shale processing

CHAPTER 5

Technology

Introduction ● .*. ... . * * ,, *,, , **,,.*.,.Page119

Summary of Findings. . . . . . . . . . . . . . . . .. ..119

An Overview of Oil Shale Processing . ......120

Oil Shale Mining. . . . . . . . . . . . . . . . . . . . . .. .123Surface Mining. . . . . . . . . . . . . . . . . . . . . . . . . 123Underground Mining . ...................125

Oil Shale Retorting. . ...................,128True In Situ. . . . . ................,......128Modified In Situ . .......................131Aboveground Retorting . .................137Advantages and Disadvantages of the

Processing Options. . ..................153Oil Recovery . . . . . ......................154

Properties of Crude Shale Oil .. .... ... ....155

Shale Oil Refining. . ..................,..157Shale Oil Upgrading Processes . ....,......158Total Refining Processes . ................160Cost of Upgrading and Refining . ...........162

Markets for Shale Oil. . ..................163Shale Oil as a BoilerFuel . ................163Shale Oil as a Refinery Feedstock . .........164Shale Oil as a Petrochemical Feedstock .. ...166

Issues and Uncertainties . ................167

R&D Needs and Present Programs. . ........170R&D Needs . . . . . . . . . . . . . . . . . . . . . . . . . . . .170Present Programs. . . . . . . . . . . . . . . . , . . , . . .172

Policy Options . . . . . . . . . . . . . . . . . .**.,*,.. 173R&D. . . . . . . . . . . . ................,.....173

PageDemonstrat ion . . . . . . . . . . . . . . . . . . . . . . . . .173

Chapter 5 References. . ..................175

List of TablesTable No. Page18. Overall Shale Oil Recoveries for

Several Processing Options . . . . . . . . . 15519. Properties of Crude Shale Oil From

Various Retorting Processes. . . . . . . . . 15620. Supply of Finished Petroleum Products

in PADDs 2, 3, and 4 in1978 . . . . . . . . . 16521. Technological Readiness of Oil Shale

Mining, Retorting, and RefiningTechnologies . . . . . . . . . . . . . . . . . . . . . 168

List of FiguresFigureNo. Page19.20.

21.22.23.

24,

25.

26.27.

Oil Shale Utilization . . . . . . . . . . . . . . . 121The Components of an UndergroundMining and Aboveground Retorting OilShale Complex. . . . . . . . . . . . . . . . . . . . 122An Open Pit Oil Shale Mine. . . . . . . . . . 124Open Pit Oil Shale Mining. . . . . . . . . . . 125The Colony Room-and-PillarMiningConcept . . . . . . . . . . . . . . . . . . . . . . . . . 126Room-and-Pillar Mining on MultipIeLevels . . . . . . . . . . . . . . . . . . . . . . . . . . . 127The Original Mine Development Planfor Tract C-b . . . . . . . . . . . . . . . . . . . . . 128True In Situ Oil Shale Retorting . . . . . . 129Modified In Situ Retorting. . . . . . . . . . . 132

28.

29.

30.

31.

32.

33.34.35,

36.37,

38.

39.

4U.41.

P a g e

The RISE Method of MIS Oil ShaleRetorting . . . . . . . . . . . . . . . . . . . . . . ,. 134Initial Modular MIS RetortDevelopment Plan for Tract C-a . . . . . . 135Present MIS Retort Development Planfor Tract C-a . . . . . . . . . . . . . . . . . . . . . 136Retort Development Plan for theMulti Mineral MIS Concept.. . . . . . . . . 136Preparation of a Multi Mineral MISRetort . . . . . . . . . . . . . . . . . . . . . . . . . . . 137A Set of Multi Mineral Misreports . . . 138The Operation of an NTU Retort.. . . . . 140Discharging Spent Shale Ash Froma40-Ton NTU Retort. . . . . . . . . . . . . . , . . 141The Paraho Oil Shale Retorting System 143The Paraho Semiworks Unit atAnvil Points, Colo. ● , ● ● ● ● ● ● . ● . . . ● , . ● 143The Petrosix Oil Shale RetortingSystem . . , . . , . , . . . . . . . , , . . 0 . , . , 0 . 145The Petrosix Demonstration Plant,Sao Mateus do Sul, Brazil. . . . . . . . . . . 146The Union Oil “B” Retorting Process.. 147Block Diagram for the SuperiorMulti Mineral Concept . . . . . . . . . . . . . 149

42.43.

44,

45*

46.

47*

48.

49.

50.

P a q e

The Superior Oil Shale Retort.. , . . . . . 150The Colony Semiworks Test FacilityNear Grand Valley, Colo. . . . . . . . . . . . 151The TOSCO II Oil Shale RetortingSystem .,, , . . . . . 0 ., . . . . ., .,....,, 152The Lurgi-Ruhrgas Oil Shale Retorting

. ,0 ,0 . . . . . . . . . . . . . . . . . . . . . 153Refining Scheme Used by the U.S.Bureau of Mines to Maximize GasolineProduction From Shale Oil . . . . . . . . . . 161Refining Scheme Employing CokingBefore an Initial Fractionation, Used byChevron U.S.A. in RefiningExperiments. ., . . . . . . . . . . . . . . . . . . . 161Refining Scheme Employing InitialHydrotreating, Used by Chevron U.S.A.in Refining Experiments . . . . . . . . . . . . 161Refining Scheme Employing InitialFractionation, Used by SOHIO inPrerefining Studies . . . . . . . . . . ... , . . 162The Petroleum Administration forDefense Districts. . . . . . . . . . . . . . . . . . 165

CHAPTER 5

Technology

IntroductionThe mining and processing technologies

that can be used to convert kerogenf the or-ganic component of oil shale, into marketablefuels are discussed in this chapter. The char-acteristics of these technologies will influ-ence the effects that an oil shale industry willhave on the physical environment, and theirtechnological readiness will affect the rate atwhich an industry can be established. Thefollowing subjects are discussed:

●

●

●

the general types of processing methodsand their major unit operations;the mining methods that could be used toremove oil shale from the ground andprepare it for aboveground processing;the generic types of retorting methods

SummaryOil shale contains a solid hydrocarbon called

kerogen that when heated (retorted) yields combusti-ble gases, crude shale oil, and a solid residue calledspent, retorted, or processed shale. Crude shale oilcan be obtained by either aboveground or in situ (inplace) processing. In aboveground retorting (AGR),the shale is mined and then heated in retortingvessels. In a true in situ (TIS) process, a deposit isfirst fractured by explosives and then retorted under-ground. In modified in situ (MIS) processing, a por-tion of the deposit is mined and the rest is shattered(rubbled) by explosives and retorted underground.The crude shale oil can be burned directly as boilerfuel, or it can be converted into a synthetic crude oil(syncrude) by adding hydrogen. The syncrude canalso be burned as boiler fuel, or it can be convertedto petrochemicals or refined to obtain finished fuels.Some of OTA’s major findings concerning these min-ing and processing technologies are:

● Limited areas of the oil shale deposits may beamenable to open pit mining. This technique hasnever been tested with oil shale but it is well-

●

●

●

●

●

that could be used to convert the oilshale to liquid and gaseous fuels;the upgrading and refining methods thatcould be used to convert crude shale oilto finished products;the potential markets for shale-derivedfuels;the technological readiness of the majorsteps in the oil shale conversion system;the uncertainties and the research anddevelopment (R&D) needs that are asso-ciated with each major unit operation;andthe policies available to the Governmentfor dealing with the uncertainties,

of Findings

●

●

advanced with other minerals. More oil shale ex-perience has been acquired with undergroundmining, particularly room-and-pillar mining, andpreparing MIS retorts. Although uncertainties re-main, the mining technologies should advancerapidly if presently active projects continue andsuspended ones resume.

TIS is presently a very primitive process, althoughR&D and field tests are being conducted. The prin-cipal advantages of TIS are that mining is notneeded and surface disturbance from facility sitingand waste disposal is minimized. The principaldisadvantages are a low level of technologicalreadiness, low recovery of the shale oil, and a po-tential for surface subsidence and leaching of thespent shale by ground water.

MIS is a more advanced in situ method. It is beingfurther developed on two lease tracts and a pri-vately owned site. The Department of Energy(DOE) is providing substantial R&D support. Theprincipal advantages of MIS are that large depos-

119

120 ● An Assessment of Oil Shale Technologies

its can be retorted, oil recoveries per acre affectedare high, and relatively few surface facilities arerequired. However, some mining and some dis-posal of solid wastes on the surface are required,and the oil recovery per unit of ore processed islow relative to AGR methods. The burned-out MISretorts have a potential for ground water pollution.

● AGR also has a medium level of technologicalreadiness. Three retorts have been tested for sev-eral months at rates approaching one-tenth the ca-pacity of commercial-size modules. Others are stillat the laboratory or pilot-plant stages. The princi-pal advantage of AGR processing is high oil recov-ery per unit of ore processed. However, with somemining methods, oil recoveries per acre may belower than with MIS. Surface disturbance is high-est with AGR because of the extensive surface fa-cilities, and because large quantities of solidwaste are generated.

● The physical and chemical properties of crudeshale oil differ from those of many conventionalcrudes. However, depending on the nature of theupgrading techniques applied, the syncrude canbe a premium-quality refinery feedstock, compar-able with the best grades of conventional crude.Shale oil is a better source of jet fuel, diesel fuel,and distillate heating oil than it is of gasoline. Al-though some technical questions remain, the up-grading and refining processes are well-ad-vanced. Refining shale oil may cost from $0.25 to

●

●

$2.00 more per bbl than refining some of thepoorer grades of domestic crude.

The initial output from the pioneer oil shale in-dustry will probably be marketed near the oil shaleregion. Once the industry is established, the shaleoil will probably be used as boiler fuel or refined inthe Rocky Mountain States. A large industry willmost likely supply oil to Midwest markets. A 1-million-bbl/d industry could completely displacethe quantities of jet, diesel, and distillate heatingfuels that are presently obtained from foreignsources in the entire Midwest.

With the present technical status of the criticalretorting processes, deploying a major oil shale in-dustry would entail appreciable risks of techno-logical and economic failure. Although much R&Dhas been conducted, and development is proceed-ing, the total amount of shale oil produced to dateis equivalent to only 10 days of production from asingle 50,000-bbl/d plant. Because of its primi-tive status, much basic and applied R&D is neededfor the TIS method. The MIS approach and someof the AGR processes are ready for the next stageof development—either modular retort demonstra-tions or pioneer commercial-scale plants. Suchdemonstrations would be costly, but they wouldsubstantially reduce the risks associated with themuch larger capital investments needed to createan industry,

An Overview of Oil Shale ProcessingConverting shale in the ground to finished broken with explosives to create a highly

fuels and other products for consumer mar- permeable zone through which hot fluidskets involves a series of processing steps. can be circulated; andTheir number and nature are determined by ● AGR processes in which the shale isthe desired mix of products and byproducts mined, crushed, and heated in vesselsand by the generic approach that is followed near the minesite.in developing the resource. The alternative Figure 19 is a flow sheet for the steps com-approaches are: mon to all three options. How the steps would

●

●

TIS processes in which the shale is left be integrated in an AGR facility is shown inunderground, and is heated by injecting figure 20. In the first step, the oil shale ishot fluids; mined and crushed for aboveground process-MIS processes in which a portion of the ing, or the deposit is fractured and rubbledshale deposit is mined out, and the rest is for in situ processing. The main product is

Ch 5– Technology 121

Figure 19 .– Oil Shale Utilization

Mining & Crushingor In situ retort

Wastes &b

preparation byproducts7

Treated Re-Use~ % * Reinfectionm ~ water Discharge

a ~o

Y ?- #

Wastes & ResiduesRetorting Treatment # \

byproductsDisposal

TA

~ ~@

6 ~ Sulfur, NH3,*

Industrial●

byproducts markets

71 f

Upgrading< Wastes &

byproducts

I

9‘ransportatonm ‘ef’n’ng l’=% “strbut”n t-+ C==laMay not be nee~e(j for some in S1 tu methods

SOURCE Off Ice of Technology Assessment

raw oil shale with a particle size appropriatefor rapid heat transfer. Nahcolite ore can beone of the various byproducts from this step.Dust and contaminated water are among itswastes, In the retorting step, the raw oil shaleis heated to pyrolysis temperatures (about1,000° F (535° C)) to obtain crude shale oil.Other products are the spent shale residue,pyrolysis gases, carbon dioxide, contami-nated water, and in some cases additionalnahcolite and dawsonite ore. The crude shaleoil may be sent to an upgrading section inwhich it is physically and chemically modifiedto improve its transportation properties, toremove nitrogen and sulfur, and to increaseits hydrogen content. (Crude shale oils fromsome in situ processes may not need upgrad-ing before transportation. ) Contaminated airand water, and in some units refinery coke,are the wastes produced along with gases

that contain sulfur and nitrogen compounds.Depending on the extent of the treatment, theupgraded product—shale oil syncrude-canbe a high-quality refinery feedstock, compar-able with the best grades of conventionalcrude. In the refining step, which may be con-ducted either onsite or offsite, hydrogen isadded to convert the syncrude to finishedfuels such as gasoline, diesel fuel, and jetfuel. The syncrude, or the crude shale oil,could also be used directly as boiler fuel.After refining, the fuels are distributed toconsumer markets. Refining also produceswaste gases and various contaminated con-densates.

To protect the environment, contaminatedwater must be treated for reuse in the oilshale facility, for reinfection into the groundwater aquifer source, or for discharge into

122 ● An Assessment of 01/ Shale Technologies

Figure 20.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTSFROM UPGRADING UNITS

. Low Sulfur Fuel Oil . Ammorwa● Liquefied Petroleum Gas ● Sulfur. Coke

UPGRADING UNITS u RETORT UNITS

-— . . w-

de Convevors-. == . - . ,.-< -– !* .; ;... . . . . .. + . . . .. Sha ,

= - . . .s. . , ,... ., . Processed.: - - ““ - ,— /. -. ., L

. . . . . — - Y.\

b, 7 “- ‘ Catchment Dam. .

/ Surface RunoffWater reused

HEADFRAME DISCHARGESTATION

surface streams. Contaminated air and proc-ess gases must be purified to meet Federaland State air pollution standards before theycan be discharged to the atmosphere. Thewaste gases from retorting, upgrading, andrefining are potential sources of ammonia(for fertilizer and other uses) and sulfur (forsulfuric acid and many other materials).These can be recovered during the treatmentsteps and sold to industrial processors. Insome portions of the Green River formation,the solid residues from mining and retortingwill contain nahcolite (which can be used toproduce soda ash and for stack gas scrub-

[_

TIPRIMARYCRUSHING

i

r~L ~-.=.

Roof Upper BenchLoading

---:, .4*!BOMng ScaImg Dnllmg and Blasting x . -’

,.-1 . - . —

——

gr~~;g;$f~

—.. </, .:.: - - ‘ ) “—-

$;::. {

.“ 1?~~ Drdlmg} Lower Bench

/ - -~—, ”

ROOM AND PILLAR MINING(Several Hundred Feet or moreUnderground)

SOURCE C b Shale 01 I Project Defa(led Deve/oprnenf Plan and Re/ated Mater/a/:

u

SKIP LOADING STATION

Ashland 011, Inc and Shell 011 Co , February 1976, p 1-24

bing) and dawsonite (a source of aluminummetal). In any case, spent shale from above--ground processing must be moistened, com-pacted, and revegetated to prevent erosionand leaching. Retorted shale in in situ retorts,and spent shale from surface operations thatis backfilled into underground openings, mustbe protected from leaching by ground water.

This chapter deals with the processingtechnologies used in mining, retorting, up-grading, and refining. Technologies for treat-ing air, water, and solid wastes are discussedin chapter 8.

Ch 5– Technology ● 123

Oil ShaleBoth MIS and AGR require mining. In the

case of AGR, the mined shale is conveyed toretorts where it is processed to recover shaleoil. With MIS, the shale may also be retortedaboveground, or it may be discarded on thesurface as a solid waste.

