Energy & Fuels 2007, 21, 1195-1196
1195
Direct Heating in Oil Refineries Using Gas Turbine Exhaust David McKeagan* Department of Chemical Engineering, McGill UniVersity, 364 Alexandria, St.-Lambert, Quebec J4R 1Z2, Canada ReceiVed NoVember 6, 2006. ReVised Manuscript ReceiVed January 24, 2007 Oil refineries enjoy important opportunities for the integration of gas turbines into their overall energy balance because turbine exhaust gases are at temperatures typically required for process heating. Large quantities of electrical power can be extracted before heat from the gas is used in the refining process. In this paper, we look at a proposed 300 000 barrels per day bitumen upgrader supplied internally with its 540 MW requirement of electric power and show how the atmospheric and vacuum distillation sections could be heated with waste heat from two gas turbines. A third gas turbine would provide its waste heat to superheat byproduct steam from the rest of the upgrader to produce a total of 1190 MW of electrical power. The three gas turbines would emit about 4.7 megatonnes of CO2 per year. With the bitumen upgrader proposal, the coal-fired steam generator and gas-fired process heaters for the distillation would produce 3.5 megatonnes per year of CO2. The extra 650 MW produced with the gas turbines could be sold into the grid and allow the shutdown of an equivalent in coal-fired power generation emitting about 8.0 megatonnes, a net saving of 3.3 megatonnes of CO2 per year. Gas turbines are reliable and can be readily turned up or down to meet process needs. They are used for peak management of power grids and as stand-alone generators in remote service. A number of refineries have installed gas turbines for power generation where the waste heat is used to generate steam for refinery consumption. Iaquaniello and Pietrogrande1 show how a gas turbine could be retrofitted to either a hot oil heater or a topping furnace to provide some of the convection heating directly and generate electricity with an attractive payback. What we propose is to completely replace the furnaces typically used for heating feed to refinery atmospheric and vacuum distillation with gas turbines. The specific example used in this paper is from the Alberta Department of Energy study of a bitumen upgrader that was published recently on their Web site. David Netzer outlines a preliminary process design for an integrated facility to upgrade tar sands bitumen for the production of transportation fuels and petrochemicals.2 A mixture of 100 000 bpsd of diluent naphtha combined with 300 000 bpsd of bitumen is preheated with steam and fed to a naphtha recovery fractionator. The tower bottom stream is further preheated with steam and a direct-fired heater and then fed to a diesel recovery fractionator. Long resid from this tower is subsequently heated in a direct-fired furnace and fed to a vacuum tower where gas oils and short resid are separated. A simplified sketch of this process is shown in Figure 1.3 * Author e-mail:
[email protected]. (1) Iaquaniello, G.; Pietrogrande, P. Gas Turbines in Cogeneration. In Encyclopedia of Chemical Processing and Design; McKetta, J. J., Ed.; M. Dekker: New York; Vol. 24, pp 267-280. (2) Netzer, D. Alberta Bitumen Processing Integration Study. http:// www.energy.gov.ab.ca/ (accessed March 2006).
Figure 1. Atmospheric and vacuum distillation train heated with steam and direct-fired furnaces. Table 1. Use of Energy Fed to Gas Turbines
natural gas firing turbine absorbed preheat V-102 feed E-104 heating preheat V-202 feed absorbed by E-107 E-103 heating steam generation and superheating
T-1
T-2
T-3
2364 694 500 470
2364 694
2364 694
410 140 461
893
165 1109
Table 2. Comparison of Utility Costs and Benefits ($/h)
steam fuel gas coal and coke electric power total
upgrader proposal
gas turbine alternative
$-10 650 -5460 -1725 43 200 25 365
$-11 620 -42 550 95 260 41 090
In the alternate scheme that we propose, exhaust from a natural-gas-fired gas turbine (T-1) would preheat feed to the diesel recovery fractionator, replacing furnace H-101; preheat (3) A more complete outline is shown in drawings AB-003 and -004, pp. 117-8 of Netzer’s report (ref 2).
10.1021/ef0605549 CCC: $37.00 © 2007 American Chemical Society Published on Web 03/06/2007
1196 Energy & Fuels, Vol. 21, No. 2, 2007
Communications Table 3. Comparison of Major Capital Cost Items (MM$ Installed) upgrader proposal power plant gas and steam turbines topping furnaces heat exchangers total
Figure 2. Atmospheric and vacuum distillation train heated with gas turbine exhaust.
the feed to the naphtha recovery fractionator, instead of highpressure steam in E-104; and generate 300# superheated steam. This scheme is outlined in Figure 2. As also shown in Figure 2, a second gas turbine (T-2) exhaust would replace the direct-fired heater for vacuum tower feed heating; heat the naphtha fractionator bottoms, replacing highpressure steam in E-107; produce 50# superheated steam for stripping; and generate 300# superheated steam. The third gas turbine (T-3) would superheat 1030# and 300# steam from the upgrader complex, replace low-pressure steam
gas turbine alternative
826 612 16 4 846
95 707
in naphtha fractionator preheater E-103, and generate 300# and 50# steam. Turbines were selected to ensure that all heat for feed to distillation not recovered from product recycling would come from turbine exhaust. Calculations assumed three CGE PG9351 gas turbines that together would produce 610 MW of electricity. Superheated steam recovered from the turbine exhaust would generate 650 MW of additional power. The overall energy efficiency is above 90%. Heat balances on the turbines are shown in Table 1 (figures are in MM BTU/h). An economic comparison of the principal variable cost items is shown in Table 2. This analysis is based on natural gas at $6/MM BTU; sub-bituminous coal, $18/ton; internally generated coke, $6/ton; electric power, $0.08/kW h; and steam related to the natural gas price by 1.1 for high pressure, 1.0 for medium pressure, and 0.9 for low pressure. The major capital items’ installed costs are shown in Table 3. This analysis shows that, for natural gas at $6/MM BTU, it is more economical to use the gas turbine approach. The two approaches break even at $8.73/MM BTU. This approach offers oil companies an opportunity to smooth over environmental concerns about increased refining activities and to financially benefit from carbon credit trading. In cooperation with power utilities, refiners can contribute to clean power production and increased system reliability through decentralization. EF0605549
