HTGR APPLICATION FOR SHALE OIL RECOVERY

R. N. Quade and R. Rao

GA Technologies Inc.

P. 0. Box 85608

San Diego, CA 92138

ABSTRACT

The High-Temperature Gas-Cooled Reactor (HTGR)

utilizes a graphite-moderated core and helium as pri

mary coolant. Developed for electric power produc

tion, the 842-MW(t) [330-MW(e)] Fort St. Vrain plant

is currently operating at Platteville, Colorado.

Studies have been performed that couple steam pro

duced at 540C (1000F) and 17 MPa (2500 psia) to two

oil shale processes: the Paraho indirect retorting

and the Marathon direct steam retorting. The plant,

consisting of two 1170-MW(t) HTGR's, would also pro

duce electric power for other shale operations.

Results show economic and environmental advantages

for the coupling.

INTRODUCTION

The HTGR is an advanced, high-efficiency reactor

system that can play a vital role in meeting the

future energy needs of the nation by contributing not

only to the generation of electric power but also to

the industrial and commercial energy sectors tradi

tionally served by fossil fuels.

Designed and developed by GA Technologies Inc. ,

the HTGR is a refinement of the gas-cooled reactor

approach developed in Europe beginning in 1956.

Thirty-nine gas-cooled reactors in eight countries

have accumulated operating experience that accounts

for a quarter of worldwide nuclear-generated elec

tricity. While these reactors differ in many

respects from the HTGR, they have proved thegas-

cooling concept as well as major components similar

to those used in the HTGR.

In the U.S., the 40-MW(e) Peach Bottom 1 proto

type reactor successfully demonstrated the basic

characteristics of the HTGR with over seven years of

commercial operation on the system of Philadelphia

Electric (1967-1974) (Ref. 1). The 330-MW(e) Fort

St. Vrain demonstration reactor at Platteville, Colo

rado, 35 miles northwest of Denver, has been generat

ing electric power on the Public Service of Colorado

system since 1976. In November 1981 it achieved suc

cessful full-power operation with all plant systems

and components performing at or near design condi

tions. This reactor produces steam at 538C (1000F)

and 17 MPa (2500 psia) with reheat to 538C (1000F)

and 4 MPa (600 psia) (Ref. 2). Based upon the fea

tures of the Fort St. Vrain design, larger plants for

electric power production were designed. More

recently other applications where electricity is not

the prime product have been examined. In many of

these areas,the light water reactors cannot compete

because they cannot provide energy at the required

temperature.

Most energy-intensive industrial processes

require considerable process steam and electric

power. Cogeneration of electric power and process

steam is an advantageous blending of twowell-

developed technologies, with a resultant increase in

overall energy utilization. The cogenerating HTGR

steam cycle system (HTGR-SC/C) is well suited to per

form this service.

The energy requirements for a complete inte

grated oil shale facility include heat to retort the

shale, hydrogen to upgrade the kerogen, and steam and

electricity for overall plant operation. The higher-

temperature process heat version of the HTGR can pro

vide all of these functions, but it must be recog

nized that considerable development effort will be

required before commercial versions of this system

can be offered. Another paper presented at this con

ference (Ref. 3) discusses a method of coupling the

process heat HTGR to an oil shale facility.

This paper shows how the steam cycle HTGR can be

used with an indirect retorting process and a direct

steam retorting process. If there is large scale

expansion of the oil shale industry in the tri-state

area, large amounts of electricity will also be

needed. In addition to the process energy, the HTGR

can provide electricity for other oil shale opera

tions without adding fossil pollutants to the atmos

phere. This concept will add a very economical

source of electricity to power the industry while

minimizing the on-site use of product fuel.

HTGR DESCRIPTION

To maximize the advantage of scale while also

325

providing a range of plant sizes, a modular design

approach has been adopted for the HTGR-SC/C. An

1170-MW(t) plant has two steam generator/helium cir

culator loops, a 2240-MW(t) plant has four loops, and

a 3360-MW(t) plant has six loops.

The arrangement of an HTGR is shown in Figure 1.

The helium coolant flows downward through the central

core region, where it is heated to about 700C

(1290F). It passes radially outward to the primary

loop lower cross ducts and then flows through the

once-through steam generators, each consisting of a

helical coil economizer-evaporator-superheater region

and a straight tube superheater, where 17.3 MPa,

541C (2515 psia, 1005F) steam is produced. The gas

then is compressed in vertically mounted,single-

stage centrifugal circulators driven by synchronous

variable speed electric motors and returned through

the primary loop upper cross ducts to the inlet

plenum at about 320C (608F).

