Elsevier

Fuel

Volume 117, Part B, 30 January 2014, Pages 1288-1297
Fuel

Simulation of the integration of a bitumen upgrading facility and an IGCC process with carbon capture

https://doi.org/10.1016/j.fuel.2013.06.045Get rights and content

Highlights

  • Integration of a bitumen upgrading process with an IGCC with acid gas removal.

  • Utility consumption and power generation in function of the extent of CO2 capture.

  • Production crude oil with process steam, power and hydrogen self-sufficiency.

Abstract

Hydrocracking and hydrotreating are bitumen upgrading technologies designed to enhance fuel quality by decreasing its density, viscosity, boiling point and heteroatom content via hydrogen addition. The aim of this study is to evaluate the feasibility of integrating slurry hydrocracking, trickle-bed hydrotreating and residue gasification using the Aspen HYSYS® simulation software. Close-coupling the bitumen upgrading facilities with gasification allows one to achieve a hydrogen and power self-sufficient upgrading facility with CO2 capture. Hydrocracker residue is first withdrawn from a 100,000 BPD Athabasca bitumen upgrading facility, characterized via ultimate analysis and then fed to a gasification unit where it produces hydrogen that is partially recycled to the hydrocracker and hydrotreaters and partially burned for power production in a high hydrogen combined cycle unit. The integrated design is simulated for a base case of 90% carbon capture utilizing a monoethanolamine (MEA) solvent, and compared to 65% and no carbon capture scenarios. The calculated net plant efficiency on a HHV basis is between 29% and 41%. The gasification of 320 tonne/h of carbonaceous fuel is required in order to obtain a process that is self-sufficient in hydrogen, power and heating requirements. For this system, co-feeding of petroleum coke is necessary in order to produce 983 MW of power and meet the steam demand of the purification units that keep the heteroatom content in the flue gas below environmental regulatory limits while capturing 7.88 million tonne of CO2 per year. The carbon emission rate is controlled in the simulation by varying the water–gas shift steam consumption and the lean amine circulation rate.

Introduction

The worldwide oil demand is on the rise and is predicted to climb from around 85–105 million barrels per day by 2030 [1]. Unconventional oil resources, i.e. extra heavy oil and bitumen, consist of around 6 trillion barrels which constitutes about 30% of world oil reserves [2], [3]. However, before refining, the unconventional oil requires upgrading via carbon rejection or hydrogen addition technologies due to their high heteroatom content, viscosity, boiling point and density. The simulation of a bitumen upgrading process operating with unit operations including a Canmet slurry hydrocracker and naphtha (b.p. 40–180 °C) hydrotreater, light gas oil (b.p. 180–360 °C) hydrotreater and heavy gas oil (b.p. 360–540 °C) hydrotreater was performed using Aspen HYSYS® in order to determine the hydrogen consumption of the facility, CO2 emitted, utility consumption and quality of synthetic crude oil (SCO) based on various operating parameters. The residue (b.p. 540+ °C) withdrawn from the slurry hydrocracker could be subsequently upgraded in a coker in order to produce more light oils, burned in cement kilns and boilers or charged in a gasification process for hydrogen production [4]. The upgrading simulation estimated a hydrogen requirement of 15,000 kg/h for the production of a high yield high quality SCO from 100,000 BPD of Athabasca bitumen [5]. In order to reduce the net hydrogen requirements, the hydrocracker residue can be integrated with a gasification facility.

Similar upgrading process combinations have been tested or contemplated industrially. The Long Lake integrated upgrading project operated by Nexen Inc. charges deasphalted bottoms (capacity of 72,000 BPD) in four Shell Gasification Process trains in order to ultimately produce the required hydrogen for their hydrocracking operation and for syngas fuel that can be utilized for steam-assisted gravity drainage (SAGD) or cogeneration (Cogen) operations [6], [7]. The North West Upgrading Inc. facility is an ongoing project that plans to combine the LC-Fining ebullating bed hydroprocessing technology and a heavy petroleum residue gasifier [8]. The Shell Pernis Refinery in Rotterdam, Netherlands (capacity of 400,000 BPD) also includes a gasification process in their plant in order to produce synthetic gas from heavy visbreaking residue or straight-run vacuum residue [9]. The bitumen upgrading and gasification process integration have additional potential benefits than solely alleviating the hydrogen demand of the hydrocracker and hydrotreaters and maximizing the SCO volumetric yield. The addition of acid gas removal technologies such as amine, Rectisol or Selexol for CO2 and H2S capture allow the overall process to reduce criteria for air contaminants and CO2 emissions. The inclusion of high hydrogen syngas gas turbines and steam turbines can also allow the plant to potentially achieve power and thermal self-sufficiency. In this study, the effect of 65% and 90% carbon capture cases has been evaluated relative to the integrated process operation without carbon capture and the amount of gasifier feed required to meet the upgrading process hydrogen demand is estimated for various hydrocracker residue conversions.

Section snippets

Process description and simulation

The overall process presented in Fig. 1 consists of the integrated Athabasca bitumen upgrading facility and the gasification process studied here. The upgrading section residue is fed to a gasifier in which carbon monoxide and hydrogen are produced forming a synthetic gas called syngas. The syngas is cleaned and cooled prior to the removal of sulfur species. The sweet syngas is then passed through water–gas shift reactors in which carbon monoxide and water react to produce hydrogen and carbon

Discussion

The entrained flow slagging gasifier is assumed to reach chemical equilibrium at an operating temperature of 1427 °C [14]. Therefore, the important parameters that impact the gasifier operation are its isothermal temperature and the oxygen and steam feed rates. Fig. 5 presents case studies during which the hydrogen, carbon monoxide, carbon dioxide, methane and steam generation are monitored in function of various oxygen and steam to carbon ratio. Oxygen-to-carbon ratios should never exceed 0.5

Conclusion

A gasification process with carbon capture is simulated and integrated with a bitumen upgrading facility in order to obtain a hydrogen, power and energy self-sufficient operation. An entrained flow slagging gasifier is chosen for the gasification of the hydrocracker petroleum feed at an oxygen and steam to carbon molar ratio of 0.45 and 0.1. Only 34.8% of the hydrogen demand of the hydrocracker operating at a conversion of 91% and constant hydrodesulfurization and hydrodenitrogenation of 90%

Acknowledgements

I would like to thank Mr. David McCalden and Dr. Dennis Lu at CanmetENERGY Ottawa as well as Edward Little, Dr. Jinwen Chen and Dr. Mugurel Munteanu at CanmetENERGY Devon for their valuable technical input. I also want to recognize the thoughts and contributions of Dr. Theo de Bruijn. Finally, I would like express my gratitude for the financial support of the Natural Sciences and Engineering Research Council of Canada and Natural Resources Canada.

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