have been forced to adjust operations to meet a number of emerging goals: increasing diesel production, processing heavy and highly contaminated crudes, and meeting stringent environmental emissions limitations and product specifications. The hydrocracking process has emerged as the primary diesel producer in many refinery configurations, and as environmental regulations on transportation fuels continue to tighten, the hydrocracker will be one of the tools available to refiners to meet new product specifications. Unlike FCCU processes, hydrocrackers can effectively yield ultra-low sulfur diesel (ULSD) streams whereas middle-distillate range FCC products will regularly require additional treating to meet product blending specifications.
Hydrocracking technologies typically range between two extreme operational regimes. On the low-conversion end (20-40%) is mild hydrocracking that typically converts VGO to ULSD and an upgraded FCCU feed. At the other end is conventional or high-pressure hydrocracking that can achieve near 100% conversion of many different feeds to ultra-clean distillates, naphtha, and lube oil base stocks. In between these extremes are moderate-pressure schemes that trade a small measure of conversion for reductions in capital expense and hydrogen consumption. Special configurations can be set up for multi-feed processing or for converting so-called difficult feeds (high endpoint, aromatics, and nitrogen) like LCO to distillates that meet current specifications. Also, there are schemes that decouple conversion and product quality, providing additional flexibility in operations and avoiding overcracking the distillate product.
In diesel oriented refineries, heavy oil and VGO will be hydrocracked to increase the yield of diesel range streams. Companies have turned to two-stage recycle (TSR) hydrocracking and reverse-staging configurations, which have advantages and disadvantages compared to other process schemes. Methods to operate at lower conversion per pass in order to increase middle distillate selectivity are also being addressed, in addition to advances in monitoring and control. Catalyst developments aim to improve HDS activity, reduce catalytic deactivation, increase diesel yield, reduce operating pressure, and extend cycle length.
With changing market dynamics and fuel consumption patterns that heavily favor the production/use of diesel over gasoline, process designers and catalyst manufacturers are feverishly developing cost-effective and energy-efficient hydrocracking technology and revamp options to satisfy the refining industry around the world. Also, refiners will begin to rely more heavily on hydroprocessing units to produce high-quality, high-value products. Finally, the utilization of hydrocracking technologies to upgrade resid and/or renewable feeds to produce additional supplies of high quality diesel has been covered extensively through commercial projects and R&D work over the past several years. Additionally, the hydrocracking section features the latest trends and technology offerings, including:
Hydrogen Production, Purification, and Recovery
Refinery hydrogen demand is increasing for two primary reasons: (1) the decreasing quality of the world's crude supply means more hydrogen is required to upgrade heavy material to lighter products and remove high levels of contaminants, and (2) the stricter regulations that have been enacted for transportation fuels, such as ultra-low sulfur requirements for diesel, require increased levels hydroprocessing. Refiners that are not equipped with adequate desulfurization capacity could face a similar situation to what Mediterranean refiners experienced during the Arab Spring, when light sweet crude supplies from Libya were essentially cut off. As a result of the supply disruption, these facilities were forced to scramble to find similar-quality feedstocks, driving up the costs for crudes from the North Sea and Nigeria, and pressuring down refining margins in the region.
In refineries, the major H2 consuming processes are hydrocracking, VGO hydrotreating, distillate hydrotreating, naphtha hydrotreating, aromatics saturation, and isomerization. Catalytic reforming is the major source of H2 with about 110 scf/bbl produced by semi-regenerative units and 1.7K scf/bbl coming from continuous catalyst regeneration units. In the US, however, H2 production from catalytic reformers will decline as a result of EPA legislation: beginning in 2011 benzene content in gasoline was cut from 0.97 vol% to 0.62 vol%. Additionally, the role of the naphtha reformer has been greatly diminished in light of a general shift away from gasoline production to diesel, particularly in Europe.
There are several options available to refiners for meeting growing H2 needs. Hydrogen can be obtained as a byproduct from naphtha catalytic reformers, purchased from third-party sources, or produced in on-purpose H2 facilities. The most common on-purpose hydrogen production technology is steam reforming, which can handle a variety of feedstocks including natural gas, LPG, naphtha, and various refinery offgas (ROG) streams. At present, 80% of refineries throughout the world use steam reforming of natural gas for H2 production while 15% use steam reforming of naphtha. The latter is preferred in countries, such as India, Japan, and South Korea, where a reliable supply of abundant and cheap natural gas is unavailable.
Other options include autothermal reforming (ATR) and gasification or partial oxidation (POX). Gasification uses high-purity oxygen (O2) and has a high operating cost despite the fact that it can process low-value, bottom-of-the-barrel feeds. Nevertheless, gasification provides several additional intrinsic advantages in terms of cogeneration strategies and the potential to apply CO2 capture and sequestration (CCS) technology. A final production option, not yet commercially established, is the use of reactor membranes to increase H2 production while also lower energy consumption. Hydrogen can also be recovered from ROG streams within the refinery as a low cost option to increase H2 supplies. Those streams exiting naphtha catalytic reformers, high-pressure hydroprocessing units, toluene hydrodealkylation units, and fluid catalytic cracking (FCC) units consist of 10-95% H2.
Because steam methane reforming is considered to be a mature technology, process designers and catalyst manufacturers are working to improve energy efficiency on the unit while also utilizing skid mounted and/or compact designs to lower unit fabrication and installation costs. Finally, the utilization of renewable feeds to yield hydrogen from reformers has been covered extensively through R&D work over the past several years. Additionally, the hydrogen section features the latest trends and technology offerings, including:
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