LINEAR

PRESTRESSING

SYSTEM

CONTROL ROD DRIVE

AND REFUELING

PENETRATION

Fig. 1. 2240-MW(t) HTGR arrangement

The entire helium circuit is enclosed in a

thick-walled, multicavity pres tressed concrete reac

tor vessel (PCRV), which functions as the primary

containment and biological shielding for the reactor

core and primary coolant system. The PCRV is con

structed of high-strength reinforced concretepre-

stressed by linear and circumferential prestressing

systems. A separate core auxiliary cooling system

(CACS) with its own heat exchangers and helium circu

lators is also located in the PCRV wall. The PCRV

and ancillary systems are housed inside a reactor

containment building, which is a conventional steel-

lined reinforced concrete structure.

HTGR fuel is made up of tiny spheres of uranium

and thorium in the form of UCO and Th02, each of

which is coated with pyrolytic carbon and silicon

carbide, which serve to retain fission products.

These particles are mixed and cast into small com

pacts, which are sealed into fuel cavities running

vertically through prismatic hexagonal graphite fuel

elements. The active core consists of stacks of

graphite fuel elements with holes for coolant chan

nels, fuel rods, and control rods. More detailed

information on the HTGR can be found in Ref. 4.

Flexibility in the process steam temperature and

pressure conditions from an HTGR used in a cogenerat-

ing mode is provided by several possible combinations

of turbine arrangements. If medium-temperature,

medium-pressure steam is required for the process,

the steam from the HTGR can be expanded through a

topping turbine and then sent to the process. If

more electricity is needed, some of steam can be

further expanded and condensed. If high-temperature

steam is needed for the process, steam can be taken

first to the process and then put through the turbine

for electric power production. Each coupling to oil

shale processes would involve a different balance of

plant arrangement, as described later.

APPLICATION OF HTGR TO OIL SHALE PROCESSES

Although many oil shale processes are under

development, evaluation of the state-of-the-art can

didates has shown two types that are suitable for

coupling to a steam cycle HTGR. One is the indirect

retorting process, such as Paraho, Union B, Petrosix,

or Superior, where heat is transferred to a recycle

gas that is used to directly contact and pyrolyze the

shale. The steam temperature normally provided by

the HTGR [538C (1000F)] is lower than current recy

cle gas temperatures, and some modification to the

retort kinetics would be expected. The second type

of process is direct contact with shale where steam

is the heating medium. In this case retort kinetics

are not compromised since retorting temperatures of

482C (900F) can be realized. With the help of

process developers, studies have been performed by GA

Technologies that investigate technical coupling,

economic comparisons, and environmental effects for

the two types of processes. For these studies the

Paraho indirect and Marathon steam retorting proc

esses were chosen as representative. The studies

326

assume that upgrading of the kerogen to syncrude will

take place at the oil shale site by hydrogen addi

tion. Hydrogen for this upgrading would be produced

by steam methane reforming of the product off -gas.

The energy for this reforming is assumed to come from

product oil or gas. The actual development in the

tri-state area may show that the kerogen upgrading

function should be centralized, perhaps a long dis

tance from the site. In this case, all the onsite

energy could be supplied by the steam cycle HTGR,

with a resulting decrease in site environmental

effects.

HTGR INTEGRATION WITH SELECTED SHALE RETORTING

PROCESSES

Indirect Shale Retorting with Hot Recycle Gas

In the indirect shale retorting process as

developed by Paraho Development Corporation (Ref. 5),

hot recycle gas is used to pyrolyze the shale. The

recycle gas is circulated in a closed loop. The gas

is heated in a gas heater or heat exchanger by an

external heat source, or in the case of an HTGR-SC/C

plant by its steam to approximately 510C (950F).

During pyrolysis, the kerogen within the oil shale

decomposes into shale oil. At the same time, large

quantities of hydrocarbon-rich off-gases are liber

ated. As the gases ascend in the retort vessel, the

moving bed of crushed shale flowing downward is con

tacted and gets preheated before reaching the retort

zone in the vessel. The retort off-gas, containing

entrained oil mist, flows from the top of the retort

and passes through the oil recovery system. The oil

recovery system consists of a coalescer for initial

recovery, an electrostatic precipitator for second

stage recovery, and a knock-out drum at the recycle

gas compressor discharge for removal of heavy oil

carry-over.

Figure 2 shows the overall process plant

arrangement for a commercial operation of the indi

rect shale retorting, including recycle gas heating

by HTGR steam and crude shale oil upgrading. The

shale feed rate for the commercial operation was

selected to match the use of an 1170-MW(t) HTGR-SC/C

plant. Approximately 2.72 x106 kg/h (72,000 T/D) of

sized shale enters 10 parallel trains of indirect

heated retorts. Each retort is a refractory-lined

vertical kiln that acts as a countercurrentgas-

to-solids heat exchanger. Hot recycle gas is circu

lated at a rate of 1.2 x106

m3/h (42.56 x106

SCFH)

and at a pressure/temperature of 0.10 MPa (15 psia)/

510C (950F) in each retort.

