Liquefaction co-processing of coal shale oil at - Argonne National ...
Liquefaction co-processing of coal shale oil at - Argonne National ... Liquefaction co-processing of coal shale oil at - Argonne National ...
cost of coal liquefaction, the high recycle oil requirements. In all direct liquefaction processes coal is slurried with a process derived recycle oil at a mica1 ratio of 2:l recycle oil to coal feed. Coprocessing of residuum and coal reduces the high cost associated with recycle oil by eliminating or reducing the requirements for recycle oil. Coprocessing hydrocracking technology was originally developed for processing heavy crude with coal additives as a means of inhibiting the formation of coke. The CANMET hydrocracking process is based upon this comcept. This emerging technology shows promise of I]iqh demetallization, residuum hydrocracking, and high conversion of the pitch (975 F ) fraction. Coal additives include 1.0 - 2.0 wt.% of fine coal and ferrous sulfate. Integration of the CANMET type process initially to an existing refinery and/or idle units is a first step toward utilization of coal and heavy oils (pitch and asphaltenes). A once through process arrangement without the use of a recycle stream may also be possible at lower coal concentrations. Coprocessing technologies to be included in a staged approach are HRI, Lumnus, and the Cherry-P processes which can process up to 50 wt.% of coal in heavy oil fraction. Implementation of coprocessing will likely require additional refinery hydrogen generation. This will probably be based upon steam reforming of hydrocarbon gases and light naphtha. Steam reforming is a well established and adopted method of generating hydrogen. The expansion of reforming units can be accomplished more easily than integrating gasification units into refineries. Hydrostabilization of product distillates are incorporated into a refinery to provide hydrotreatment and product stabilization prior to distribution outside the refinery complex. Further pretreatments for heteroatom removal may be required in a refinery utilizing coprocessing derived liquids. The introduction of coal/residuum coprocessing will tend to reduce crude re- quirements. The extent of reduction will be dictated by market demands as well as product yields and qualities of the coprocessing distillate liquids. Other positive factors are 1) the use of existing refinery and infrastructure, 2) better economics than direct liquefaction, 3) compatability with the use of heavier crudes, and 4) the capability of installing a coprocessing unit independently from existing refinery operations. Potential Coal Requirements An estimate of the potential coal requirements for coal/oil coprocessing for the general refinery types in the United States is presented in Table 2. These capacities represent an upper limit for the application of coal/residua coprocessing as fuel oil production was assumed to be zero. It was also assumed that COprocessing is more economic than vacuum distillation (both cases are highly unlikely). Based upon a 1985 production capacity of 890 million tons of coal in the U.S.; coal producing capacity would have to increase by one-third if the upper limits of coal/residua coprocessing were achieved. The most likely near term application for coal/oil coprocessing appears to be for residuum conversion capacity additions to low conversion refineries to improve profitability and to high conversion refineries to provide the capability for handling future feedstocks with increasingly higher residuum content. This premise is based on the assumption that present trends toward a heavier crude feedstocks and lighter reduced fuel oil requirements will continue. In terms of refinery capacity, average size Hydroskimming or Topping and High Conversion Refineries 229
processing 25,000 and 150,000 bbl/day of heavy crude (25' API), respectively, w i l l require approximately 850 and 4,000 tons/day of coal, respectively, when coprocessing at slurry concentrations of 50%. These coal capacities are well within existing transportation and handling experience for coal fired industriallutility boiler applications. Process Economics While the detailed engineering required to develop definitive coprocessing economics was beyond the scope of the effort, this paper would not be complete without presenting some guidelines. For this purpose, the installation of a coprocessing plant with a residuum throughput of 10,000 bbl/day (600-700 tons/day of coal) to a refinery (Figure 2) is estimated to cost of the order of fl70MM. This cost includes coal hand1 ing and preparation, coal/residuum conversion and allowances for hydrocarbon steam reforming for hydrogen generation (- 40% of the cost). Land and owner costs are not included in the estimate. In addition, it must be stressed that actual costs are refinery specific and w i l l vary greatly, depending upon the adequacy and availability of refinery utility systems and the degree of integration capabi 1 ity. Oevel opment Program Requirements A potentially broad variety of coals and petroleum residua are candidates for coprocessing. The properties of these feedstocks will have to be investigated in bench scale experiments to define product quality. In addition, better characterization of hydrogen requirements are required to improve economies. These data are required to facilitate the design and integration of coprocessing units into existing refineries. Conclusions Although continued Research and Development are required to define product quality and yields, coprocessing of coal and residual oil shows promise. It is anticipated that initial application of coprocessing will involve the utilization of small amounts of coal (1-2 wt.%) in existing refineries. This will be followed by demonstration units (10,000-15,000 bbl/day) utilizing a staged approach, processing 30-40 wt.% coal. Commercial units should be able to process up to 50-60 wt.% coal and will be integrated into high and low conversion refineries using vacuum residua as feedstocks and that there is a potential for the installation of upwards of 100 units of 10-15,000 bbl/day capacity. 230
- Page 27 and 28: 100. 2 8%. M = ?8. 38. .... . . . .