Green River oil shale deposits are charac-terized by their extreme thickness and bytheir extensiveness. The richer shale zones inthe Piceance basin, for example, are morethan a thousand feet thick, in places, and arecontinuous over an area of 1,200 mi2. Depos-its of this nature could be amenable to eithersurface mining (strip or open pit) or to under-ground mining methods (such as room and pil-lar), depending on topographical features, ac-cessibility, overburden thickness, presence ofground water in the mining zone, and manyother factors. Surface mining may be feasiblefor very thick oil shale zones that are notdeeply buried, especially if their average oilyield is not high, Because of the thickness ofthe overburden, only a limited area of thePiceance basin and somewhat more of theUinta basin and the Wyoming basins is amen-able to surface mining. In other areas,streams have eroded gulleys and canyonsthrough the shale beds, exposing some of thericher shale zones. Shale that outcrops inthese areas, plus the shale in all deeplyburied beds, will probably be extracted byunderground mining,

Despite the high price of crude oil, oil shaleis a lean ore compared with many ores thatcontain valuable metals. Economies of scaleencourage massive mining installations, re-gardless of the mining method selected. Aprospective developer once characterizedcommercial-scale oil shale mines as “prodi-gious, ” because it connotated a larger sizethan “giant.’” A sense of this can be con-veyed by comparing their capacities withthose of more conventional mines. At present,the largest surface mine in the United Statesis Kennecott Copper’s Bingham Canyon pit inUtah, which produces about 110,000 ton/d ofcopper ore. The largest underground mine is

Miningthe San Manuel copper mine in Arizona,which yields about 50,000 ton/d of ore, About70,000 ton/d of 30 gal/ton oil shale wouldhave to be mined to support a single 50,000-bbl/d plant that used aboveground retorts. *This mine would be substantially larger thanthe San Manuel mine. A 400,000-bbl/d indus-try of aboveground retorts would have tomine about 560,000 ton/d—the equivalent of5 Bingham Canyon pits or 11 San Manuelmines. If the same industry used only MIS,about 230,000 to 460,000 ton/d would have tobe mined—the equivalent of four to sevenSan Manuel mines. ** Some of the mining

techniques that could be used to achievethese levels of production are describedbelow.

Surface Mining

The two principal types of surface mining—open pit and strip—both have been widelyused to develop coal seams and deposits ofmany other minerals. Their technical aspectsare fairly well-understood for these minerals.However, their feasibilities and effects varywith the nature of the ore body. Neither tech-nique has yet been applied to the oil shales ofthe Green River formation.

Surface mining is economically attractivefor large, low-grade ore deposits because itpermits high recovery of the resource andallows sufficient space for very large and ef-ficient mining equipment. An open pit minecould recover almost 90 percent of the oilshale in a very thick deposit. Strip miningcould provide even higher recoveries. In con-trast, underground mining would recover lessthan 60 percent. One of the reasons that in-dustry’s bids on a lease for Federal tract C-awere so high was that the deposit could be

*This assumes recovery of 100 percent of Fischer assay oil,a recoverv efficiency that h:)s been achieved in tests of the“rOSCO 11 technology.

**This assumes mining of 20 to 40 percent of the shnle in theretort volume, and an oil recovery of 60 percent of Fischerassay.

124 ● An Assessment of 011 Shale Technologies

mined by open pit methods. About five timesas much shale could be recovered by open pit,which could have mined the entire deposit,than by underground room-and-pillar mining,which would have been limited to a relativelythin zone.2

A mature open pit mine is shown in figure21 and the steps in its operation in figure 22.In the first step, overburden is drilled andblasted loose over a large area above the oilshale zone. The burden is carried by trucks orconveyors to an offsite disposal area. Whenenough burden is removed to expose the shalebeds, the shale itself is drilled and blasted,and is hauled from the pit for processing inaboveground retorts. As mining proceeds, ahuge hole is formed, extending from the top ofthe overburden to deep into the oil shale de-posit. The walls of the pit are under pressurefrom the overburden, and must be angled out-

Figure 21 .— An Open Pit Oil Shale Mine

Off site disposal

Ov n

SOURCE Hear/rigs on 0// Sha/e Leasing, Subcommittee on Minerals, Materials,and Fuels of the Senate Commltee on Interior and Insular Affairs,94th Cong 2d sess , Mar 17, 1976, p 84

wards to transmit the pressure without col-lapsing.

Open pit mining was originally proposedfor tract C-a by the Rio Blanco Oil Shale Co.,the lessee. The pit was to have started in thenorthwest corner of the tract, and eventuallyto have covered its entire surface. After afew decades, freshly removed overburdenand spent shale from the aboveground retortswould have been returned to the pit as back-fill. In the interim, the solid wastes wouldhave been disposed of on a highland to thenortheast of the tract boundaries. This con-cept was abandoned when the Department ofthe Interior (DOI) refused to allow offtractwaste disposal. Rio Blanco later switched toMIS techniques because the alternative—un-derground mining—would have reduced re-source recovery and threatened profitableoperations. * At present, there are no plansfor any open pit mines, although Rio Blancomay reconsider its original plan if offsite dis-posal were allowed.3

In strip mining, overburden is removedwith a dragline—a massive type of scrapershovel. When the dragline has filled its scoop,it pivots and dumps the burden into an adja-cent mined-out area. One difference betweenopen pit and strip mines is that in strip min-ing, the burden is simply cast into a nearbyarea; in open pit, it must be moved far fromthe minesite to prevent interfering with thedevelopment of the pit. Strip mining has notbeen proposed for any of the Green River de-posits.

Surface mining of most oil shale deposits ismade difficult by the great thickness of theoverburden that covers them. In the center ofthe Piceance basin, for example, the 2,000-ft-thick oil shale zones are buried under about1,000 ft of inert rock and very lean oil shale.This does not necessarily preclude surfacemining, because the deposits are generallycharacterized by a favorable stripping ra-tio—the ratio of overburden thickness to ore-body thickness. The thick beds in the centerof the Piceance basin have 1 ft of overburden

*This change in plans is discussed in vol. 11,

Ch 5–Technology 125

Figure 22.—Open Pit Oil Shale Mining

II

Jl-.-/

OVERBURDEN

t4 0 -– —“ — “ — — “

1OIL SHALE

SOURCE U S Energy Oullook–An Ifrtenrn RePort The National Petroleum Council Washington D C 1972

for every 2 ft of oil shale—a stripping ratio of1:2. With coal, a stripping ratio of 10:1 isoften economically acceptable. A study by theNational Petroleum Council indicates thatopen pit mining would be favored for strip-ping ratios between 2:1 and 5:1, strip miningfor smaller ratios, and underground miningfor larger ratios than 5:1.’

However, the economic principles of coalmining should be applied with caution to oilshale. Removing 1,000 ft of overburden to re-cover 2,000 ft of shale might be possible intheory, but the pit’s boundaries would be soextensive that it would have to be located ona very large tract. Furthermore, the large“front-end” investment in removing overbur-den many years in advance of retorting wouldprobably make open pit mining of deep depos-its uneconomical. Also, strip mining wouldnot be feasible in many parts of the oil shaleregion, even those with favorable strippingratios, because the dragline would have toreach to the bottom of a 3,000-ft-thick layer ofoverburden and oil shale. It is not clear thatsuch a machine could be built.

Underground Mining

Many underground mining procedureshave been proposed for oil shale deposits5-10

but to date only room-and-pillar mining andmining in support of MIS retorting have beentested at any significant scale. In room-and-pillar mining, some shale is removed to formlarge rooms and some is left in place, as pil-lars, to support the mine roof, The relativesizes of rooms and pillars are determined bythe physical properties of the shale, by thethickness of the overburden, and by theheight of the mine roof. Most of the depositsof commercial interest are very thick andhave relatively few natural faults and fis-sures. The ore itself resists compression andvertical shear stresses. These propertiesallow the use of large rooms, and relativelylittle shale needs to be left as unrecoverablepillars.

The U.S. Bureau of Mines (USBM) studiedunderground mining of oil shale at the AnvilPoints Experimental Station in the late 1940’sand early 1950's. 11 The primary purpose of


the mining program was to supply raw shale mining plan proposed for Colony Develop-for the Bureau’s retorting experiments, but ment’s 46,000-bbl/d facility in the Piceancethe program was also designed to develop a basin. 12 The rooms are 60 ft wide; the pillarssafe, low-cost mining method. The room-and- are 60 ft square; and the mine roof is 60 ftpillar technique was adopted after extensive high. Mining is conducted in two 30-ft-hightesting. From their studies, which included benches. The upper bench is mined first byenlarging the rooms until the roof failed, the drilling blastholes into the walls of a produc-investigators concluded that for safe mining tion room, and breaking the shale loose withconditions the rooms should be 60 ft wide explosives. The broken shale is carried bywith pillars that are 60 ft on a side. trucks to the crushers where it is crushed to

the size range required by the TOSCO 11Many of the modern mine designs have aboveground retorts. The walls and the roof

been patterned after the USBM experimental of the new room are then “scaled” to removemine. The design depicted in figure 23 is the shale that was loosened by the blasting but

Figure 23.—The Colony Room-and-Pillar Mining Concept

SOURCE R W Marshall Colony Development Operation Room. andPlllar 011 Shale Mlnlng, ” Quarterly 01 the Colorado School o/ Mines, VOI 69, No 2 April 1974. PP171 184

Ch 5–Technology ● 127

did not fall. Holes are drilled into the roof,and roof bolts are inserted to assure its integ-rity, thus protecting the miners from rooffalls. The USBM studies indicated that roofbolts would have to be installed in the accesspassageways but not in areas that were ac-tively being mined. These production roomswould be vacated long before there was anyserious danger of roof falls.

The lower bench is mined next, The se-quence is similar except the blastholes aredrilled into the floor of the upper bench, andadditional roof bolting is not needed, The cy-cle of drilling, blasting, loading, scaling, androof bolting was designed to produce about66,000 ton/d of shale. About 60 percent of theshale in the mining zone was to be removedfor processing in the aboveground retorts.The rest was to remain in the support pillars.Colony estimated that enough shale is presentin the 60-ft seam to support the retorting fa-cility for at least 20 years.

The same type of mine was proposed by theColony partners for development of tract C-b,after considering longwall mining, long-holeblasting, continuous mining, block caving,open pit mining, in situ processing, and manyother options. The major advantages of theroom-and-pillar method were identified as: 13

it is highly flexible and can easily bemodified to accommodate new condi-tions, new equipment, or technologicaladvances:it can be highly mechanized and highoverall production rates can be achievedbecause many areas can be mined simul-taneously:the mine openings are relatively easy toventilate:development of access passageways isalso a production operation because oilshale would be removed; andthe mine could be designed to minimizesurface subsidence.

disadvantages were the high cost of theroof support system and the relatively low re-covery. In this regard, it was estimated thatonly 30 to 50 percent of the shale in a 75-ft-thick interval could be recovered. Higher re-

coveries would be possible if the pillars weresubsequently mined out or if the mining wereconducted on multiple levels. (See figure 24, )

Figure 24. —Room-and-Pil lar Miningon Multiple Levels

&

\~ Pillar. Room

, >ill~ Mining

L e v e l

SOURCE Hearing on 0// Shale Leas/rig Subcommittee on Minerals Materialsand Fuels of the Senate Comm It lee on I n Ierlo r and I n su Iar Affairs94th Cong 2d sess Mar 17 1976 p 83

The mine eventually would have extendedunder the entire surface of tract C-b, asshown in figure 25. However, the conceptwas abandoned when it was discovered thatthe shale in the mining zone was highly frac-tured—a condition that would have requiredlarge support pillars thus reducing resourcerecovery to uneconomic levels. All of theoriginal partners subsequently withdrewfrom the tract, and it is now being developedby MIS methods by Occidental Oil Shale andTenneco Oil Co.

Mining to prepare for MIS retorts is dis-tinguished from room and pillar both by thevolume of the deposit that is disturbed and bythe configuration of the disturbed areas. Asindicated, the underground mines both on theColony property and on tract C-b would havebeen developed in a 60-ft-high mining zone;

.


Figure 25.—The Original Mine Development Plan for Tract C-b

~– BoUNDARy OF TRACT C-B#

mlllr--nl l-----~”--!n ,/ - :...--. ...1

1--- - - - - - - +-------- - - - - J-

1---------!1 , 1~---------l----------il ! IIII : II II I 1 -.. .-. -. J . -. J 4111} 1- t . 11 II -

1--- ’’-----;1 I -i ‘---”----1 ------- II ‘ II—— —

ST- / : 11111 -––- ‘- - - –-=---” / “/’

I ‘------1 ~i ~~- ‘- -- I !I

~ 1 iI N

Lc!_!_J[

11 l--‘-J: II o

IRAISE TO 0:

20m

‘ uRFACE \ I I ~:~

i - ::::::T-- . - . ,

‘ - ’ - Z%i‘ ?!’;’:;‘“i ‘ ] ‘

—. I/_7 EXHAUST I

SHAFT

1 .~ - - - - - - - - .:- .“. 1

1. ,~- ;

‘i I------- . . . . . j

I I I I I l:%%% I ~------ ---------

I

I I II[....-..-:::-”:::::; ‘ 1-------------,1 sHAm, .tqw i IT

i SHOP EXHAUST RAISES/ r - - -... ~ -~-- -- .–. --

I /[ I000000[noooooc.--.._A. I

II ! 11111 I

+i 1“--- ‘- - - ‘ - ‘ \L------ ----- -j= PLANT 8SHA~ PILLAR

1

} ‘- --- ”---;I 11 I+w I ‘-

SOURCE C-b Shale 011 Project, Detaded Deve/OPmefrt plan and Relafed MaterlalS, Ashland 011, Iflc , and Shell 011 Co , February 1976, p IV-1 1

present plans for the MIS operations on in which the MIS retorts will be created, plustracts C-a and C-b call for recovering oil from shafts from the surface for ventilation, drain-the shale in a 750-ft-high zone. However, the age, passageways for the miners, and trans-actual mining required to support this devel- portation of combustion air and retortingopment will take place in relatively confined products. Some of the mining plans are dis-areas. The mine will consist primarily of fair- cussed later in the section on MIS retortingly small underground openings in the region methods.

Oil Shale RetortingThe three generic methods for recovering True In Situ

shale oil from oil shale deposits are describedbelow. Brief discussions of some of the more The sequential steps in TIS processing are:significant R&D programs that have been con-ducted as part of their development are in- 1. dewatering, if the deposit occurs in aeluded. ground water area;

Ch. 5–Technology ● 129

2.

3.

4.

The

fracturing or rubbling if the deposit isnot already permeable to fluid flow;injection of a hot fluid or ignition of aportion of the bed to provide heat for py-rolysis; andrecovery of the oil and gases throughwells.

principles of TIS processing are illus-trated in figure 26. Several types have beenproposed that differ from each other with re-spect to the methods for preparing and heat-ing the deposit. All use a system of injectionand production wells that are drilled accord-ing to a prescribed pattern. One that is com-monly used is the “five-spot” pattern in whichfour production wells are drilled at the cor-ners of a square and an injection well isdrilled at its center. The deposit is heatedthrough the injection well and the productsare recovered through the production wells,

For efficient TIS processing, the depositmust be highly permeable to fluid flow, whichis true of portions of the Green River oilshales. A good example is the Leached Zone

of the Piceance basin where ground waterhas dissolved salt deposits to leave largerubble-filled zones. It is estimated to containabout 550 billion bbl of shale oil in place. 14

There are interconnected fractures and voidsin other areas of the formation, but these, ingeneral, have only a very limited permeabili-ty. The permeability of most of the zones thatappear to have commercial promise is essen-tially zero. Deposits that lie near the surfacecould be fractured by injecting water or ex-plosive slurries, but mining would probablybe needed to increase the permeability ofdeeply buried deposits. MIS or AGR proc-esses are more appropriate for the deeper re-sources.

In 1961, Equity Oil Co. began developing aTIS process for the Leached Zone, which wastested in the Piceance basin between 1966and 1968. It involved dewatering a portion ofthe zone followed by injecting hot natural gas.Pyrolysis gases and a small amount of oilwere swept in the natural gas stream to pro-duction wells through which they were

Figure 26. —True In Situ Oil Shale Retorting

1? 11

PRC‘DUC1NGWWQM13

SOURCE B F Grant Retorting 011 Shale Underground—Problems and Posslbllltles, ouarfedy of the Co/orado Schoo/ ofM(nes VOI 59, No 3, July 1964, p 40

130 . An Assessment of 01/ Shale Technologies

pumped to the surface. The gas was sepa-rated from the oil, reheated, and reinfectedinto the deposit. The oil had a much lowerpour point, viscosity, and nitrogen contentthan oils from aboveground retorts. * Thesefavorable characteristics may have been re-lated to the solvent properties of the naturalgas, and to the absence of oxygen from the re-torting zone. The quality of the retort gaseswas also good, partly because of their naturalgas component, and partly because during re-torting combustion and the decomposition ofcarbonate minerals were minimal. **

Process development was not pursued be-cause too much of the natural gas was lost inthe unconfined formation. In 1968, AtlanticRichfield Co. (ARCO) purchased an interest inthe process and resumed its development. In1971, a revised concept was announced inwhich superheated steam, rather than natu-ral gas, was to be used to heat the deposits. In1977, DOE contracted with Equity to test theconcept in a 50()-f t-thick seam in the LeachedZone of the Piceance basin. The seam under-lies about 0.7 acre of surface, and containsabout 700,000 bbl of oil in place. It has beenestimated that as much as 300,000 bbl couldbe recovered over a 2-year period, with abouthalf of the oil produced in the first 7 months. ’sSteam injection has begun at the site, and willcontinue through 1981. No detailed estimateshave yet been released of production rates orretorting efficiency. If the process proves tobe technically and economically feasible, itcould be applied in portions of both the Pice-ance and the Uinta basins.