SHALE

FINES

MINING

86,320 kg/h

(190,300 LB/HR)

240MW(e) PROCESS STEAM

PLANT POWER ,

C02VENT

2.86 MMkg/h (75,604 T/D)

SECONDARY

CRUSHING.

SCREENING,AND STORAGE

2.72 MMkg/h

(71,867 T/D)

INDIRECT

HEATED

RETORTS

(10)

510C

(950F)

2.32 MMkg/h

(61,490 T/D)

SPENT

SHALE

DISPOSAL

FUEL GAS

0.47 MMm3/d (16.74 MMSCFD)

VENT

CLAUS SULFUR

PLANT AND

TAIL GAS

CLEANUP

SULFUR

AMMONIA

STRETF0RD

SULFUR

RECOVERY

SULFUR

Fig. 2. Process block diagram for a commercial shale surface retorting operation with 510C (950F)

recycle gas using an 1170-MW(t) HTGR-SC/C plant

327

About 99% of the oil in gas is recovered to

yield approximately 6680 m3/d (42,000 B/D) of crude

shale oil. The Fischer Assay characteristics of the

shale pyrolysis depend on the retort operating param

eters, and for the selected pressure/ temperature

parameters in the present indirect process, a Fischer

Assay value of approximately 87% was estimated. The

upgrading facilities included a product gas cleanup

system, a hydrogen production plant, and ahydro-

treater. Acid gases, such as CO2 and H2S, were

stripped from the off-gases, and a portion of the

resulting product gas was used as feed to the hydro

gen plant and the balance as high-Btu fuel gas.

Hydrotreating of the synthetic crude removes nitro

gen, sulfur, and oxygen by turning them into ammonia,

hydrogen sulfide, and water, respectively.

The energy demand at various stages of the com

mercial indirect shale retorting process is shown in

Table 1. The single largest energy demand occurs in

the retorting phase. Figure 3 shows thetemperature-

heat diagram for the indirect shale retorting process

using recycle gas. The HTGR-SC/C plant can supply

all the process thermal and electrical energy

requirements except for the hydrogen (H2) production

plant. The H2 plant requires energy at a higher tem

perature [>538C (1000F)], and therefore it is sup

plied by product oil and gas. The 1170-MW(t)HTGR-

SC/C provides about 66% of the process thermal energy

demand and 100% of the process electric power demand.

TABLE 1

ENERGY REQUIREMENTS FOR SHALE RETORTING OPERATIONS

6,680 m3/d 7,950 m3/d

(42,000 B/D) (50,000 B/D)

Crude Crude

Indirect Gas Direct Steam

Retorting Retorting

Shale retorting, MW(t) 320 372

Process steam, MW(t) 64 67

Hydrotreater, MW(t) 10 13

Hydrogen plant, MW(t) 204(a) 205<a)

Process electric power, 157 241

MW(e)

(^Energy is required at high temperature [>538C

(>1000F)] and is supplied by product oil and gas.

Figure 4 shows the integration of an 1170-MW(t)

HTGR-SC/C plant with a commercial 6680 m3/d (42,000

B/D) indirect shale retorting operation. About 75%

of the primary steam exiting the HTGR-SC/C plant is

used for heating the recycle gas and is then expanded

through power turbines, cogenerating electric power.

PROCESS HEAT LOAD [MW]

Fig. 3. Temperature versus heat load diagram for

direct and indirect shale retorting

operations

The remaining 25% of the primary steam is expanded

through a condensing turbine-generator unit to

enhance electric power production.

Also shown in Figure 4 is the extraction of 24

kg/s (192,100 lb/hr) of steam at 1.1 MPa (160 psi)

from turbogenerator T-G 2 for process use.Addition-

ally, some steam from the heat exchanger HX 2 outlet

is used in the hydrotreating process, having a heat

load of 10.3 MW(t), to heat fluid from 368C to 396C

(695F to 745F).

An 1170-MW(t) variable cogeneration HTGR plant

was added as a backup power plant. A backup power

plant is required since the process plant annual

capacity requirement (90%) is higher than the design

capacity factor (80%) of the HTGR-SC/C plant. The

variable cogeneration HTGR can function either as the

base HTGR-SC/C plant or as a full electric plant by

the use of its turbogenerator units. The variable

cogeneration HTGR plant has a capacity factor of 75%

in an all-electric mode. As a backup, it functions

as a steam cycle/cogeneration plant for 10% capacity.