- Page 29 and 30: CATALYTIC CO-PROCESSINS OF OHIO NO.
- Page 31 and 32: CATALYST COMPARISON STUDY The premi
- Page 33 and 34: fractions and a decrease of heavier
- Page 35 and 36: TABLE 2 Coal Analyses I1 1 i noi s
- Page 37 and 38: Temperature WHSV, G/hr/cc TABLE 6 C
- Page 39 and 40: z FIGURE 3 COAL REACTIVITY SCREENIN
- Page 41 and 42: COPROCESSING USING HzS AS A PROMOTE
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- Page 47 and 48: Table 1 Analysis of Feedstocks Fore
- Page 49 and 50: THO-STAGE COPROCESSING OF SUBBITUMI
- Page 51 and 52: esult in retrogressive reactions ta
- Page 53 and 54: 8. 6. Ignasiak, L. Lewkowicz, G. Ko
- Page 55 and 56: Table 4 OVERALL MASS BALANCE FOR TH
- Page 57 and 58: BACKGROUND COAL LIQUEFACTION/RESID
- Page 59 and 60: system, which could be operated wit
- Page 61 and 62: TABLE 1 EFFECT OF LC-FINING~"' TEMP
- Page 63 and 64: Figure 1. SCHEMATIC OF LCI CO-PROCE
- Page 65 and 66: SIMULATION OF A COAL/PETROLEuII RES
- Page 67 and 68: 20 pseudocomponents was developed t
- Page 69 and 70: ottoms is less sensitive to the num
- Page 71 and 72: Low Pressure Separator A temperatur
- Page 73 and 74: 7. Gallier, P.W., Boston, J.F., Wu,
- Page 75 and 76: I I I I I I I I I 100- --- Experime
- Page 77: Coprocessing Schemes The coprocessi
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- Page 85 and 86: the coal itself. The chemical compo
- Page 87 and 88: - - ITSL PAH Fraction PAH Fraction
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- Page 103 and 104: CONCLUSIONS Separation of a light h
- Page 105 and 106: Table 3. Results of activity testin
- Page 107 and 108: feed coal and plant configuration a
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- Page 111 and 112: temperature, time and solvent power
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<strong>co</strong>st <strong>of</strong> <strong>co</strong>al liquefaction, the high recycle <strong>oil</strong> requirements. In all direct<br />
liquefaction processes <strong>co</strong>al is slurried with a process derived recycle <strong>oil</strong> <strong>at</strong> a<br />
mica1 r<strong>at</strong>io <strong>of</strong> 2:l recycle <strong>oil</strong> to <strong>co</strong>al feed. Co<strong>processing</strong> <strong>of</strong> residuum and <strong>co</strong>al<br />
reduces the high <strong>co</strong>st associ<strong>at</strong>ed with recycle <strong>oil</strong> by elimin<strong>at</strong>ing or reducing the<br />
requirements for recycle <strong>oil</strong>.<br />
Co<strong>processing</strong> hydrocracking technology was originally developed for <strong>processing</strong> heavy<br />
crude with <strong>co</strong>al additives as a means <strong>of</strong> inhibiting the form<strong>at</strong>ion <strong>of</strong> <strong>co</strong>ke. The<br />
CANMET hydrocracking process is based upon this <strong>co</strong>mcept. This emerging technology<br />
shows promise <strong>of</strong> I]iqh demetalliz<strong>at</strong>ion, residuum hydrocracking, and high <strong>co</strong>nversion<br />
<strong>of</strong> the pitch (975 F ) fraction. Coal additives include 1.0 - 2.0 wt.% <strong>of</strong> fine <strong>co</strong>al<br />
and ferrous sulf<strong>at</strong>e.<br />
Integr<strong>at</strong>ion <strong>of</strong> the CANMET type process initially to an existing refinery and/or idle<br />
units is a first step toward utiliz<strong>at</strong>ion <strong>of</strong> <strong>co</strong>al and heavy <strong>oil</strong>s (pitch and<br />
asphaltenes). A once through process arrangement without the use <strong>of</strong> a recycle<br />
stream may also be possible <strong>at</strong> lower <strong>co</strong>al <strong>co</strong>ncentr<strong>at</strong>ions.<br />
Co<strong>processing</strong> technologies to be included in a staged approach are HRI, Lumnus, and<br />
the Cherry-P processes which can process up to 50 wt.% <strong>of</strong> <strong>co</strong>al in heavy <strong>oil</strong><br />