At present, no work is being done in slight-ly fractured formations, but much research isbeing performed to develop methods for in-creasing their permeability by enlarging nat-ural fractures and creating new ones. Some

*rI’hese properties have economic significance. Pour point isthe lowest temperature at which oil will flow. Oils with highpour points are hard to transport because they solidify at nor-mal ambient temperatures. Viscosity is a measure of a fluid ”sresistance to flow. Oils with high viscosity are expensive topump. Reducing the high nitrogen content of most crude shaleoils consumes hydrogen, which is costly.

**Both of these processes produce carbon dioxide, which isa major constituent of gases produced by some above-ground re-torts.

of the fracturing techniques used have beenchemical explosives, electricity, and injectinghigh-pressure air and water. These methodshave been used to enhance recovery of con-ventional petroleum; oil shale fracturingposes a similar problem. Nuclear explosiveswere also proposed in the 1960’s, but werenot tested because of their potential for harm-ing the environment, A nuclear test—ProjectRio Blanco—was conducted in the Piceancebasin to fracture sand formations containingnatural gas. The test failed.

The earliest TIS work was by Sinclair OilCo., between 1953 and 1966. A thin section ofshale in the Mahogany Zone of the Piceancebasin was fractured by injecting air. The bedwas ignited, although with difficulty, and asmall quantity of shale oil was collected be-fore the hot shale swelled and sealed thefractures. After additional tests, Sinclair con-cluded that the zone’s limited permeabilitywould not permit profitable operations. *

Research on TIS processing began atUSBM in the early 1960’s. In 1974, the pro-grams and personnel were transferred to theEnergy Research and Development Adminis-tration, and in 1978, they moved to DOE. TheR&D programs have included laboratory ex-periments, computer simulations, pilot-plantstudies, and field tests. Among the latterwere tests of electrical, hydraulic, and ex-plosive fracturing and combustion retortingnear Rock Springs, Wyo. These revealedsome of the problems associated with the TISapproach. In one early test, for example,after inert gas at about 1,300° F (7050 C) waspumped into a fractured formation for a peri-od of 2 weeks, about 1 gal of shale oil was re-covered. In another experiment in a zone thatcontained 7,800 bbl of shale oil in place, itwas estimated that only 60 bbl of the close to1,000 bbl that were released were actuallyrecovered.

Low oil recoveries are often associatedwith TIS processing because of the large im-

*rI’he results of a mathematical simulation indicated thatabout 18 years of continuous steam injections would be re-c~uired to heat the shale to pyrolysis temperatures within a 30-ft radius of a fracture.


permeable blocks of shale in the fracturedformation. These cannot be fully retorted in areasonable length of time. Irregular fractur-ing patterns that can cause the heat carrierto bypass large sections of the deposit areanother problem. Oil shale that is located inthe bypassed regions will not be retorted,And, even if all of the shale in a fracturedarea were retorted, much of the oil would notreach the production wells, but would remaintrapped in the pores of the spent shale orwould diffuse beyond the production wells, tobe lost in surrounding areas.

To develop methods for improving recov-ery, an extensive R&D program has been con-ducted at the Federal research center in Lar-amie, Wyo. Aboveground batch retorts withcapacities of both 10 and 150 tons of shalehave been used to simulate in situ retorting,but under more controlled conditions than ex-ist underground. Oil recoveries of up to 67percent have been achieved, and an experi-ment in a “controlled-state” retort achieved95-percent oil recovery. *

In 1976 and 1977, the program was ex-panded to include field tests of different frac-turing and retorting techniques under cost-sharing contracts with Equity Oil, Talley -Frac, Inc., and Geokinetics, Inc.** The Equityprogram has been described. The Talley-Fracprogram was terminated after the fracturingmethod failed. The Geokinetics process uses afracturing technique called surface uplift inwhich an explosive is injected into severalwells and detonated to fracture the shale andmake it permeable to fluid flow, The shale isignited by injecting air and burning fuel gasthrough one well. It is pyrolyzed by the heatthat sweeps through the bed in the gasstream, Oil and gases are pumped to the sur-face through outlying production wells. It ishoped that the technical feasibility of the

*rI’he large retorls resemble the classic Newia-Tex:]s-Utah(N’I’U) retort that is described later in this chapter. Because ofthe higher percentage of void volume in the rubble, these re-torts provided better simulations of hlIS processing thtin of‘1’1S. “1’he controlled-state retort was much smfiller and wasequipped for better cent rol of retortin~ renditions.

**Tbe procurement also included a contract with OccidentalOil Shale, Inc., to develop its MIS process, which is discussed inthe next section.

process can be demonstrated for thin depos-its that are covered by less than 100 ft ofoverburden. It has been estimated that thereare at least 6 billion bbl of shale oil in place inthis type of deposit. It is common in the Uintabasin,16) and at present, would be most eco-nomically developed by strip mining.

Geokinetics has been investigating the sur-face uplift approach since 1973, and is pres-ently burning its 20th retort in Utah. Thelargest retort prior to 1979 measured 130 ftby 180 ft by 30 ft thick. A retort about 200 fton a side and 30 ft thick will be required todemonstrate the technical feasibility of theprocess. By 1982, DOE and Geokinetics hopeto have developed a commercial-scale opera-tion with a production capacity of 2,000bbl/d.17

Modified In Situ

In MIS processing, the permeability of oilshale deposits is increased by mining someshale from the deposit and then blasting theremainder into the void thus created. Thetwo-step process is depicted in figure 27. Inthe first step, a tunnel is dug to the bottom ofan oil shale bed, and enough shale is removedto create a room with the same cross-section-al area as the future retort. Holes are drilledthrough the roof of the room to the desiredheight of the retort. They are packed with ex-plosives that are detonated in the secondstep. A chimney-shaped underground retortfilled with broken shale results. The accesstunnel is then sealed, an injection hole isdrilled from the surface (or from a highermining level) to the top of the rubble pile. Thepile is ignited by injecting air and burningfuel gas, and heat from the combustion of thetop layers is carried downward in the gasstream. The lower layers are pyrolyzed, andthe oil vapors are swept down the retort to asump at the bottom from which they arepumped to the surface. The burning zonemoves slowly down the retort, fueled by theresidual carbon in the retorted layers. Whenthe zone reaches the bottom of the retort, theflow of air is stopped, causing combustion tocease.

132 An Assessment of Oil Shale Technologies

Figure 27. —Modified In Situ Retorting

STEP A

/OVERBURDEN

F--- —~ 7— 7 – 7— B L A S T H O L E S

‘/////Al LEAN SHALEREMOVED FOR

/ / / / / / l I OR DISPOSAL

/

STEP B GAS TO---–

,- d:

–~ PURIFICATIONRECYCLE GAS ~~, ~BLOWER .COMBUSTION. AIR—

.—

OVERBURDEN

——.n/ ’ b-, <-/ .< ,(![ 1

,,/, /‘,/ , //,

‘ / ,/‘/ //,/ ,!’ , / , ,

//,/ :/,{’ k J/ , ‘,,

/ /,’/ , //// , .v’ ] //,/1‘ ‘ i \ RUBBLED SHALE

P-——————=——————”’SOURCE T A Sladek Recent Trends In 011 Shale — Part 2 Mlnlng and Shale 011 Extraction Processes Mjnera/ /rrdus/rles Bu//e/lrr VOI 18 No 1 January 1975, p 18

Phofo credif OTA staff

Head frame at tract C-a

Occidental Oil Shale, Inc., a subsidiary ofOccidental Petroleum (Oxy) has demon-strated the MIS process, 18 Oxy’s work beganin 1972 on the D. A. Shale property alongLogan Wash—a private tract on the southernfringe of the Piceance basin about 50 milesnortheast of Grand Junction, Colo. To date,six retorts have been burned at the site, withvarying degrees of success. The first retortwas about 32 ft on each side and 70 ft high.About 60 percent (1,200 bbl) of the shale oil inplace was recovered, comparable to the bestresults from USBM’s experiments at Lara-mie, The next two retorts were slightlylarger, and performed similarly, The fourthretort was of nearly commercial size—120 fton each side and 270 ft high. It containedabout 32 times as much shale as the first re-tort and yielded about 25 times as much oil.The fifth was the same size but was designedfor a much lower void volume. The rubblingstep did not evenly distribute the void volume,and the performance was poor. Only 40 per-cent of the oil was recovered. The burning of


retort 6 began in 1978, but the sill pillar—thelayer of unbroken shale that caps a retort—collapsed into the rubble pile. Operationswere disturbed while the top was resealed,but retorting was eventually completed, andabout 40 percent of the oil was recovered.DOE will share the costs of retorts 7 and 8,which are scheduled for 1980 and 1981,

The oil shale at the Logan Wash site is notconsidered to be of commercial quality be-cause of its low kerogen content. In 1976, Oxyacquired access to the higher quality re-sources of tract C-b by exchanging its tech-nical knowledge for a half interest in thelease. In 1978, Ashland Oil Co., Oxy’s partnerin the C-b Shale Oil Venture, withdrew andleft Oxy in full charge. In 1979, Tenneco OilCo. purchased a half interest in the lease for$110 million and is proceeding to develop thetract in cooperation with Oxy, If presentplans are followed, Oxy’s technology could beused to produce about 57,000 bbl/d by 1985.

Oxy’s technique uses a vertical burn con-figuration— that is, the combustion zone pro-gresses vertically through the shale bed. It isalso theoretically possible to advance theburn front horizontally, in much the sameway as it is done in TIS processing. A crudeversion of this approach was implemented inGermany during World War II, when a fewMIS retorts were created by digging tunnelsinto oil shale deposits and then collapsingtheir walls into the void volume. These opera-tions were short-lived because oil recoverieswere extremely low, and they were very hardto control. 19

Horizontal MIS might be practical if a tech-nique could be developed to remove large sec-tions of oil shale strata. One possibility is touse solution mining: the injection of fluids intothe formation to dissolve soluble salts fromamong the oil shale layers, The result wouldbe a honeycomb pattern of voids that couldthen be distributed throughout the area to beretorted by injecting and detonating an explo-sive slurry. This method would be limited toareas like the Leached Zone or the SalineZone that contain significant concentrationsof soluble salts. Other methods, such as long-

wall mining or mechanical underreaming,could be used in other areas. It might be pos-sible to operate mechanical underreamingmachines by remote control from the surface,thus reducing or even eliminating the needfor miners to work underground. None ofthese approaches has been tested in any oilshale deposit.

Other MIS techniques that use vertical-burn patterns have also been developed. Forexample, the firm of Fenix and Scisson de-signed two systems for underground mining,rubbling, and retorting in the vertical mode. z’)

To date, they have been tested only with acomputer model. DOE’S Lawrence LivermoreLaboratory has also developed an MIS tech-nique called rubble in situ extraction (RISE)with the aid of computer simulation and lab-oratory experiments in pilot-scale above--ground retorts.21-23 (See figure 28. ) Severallevels are mined, and a portion of the depositis removed at each. The remaining shale isbroken with explosives. Sufficient brokenshale is then removed so that there is a totalvoid volume of 20 percent in the retort area.The rubble is then ignited at the top, and re-torting proceeds as in the Oxy system.

The RISE approach was originally pro-posed by Rio Blanco Oil Shale Co. for tractC-a, but the firm is now going ahead with itsown process, which has benefited from tech-nical information acquired under a licensingarrangement with Oxy. Livermore’s modelingstudies and laboratory experiments are con-tinuing.

The initial plans for developing tract C-a byMIS methods are shown in figure 29. Theywould have involved five precommercial re-torts of increasing size. The present plan,which was adopted after purchase of Oxy’sMIS technology, is shown in figure 30. In thenew development plan, a small pilot retort(retort “O”) will be followed by two demon-stration retorts of increasing size. The largest(retort “2”) will be close to commercial scale.Several options of different size are beingconsidered for retort 2, with one option a re-tort with dimensions 60 ft by 150 ft by 400 fthigh, The method by which the shale is rub-


Figure 28.—The RISE Method of MIS Oil Shale Retorting

~“” ~~~--.—-~ - - -. — --- —-- —--- —- ———-—-—-— ‘- .—.— =.

//-/5OIL OUT/

A. Isometric

I 1 I

I 1Level A

(1

. .. . .? . “ .“.’.s+

Development proceeds simultaneously on several levels. At eachlevel, horizontal drifts are driven the full width of the retort block,and a vertical slot is bored to provide void volume for blasting.About 200/. of the broken shale is removed after each blastingoperation. The rest is left in the retort volume.

. . . . : Sublevel Level B4 Starting slot

‘“’”””””””””””””’!!;:-. . . . . . . . . . . . . . . . . . . . . .~Leve’c

B. Elevation

SOURCES: 01/ Shale Retorting Technology, prepared for OTA by Cameron Engineers, Inc., 1978; and C. K. Jee, et al., Rewew and Analyws of Od Shale Techno/ogy—Vo/ume 3. Mod/tied In Situ Tec/rrro/ogy, report prepared for the U.S Department of Energy by Booz-Allen & Hamilton, Inc , under contract No, EX-76-C-01-2343, August 1977, p. 6.


Figure 29.— Initial Modular MIS Retort Development Plan for Tract C-a

COMMERCIALFIELD 2 1

c’ ‘r

,,. ’

r~.,

)

,. -.-

/ ‘> t -“

SOURCE RIO Blanco 011 Shale Project Revised Deta~/ed De~e/OP~eflt P/an Tracf C a Gulf 011 Corp and Standard 011 Co (Indiana), May 1977 P 125

bled, and the fraction of the shale that ismined from each retort area are two of themajor differences between the Rio Blanco ap-proach and Oxy’s technique. Oxy has testedseveral rubbling methods, including drillingblastholes up from a room at the bottom of theretort, drilling down from the top, and boringa central shaft the full length of the retortand then blasting the surrounding shale intothe shaft. In Rio Blanco’s approach, a roomwill be created at the bottom of the future re-tort, blastholes will be drilled from the sur-face into the roof of the room, and explosiveswill be detonated sequentially at differentlevels, The shale above the room will therebybe blasted loose in layers, with each layer ofrubble falling to the bottom of the retort

volume before the next higher layer isblasted. Through this technique, Rio Blancohopes to obtain uniform size distribution inthe rubble. This is believed to be a key techni-cal requirement for efficient MIS retorting.Rio Blanco also proposes to mine twice thevolume (40 v. 20 percent) as is contemplatedby Oxy.

Another MIS method that is still being de-signed is the integrated in situ technology pro-posed by Multi Mineral Corp. for recoveringshale oil, nahcolite, alumina, and soda ashfrom oil shale deposits in the Saline Zone ofthe Piceance basin. This zone underlies theLeached Zone, is relatively free from ground


Figure 30.— Present MIS RetortDevelopment Plan for Tract C-a

\ Down-Hole

Escape%

Shaft

%=

I’HFVentilation Shaft

Off-Gas Shaft

- Access Shaft

figure 31, If technical and economic feasibili-ty is indicated during the test program, MultiMineral would proceed to a commercial-scalefacility that would produce 50,000 bbl/d ofshale oil, 10,000 ton/d of nahcolite, 1,000ton/d of alumina, and 20,000 ton/d of sodaash.