For the remaining 65% capacity, it operates as an

electric plant, generating a net 428 MW(e). Figure 5

schematically shows the operation of the two HTGR

plants relative to the process plant energy demand.

Figure 5 also includes a table showing the salable

electric power from the two HTGR plants at various

process plant operating periods. The salable elec

tric power can be classified as "firmpower"

and

credited accordingly (see Economics Section) if this

power is made available for sale for a minimum of 75%

of a specified period (usually one year); otherwise

it will be considered as "non-firmpower."

328

? 0.10 (15) P | TO RETORT

510 (950)T

HX2

HX1

0.1 (15) P

138 (280) T

1.21 x10em3/h (42.56 x10bSCFH)

RECYCLE GAS

ALLOCATION OF REACTOR POWER OUTPUT MW %

PROCESS USES

STEAM POWER TO PROCESS 394 34

ELECTRIC POWER 157 13

AUX POWER 35 3

OTHER USES

ELECTRIC POWER 83 7

LOSSES 501 43

TOTAL REACTOR POWER OUTPUT 1170 100

LEGEND

W = FLOWKG/SUO6

LB/HR)

P = PRESSURE MPa (PSIA)

T = TEMPERATURE C (F)

Fig. 4. Integration of an 1170-MW(t) HTGR-SC/C plant with a commercial indirect shale retorting

operation using recycle gas

i

345

LE

MWe

SA83

MWe

83<

MWe

i 157

MWe

394

MWt

PROl ESSPROC

HEAT

+

STEAM

204

MWt

H2PLANT

rV11 70 MWt HTGR

VARIABLE COGEN. PLANT(NON-FIRM)

NBACKUP (UNIT 2)

(FIRM)

FN

1170 MWt HTGR-SC/C

UNIT1

V

1170

MWt

HTGR

BACK

UP

(UNIT 2)

ENERGY SUPPLIED BY PROD OIL + PROD GAS

LNr50 60 70 80

90*

100

DUTY CYCLE (%)

(#PROCESS PLANT REQUIREMENT)

HTGR CAPACITIES

0-65% 65%-80% 80%-90%

DUTY CYCLE,%'

BASE HTGR-SC/C PLANT, MWt

BACKUP HTGR PLANT, MWt

ELECTRIC POWER FOR SALE

65

1170

1170

511

15

1170

83

10

1170

83

Fig. 5. Operation of two 1170-MW(t) HTGR plants for

a commercial indirect shale retorting plant

DIRECT SHALE RETORTING PROCESS WITH SUPERHEATED STEAM

In the direct shale retorting process with

superheated steam, shale is pyrolyzed in a vertical

kiln by passing superheated steam vapor at superfic

ial velocities ranging from 0.50 to 1.0 m/s (100 to

200 ft/min) and at a temperature of 510C (950F) or

higher. This process was developed by the Marathon

Oil Company (Research Division) of Denver, Colorado.

In the upper portion of the retort vessel where the

feed enters,shale is preheated by contact with a mix

of ascending hot steam and gases. The retorting

steam and off-gases released carry the shale oil mist

from the retort. Fischer Assay values in excess of

100% are predicted in the direct shale retorting

process with superheated steam and with several com

binations of pressure/ temperature parameters

(Ref. 6). Figure 6 shows the process arrangement for

commercial direct steam retorting of shale. The lib

erated off-gases and steam carrying droplets of shale

oil flow through an evaporator/condenser unit in

which steam is condensed. The condensate (water) is

then separated from oil and is circulated as the

cooling medium in the evaporator. The evaporator

exit steam (dry, saturated) is compressed to the

desired pressure by a steam compressor for injection

into the retort prior to heating by the HTGR steam.

The off -gases, after treatment and cleanup, are used

329

as fuel gases in a hydrogen plant and partially as

feed in the hydrogen plant.

Approximately 2.66 MMkg/h (70,000 T/D) of sized

shale is retorted in 10 parallel retorts. A total of

53 kg/s (422,400 lb/hr) of superheated steam vapor

required for retorting the shale is injected into the

retorting zone of each unit at a relatively low pres

sure [0.17 MPa (25 psia)]. The steam exiting the

evaporator/ condenser unit is heated to the required

temperature [513C (955F)] by the high-temperature

steam from the HTGR plant via heat exchangers.

The shale oil upgrading facilities are similar

to those employed in the indirect shale retorting

process described earlier. About 8590 m3/d (54,030

B/D) of hydrogenated shale oil is estimated as the

gross plant yield from the upgrading plant.

Table 1 shows the process energy demand at vari

ous stages of the commercial direct steam shale

retorting operation. As in the indirect process, the

single largest energy demand occurs in the shale

retorting phase. The increased electric power demand

occurs in the direct retorting process owing to the

requirement of considerable steam compressive power

[-96 MW(e)].