fraction.<br />
Implement<strong>at</strong>ion <strong>of</strong> <strong>co</strong><strong>processing</strong> will likely require additional refinery hydrogen<br />
gener<strong>at</strong>ion. This will probably be based upon steam reforming <strong>of</strong> hydrocarbon gases<br />
and light naphtha. Steam reforming is a well established and adopted method <strong>of</strong><br />
gener<strong>at</strong>ing hydrogen. The expansion <strong>of</strong> reforming units can be ac<strong>co</strong>mplished more<br />
easily than integr<strong>at</strong>ing gasific<strong>at</strong>ion units into refineries.<br />
Hydrostabiliz<strong>at</strong>ion <strong>of</strong> product distill<strong>at</strong>es are in<strong>co</strong>rpor<strong>at</strong>ed into a refinery to<br />
provide hydrotre<strong>at</strong>ment and product stabiliz<strong>at</strong>ion prior to distribution outside the<br />
refinery <strong>co</strong>mplex. Further pretre<strong>at</strong>ments for hetero<strong>at</strong>om removal may be required in a<br />
refinery utilizing <strong>co</strong><strong>processing</strong> derived liquids.<br />
The introduction <strong>of</strong> <strong>co</strong>al/residuum <strong>co</strong><strong>processing</strong> will tend to reduce crude re-<br />
quirements. The extent <strong>of</strong> reduction will be dict<strong>at</strong>ed by market demands as well as<br />
product yields and qualities <strong>of</strong> the <strong>co</strong><strong>processing</strong> distill<strong>at</strong>e liquids. Other<br />
positive factors are 1) the use <strong>of</strong> existing refinery and infrastructure, 2) better<br />
e<strong>co</strong>nomics than direct liquefaction, 3) <strong>co</strong>mp<strong>at</strong>ability with the use <strong>of</strong> heavier crudes,<br />
and 4) the capability <strong>of</strong> installing a <strong>co</strong><strong>processing</strong> unit independently from existing<br />
refinery oper<strong>at</strong>ions.<br />
Potential Coal Requirements<br />
An estim<strong>at</strong>e <strong>of</strong> the potential <strong>co</strong>al requirements for <strong>co</strong>al/<strong>oil</strong> <strong>co</strong><strong>processing</strong> for the<br />
general refinery types in the United St<strong>at</strong>es is presented in Table 2. These<br />
capacities represent an upper limit for the applic<strong>at</strong>ion <strong>of</strong> <strong>co</strong>al/residua <strong>co</strong><strong>processing</strong><br />
as fuel <strong>oil</strong> production was assumed to be zero. It was also assumed th<strong>at</strong> CO<strong>processing</strong><br />
is more e<strong>co</strong>nomic than vacuum distill<strong>at</strong>ion (both cases are highly<br />
unlikely). Based upon a 1985 production capacity <strong>of</strong> 890 million tons <strong>of</strong> <strong>co</strong>al in the<br />
U.S.; <strong>co</strong>al producing capacity would have to increase by one-third if the upper<br />
limits <strong>of</strong> <strong>co</strong>al/residua <strong>co</strong><strong>processing</strong> were achieved.<br />
The most likely near term applic<strong>at</strong>ion for <strong>co</strong>al/<strong>oil</strong> <strong>co</strong><strong>processing</strong> appears to be for<br />
residuum <strong>co</strong>nversion capacity additions to low <strong>co</strong>nversion refineries to improve<br />
pr<strong>of</strong>itability and to high <strong>co</strong>nversion refineries to provide the capability for<br />
handling future feedstocks with increasingly higher residuum <strong>co</strong>ntent. This premise<br />
is based on the assumption th<strong>at</strong> present trends toward a heavier crude feedstocks and<br />
lighter reduced fuel <strong>oil</strong> requirements will <strong>co</strong>ntinue. In terms <strong>of</strong> refinery capacity,<br />
average size Hydroskimming or Topping and High Conversion Refineries<br />
229