The Multi Mineral approach resembles theRISE technique in that mining and rubblingare conducted at several levels along theheight of the retort, It departs from RISE inthat, after rubbling, the broken shale in theretort is removed from the bottom, crushedand screened, and returned to the top in acontinuous operation. This part of the retortdevelopment plan is shown in figure 32. Therubbled shale will contain free nahcolite and

+1 I I Ill II II II z SeDaratorFigure 31 .— Retort Development Plan for the

Multi Mineral MIS Concept

SOURCE The Pace Co Consultants and Engineers Inc Cameron Synthe(lcFue/s Report VOI 16 No 3 September 1979 p 28

water, and contains extensive resources ofnahcolite and dawsonite in addition to oilshale. Development is hindered because thezone is deeply buried (about 2,000 ft) belowthe surface of the basin. To reduce the costsof its R&D program, Multi Mineral has pro-posed to use an 8-ft-diameter shaft that wasdrilled by USBM in 1978 through the LeachedZone and into the Saline Zone. In the firstphase, mining and mine safety methods willbe tested, and about 8,000 tons of nahcoliteand 11,000 bbl of shale oil will be produced.The nahcolite will be used for stack-gasscrubbing tests in a powerplant. In the sec-ond phase, a retorting module will be used toproduce up to 3,000 ton/d of nahcolite, 10,000bbl/d of shale oil, 200 ton/d of alumina, and3,000 ton/d of soda ash. The modular retortand the access shafts and drifts are shown in

--(LEVEL B)

.-

(LEVE~D;- -

CROSS CUT

STOPE FLOOR

SOURCE B Welchman, Sa//ne Zone 0// Sha/e Deve/opmen/ by [he /nlegrated/n S/fU Process Multi Mineral Corp Houston Tex December 1979.p 9


Figure 32.— Preparation of a Multi MineralMIS Retort

I< HOLE NO. 1

HOLE NO. 2 ➤

BACKFILLED n

SHAFT

2200’\)/ LEVEL

\

w \

SOURCE B We(c hman Sa/~ne Zone O() Shd/e Deve/oprnent by fhe /nlegrd(edIn SJtu Process M u It I M I neral Corp H o uston Tex December 1979

D 15

nahcolite that is still associated with thelarge blocks of shale. Crushing will liberatemost of the associated nahcolite, and screen-ing will separate it from the shale particles.The shale will be backfilled to the top of theretort; the nahcolite is transported to the sur-face for processing. The result would be a re-tort that is filled with uniformly sized oil shaleparticles. With this configuration, Multi Min-eral hopes to avoid the channeling and by-passing problems that may occur in TIS andMIS processing.

In a commercial-scale facility, the retortswould be operated in sets of three, as shownin figure 33, In retort 3, the oil shale is beingpyrolyzed by injecting hot gases to produceshale oil (which is removed to the surface),

residual carbon, and soda ash and aluminumoxide—the products of the thermal decompo-sition of dawsonite. The last three productsremain in the retort rubble. In retort 2, the re-sidual carbon is being gasified by injecting amixture of steam and air. The heat from thegasification reaction is carried to retort 3. Inretort 1, the hot gasified shale is being cooledby passage of cold recycle gas. The heat thusrecovered is conveyed to retort 2. After theshale in retort 1 is cooled, the soda ash andthe aluminum oxide can be leached out withwater. The leachate is then pumped to thesurface and processed to recover its mineralvalues.

Temperature control is the key to the entireoperation. Oil alone could be recovered witha combustion-type method, such as Oxy’s, butbecause of the high temperatures, the decom-position of the dawsonite would produce com-pounds insoluble in water. The gas-recycleheating method would avoid this problem bymaintaining lower retorting temperatures.The operation also depends on the ability ofexplosive rubbling techniques to producebroken shale that can be fed to conventionalcrushing equipment. Overall, the method isvery interesting because of its potential forsimultaneously recovering fuel and mineralsfrom deposits that may not be accessible withany other approach. However, too little isknown about the various steps to permit athorough evaluation at this time.

Aboveground Retorting

Hundreds of retorts have been invented inthe 600-year history of oil shale development.Most were never brought to the processingstage but some were tested using laboratory-scale equipment, and a few at pilot-plant andsemiworks scales. None has been tested at ascale suitable for modern commercial opera-tions. This section summarizes the technicalaspects of seven retorting systems that offerthe promise of being applicable in the nearfuture. One obsolete technology that is thebasis for severalalso discussed.

of the modern systems is

l – < . . . - 1


Figure 33.— A Set of Multi Mineral MIS Retorts

EXCESSGAS

RETORT 1 RETORT 2 (RETORT 3(HEAT RECOVERY) (CARBON RECOVERY) (PYROLYSIS) tII

COLD RECYCLE GAS I ‘;

TK===========--====-=------=="*----=---*==---------; Iil,1

iIIII

OILIt‘11,1,1,

;1

Ii

t1,I,1

--- - ----- a

SOURCE B Welchman, Sa//rre Zone” 0(/ Shale Deve/oprnerrf by the Irrtegrafed In SIfu Process, Multl Mineral Corp , Houston, Tex December 1979, p 11

Although aboveground retorts differ wide-ly with respect to many technical details andoperating characteristics, they can begrouped into four classes:

Class 1: Heat is transferred by conduc-tion through the retort wall. The Pump-herston retorts used in Scotland, Spain,and Australia were of this class, as isthe Fischer assay retort that was devel-oped in the 1920’s. It is a laboratorydevice for estimating potential shale oilyields. Its oil yield is the standard to ●

which the retorting efficiencies of allother retorts are compared. Becauseconduction heating is very slow, no mod-ern industrial retorts are in class 1.Class 2: Heat is transferred by flowinggases generated within the retort bycombustion of carbonaceous retortedshale and pyrolysis gases. Retorts in thisclass are also called directly heated.

They include the Nevada-Texas-Utah(NTU) and Paraho direct processes de-scribed below, and also USBM’s gascombustion retort and the Union “A”retort. Class 2 retorts produce a spentshale low in residual carbon and low-Bturetort gas. Their thermal efficiencies arehigh because energy is recovered fromthe retorted shale. However, recoveryefficiencies are relatively low—about 80to 90 percent of Fischer assay.

Class 3: Heat is transferred by gasesthat are heated outside of the retort ves-sel. Retorts in this class are also calledindirectly heated. They include the Para-ho indirect, Petrosix, Union “B,” and Su-perior retorts discussed below, and alsothe Union SGR and SGR-3, the obsoleteRoyster design, the Soviet Kiviter, theTexaco catalytic hydrotort, and others.These retorts produce a carbonaceous


spent shale and a high-Btu gas. Thermalefficiencies are relatively low becauseenergy is not recovered from the residu-al carbon, but oil recovery efficienciesare high, from 90 to over 100 percent ofFischer assay.

● Class 4: Heat is transferred by mixinghot solid particles with the oil shale.They include the TOSCO II and Lurgi-Ruhrgas retorts described below, andalso the Soviet Galoter retort. Class 4 re-torts achieve high oil yields (about 100percent of Fischer assay) and produce ahigh-Btu gas. The spent shale may ormay not contain carbon, and thermal ef-ficiencies vary, depending on whetherthe spent shale is used as the heat car-rier. The retorts are sometimes referredto as indirectly heated, as in class 3, be-cause they also lack internal combus-tion, and produce a similar gas product.

Several other conversion methods have beendeveloped that cannot easily be placed inthese classes. These include microwave heat-ing, bacterial degradation, gasification, andcirculation of hot solids slurries. Althoughsome of these processes have potentially val-uable characteristics, they will not be dis-cussed in this section because they have notyet been proposed for near-term commercialapplication.

The Nevada-Texas-Utah Retort

The NTU retort is a modified downdraftgas producer similar to units used in the 19thcentury to produce low-Btu gas from coal. Itis a vertical steel cylinder, lined with refrac-tory brick and equipped with an air supplypipe at the top and an exhaust pipe at the bot-tom. The top may be opened for charging abatch of shale; the bottom for discharging thespent shale after retorting. The unit was de-veloped and tested for oil shale processing bythe NTU Co. in California in 1925, and wasalso tested by USBM at Rifle, Colo., from 1925to 1929. Two units with nominal capacities of40 tons of raw shale were built and operatedby USBM at Rifle between 1946 and 1951.They produced more than 12,000 bbl of shale

oil. Three units that were operated in Austra-lia during World War 11 produced nearly500,000 bbl. As noted previously, USBM usedtwo units to simulate in situ retorting.

The operating sequence for the NTU retortis shown in figure 34. The unit is loaded withcrushed oil shale and sealed. The gas burneris lighted, and air is blown in. Once the top ofthe shale bed is burning (step A), the fuel gasis shut off but the air supply continues. As theair flows through the burning layer, it isheated to approximately 1,500° F (815° C).This hot gas heats the shale in the lower lay-ers and induces the pyrolysis of the kerogen.The oil and gases produced are swept downthrough the cooler portions of the bed to theexhaust port (step B). The solid product fromthe conversion of the kerogen (residual car-bon) remains on the spent shale and is con-sumed as the combustion zone moves downthe retort, providing fuel for additional com-bustion and thereby heat for additional pyrol-ysis. When all the carbon is burned from theupper layers of the bed, the four zones shownin step C are formed. The top layer containsburned and decarbonized spent shale. Thesecond layer is burning, releasing heat for py-rolysis in the third layer. In the bottom layer,the shale is being heated but is not yet at py-rolysis temperatures.

As time passes, the top layer expandsdownward and the lower three zones moveuniformly down the retort. When the leadingedge of the combustion zone reaches the ex-haust port, oil production ceases, air injectionstops, and the retort is emptied. The dumpingof spent shale ash from the 40-ton NTU atLaramie is shown in figure 35. The entirecycle, from ignition to dumping, takes about40 hours.

NTU retorts are simple to operate, and re-quire no external fuel except for smallamounts of gas to start the retorting. Theycan process a wide variety of shales with oilrecoveries ranging from 60 to 90 percent ofFischer assay. They are unsuitable for mod-ern commercial applications because theyare batch units with high labor costs andsmall capacities. Over 600 150-ton retorts

— .


Figure 34.—The Operation of an NTU Retort

r AIR SUPPLY

BLOWER

h- GAS BURNER: ON

SHALE IGNITES:

ED

~1N BURNER GAS AND

)

~1

SHALE OFF-GASHEAT REMAININGSHALE

1- BURNER FLUE GASSMOKE, AND FUMES

STEP A

E— AIR S U P P L Y

BLOWER

GAS BURNER: OFF

STEP B

COMBUSTION ZONE;RESIDUAL CARBON BURNSIN AIR STREAM

PYROLYSIS ZONE:KEROGEN CONVERSIONWITHOUT FURTHERCOMBUSTION

PREHEAT ZONE:SHALE HEATED BYOFF-GAS TO BELOWPYROLYSIS TEMPERATURE

LOW-BTU GAS AND OIL MISTTO SEPARATION EQUIPMENT

r AIR SUPPLY

BLOWER

/%-

GAS BURNER: OFF

}SPENT SHALE ZONE:ALL RESIDUAL CARBON

}

BURNED

COMBUSION ZONE:RESIDUAL CARBON

1

BURNING

PYROLYSIS ZONE;KEROGEN CONVERSION

N!!iN\ \

l\ II‘+

( PREHEAT ZONE;{

Y\\ yt LOW-BTU GAS AND

OIL MIST

STEP C

SOURCE T A Sladek, Recent Trends In 011 Shale– Part 2 Mining and Shale 011 Extract Ion Processes, M(nera/ /ndustr/a/ Elu//ef/n VOI 18 No 1 January 1975 p 5

would be needed to produce 50,000 bbl/d ofcrude shale oil. In contrast, plants using someof the continuous technologies described be-low would require only about six retorts forthe same production capacity.

The Paraho Direct and Indirect Retorts

An NTU retort becomes a Paraho direct re-tort when it is turned upside down, made con-tinuous, and mechanically modified. The Par-aho retorts are based on USBM’s gas combus-tion retort which, in turn, evolved from theNTU retorts tested at Anvil Points in the late1940’s. The gas combustion process wastested in 6-, 10-, and 25-ton/d units by USBMbetween 1949 and 1955, and by a consortiumof six oil companies between 1964 and 1968.The Paraho direct retort is similar in design

to the gas combustion technology but it ismore likely to be commercialized.-It was de-veloped by Development Engineering, Inc.,(DEI) in the late 1960’s, and was tested forlimestone calcining in three cement kilns inSouth Dakota and Texas. Each kiln had a ca-pacity of 330 ton/d and was comparable tothe largest gas combustion retort tested bythe six oil companies.

After verifying the solids-flow character-istics of the Paraho technology in the lime-stone kilns, DEI leased the Anvil Points sitefrom the Federal Government in May 1972,and began a 5-year program to develop thetechnology for oil shale processing. Fundingwas obtained from a consortium of 17 energycompanies and engineering firms. In returnfor a contribution of $500,000, each company


Figure 35.— Discharging Spent Shale Ash From a 40-Ton NTU Retort

.

SOURCE U S Department of Energy

142 ● An Assessment of 0il Shale Technologies

was guaranteed a favorable royalty arrange-ment in any subsequent commercial applica-tion of DEI’s technology. The Paraho Develop-ment Corp. was formed to manage the proj-ect. * Two retorts, a pilot-scale unit 4.5 ft indiameter and 60 ft high and a semiworks unit10.5 ft in diameter and 70 ft high, were in-stalled and tested after August 1973. Theywere used to produce over 100,000 bbl ofcrude shale oil, some of which was used forrefining and end-use experiments by DOEand the Department of Defense. Maximumthroughput rates reached about 400 ton/d inthe semiworks unit. Both direct and indirectheating modes were tested.

The Paraho retort is shown in figure 36,and the Anvil Points semiworks unit in figure37. In its direct mode, the retort is very simi-lar to the older gas combustion design. How-ever, significant differences exist in the shalefeeding mechanism, in the gas distributors,and in the discharge grate. During operation,raw shale is fed to the retort through a rotat-ing distributor at the top. It descends as amoving bed along the vertical axis of the re-tort. As it moves, it is heated to pyrolysis tem-peratures by a rising stream of hot combus-tion gases. The oil and gas produced areswept up through the bed to collecting tubesand out of the retort to product separationequipment. The retorted shale retains the re-sidual carbon. As the shale approaches theburner bars, the carbon is ignited and givesoff the heat required for pyrolyzing addition-al raw shale. Passing beyond the burner bars,the shale is cooled in a stream of recycle gasand exits the bottom of the retort through thedischarge grate. It is then moistened and sentto disposal.

The retort may also be operated as a class3 retort. The configuration would resembledirectly heated operations except that airwould not be injected and the offgas steamwould be split into four parts after oil separa-tion. One part would be the net product gas.Another would be sent through a reheatingfurnace and then reinfected into the middle of

*“ Paraho” is from the Portuguese words “para homen”’—for mankind.

Figure 36.— The Paraho Oil Shale Retorting System

RAWSHALE

(?w ltl-

1 OIL MISTSEPARATORS

- - - - -—-MIST

FORMATIONAND

PREHEATING- — - - - - OILRETORTING OIL

ZONE PRODUCT ru

I I GAS ELECTROSTATIC-- — - --- t PRECIPITATOR

COMBUSTION F 1ZONE

- 4 i----—-RESIDUECOOLING

ANDGAS

PREHEATING\ - - - — - -

/v

4●

t * A A

RECYCLE GASBLOWER

AIR BLOWER

~ SpEED‘yCONTROLLER

RESIDUE

A. Direct Heating M o d e

RAWSHALE

OIL MiSTSEPARATORS

MISTFORMATION

ANDPREHEATING

——-—- — [ ~OILRETORTING OIL

ZONESTACK L—

tGAS ELECTROSTATIC

- - — - —- < HEATER PRECIPITATOR

HEATING0

T RECYCLE GASi—

tBLOWER

----- --RESIDUECOOLING PRODUCT GAS

ANDGAS

~REHEATIN$ AIR BLOWER—— — - -

c?-

‘)1(RESIDUE

B. Indirect Heating Mode

SOURCE C C Shlh, et al Techno/ogma/ Ovefv)ew Reporfs for Eight Sha/e 0//Recovery Processes report prepared for the U S Environmental Pro-tection Agency by TRW under contract No EPA.600/7.79-075 March1979, pp 20 and 23


Figure 37.— The Paraho Semiworks Unit at Anvil Points, Colo.

SOURCE Paraho Development Corp


the retort. A third would not be reheated butwould be reinfected through the bottom of theretort to cool the shale before discharge. Thefourth would be used for fuel in the reheatingfurnace. All heat for kerogen pyrolysis wouldbe provided by the reinfected gases, and nocombustion would occur in the retort vesselitself.