The integration of the 1170-MW(t) HTGR-SC/C

plant with the direct shale retorting process is very

similar to that described earlier for the indirect

retorting process with the exception that all the

primary HTGR steam is circulated through heat

exchanger HX 2 for heating the low-pressure retorting

steam, thus eliminating the additional HP/LP turbo

generators. Table 2 shows the HTGR-SC/C plant heat

balance from the direct steam retorting operation.

TABLE 2

1170-MW(t) HTGR-SC/C PLANT HEAT BALANCE FOR A

7,950 m3/d (50,000 B/D) CRUDE SHALE OIL PLANT USING

DIRECT STEAM RETORTING

Allocation of Reactor Power Output MW %

Process uses

Steam power to process 432 37

Electric power 222 19

Condenser/ losses 516 44

Total reactor power output 1170 100

One 1170-MW(t) HTGR-SC/C plant is suited for the

8590 m3/d (54,030 B/D) direct shale retorting process

with steam. The HTGR-SC/C plant primary steam, which

is delivered at 17.3 MPa (2515 psia) and 540C

(1005F), provides the heat for the retorting steam

and for hydrotreating and also supplies steam at var

ious stages of the process. Surplus steam from the

HTGR-SC/C is expanded through power turbines ,

cogen-

erating electricity. In addition, the HTGR-SC/C

plant delivers 25 kg/s (202,000 lb/hr) of 1.1-MPa

(160-psia) saturated steam for the process.

Figure 3 shows the temperature-heat diagram for

P = 0.18(26)

T = 513(955)

W = 191,600(422,398)

P =

T '

W =

TO HTGR <H_

PLANT

W = 10,767 (23,737)

DATA SHOWN FOR ONE MODULE;

NO. OF MODULES: 10

GAS, OIL, AND

STEAM MIX

SHALE FEED

0.26 MM kg/h

(7000 T/D)

T = 25 (77)

0.19 (27)

189 (372)

191,600(422,398)9.6 MWe

P = 0.16 (23.2)

T = 113(235.5)

W = 215,347 (474,751) STEA

j -(C^) C\ fOFF-GAS 10,510 m3/h

\ ^y \ ( I (375,340)

RETORT

P = 0.09(12.5)

T = 96 (204)

P = 0.01 (14)

T = 51.6(125)

W = 204,579(451,014)

\J

SCFH

P = 0.21 (30)

T = 96 (204)

W = 23,747

(52,353)

SPENT

SHALE

P = 0.17(25)

T = 510 (950)

W = 23,747 (52,353)

BLOW

DOWN

?mum niunr

795 m3/d (5,000 B/D) RAW OIL

SPENT SHALE

0.23 MM kg/h (6010 T/D)

T = 149(300)

MAKE-UP

FROM HTGR PLANT

MAKE-UP (IF REQD)

LEGEND

P = MPa (PSIA)

T = C(F)

W = kg/h (LB/HR)

Fig. 6. Process arrangement for a 7950 m3/d (50,000 B/D) direct steam retorting of oil shale

330

the direct shale retorting process with steam. As in

the indirect process, heat to the hydrogen production

plant is provided by product oil and gas. About 69%

of the process thermal energy requirement and 92% of

the electric power demand are provided by an1170-

MW(t) HTGR-SC/C plant.

For the same reasons stated for the indirect

process plant operation, an additional 1170-MW(t)

variable cogeneration plant was provided in the

direct steam retorting process as backup. Figure 7

shows the operation of the two 1170-MW(t) HTGR plants

relative to the process plant energy demand and the

salable electric power resulting from the backup HTGR

plant .

SALE408

MWe

MWe

452

MWt

PROC ;ss

PROC

HEAT

+

STEAM

205

MWt

H2PLANT

rNr

20

MWe

BACKUP 1170 MWt HTGR

VARIABLE COGEN.

HTGR PLANT (UNIT 2)

BASE 1170 MWt HTGR-SC/C

PLANT (UNIT 1)

Nr

BACK

UP

HTGR

PLANT

(UNIT 2)

ENERGY SUPPLIED BY PROD OIL + PROD GAS

LV

the energy plants covered the HTGR plant and the com

peting standard oil/gas-fired plant. The capital

costs included plant investment, engineering ser

vices, construction expenses, contingency, and work

ing capital. A preliminary capital cost was devel

oped based on such information as process flow dia

grams, major equipment sizes, in-house pricing for

process packages, budget prices based on similar pro

jects, and published cost data.