To date, the Paraho retorting technologyhas been tested at about one-twentieth of thesize that would be used in commercial plants.Paraho would like to test a full-size moduleproducing about 7,300 bbl/d at Anvil Points,and has submitted a proposal to DOE for sucha program. Both direct and indirect heatingmodes would be tested. Permission has beenobtained from the Department of the Navy touse large quantities of shale from the NavalOil Shale Reserves for the program. An envi-ronmental impact statement (EIS) is beingprepared for the project. Paraho has re-sponded to a DOE Program Opportunity No-tice for a $15 million engineering design studyof modular oil shale retorting, and wouldbase the design of the Anvil Points module onresults of the study. Outcome of the procure-ment has not yet been announced.

The Petrosix Indirectly Heated Retort

The Petrosix process was developed for theBrazilian Government by Petrobras, the na-tional oil company, with the assistance ofCameron and Jones, Inc., a U.S. engineeringfirm, Russell Cameron, later president ofCameron Engineers, worked on the gas com-bustion program at Anvil Points, as did JohnJones, later president of Paraho. The systemis depicted in figure 38. Figure 39 is a photo-graph of the demonstration retort that hasbeen built and tested in Brazil. The retort is18 ft in diameter, and has a capacity of 2,200ton/d of Irati oil shale. It was built in 1972,and tested intermittently until quite recently.In 1975, a U.S. patent was issued for the proc-ess, A 50,000-bbl/d plant is planned by theBrazilian Government, to be developed in atwo-stage project. The first stage would in-volve construction of a 25,000-bbl/d facilityabout 5 miles from the site of the demonstra-

tion plant near the city of Sao Mateus do Sulin the State of Parana. In the second stage,the full commercial plant would be built onthe same site, to include 20 Petrosix units,each about 33 ft in diameter. Brazil is notcommitted to either stage, but if financing isobtained in 1980, the first stage could be com-pleted by 1983 and the second by 1985. Inaddition to the shale oil, the plant wouldalso produce sulfur and liquefied petroleumgases. Preliminary plans are also being pre-pared for two additional commercial-scaleplants south of the present demonstrationplant in the State of Rio Grande do Sul.

Except for mechanical differences, thePetrosix retort is very similar to the Parahoindirect retort described above. This similari-ty is not surprising in view of the shared engi-neering heritage of the two systems. Oneoperational difference is that the Petrosixspent shale is discharged into a water bathand pumped in a slurry to a disposal pond.Paraho shale is discharged dry, with only alittle water added prior to disposal.

Little information has been released aboutthe demonstration program. Oil characteris-tics have been described, but these have littlerelevance to the processing of Green Rivershale. It can be predicted that the retortshould have high oil recovery efficiencies andproduce a retort gas with high heating value.The spent shale would be carbonaceous. Inthe demonstration plant, recovery of energyfrom the spent shale was not possible be-cause of the slurry disposal method. In anycommercial plant, it is possible that the shalewould be burned in a separate unit to pro-duce heat for pyrolysis.

The Union “B’ Indirectly Heated Retort

The Union “B” retort is a class 3 retort thatevolved from the Union “A,” a class 2 retort,by the Union Oil Co. of California. Two othersystems, the SGR and SGR-3, have also beenproposed by Union, Union describes them allas continuous, underfeed, countercurrent re-torts. The “B” has not been field tested, butthe “A” was tested in Colorado in the 1950’s


Figure 38. —The Petrosix Oil Shale Retorting System

=ALGAS<”’LSHALEFEED

PYROLYSISVESSEL

DISCHARGEMECHANISM

D

HIGH BTU GASFEED HOPPER

PRODUCT FORPURIFICATION

DISTRIBUTOR ELECTROSTATICPRECIPITATOR CONDENSER

●

CYCLONEI

SEPARATOR

HEAVYCOMPRESSOR

SHALE OILHOT

HEAVY

0 0 0 0 0 d ‘ A sSHALE OILv 9

\WASTEWATER

HEATER

\ COOL GAS

WATERJftJ -SEAL SYSTEM

RETORTED SHALE SLURRYTO DISPOSAL

SOURCE 0// Sha/e Refer//ng Technology, prepared for OTA by Cameron Engineers, Inc , 1978

at up to 1,200 ton/d. Figure 40 is a sketch ofthe Union “B” design. It incorporates most ofthe design features of the “A.”

During operation, shale is fed through thebottom of the inverted-cone vessel. The re-torting process thereafter resembles that of acontinuous NTU retort. Hot gases enter thetop of the retort and pass down through therising bed, causing kerogen pyrolysis. Shaleoil and gas flow down through the bed. The oilaccumulates in a pool at the bottom, whichseals the retort and acts as a settling basinfor entrained shale fines. Oil and gas are

withdrawn from the top of the pool. The gasesare split into three streams. One is reheatedand reinfected to induce additional kerogenpyrolysis; one is used as fuel in the reheatingfurnace; and one is the net product. The shaleis discharged from the top of the retort andfalls into a water bath in the retorted shalecooler. From there it is conveyed to disposal.

The key to all of Union’s retorting systemsis the solids pump that is used to move the oilshale through the retort. In the “B” design,the solids pump is mounted on a movable car-riage and is immersed in the shale oil pool.


Figure 39.— The Petrosix Demonstration Plant, Sao Mateus do Sul, Brazil

SOURCE Cameron Engineers, Inc

Ch 5– Technology . 147

TiT

A. The

rk!%

Figure 40.—The Union Oil “B” Retorting Process

Ii?P-4‘. “’

=.+.’.’ AA-+--d 1= OIL LEVEL

RETORTED SHALE/ DISCHARGE

\\\\\l\llt.h\\\\\\lll

j?{!

r T—r

TO WATER SEAL

7

RETORT* GAS

- R O C K P U M P

Mm * SHALE OIL

I

m

\ \ \ \~\\\ ‘ \ \ \\~. \ \ ’ \l\\ . ~. . .1 \ \ \ \ \“.’\\\\\\\\\\\\~.\

Retorting System

SHALE IN SHALE IN

ISHALE IN SHALE IN

B. Hock Pump Detail

SOURCE 0/1 Strale Reforf/ng Technology, prepared for OTA by Cameron Engineers Inc .1978

.

148 . An Assessment of Oil Shale technologies

The pump consists of two hydraulic assem-blies that act in sequence. (See figure 40.)While the cylinder of one assembly is fillingwith oil shale, the other is charging a batch ofshale into the bottom of the retort. When thisoperation is completed, the carriage moveshorizontally on rails until the full cylinder isunder the retort entrance. A piston thenmoves the oil shale in this cylinder upwardsinto the retort, while the other fills with freshshale from the other feed chute. The carriagethen returns to its original position and theprocess is repeated.

The “B” achieves high oil yields, and theretort gas has a high heating value, althoughmuch of it is consumed in the reheating fur-nace. The mechanical nature of the rockpump is troublesome because its movingparts would be subject to wear during opera-tion. However, the pump is immersed in theshale oil pool, which should provide adequatelubrication. Union appears to be satisfiedwith its reliability.

In 1976, Union announced plans to build ademonstration plant on its private land in Col-orado. The “B” retort was to be used to pro-duce 7,000 bbl/d of shale oil from 10,000 ton/dof oil shale. Later, the announced capacitywas increased to 9,000 bbl/d. The demonstra-tion plant, called the Long Ridge project,would be the first step towards a 75,000-bbl/dcommercial-scale plant. Air quality permitshave been obtained for the modular plant,which could be completed before 1985. Con-struction has not begun because Union isawaiting financial incentives from the Feder-al Government.

The Superior Oil Indirectly Heated Retort

The Superior retort is unique among theaboveground retorts discussed in this sectionbecause it is designed for recovery of sodium-bearing minerals in addition to shale oil. Asdiscussed in chapter 4, the minerals nahcoliteand dawsonite occur in substantial quantitiesin portions of the Piceance basin. They arepotential sources of sodium bicarbonate,soda ash, and aluminum.

A block diagram for the Superior approachis shown in figure 41. In step 1, the minedoil shale is crushed to pieces smaller than 8inches and screened. About 85 to 90 percentof the nahcolite in the shale is in the form ofdistinct, highly friable nodular inclusions thatbecome a fine powder during the crushingoperation. This is screened from the coarsershale in step 2. The shale is then furthercrushed to smaller than 3 inches and is fed instep 3 to a doughnut-shaped traveling-grateretort, which includes sequential stages forheating, retorting, burning, cooling, and dis-charging the oil shale feed. The retort issketched in figure 42. In the heating section,oil is recovered by passing hot gases throughthe moving bed. In the carbon recovery sec-tion, process heat is recovered by burning theresidual carbon. In the cooling section, inertgases are blown through the bed of spentshale, cooling the shale and heating the gasesfor use in the heating section. After dis-charge, the cooled spent shale is sent to otherunits in which alumina is recovered from cal-cined dawsonite and soda ash from calcinednahcolite. The alumina is shipped to offsitealuminum refineries; the soda ash to glassplants; and the nahcolite to refineries andpowerplants for use as a stack-gas scrubbingagent.

Superior chose the traveling-grate retortbecause it allows close temperature control,important to maintaining dawsonite’s solubil-ity during the burning stage. Similar, simplerdevices have been used to sinter iron ore forsteelmaking and to roast lead and zinc sul-fides. Superior’s process has been tested foroil shale in pilot plants in Denver and Cleve-land. A commercial-scale plant would con-sume 20,000 ton/d of oil shale to produce10,000 to 15,000 bbl/d of shale oil, 3,500 to5,000 ton/d of nahcolite, 500 to 800 ton/d ofalumina, and 1,200 to 1,600 ton/d of soda ash.

In the early 1970’s, Superior proposed tobuild a commercial-size demonstration planton its 7,000-acre tract in the northern Pi-ceance Basin. The deposit was to be devel-oped by deep room-and-pillar mining on sev-eral levels. The single retort was to produce


Figure 41 .— Block Diagram for theSuperior Multi Mineral Concept

14EH---TI I

I ISPENT SHALE

SHALE

STEP 2 STEP 3 STEP 4SHALE

NAHCOLITEASH

> OIL EALUMINA &

RECOVERY RECOVERY SODA ASHRECOVERY

● ● ● ●NAHCOLITE OIL SODA ASH ALUMINA

SOURCE 01/ Shale Retorting Technology, prepared for OTA by Cameron Englneers, Inc .1978

11,500 bbl/d of shale oil, plus the byproductsdescribed above. Although the tract’s re-sources are extensive, its L-shaped configu-ration does not favor large-scale develop-ment. Superior therefore proposed to ex-change portions of the tract for adjacent landcontrolled by the Bureau of Land Manage-ment (BLM). Approval was delayed by BLMreview and by preparation of an EIS, a draftof which was recently released. In February1980, BLM denied the exchange because thetwo tracts involved were not considered tohave equivalent value. The decision is open toreview.

The TOSCO H Indirectly Heated Retort

The TOSCO II is a class 4 retort in whichhot ceramic balls carry heat to finely crushedoil shale, It is a refinement of the Aspecoprocess developed by a Swedish inventor.Patent rights were purchased by The OilShale Corp. (later Tosco) in 1952. Early devel-opment work was performed by the DenverResearch Institute, including testing of a 24-ton/d pilot plant. In 1964 Tosco, Standard OilCo. of Ohio (SOHIO), and Cleveland Cliffs IronCo. formed Colony Development, a joint ven-ture company, to commercialize the TOSCO IItechnology. Between 1965 and 1967, thegroup operated a 1,000-ton/d semiworksplant on its land near Grand Valley, Colo.,next to the site of Union’s semiworks opera-tions. In 1968, Colony prepared a preliminary

engineering design and cost estimate for acommercial-scale plant that would containsix TOSCO II retorts, and convert 66,000ton/d of oil shale into about 46,000 bbl/d ofshale oil. In 1969, ARCO joined Colony, and asecond semiworks program began to testscaleup procedures and to evaluate environ-mental controls. The program continued untilApril 1972. Between 1965 and 1972 the semi-works plant converted 220,000 tons of oilshale into 180,000 bbl of shale oil.

In 1974, the 1968 cost estimate, which hadbeen updated in 1971, was further revised toincorporate operating data from the latterpart of the semiworks program and to ac-count for additional pollution controls. Theresulting cost estimate was about three timesas large as the previous estimate. This costescalation raised doubts about commercialfeasibility, and the project was postponed in-definitely. SOHIO and Cleveland Cliffs subse-quently withdrew from the Colony group.

Early in 1974, Tosco, ARCO, Ashland, andShell purchased a lease for tract C-b from theFederal Government. Initial developmentplans for the tract involved a plant similar tothat proposed for Colony’s private tract.These plans were also affected by the cost es-calations, and in 1976 suspension of opera-tions on tract C-b was granted by the Govern-ment. In 1977 Tosco and ARCO withdrewfrom the tract. Shell withdrew in 1977. Ash-land, the remaining partner, teamed withOxy to develop the tract using MIS tech-niques.

Colony’s semiworks retort, which is aboutone-tenth of commercial scale, is shown infigure 43. The TOSCO II retorting system issketched in figure 44. Raw shale is crushedsmaller than one-half inch and enters the sys-tem through pneumatic lift pipes in which theshale is elevated by hot gas streams and pre-heated to about 500” F (260° C). The shalethen enters the retort, a heated ball mill, andcontacts a separate stream of hot ceramicballs. As the shale and balls mix, the shale isheated to about 950

0 F (5100 C), causing re-

torting to take place. Oil vapors and gases arewithdrawn. The oil is condensed in a fraction-

150 . An Assessment of Oil Shale Technologies

Figure 42.—The Superior Oil Shale Retort

COOLRECYCLE

GAS

SHALEFEED

HOTRECYCLE

S+LE HEATING+

‘ A s -~

COOLRECYCLE

/GAS

1- --~---

1

SOURCE. 0// Sha/e Retorturg Tec/rno/ogy, prepared for OTA by Cameron Eng!neers, Inc , 1978 (after Arthur G McKee & Co j

ator. Some of the gases are burned in a heat-er to reheat the ceramic balls to about 1,2000F (650° C). At the retort exit, the retortedshale and the cooled ceramic balls pass overa trommel, a perforated rotating separationdrum. The shale, which has been thoroughlycrushed during retorting, falls through holesin the trommel. It is cooled and sent to dispos-al. The larger balls pass over the trommeland are sent to the ball heater.

Oil yields exceeding 100 percent of Fischerassay have been reported for the TOSCO IItechnology. However, overall thermal effi-ciencies are low because energy is not recov-ered from spent shale carbon, and much ofthe product gas is consumed in the ball heat-er. Tosco has patented processes to burn theretorted shale as fuel for the ball heater, thus

increasing energy recovery, and freeingvaluable retort gases for other uses.

the

The retort’s chief disadvantages are itsmechanical complexity and large number ofmoving parts. The ceramic balls are con-sumed over time. The need for a fine feed sizeresults in crushing costs that are higher thanthose of systems that can handle coarserfeeds. On the other hand, all crushing opera-tions produce some fine shale that could bescreened from the feed to coarse-shale re-torts and converted in auxiliary TOSCO IIunits. Disposal of TOSCO II spent shalepresents some problems because it is veryfinely divided and contains carbon.

At present Tosco is participating in twoprojects that are committed to its proprietary


Figure 43. — The Colony Semiworks Test Facility Near Grand Valley, Colo.