It was assumed that the HTGR was an"nth"

plant

and that commercial shale recovery operations in the

U.S. would be on-stream around the year 2005. A sum

mary of the financial assumptions and ground rules

used for the cost development and for subsequent eco

nomic analysis is shown in Table 3. Power plant cost

for the 1170-MW(t) HTGR-SC/C plant was developed by

GA Technologies in cooperation with United Engineers

and Constructors. Table 4 shows the capital costs of

HTGR power plant and process plants (direct and indi

rect processes). The standard indirect shale retort

ing process with hot recycle gas integrates a product

oil/gas-fired power plant to provide the process

thermal and electric power needs.

DUTY CYCLE (%)

(*PROCESS PLANT REQUIREMENT)

TABLE 3

SUMMARY OF FINANCIAL ASSUMPTIONS

HTGR CAPACITIES

0-65% 65%-80% 80%-90%

DUTY CYCLE, % 65 15 10

BASE HTGR-SC/C PLANT, MWt 1170 1170 -

BACKUP HTGR PLANT, MWt 1170 - 1170

ELECTRIC POWER

-SALE 408 - -

-PURCHASED- 20 20

Fig. 7. Operation of two 1170-MW(t) HTGR plants for

a commercial direct steam shale retorting

plant

CAPITAL COST AND ECONOMIC CONSIDERATIONS

Preliminary cost estimates of the process and

energy plants were made for the commercial direct and

indirect shale retorting operations. The process

plant cost estimates were based on an earlier study

performed by Davy McKee Engineers (Ref. 3) for GA

Technologies. Suitable allowances were made in the

base case equipment costs to reflect changes in shale

feed rate and crude oil processing rate in the

respective process. The capital costs developed for

Base data of all costs

Date of operation for all plants

Investment life for all plants, yr

Credit value for electric power,

mills/kW(e)-hr

2005 fuel cost projections, $/GJ($/106

Btu) (January 1983$)

Nuclear

Oil/gas

Common cost factors, %

Weighted cost of capital

Levelized fixed charge rate

(utility /industry)

Allowance for funds duringconstruction (utility/industry)

Real escalation rates, %

General

Electric power

Natural gas/oil

Mined shale

(a)Sale - firm.

(b)purchased.

(c)Sale -

nonfirm.

January 1983

January 2005

30

53(a), 84(b)]

33(c)

1.30 (1.37)

8.82 (9.30)

5.4

8.3/13.7

4.4/8.5

0.0

0.5(a,b)/i.o(c)

1.5

2.0

331

TABLE 4

ECONOMIC ANALYSIS FOR DIRECT AND INDIRECT

RETORTING OF OIL SHALE

Standi

Indirect

Retort:

ltd

Shale

Ing

Assist

Indirect

Retort:

ted

Shale

Ing

Assisted

Direct Shale

Retorting

Plane Parameters

Input

Shale feed, MMkg/h (T/D) 2.46 (65 ,600) 2.72 (71 ,900) 2.65 (70,000)

Energy plant, MW(t) 1155 2 x 1170 2 x 1170

Output

Product/3) MMBBL/yr 10.238 14.578 16.836

Salable electric power 511(b) 408(b)

Process thermal efficiency, X 60 59 67

Capital Cost

Energy plants 174 2023 2036

Process plant 1637 1749 1880

Total Capital Requirement 1811 3772 3916

Annual Cost (1983 MM$, 30-yr

Levelized)

Fixed

Energy plant (utility rate) 15 172 173

Process plant (industry rate]1 224 240 258

Fuel (nuclear) 74 74

Scarcity of mined shale 127 139 135

O&M

Energy 7 64 64

Process 168 182 182

Electric power (credit) ~

(137) (83)

Total Annual Cost 541 734 803

Product Cost, S/B (1983$) 52.84

fuel use.

rtions.

50.35 47.70

(a'Net output excluding process i

'"'Includes firm and non-firm poi

The economic analysis was performed using the

revenue requirement method. The revenue requirement

method (Ref. 7) is commonly accepted by the electric

utility industry for evaluating long-lived power

plant projects, and it determines the revenue needed

by the owner as compensation for all expenditures

fixed and variable. Hence, the revenue requirements

of the owner are the costs to the consumer of the

process steam cogenerated. Base year capital costs

are escalated through plant construction, and inter

est during construction is added to arrive at a total

capital cost in constant base year (1983) dollars. A

fixed charge rate is applied to the total capital

cost to arrive at an annual fixed charge to which are

added the levelized annual fuel costs, levelized ann

ual operation and maintenance (O&M) costs, and a cre

dit for the levelized value of cogenerated power to

arrive at a total levelized annual cost.

Table 4 also shows the economic results of the

direct and indirect shale retorting operations in

constant 1983 dollars. A 30-year levelization per

iod, commensurate with the plant life, was assumed.