SOURCE Colony Development Corp


Figure 44.—The TOSCO II Oil Shale Retorting SystemFLUE GAS PREHEAT SYSTEM

TO ATMOSPHERE4

STACK—

RAWCRUSHED

SHALE

WATER VENTURI BALLS

WET SCRUBBER

SEPARATOR FOUL WATER To

-hz FOUL WATER

~ STRIPPER

CERAMIC uBALL

a NAPHTHA

HEATER:

SLUDGE” Fv< -

- HYDROCARBON ~ GAS OIL TO GAS 01 L

VAPORS HYDROGENATION

nHOT BALLS BOTTOMS OIL TO

: ACCUMULATOR DELAYED COKERQ~u.w~

2wt-3-1 BALL CIRCULATIONE SYSTEM STACK

VENTURIWET

SCRUBBERI

HOT FLUE GAS

PREHEAT SYSTEM HOT

(INCLUDES INCINERATOR) PROCESSEDSHALE

FLUE GAS+

*cnnu CTFAM SLUDGE I

COOLER

“’++MOISTURIZER

MOISTURIZER4 SCRUBBER

r+)WATER STACK

VENTURI WETSCRUBBER

tSLUDGE

MOISTURIZED PROCESSED

- ‘+$%spOsALCOVERED PROCESSEDSHALE CONVEYOR

SOURCE 0// Shale Retorflng Technology prepared for OTA by Cameron Engineers, Inc , 1978.

retorting technology. The Colony project has The Lurgi-Ruhrgas Indirectly Heated Retortbeen mentioned previously. The other ven-ture, the Sand Wash project, is being devel- The Lurgi-Ruhrgas retorting system uses aoped on 14,000 acres of land in the Uinta class 4 retort in which hot retorted shale car-Basin leased from the State of Utah. Unlike ries pyrolysis heat to oil shale. The processthe Colony project, which has been sus- was developed jointly by Ruhrgas A. G. andpended pending resolution of economic uncer- Lurgi Gesellschaft fur Warmetechnik m. b. H.,tainties, Sand Wash is proceeding towards two West German firms that have been in-commercialization in compliance with the due volved in synfuels production for decades.diligence requirements of the State leases. A The process was developed in the 1950's forplant similar to the proposed Colony facility is low-temperature coal carbonization. A 20-contemplated, but no schedule has been an- ton/d pilot plant was built in West Germany,nounced for its construction. At present, to test a variety of coals, oil shales, andwork consists of monitoring the environment, petroleum oils. European shales were testedand preparing to sink a mine shaft. in the late 1960’s, and Colorado oil shale in


1972. The plant has since been scrapped butsmaller retorts are available.

Coal processing plants using the Lurgi-Ruhrgas technique have been built in Japan,West Germany, England, and Argentina.There are also two Yugoslavian plants, eachbuilt in 1963, with a capacity of 850 ton/d ofbrown coal. The Japanese plant is also ofcommercial size, and uses the process tocrack petroleum oils to olefins. No large-scaleoil shale plants have yet been built.

The retorting system is shown in figure 45.Finely crushed oil shale is mixed with hot re-torted oil shale in a mechanical mixer that re-sembles a conventional screw conveyor. Re-torting takes place in the mixer, and gas andshale oil vapors are withdrawn. Dust is re-moved from these products in a cyclone sepa-rator and oil is separated from the gas by con-densation. Retorted shale leaves the mixerand is sent to a lift pipe where it is heated toabout 1, 100° F (5950 C) in a burning mixtureof fuel gas and air. The hot retorted shale isthen sent back to the mixer, and the processis repeated.

High oil yields have been reported for theretort, and the product gas is of high quality.

Figure 45. —The Lurgi-Ruhrgas Oil ShaleRetorting System

WASTE HEAT

-OLIDS1 ~-~ FLUE GAS wAsTE

RECOVERY

OIL GASEOUS ANOLIQUID PRODUCTS

CONDENSERDUST

MIXING SCREWTYPE RETORT SOLIDS

SURGE

LIFTBIN

PIPE

TO WASTE

~ AIR - FUEL(!! Reqwed)

SOURCE 0// .Shale Retorf/ng Technology, prepared for OTA by Cameron Engtneers Inc 1978

Except for the mixer, the process is mechani-cally simple and has few moving parts. Itshould be capable of processing most oilshales, if they are crushed to a fine size. Thetwo major problems with the system appearto be accumulation of dust in the transferlines and dust entrainment in the oil. Dustycrude oil is not a severe problem because thedust is concentrated in the low-value residualproduct when the oil is subsequently refined.As with the TOSCO II process, requirementsfor a fine feed material will result in highcrushing costs. These costs would be partial-ly offset by the ability to process the fine frac-tion from any crushing process, includingthose used to prepare shale for coarse-shaleretorts.

In 1972, Lurgi proposed to develop its re-torting technologies with Colorado oil shale.The program was not funded, but Lurgi’s in-terest in commercializing the technique hascontinued. In recent years Lurgi has beenworking with Dravo Corp. to interest U.S.firms in using the technology. At present, atleast one company—Rio Blanco—has ob-tained a license to investigate the use ofLurgi-Ruhrgas retorts. Present plans call forconstructing a modular Lurgi-Ruhrgas retortthat will be close to commercial size (2,200ton/d). It will be used to retort the shale thatwill be mined during the preparation of MISretorts on tract C-a.

Advantages and Disadvantages ofthe Processing Options

The greatest advantage of TIS processingis that mining is not required, and spent shaleis not produced on the surface. The technical,economic, and environmental problems asso-ciated with above-ground waste disposal arethereby avoided. MIS does involve mining andaboveground waste disposal, although to alesser extent than with AGR. However, theMIS waste is either overburden or raw oilshale. Both materials are found naturally ex-posed on the surfaces of deeper canyons inthe oil shale basins. Although raw shale haslow concentrations of the soluble salts, it doescontain soluble organic materials that could

154 . An Assessment of 011 Shale Technologies

be leached from the disposal piles. It shouldbe noted that the presence of spent shale un-derground has the potential to cause environ-mental problems because soluble salts couldbe leached by ground water. Therefore, envi-ronmental controls will also be needed forTIS and MIS methods.

Surface Facilities

TIS has another theoretical advantage inthat the required surface facilities are min-imal, consisting only of wells, pumps, gascleaning and product recovery systems, oilstorage, and a few other peripheral units.These facilities would probably resemblethose for processing of crude oil and naturalgas. MIS requires more facilities to supportthe mine and the waste disposal program.Aboveground processing, which uses thelargest number of facilities, causes the mostsurface disruption.

Oil Recovery

The advantage of AGR is that the condi-tions within the retorts can be controlled toachieve very high oil recoveries—approach-ing or even in some cases exceeding the yieldsachieved with Fischer assay retorts. Retort-ing efficiencies are usually lower for MISprocessing and much lower for TIS becauseof the difficulty in obtaining a uniform dis-tribution of broken shale and void volume,which in turn, makes it difficult to maintainuniform burn fronts and leads to channelingand bypassing of the heat-carrier gases. Thefew estimates of the retorting efficiencies ofTIS operations that have been published havenot been encouraging. (USBM achieved recov-eries of 2 to 4 percent in its field tests. ) MISretorting has not exceeded 60-percent recov-ery of the potential oil in the shale within the

retorts. It is expected that yields from MIS re-torts could be increased by injecting steam orhydrocarbon gases (as is done in Equity’s TISprocess), but it is doubtful that recoveries canreach those of carefully controlled above--ground retorts. On the other hand, the pres-ent low efficiencies of MIS operations arepartially compensated for by their ability toconvert very large sections of an oil shale de-posit, by their ability to process shale of alower grade than would be practical for AGR,and by their lower cost of preparing the shalefor retorting.

It is difficult to compare overall recoveriesfrom MIS and AGR without making numerousassumptions about the operating characteris-tics of both systems. To make a rough com-parison, it could be assumed that AGR (withroom-and-pillar mining) and MIS were to beapplied to two 30()-f t-thick deposits with iden-tical physical characteristics. The net recov-eries from several development options aresummarized in table 18. The highest recovery(100 percent) is for full-subsidence mining inconjunction with AGR processing. It shouldbe noted that full-subsidence mining, foreither MIS processing or AGR, would resultin extensive surface disturbance and couldincrease risks to the miners. Subsidence min-ing has never been tested in oil shale. Its po-tential for surface disturbance could be re-duced by backfilling the mined-out areas withspent shale from surface processing, The re-torted shale in burned-out MIS retorts wouldalso reduce the severity of subsidence.

The three generic approaches to oil shaleprocessing also have various other advan-tages and disadvantages with respect towater needs, environmental effects, financialrequirements, and social and economic im-pacts. These aspects are discussed in the re-spective chapters of this report.


Table 18.–Overall Shale Oil Recoveries for Several Processing Options

First-stageCase retorting technology First-stage mining method

1 AGR Conventional room-and-pillar mining on three levels 60-ftrooms, 60-ft barrier and siII pillars.

2 MIS Conventional MIS mining. 40% of shale left behind in barrierpillars 20% of the disturbed shale IS removed to the surfaceto provide void volume in the retorts

3 MIS As in case 24 AGR As in case 1

5 MIS Full subsidence b6 MIS Full subsidence b7 AGR Full subsidence b

Second-stage processing

None

None

AGR processing of the mined shaleBarrier and siII pillars collapsed andretorted by MIS

NoneAGR processing of the mined shaleNone.

Overall shaleoil recoverya

36%

29%

41 %,

74%

48%68%

100%

aAssurnlng AGR reco~ers 100 ~ercenl of the potential 011 In the shale retorted MIS assumed to recover 60 percent of the potential 011bEntlre deposit IS mned

SOURCE Off Ice of Technology Assessment

Properties of Crude Shale OilCrude shale oil (also called raw shale oil,

retort oil, or simply shale oil) is the liquid oilproduct recovered directly from the offgasstream of an oil shale retort. Synthetic crudeoil (syncrude) results when crude shale oil ishydrogenated. In general, crude shale oilresembles conventional petroleum in that it iscomposed primarily of long-chain hydrocar-bon molecules with boiling points that spanroughly the same range as those of typicalpetroleum crudes. The three principal differ-ences between crude shale oil and conven-tional crude are a higher olefin content (be-cause of the high temperatures used in oilshale pyrolysis), higher concentrations of oxy-gen and nitrogen (derived from oil shale kero-gen), and, in many cases, higher pour pointand viscosity,

The physical and chemical properties ofcrude shale oil are affected by the conditionsunder which the oil was produced. Someretorting processes subject it to relativelyhigh temperatures, which may cause thermalcracking and thus produce an oil with a loweraverage molecular weight. In other processes(such as directly heated retorting) some of thelighter components of the oil are incineratedduring retorting. The result is a heavier finalproduct. Others may produce lighter prod-ucts because of refluxing (cyclic vaporizationand condensation] of the oil within the retort.

One of the most important factors is the con-densing temperature within the retorting sys-tem—the temperature at which the oil prod-uct is separated from the retort gases, Thelower this temperature, the higher the con-centration of low molecular weight com-pounds in the product oil,

The properties of crude shale oil from sev-eral aboveground and MIS retorting proc-esses are listed in table 19.24 It is important tonote that the oils that are characterized wereproduced in small-scale test runs under con-ditions that may not be representative ofthose that will be encountered in other areas,and with larger processing systems. The oilsfrom commercial-scale facilities in otherparts of the oil shale region may have proper-ties that are quite different,

The properties of the oil produced by dif-ferent AGR processes vary widely, but thedifferences between these oils and the in situoils are much more significant. In situ oils aregenerally much lighter, as indicated by theirhigher yields of material with relatively lowboiling points, and would produce more low-boiling product (such as gasoline) and lesshigh-boiling product (such as residual oil). Ingeneral, the low yields of residuum makeshale oils attractive as refinery feedstocks incomparison with many of the heavy conven-


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tional crudes that are currently being proc-essed in the United States. For example, insitu oil from Oxy’s MIS process contains 1 to4 percent of material with a boiling range ofover 1,000° F (5350 C), compared with 20 per-cent for crude from Alaska’s North Slope,and 18 percent for Arabian Light crude.25 26

Other foreign crudes, such as Kuwait andArabian Heavy, contain even larger residuumfractions. Oils from some AGR processes con-tain as much as 30 percent of residuumwhich, although higher than the contents of insitu crudes, is substantially lower than thatfor many conventional crudes.

Coal-derived liquids are often regarded asalternatives to shale oil feedstocks. However,syncrudes from coal have a much higher yieldof gasoline and low-boiling distillates thanshale oil, with little or no material boiling attemperatures above 850° to 1,000° F (4550 to535° C), The coal liquids would be well-suitedfor gasoline production because their higherconcentrations of lower boiling constituentswhen refined would yield the desired lightnaphtha fractions. Shale oil, on the otherhand, has a much higher concentration ofhigh-boiling compounds, and would favor pro-duction of middle distillates (such as dieselfuel and jet fuels) rather than naphtha, Shaleoil and coal-derived syncrudes should, there-fore, be regarded not as a competitive or sub-stitutable feedstocks but rather as comple-mentary feedstocks, with each yielding a dif-

Shale OilShale oil has been successfully refined in

oil shale operations in Sweden, Scotland,Australia, West Germany, the U. S. S. R., andother countries, although on a relativelysmall scale and under unusual economic con-ditions. In the United States, the initial refin-ing research was conducted by USBM at thePetroleum and Oil Shale Experiment Stationat Laramie, Wyo. It was coordinated with theearly development of the gas combustion re-tort at Anvil Points, Colo. The results of thiswork, plus the findings of other investigators,allowed a preliminary assessment to be made

ferent major fuel product from an equivalentamount of refining.

Among the negative characteristics of mostcrude shale oils are high pour point, highviscosity, and high concentrations of arsenicand other heavy metals and of nitrogen. Thepour point and viscosity are of economic im-portance because transporting viscous oilthat has a high pour point is difficult and cost-ly, thus suggesting the need for pretreatmentprior to marketing. * As shown in table 19, insitu oils with their relatively low pour pointsand viscosities could be marketed withoutpretreatment but they would retain their highnitrogen contents. This would reduce theirvalue as refinery feedstocks and boiler fuels.

High concentrations of arsenic and othermetals are a disadvantage because they poi-son refining catalysts, especially in hydro-genation units. They must be removed prior tocatalytic processing, and a variety of physi-cal and chemical methods have been devel-oped for this purpose.28 29 It should be notedthat the concentrations of heavy metals incrude shale oil will vary with the location ofthe deposit from which the oil is recovered.Oils from some sites may be relatively free ofsuch contaminants.

* S o m e convention:]] (Iru(ics h:)~[’ ({)mpilr[]t)l} h]gh pourpoints. For example, the Alt[~mon I crude from Ut:)h hi]s ;{ pourpoint Of about 100° F (35° (;).

Refiningof the economic aspects of shale oil utiliza-tion, and justified continued efforts aimed atits recovery. In recent years, refining R&Dhas been revived because refiners now con-sider the availability of shale oil to be a dis-tinct possibility. There is also a need to per-form more precise and up-to-date economicanalyses.

To date, refining studies have been con-ducted on the upgrading of crude shale oil toa transportable product, and on the total re-fining of shale oil into finished fuels. The dif-


ference between these operations lies in thenature of the desired final product. As dis-cussed previously, some crude shale oils havepour points and viscosities that make trans-porting them difficult and expensive. In somesituations, economic considerations may dic-tate that the crude shale oil be partially re-fined (upgraded) near the retorting site to im-prove its transportation characteristics. Inother instances, a developer may desire to ob-tain a complete array of finished fuels froman integrated processing facility located nearthe minesite. In this case, a total-refiningfacility would be considered rather than amore simple upgrading plant.

To date, upgrading experiments have beencarried out largely at the bench scale, andin relatively small pilot plants. Theoreticalstudies and computer modeling have alsobeen used to evaluate the expected perform-ance of three types of upgrading processes:thermal, catalytic, and additive. Thermalprocesses include visbreaking (a relativelymild treatment) and coking (a severe treat-ment). Mild thermal treatment will reducepour point and viscosity, but the oil will retainits initial amounts of nitrogen and sulfur. Incontrast, severe thermal treatment reducespour point, viscosity, and sulfur content andalso causes the nitrogen compounds to con-centrate in the heavier products. The proper-ties of the lighter products will thus be con-siderably improved.

In catalytic processes, the shale oil is re-acted with hydrogen in the presence of a cat-alyst. Viscosity is reduced, and the nitrogenand sulfur are converted to ammonia and hy-drogen sulfide gases that can be recovered asbyproducts. In additive processes, blendingagents are added that reduce the pour pointand allow the crude to be transported bypipeline. Such pour point depressants havebeen added in several instances with success,but the technique is not yet highly developed.

Total refining studies have focused eitheron the needs of existing refineries that wouldhave to be modified for processing shale oil,or on those of newly built facilities that couldbe designed specifically for shale oil feed-

stocks. These studies differ in their approachto the analysis of refining requirements.Studies of existing refineries must considerthe equipment that is in place, and must allowfor the limited flexibility of this equipment forprocessing a feedstock that is different fromthe one for which the refinery was designed.Studies of specially built refineries, in con-trast, need not be biased in this manner, andcan draw upon any processing technique thatis available within the refining industry.However, both types of studies must makeassumptions about feedstock characteristicsand desired product mixes. These will varywith the location of the refinery, the nature ofthe market it serves, and the type of retortingfacility that supplies its feedstocks. The op-timal refining conditions for one set of as-sumptions will probably not be applicable toanother set. For example, a refining methodto maximize gasoline production from TOSCOII shale oil would not maximize diesel fuelproduction from Oxy’s in situ oil.

Numerous computer studies and bench-scale refining investigations have been con-ducted for a wide range of shale oil feed-stocks and operating conditions. The resultsof these studies can be extrapolated, withsome degree of caution, to predict theperformance of commercial-scale refineries.However, refining tests both in pilot plantsand in commercial-scale facilities, because ofmuch higher costs, have focused on only afew feedstocks, and have been conducted forparticular sets of operating constraints. Ingeneral, each large-scale study has dealt onlywith oil from aboveground retorts or with oilfrom in situ operations, but usually not withboth types of feedstocks. The conclusions ofall studies are highly dependent on the com-bination of feedstock and refining conditionsassumed. Caution must be used when apply-ing the results to different conditions.

Shale Oil Upgrading Processes

The treatment techniques that can be usedto improve the transportation properties ofcrude shale oil are briefly described below.


Visbreaking

This technique involves heating the crudeshale oil to approximately 900° to 980° F(480° to 525° C) and holding it at this tem-perature range for from several seconds toseveral minutes. The product is then cooled,and the gases evolved during the heating areremoved. There is little reduction in the con-tents of nitrogen, sulfur, and oxygen. There-fore, the principal improvements are reduc-tions in pour point and viscosity. This tech-nique is simple but energy-intensive. It couldreduce the pour point of crude shale oil fromabout 850 F to about 400 F (300 to 40 C).30

Coking

This process involves heating the oil toabout 900° to 980° F (480° to 525° C) andthen charging it into a vessel in which ther-mal decomposition occurs. If the vessel is acoke drum, the process is called delayed cok-ing. The coke—the solid product from ther-mal decomposition—is allowed to accumulateuntil it fills about two-thirds of the drum’s vol-ume. The feed is then switched to anotherdrum while the coke is cleaned out of the firstone.

In the fluid coking process, hot oil ischarged into a vessel that contains a fluidizedbed of coke particles. The particles becomecoated with oil, which then decomposes toyield gases and another layer of coke. Thegases are withdrawn from the vessel. Thecoke is also withdrawn continuously, at arate sufficient to maintain an active stock ofcoke within the bed.

The flexicoking process, developed byEXXON, combines conventional fluid cokingwith gasification of the product coke. The ad-vantage is that energy is recovered from thecoke. The process is used in the refining in-dustry, but tests would have to be performedto determine if it would be suitable for thecoking characteristics of crude shale oil.

Catalytic Hydrogenation

In these processes, the crude shale oil isreacted with hydrogen in the presence of acatalyst. The sulfur in the oil is converted tohydrogen sulfide, the nitrogen to ammonia,the oxygen to water, the olefin hydrocarbonsto their paraffin equivalents, * and long-chainmolecules to smaller molecules. The hydro-genation reactions can take place in a fixed-bed reactor through which a mixture of oilvapors and hydrogen is passed, in a fluidized-bed reactor, or in an ebulliating-bed reactor.The latter technique is being promoted by Hy-drocarbon Research, Inc., as the H-Oil proc-ess. Plants in several foreign nations havesuccessfully used it for heavy petroleum feed-stocks and for residuum fractions from a va-riety of crudes. In this process, a mixture isinjected into the bottom of a reactor at a highenough velocity to cause catalyst ebulliation(a boiling motion). This movement reduces thepossibility that the bed will become pluggedby coke and by the liquid tars that are formedduring the coking process. It also allows spentcatalyst and coke to be removed, and freshcatalyst to be added, so as to keep the bed ac-tively stocked.

Catalytic hydrogenation produces up-graded products of the highest quality, but itis relatively expensive. The use of fixed-bedreactors would probably be confined to thetreatment of streams from an initial frac-tionation step; fluid-bed or ebulliating-bedprocesses could be used for either frac-tionator products or for the whole shale oil.

‘Olefins are unsaturated (lower ratio of hydrogen to carbon)hydrocarbon compounds having at least one double bond. Theyare the source of synthetic polymers such as polyethylene andpolypropylene used in the manufacture of fibers and other ma-terials. Paraffins are saturated hydrocarbons (equal ratio ofhydrogen to carbon) having only single bonds. Methane,ethane, propane, and butane are some of the paraffin hydro-carbons.


Additives

Chemicals may also be added to crudeshale oil to improve its transportation proper-ties. Pour point depressants have been suc-cessful in some instances, but this does notmean that they would always work. A chemi-cal that is suitable for one type of oil may notwork at all with oil from another retortingprocess. Furthermore, pour point depres-sants are disadvantageous because they onlychange the physical characteristics of the oiland not its chemical properties. Thus, theircost can be offset only if they save transpor-tation costs.

Conventional petroleum crudes are otherpotential blending agents. Since shale oil (atleast in Colorado) will be produced in an areathat also contains petroleum reserves, andeven active crude oilfields, the possibility ex-ists that the light petroleum crudes could bemixed with crude shale oil to form a trans-portable blend. The feasibility of this conceptis unclear because, in general, the blendwould not be as valuable as a refinery feed-stock on a per-unit basis as would the petro-leum alone. However, the decrease in unitvalue would be offset by the increased vol-ume. In the case of a refinery that does nothave a reliable supply of crude, this could bea significant advantage.

Total Refining Processes

The three primary factors that affect thedesign of a refining system are:

. the characteristics of the crude shale oilfeedstock;

● the desired mix of finished products; and● the constraints imposed by the equip-

ment and operating practices of the pro-posed refinery.

The first factor probably will have the lowesteffect because, except for the higher nitrogenand arsenic contents, the characteristics ofcrude shale oil are not widely different fromthose of conventional petroleum. The secondfactor—the product mix—is much more sig-nificant. This is evidenced by the changes

that have occurred in the proposed configura-tions of shale oil refineries since the 1950’s:the earlier studies placed much more empha-sis on gasoline production. For example, earlydesigns by USBM called for the extensive useof middle-distillate cracking and reforming toyield gasoline, The ratio of gasoline to distil-late yields was nearly 3 to 1.31 Most of therefinery configurations that have been pro-posed more recently indicate a gasoline-to-distillate ratio of about 1 to 4.”

The third factor—equipment and operat-ing constraints— has become increasingly im-portant in recent years. The modifications toconvert a conventional refinery to shale oilfeedstocks might not be economically justifi-able unless the refiner could be assured of anadequate supply of shale oil. The economicdesirability of building a refinery specificallyfor shale oil would be thoroughly scrutinized.Modular retorts, or even a few pioneer com-mercial plants, would not produce enoughshale oil in the mid-term to justify a new refin-ery unless the refiner was assured that theoperations would continue until his invest-ment cost could be recovered. For this rea-son, the most recent studies have stressedmodifying existing facilities to make themsuitable for processing shale oil, rather thanbuilding new ones. In some cases, this entailsonly minor changes to installed equipment, inothers, the adaptation of an existing facilityby adding new units.

The basic unit operations in crude oil refin-ing are:

● coking, hydrotreating, distillation, hydrocracking,● catalytic cracking, and● reforming.

The various refining schemes that have beenproposed for shale oil cannot easily be gener-alized because, depending on both the de-sired product mix and the possible operatingconditions, many configurations could be de-signed that would achieve the same results.The one selected will largely depend on the

Ch 5– Technology 161

availability of equipment and the individualeconomics of the particular refinery.

One significant difference among the vari-ous configurations described in the literatureis the relative arrangement of distillation andthermal or catalytic treatment. Two generalapproaches have been investigated:

1. distillation of the whole crude into itscomponents, then catalytic or thermaltreatment; or

2. catalytic or thermal treatment of thewhole crude, then distillation.

In the first approach the properties of thefinished products are better controlled. In thesecond, the net load on successive processingunits is reduced, and, in general, the overallyield of high-value hydrocarbon products isincreased. Most of the refining research todate has been focused on the second ap-proach. Three versions are shown schemati-cally in figures 46 through 48. The scheme in

Figure 46.— Refining Scheme Used by theU.S. Bureau of Mines to Maximize Gasoline

cmdO

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Production From Shale Oil

Gas

w “ft-Gasohw~ REFORM ER

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SOURCE G L Baughman, The Refining and Markefing of Crude Sha/e 0//

figure 46, which was used by USBM at AnvilPoints in the late 1940'S,33 had a gasoline-to-distillate ratio of 3 to 1. Figure 47, a con-figuration that was investigated by ChevronU.S.A. during pilot-plant runs on Parahoshale oil,34 had a gasoline-to-distillate ratio of1 to 4. Both of these systems used an initialcoking step to upgrade the feedstock and tosupply a product stream more easily refin-

Figure 47. —Refining Scheme Employing CokingBefore an Initial Fractionation, Used byChevron U.S.A. in Refining Experiments

I T“RpJY

SOURCE G L Baughman The Ref(nfng and Markeflrtg of Crude Sha/e 0{/

Figure 48.— Refining Scheme EmployingInitial H ydrotreating, Used by Chevron U.S.A.

in Refining Experiments

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able into finished fuels. The disadvantage ofcoking is that there might not be a ready mar-ket for coke in the vicinity of the refinery, par-ticularly if it were located in the oil shale re-gion.

Another refining scheme that was investi-gated by Chevron is shown in figure 47. Ituses a fixed-bed catalytic hydrotreater to up-grade the shale oil before distillation. No cokeis produced because most of the heavier com-ponents of the crude shale oil are upgradedinto lighter and more valuable liquid fuelsduring the hydrogenation process. This meth-od may be more costly than the coking ap-proach, but that can only be determined by


operating experience and evaluating the eco-nomics.

Chevron also investigated the possibility ofsubstituting a fluidized catalytic cracker forthe hydrocracker in figure 48. A similar ap-proach was used by SOHIO in processing85,000 bbl of Paraho shale oil at its Toledorefinery. 35 The chief difference between theSOHIO runs and the Chevron experiments isthat SOHIO used an acid/clay treatment toupgrade the distillation products into jet fueland marine diesel fuel for military applica-tions. The residuum fraction from the columnwas used for fuel in the refinery.

The approach in which the crude oil isfractionated before hydrogenation or othertreatment is shown in figure 49. This scheme

Figure 49.— Refining Scheme Employing InitialFractionation, Used by SOHIO in Prerefining Studies

SOURCE. G L Baughman, The Refining and Market/rig of Crude Shale 0//

was used by SOHIO during the prerefiningstudies carried out before 10,000 bbl of Para-ho shale oil were refined at the Gary Westernrefinery in Fruita, Colo.36 During the actualrefinery run, a combination coker/fraction-ator was used rather than the separate unitsshown in the diagram.

The shale oil must also be treated to re-move excess amounts of water, ash, andheavy metals such as arsenic. Water must beremoved because it can cause cavitation in

pumps and explosions in processing units.Ash, or particulate matter, must be removedto prevent its deposition in pipes, heat ex-changers, and catalyst beds. Recent studieshave shown that heating the crude oil toabout 165° F (75° C) then letting it stand forabout 6 hours allows the water and solid mat-ter to separate from the oil. As noted, arse-nic and other metals poison the hydrotreatingcatalysts. A variety of processes have beendeveloped for their removal; consequently,their presence no longer presents a technicalproblem. ARCO has patented several cata-lytic techniques and methods for heat treat-ing the oil in the presence of hydrogen. Re-cent studies by Chevron U.S.A. have shownthat an alumina guard bed preceding the hy-drotreater will effectively remove both arse-nic and iron from shale oil. 39

The quantity and quality of the fuels pro-duced will be determined by both the configu-ration of the equipment and the operatingconditions used in the refining step. The fuelsproduced by USBM at Anvil Points in the1940’s were quite satisfactory.’” However,some of the fuels from the Gary Western re-fining run in 1975 failed to meet certain mili-tary specifications, principally those for sta-bility. 41 This has been attributed to the ap-plication of refining techniques unsuitable forshale oil feedstocks, specifically inadequatehydrogenation. Subsequent refining tests atSOHIO’s Toledo refinery show that, with ap-propriate refining, fuels can be produced thatare of superior quality and that can meet allapplicable specifications. 42

Cost of Upgrading and Refining

The most recent estimates of the cost of up-grading crude shale oil to a transportable re-finery feedstock have been prepared by Chev-ron U.S.A.43 The retorting complex that wasconsidered had a capacity of 100,000 bbl/d.Conventional hydrotreating was the upgrad-ing technique evaluated. Chevron consideredtwo possible locations for the upgrading facil-ity: a newly built unit at the retorting site; anda unit to be added to an existing refinery atsome distance from the retorts. In both cases,


the estimated cost for upgrading 1 bbl ofcrude shale oil was $6.50, in first-quarter1978 dollars. The product would be a high-quality syncrude suitable as feedstock formost refineries in the United States.

It is more difficult to estimate the costs ofthe total-refining option for converting crudeshale oil into finished fuels. This is because inaddition to the properties of the crude oil con-sideration must be given to the location of po-tential refinery sites, the availability of refin-ing equipment, the proximity and stability ofpotential markets, the ease of product distri-bution, and other factors. Chevron consid-ered some of these in its analysis of refiningcosts, although in a relatively generalizedmanner. Three total-refining options and tworefining capacities and refinery locationswere considered. For a l00,000-bbl/d refin-ery located in an urban area in the RockyMountains (e.g., Denver), the refining cost

was estimated to range from $8.00 to $10.00/bbl of crude shale oil. For a 50,000-bbl/drefinery located in a remote area of the RockyMountains (e.g., near the retorting facility),the refining cost would be approximately$10.00 to $12.00/bbl.* These are somewhathigher than the costs for refining a high-qual-ity conventional crude oil because of the addi-tional amounts of hydrogen that would beneeded to reduce the nitrogen content of theshale oil crude.

Another study compared the cost of shaleoil refining with those of refining Wyomingsour crude oil and Alaskan crude. It was as-sumed that a refinery in the Rocky Mountainregion was modified for these feedstocks. Theincreased costs to refine crude shale oil,rather than the other crudes, was in therange of $0.25 to $2.00/bbl.44 45

*Costs are in first-quarter 1978 dollars.

Markets for Shale OilCrude shale oil has three major potential

uses: as a boiler fuel, as a refinery feedstock,and as a feedstock for producing petrochemi-cals, The output from a mature oil shale in-dustry will probably be used for all three pur-poses. However, the relative importance ofthe three markets will change with time asthe industry develops. In the mid-1980’s,when shale oil first becomes available in sig-nificant amounts, its most likely use will be asboiler fuel, with only a small quantity di-rected to nearby refineries that could be mod-ified to accommodate the feedstock withoutlarge capital expenditures. As more shale oilbecomes available, its use as a refinery feed-stock will increase as conventional petroleumbecomes scarcer. At a later date, when themarket for boiler fuels declines, shale oil willbegin to be used for petrochemical produc-tion.

Shale Oil as a Boiler Fuel

Shale oil will most likely first be used as aboiler fuel because of the relatively smallcapital investments and very short leadtimesthat would be required. Because of Govern-ment regulation, the current trend in the utili-ty industry is to replace oil- and gas-firedboilers with coal-fired units, thus freeing thenatural gas for domestic consumers. In someareas, it will be a two-stage transition, withthe gas first replaced by oil, and the oil laterby coal. During the transition, there maybe amarket for about 50,000 to 80,000 bbl/d ofcrude shale oil near the oil shale region. Inaddition, the refining industry has a small butsignificant demand for boiler fuel because re-fineries are also changing from natural gas tooil. Therefore, refineries located near the oil

—


shale region are likely to be near-term shaleoil customers. In the long run, the largestmarket for shale oil boiler fuel is likely to bein the Great Lakes States. Transportation dis-tances will probably preclude its use in theother two major markets for boiler fuels—theeast and west coasts.

Shale Oil as a Refinery Feedstock

There has been relatively little research onthe refining of crude shale oil because build-ing an oil shale plant takes about 5 to 7 years,whereas a refinery operator can evaluate anew potential feedstock in a few days, devel-op a feasible refining strategy within a mat-ter of weeks, conduct the necessary pilot-plant refining studies in a few months, andmodify the refinery to accommodate the newfeedstock in less than 3 years. Thus, neitherthe developer nor the refiner has any induce-ment to study shale oil refining until they aresure that the oil will, in fact, be forthcoming.

Another reason is that until quite recently,shale oil was not considered a highly desir-able refinery feedstock. During the 1950’sand 1960’s, the refining industry tended tomaximize gasoline yields at the expense ofmiddle and heavy distillates. Because shaleoil is a good source of heavier distillates, notof gasoline, it was not highly regarded. How-ever, most projections indicate that gasolinedemand will peak in the early 1980’s and thendecline slightly, even though total demand forrefined products will continue to grow.46 Thiswill be the result of the increasing efficien-cies of gasoline engines in automobiles and ofa greater use of diesel engines in automobilesand light trucks. Also, because the currentsupplies of conventional petroleum are be-coming more like shale oil with respect totheir distillate yields, the refining industry isbeing forced to adopt techniques that wouldbe equally suitable for shale oil.