For comparison, the economic results of the standard

indirect shale retorting process using oil/gas as

fuel are included in Table 4. In the standard indi

rect retorting process, approximately one-third of

the produced oil is consumed as fuel. The annual

shale oil output shown in Table 4 is the net after

accounting for the in-house use of the product oil as

fuel. The annual cost shown in Table 4 includes a

levelized charge due to progressively higher mining

costs associated with the thinning of the shale seams

in the mine and the greater difficulty involved in

mining. The standard indirect process has a higher

product price (S52.84/B) than either of the two HTGR

assisted processes because of its considerably lower

net product output. The HTGR assisted direct steam

shale retorting process has an 11% economic advantage

and the HTGR assisted indirect retorting process has

a 5% economic edge over the standard indirect shale

retorting process based on product price. The HTGR

assisted indirect process has a lower process plant

cost (7%) and has increased revenues (65%) from the

sale of electric power as compared with the direct

retorting process. The HTGR-SC/C backup plants were

found to be economically advantageous over the

oil/gas-fired backup plants because of lower nuclear

fuel cost and additional revenues from surplus elec

tric power sale.

The development of the shale industry primarily

depends on other competing liquid fuels under devel

opment and, in particular, the world oil price.

Assuming a current (1983) world oil price of $30/B

and a real escalation rate of 1.5% per year (see

Table 3), the world oil price is estimated as $49/B

in the year 2005 (30-year levelized). Therefore, in

order for the shale oil to be competitive in the year

2005 and beyond and for the shale industry, in gen

eral, to receive any encouraging signs for continued

development, the projected real escalation rate for

the conventional oil would have to be in excess of

1.55 per year.

ENVIRONMENTAL CONSIDERATIONS

The environmental effluents from a commercial

surface shale retorting operation primarily extend to

three areas: air, water, and solid waste. Both

state and federal guidelines or regulations must be

satisfied In order to secure the operating permits.

At present, there are no federal emission standards

specifically covering oil shale production. However,

the State of Colorado has enacted some regulations on

air emissions directed to the shale oil industry

(Ref. 5). One requires commercial operations [pro

ducing more than 6.7 m3/h (1000 B/D)] to restrict

332

themselves to 0.85 kgS02/m3 (0.3 lb SO2/BBL) of oil

production plus an equal amount of the refining oper

ation. Similarly, hydrogen sulfide emission is lim

ited to 10 ppm based on a 1-hour average ambient air

concentration. The major source of sulfur dioxide

(SO2), nitrogen oxides (N0X), and carbon monoxide

(CO) will be fuel combustion for process heat, pre

dominantly at the reforming furnace. SO2 will also

be emitted in the sulfur recovery and tailgas cleanup

operations. Particulate matter emissions will occur

from fuel combustion, raw and spent shale dust in

process streams, raw and spent shale handling and

disposal, mining and blasting, and other site activi

ties that generate fugitive dust.

Table 5 presents an overall emission summary for

three commercial shale operations: (1) the standard

indirect shale retorting process using gas/oil fuels,

(2) the HTGR-SC/C assisted indirect shale retorting

process, and (3) HTGR-SC/C assisted direct steam

retorting of oil shale. Substantial reductions in

SO2 and N0X emissions occur in HTGR-SC/C assisted

shale operations, since the use of the prime source

of these effluents, i.e., oil and gas fuel, is mini

mized. The commercial oil shale plant may be assumed

to be located in an "attainmentarea,"

meaning that

the air quality is cleaner than defined by National

Ambient Air Quality Standards. Otherwise, regulatory

requirements will be applied to the allowable emis

sions.

TABLE 5

AIR EMISSION SUMMARY FOR THREE COMMERCIAL SHALE

RETORTING OPERATIONS [kg/h (lb/day) J

Standard

Indirect

Recycle Gas

Retorting2.46 x

106kg/h

(65,600 T/D)

Indirect

Recycle

Gas Retorting(HTGR-SC/C

Assisted)

2.72 x106 kg/h

(71,900 T/D)

Direct Steam

Gas Retorting(HTGR-SC/C

Assisted)

2.65 x106 kg/h

(70,000 T/D)

Particulates 102 (5,434) 78 (4,130) 77 (4,077)

S02 38 (2,071) 26 (1,400) 26 (1,400)

N0X 424 (22,880) 226 (11,970) 224 (11,864)

HC 64 (3,470) 62 (3,266) 73 (3,846)

CO 1,346 (72,680) 1,329 (71,757) 1,600 (86,390)

C02 0.3 x106

(17 x 106)

0.2 x106

(12.4 x 106)

0.2 x106

(12.4 x 106)

H2S 4.0 (212.0) 4.4 (233.0) 4.2 (222.0)

of a standard fossil plant nearly halves the overall

emission with on-site crude upgrading included. A

further reduction of approximately 30% in the emis

sion occurs if on-site upgrading is excluded. The

emission of N0X is a major contribution to the

environment from a surface shale retorting process.

Based on environmental considerations, contami

nated wastewater streams from shale surface retorting

facilities could have access to aquifers and ground

water, resulting in fouling. The USEPA has estab

lished national effluent limitations on what a point

source can discharge into the aquifers or ground

water.

PARTICULATES

_

,75X1B5

PARTICULATES

^1

i| |PAIPARTICULATES

STANDARD

INDIRECT -

FOSSIL FUEL

(WITH UPGRADING)

INDIRECT -

HTGR-SC/C

ASSISTED

(WITH UPGRADING)

INDIRECT -

HTGR - SC/C

ASSISTED

(WITHOUT UPGRADING)

Fig. 8. Air emission comparison for a 7950 m3/d

(50,000 B/D net) surface shale oil recoverywith fossil and nuclear fuels

Solid waste disposal from oil shale processing

presents one of the major problems associated with

commercial development of the oil shale industry.

The predominant source of solid waste will be shale-

derived, including spent shale, raw shale fines, and

mined raw shale. At present, no solid waste result

ing from shale surface retorting facilities has been

classified as hazardous by federal or state agencies.

However, the management of solid waste disposal will

need to incorporate the preparation of the disposal

site, transport of the waste, and assurance of the

stability of the waste pile.

Table 6 shows the environmental effluents-

gaseous, solid and liquid - from an 1170-MW(t) HTGR-

SC/C plant. These effluents are within the limits

set by the Nuclear Regulatory Commission.

Figure 8 schematically shows the impact of over

all air emission from a large commercial indirect

shale retorting process using hot recycle gas and

energy provided by a fossil plant and a 1170-MW(t)

HTGR-SC/C plant. Use of an HTGR-SC/C plant in place

CONCLUSIONS

1. The HTGR has an excellent technical fit with many

of the oil shale processes, since the temperature

capability of the reactor is high enough to

retort oil shale.

333

TABLE 6

ENVIRONMENTAL EFFLUENTS FROM AN 1170-MW(t) HTGR PLANT

Air emissions

Noble gases, Ci/yr

Iodine and particulates, Ci/yr

Solid wastes

Miscellaneous radioactive material,

Ci/yr

Liquid effluents

Mixed fission products (no

tritium), Ci/yr

99(a)

0.01

7570(b)

0.0021

(^Includes 0.09 Ci/yr of tritium.

^"'Includes tritium contained in solidifiedhigh-

specific-activity liquids.

2. The current steam cycle HTGR design based upon

the Fort St. Vrain reactor at Platteville can

produce retorting heat and plant energy for some

processes. In addition, it can provide economic

electricity for any oil shale process in the wes

tern Colorado-Utah area as early as 1995. Elec

tricity costs are estimated at 50 mills/kW-hr for

firm power and 30 mills /kW-hr for interruptible

power for 1995 startup (1983 dollars).

3. The HTGR versions can provide large environmental

benefits in terms of reduced air pollution in the

tri-state area. With on-site upgrading, approxi

mate reductions of 32% in SO2 emissions, 47% in

N0X, and 24% in particulates could be achieved.

4. Firm economic comparisons are difficult to make

at this time. Nuclear energy is at least compet

itive with other options. Depending on the value

of the salable electricity and the market value

of the displaced oil, there may be considerable

savings over the long term associated with the

nuclear option.

5. The application of the HTGR as an energy source

conserves the shale resource and enhances shale

oil production in the western U.S.

ACKNOWLEDGMENT

This work was supported by the U.S. Department

of Energy under Contract DE-AT03-76SF70046.

REFERENCES

1. Birely, W. C, "Operating Experience of the Peach

Bottom PowerStation,"

Nuclear Engineering and

Design, 26, 9-15, (1974).

2. Brey, H. L. ,and W. A. Graul, "Operation of the

Fort St. Vrain High-Temperature Gas-Cooled Reac

torPlant,"

Proceedings of the American Power

Conference, Vol. 44, 1982, pp. 795-800.

3. Wadekamper, D. C, et al., "Application of the

High Temperature Gas Cooled Reactor to Oil Shale

Recovery,"

General Electric Company, Sunnyvale,

California.

4. Boland, C. R.,et al.

,"The High-Temperature Gas-

Cooled Reactor - A Needed Option for Future

EnergyRequirements,"

Second Joint ASME/ANS

Nuclear Engineering Conference, July 26-28, 1982,

Portland, Oregon.

5. "Paraho Retorting of Oil Shale Using a Very High

TemperatureReactor,"

Davy McKee Engineers and

Constructors.

334