For these reasons, shale oil’s desirability isincreasing, and its potential availability as apremium feedstock has encouraged the refin-ing studies that have been conducted byChevron and other organizations. These stud-

ies have dealt with four general types ofrefining facilities:

1.2.

3.

4.

The

a new refinery just for shale oil;a new refinery for a mix of shale oil andconventional crude;an existing refinery modified for, anddedicated to, shale oil; andan existing refinery processing a mix ofshale oil and conventional crude.

first two approaches are precluded forthe foreseeable future because, as long as re-fined products continue to be imported, theUnited States will have excess refining ca-pacity. At least through the 1980’s, shale oilwill most likely be refined in existing refin-eries, either by itself or as a blend with con-ventional petroleum,

The shale oil produced by demonstrationfacilities will probably be processed in localrefineries* or in more distant refineriesowned and operated by the energy companiesthat participate in the oil shale programs.The much larger output from a commercial-ize industry will be more widely distributed;thus it will have to compete with other feed-stocks, at least regionally. Recent studieshave indicated that the Midwest is the mostlikely market area for large quantities ofshale oil. This includes the States in the Petro-leum Administration for Defense District 2(PADD 2), as shown in figure 50. There willbe secondary effects in other districts, as aconsequence of the supplies of shale-derivedfuels in PADD 2, because the conventional pe-troleum that it displaces will become avail-able for use elsewhere.

The quantitative impact on the supplysituation in PADD 2 can be determined by re-fering to table 20, which indicates how thedistrict’s supplies of finished fuels were di-vided among domestic and foreign sources in1978. As shown, the district consumed about518,000 bbl/d of medium and heavy distillates(jet fuels, diesel fuel, and distillate fuel oil)from foreign sources. According to Chevron’s

*’I’hese could include the Gary Western refinery in Fruita,Colo., the Little America refinery in Rawlins, Wyo., the Chev-ron refinery in Salt Lake City, Utah, ond others.


Figure 50.— The Petroleum Administration for Defense Districts

Includes Alaskaand Hawaii

SOURCE Natmna/ At/as, Department of the Intenor

Table 20.–Supply of Finished Petroleum Products in PADDs 2, 3, and 4 in 1978 (thousand bbl/d)a

PADD 2 Midwest PADD 3 Texas and New Mexico PADD 4. Rocky Mountains—Foreign Domestic Foreign Domestic Foreign Domesticsources sources Total sources sources Total sources sources Total

Gasoline. 976 1,540 2,516 422 604 1,026 33 219 252Light ends 224 236 460 276 388 664 12 25 37J e t f u e l 81 131 212 50 71 121 7 29 36Kerosine 17 27 44 19 27 46 0 2 2D i s t i l l a t e f u e l o i l 420 672 1,092 194 279 473 13 113 126Residual fuel 011 150 173 323 237 340 577 4 38 42Petrochemical feedstocks. 18 26 44 211 298 509 0 1 1Special naphthas and still gas 60 98 158 114 165 279 2 14 16O t h e r s 138 232 370 102 146 248 4 31 35

Total 2,084 3,135 5,219 1,625 2,318 3.943 75 472 547

ap,ADO = pe/rOleum ,4dmlfllSlfa10fl tor Defense Dlstrlcl

SOURCE G L Baughman The Refmmg and Markef~ng of Crude Sha/e 01/

studies, refining will convert about 74 per- tricts. The same size industry would producecent of a crude shale oil feedstock to similar about 170,000 bbl/d of gasoline, which woulddistillates.” A l-million-bbl/d industry would be equivalent to about 17 percent of the dis-yield about 740,000 bbl/d of medium and trict’s gasoline currently obtained from for-heavy distillates. If it were marketed in PADD eign sources.2, this production would completely displacethe foreign supplies and free an additional An alternative marketing strategy would222,000 bbl/d of the fuels for use in other dis- be to sell the output from a major shale oil in-


dustry in PADD 4—the Rocky Mountain re-gion—and to supply any surplus fuels to adja-cent districts such as PADD 2 or PADD 3(Texas and New Mexico). As shown in table20, the Rocky Mountain district consumes rel-atively little distillate fuel (about 20,000bbl/d) from foreign sources. A l-million-bbl/dshale oil industry could easily displace thisentire supply. The surplus production (about720,000 bbl/d) could displace about 95 per-cent of the supply of foreign-derived distil-lates in both PADD 2 and PADD 3. The gaso-line derived from the shale oil could supplyabout 67 percent of the total gasoline demandin the Rocky Mountain States.

As indicated previously, the capabilities ofthe refineries in the Midwest and the RockyMountain States will strongly affect the will-ingness of the refiners to accept shale oilfeedstocks. In some cases, shale oil could notbe accommodated without significant invest-ments of capital. However, the receptivity ofrefiners to shale oil will also be influenced bythe reliability of other feedstocks such as for-eign petroleum. The area in which the sup-plies of crude are most uncertain is the north-ern tier of States, which includes Montana,North and South Dakota, Minnesota, andWisconsin. These States have historically de-pended on refinery feedstocks from Canada,but, in recent years, a significant reduction inthese supplies has led the refiners in thisarea to look elsewhere. The result has beenthe present interest in building a pipeline totransport crude from Alaska and from for-eign nations into the area. An alternative—apipeline from the oil shale region—could alsobe built as the oil shale industry developed.

The area that covers Iowa, Missouri, Illi-nois, Indiana, Michigan, and Ohio also doesnot have an adequate indigenous supply ofcrude. However, unlike the northern tier,these States have good pipeline systems withadequate access to both foreign and domesticcrude supplies. The feasibility of marketingshale oil in this area will largely be deter-mined by the cost differential between it andother crude supplies and by the differences inthe reliability of its supply versus that of

foreign crude. Recent marketing studies haveidentified several large refineries in this areathat, with only minor modifications would beable to handle crude shale oil. 48 Furthermore,some of the refineries only have access to theheavier petroleum crudes at present, andtheir production is being limited by their ca-pacity to process the large quantities of resid-uum from the distillation of these fuels. Shaleoil, with its relatively small yield of bottomsfractions, would help alleviate this problem.

Shale Oil as a Petrochemical Feedstock

Three principal factors must be consideredin evaluating the suitability of shale oil sup-plies for producing petrochemicals:

● the yields of petrochemicals from shaleoil feedstocks;

the ability of existing and future petro-chemical plants to process the shale oil;and

● the logistics of supplying the shale oil tothe plants.

Because shale oil is produced by pyrolysis, itsolefin content is approximately 12 percent,which is appreciably higher than convention-al crudes. Together with its fairly high hydro-gen content, these characteristics make shaleoil, and its hydrogenated derivatives, appro-priate feedstocks for petrochemical produc-tion.” 50 Steam pyrolysis has been used toprocess crude shale oil, and the yields ofolefin products have been comparable withthose from many conventional crudes. Shaleoil syncrudes, with even higher olefin yields,are considered to be premium petrochemicalfeedstocks. These conclusions are based onlaboratory studies under carefully controlledconditions. The feasibility of marketing shaleoil to the petrochemical industry depends onthe ability to replicate these conditions incommercial chemical plants.

Historically, the primary feedstock for pet-rochemical plants has been natural gas liq-uids from the gulf coast. Because crude shaleoil is quite different from these liquids, itwould be difficult to switch traditionally de-


signed petrochemical plants to shale oil. How-ever, the production of domestic natural gasand its associated liquids is declining, and thepetrochemical industry is shifting to heavierfeedstocks such as naphtha and gas oils. Thesupplies of these feedstocks are uncertainand irregular. The availability of naphtha hasbeen affected by a growing demand for itsuse as a gasoline blending agent in responseto the phasing out of tetraethyl lead. Gas oilsare also being used more frequently for homeheating fuels, which causes seasonal varia-tions in their availability. Because of thesesupply uncertainties, new petrochemicalplants are being designed to be highly flexiblewith respect to feedstocks. As using heavierfeedstocks becomes more common in the in-dustry, shale oil may become a highly re-garded raw material.

The use of shale oil for petrochemical pro-duction is hampered by the distance betweenthe oil shale region and the petrochemicalplants. While refineries and oil-fired boilersare distributed fairly uniformly across the

United States, the petrochemical industry isconcentrated on the gulf coast. This concen-tration will continue into the foreseeable fu-ture. Therefore, it will be necessary to eithermove the shale oil to the coast, or to builda new petrochemical complex in the RockyMountain region. In the latter case, the half-finished products from the new plant wouldstill have to be transported to the coast forfinal conversion to commercial chemicals.The former approach is more likely but is im-peded by the lack of a product pipeline sys-tem between the oil shale region and the gulfcoast, and by the high cost of alternativemodes of transportation.

In summary, tests have shown that crudeshale oil and its derivatives could be used toproduce petrochemicals. However, these ma-terials cannot be considered to be viable feed-stocks in the near future because existingchemical plants are generally unable to proc-ess them and there is ‘no economical transpor-tation link between the oil shale region andthe existing petrochemical plants.

Issues and UncertaintiesThe technological readiness of the major

mining and processing alternatives is summa-rized in table 21. Estimated degrees of read-iness are shown as judged by DOI in 1968,51

and as they appear under present conditions.There are significant differences between thetwo evaluations because much R&D work hasbeen conducted in the interim, and becausetwo new processing methods—MIS retortingand concurrent recovery of associated min-erals—have since entered the picture. Asshown, room-and-pillar, open pit, and MISmining methods are regarded as reasonablywell-understood. Open pit mining has notbeen tested with Green River shales, but it ishighly developed for other minerals such ascopper and iron ores. It was evaluated onpaper for application to the shales on tractC-a. Some highly relevent experience hasbeen obtained from the operation of large-scale lignite (a form of coal) mines in West

Germany.5z In these operations, the lignite iscovered by 900 ft of overburden, and strip-ping operations will soon extend to 1,600 ft.This is comparable to the oil shale deposits,which are covered by a maximum of about1,800 ft of overburden.

Nevertheless, uncertainties remain withrespect to the effects of shale stability andstrength on mine design, mine safety, and re-source recovery. The effects of large inflowsof ground water, such as have been encoun-tered on tract C-a, could pose severe opera-tional difficulties, especially with under-ground mines. In all mines, the logistics asso-ciated with moving many thousands of tons ofraw material and solid wastes could presentsome formidable problems. Materials-han-dling systems exist that could be applied, butthey have yet to be tested in commercial oilshale operations.

—. .


Table 21 .–Technological Readiness of Oil Shale Mining, Retorting, and Refining Technologies

Technological readiness

Unit operation In 1968 In 1979 Developments in the Interim Remaining areas of uncertainty

MiningRoom and pillar

M I S

O p e n p i t

O t h e r

RetortingA b o v e g r o u n d

T I S

M I S

Multimineral

Upgrading andrefining. . . . . . . . .

Medium

Unknown

Low

Low

Medium

Low

Unknown

Unknown

High

Medium

Medium

Medium

Low

Medium

Low

Medium

Medium

High

SOURCE Ofhce of Technology Assessment

Mine design studies. Experience of Colony,Mobil, and the six-company program at AnvilPoints

Oxy experience at Logan Wash Mine designstudies.

Established procedure for other mineralsLarge-scale mines in West Germany. Minedesign studies for tract C-a,

Mine design studies No field experience

Pilot studies for Lurgi-Ruhrgas Semiworksprograms by Colony and Paraho Detaileddesigns by Colony and Union.

Field work and lab tests by USBM. Field testsby Equity, Geoknetics, and Talley-Frac.National lab support

Oxy experience, Design studies for tracts C-aand C-b. DOE and USBM design studiesModeling and lab support by nationallaboratories.

Pilot plant studies by Superior USBM labtests of product recovery methods. Nahcolitescrubbing tests.

Studies and refinery runs by SOHIO/Paraho,Chevron, and others. Marketing analysesby Oxy and DOE.

AGR is regarded as having a medium levelof readiness, as it was in 1968. The under-standing of its technical aspects has been im-proved since then by field tests in the Pice-ance basin, but the largest tests conducted todate have been at the semiworks scale—about one-tenth of commercial size. Their re-sults do not permit accurate cost projectionsfor commercial-scale plants. Particular prob-lems are noted with respect to the effect ofscaling up the semiworks design to commer-cial size. The on-stream factor—the fractionof the time that the retorts could be expectedto operate at design capacity—is unknown.The reliability of some associated systems(emissions controls, product recovery de-vices, materials-handling equipment) is alsoquestionable.

Rock mechanics Ground water Deep shalesLogistics.

Rock mechanics Ground water Deep shalesLogistics

Rock mechanics Logistics Reclamation

All areas

Effects of scaleup on stream factor and recov-ery. Characteristics of emissions streamsReliability of peripheral equipment Materialshandling.

Stream factor and recovery. Characteristics ofemissions streams Rock mechanics Deepshales.

Effects of scaleup on stream factor and recov-ery Characteristics of emissions streamsReliability of peripheral equipment Use oflow-Btu gas Rich shales. Mixed shales,Fracturing Rock mechanics Deep shales,

Effects of scaleup on stream factor and recov-ery Characteristics of emissions streamsReliability of peripheral equipment, Materialshandling Integration of recovery stepsUnderground waste disposal Marketabilityof byproduct minerals.

Effects of retorting conditions on crudecharacteristics Cost effectiveness of alter-nate processes Use of pour pointdepressants Effects of metals

Although understanding has increasedsince 1968, TIS must still be regarded asbeing in the conceptual stage. Many uncer-tainties remain, especially with respect toeconomics and environmental effects.

MIS retorting, a new concept since 1968,has advanced to a medium level of technologi-cal readiness, approaching that of above--ground retorts. This progress is largely a re-sult of Oxy’s development efforts in Colorado,but additional understanding has been ob-tained through simulations by USBM, DOE,and the national laboratories, most notablythe Lawrence Livermore and Los AlamosLaboratories. The remaining uncertaintiesare similar to those for aboveground retorts,except the materials-handling problems may


be less substantial with MIS methods. Themajor uncertainties relate to the use of thelarge quantities of low-Btu retort gas for pow-er generation and to the application of thetechnique to very rich or very deep shales.

The multimineral concept was also largelyunknown in 1968, although the presence ofsodium minerals was recognized. At present,the aboveground system of Superior Oil is re-garded as having medium technological read-iness. Its uncertainties are much the same asfor other AGR methods, with the addition ofthe potential difficulties with integrating thesystems for recovering mineral byproductswith those for recovering oil and gas. Themarketability of the nahcolite, soda ash, andalumina has also not been well-established.The MIS concept proposed by Multi MineralCorp. is not specifically evaluated in thetable. It would share the same uncertaintiesas conventional MIS, with additional po-tential problems introduced by the need toevacuate a large underground retort, and be-cause the oil shale resource is deeply buried.

Upgrading and refining systems were givena high rating in 1968, which has been im-proved by additional study. No major prob-lems are anticipated, although more needs tobe known about the feasibility of using pourpoint depressants, the effects of retortingconditions on the characteristics of the crudeoil, and the effects of metals (such as arsenic)on refining catalysts. The major uncertaintyin the distribution area—the existence of anadequate pipeline system to the most likelymarkets—is not directly related to the natureof the refining technology and is therefore notindicated.

It should be noted that mining and retorting(the major subprocesses having only mediumlevels of technological advancement) requireonly about 35 percent of the capital invest-ment that is needed to establish an AGR com-plex. The remaining 65 percent is distributedamong upgrading units, byproduct recoverysystems, utilities, sidewalks, and other well-established items. Yet developers hesitate tocommit themselves to oil shale plants. Thereasons given are an uncertain regulatoryclimate, an uncertain future for the price of

conventional petroleum, and the fact that allof the components of a facility must work asdesigned—not just the well-established ones.With the present state of technologicalknowledge, it is not clear that an oil shaleplant would perform as desired, nor that theoil would be sufficiently cheap to competewith its currently designated competitor—im-ported petroleum. Even though the future ofoil shale looks brighter, few companies arewilling to build large-scale plants immediate-ly. They prefer to follow conventional engi-neering practice by proceeding to an inter-mediate step—the so-called modular demon-stration retort.

The modular retort is the smallest unit thatwould be used in commercial practice, A com-mercial-size oil shale facility would use sev-eral of these retorts in parallel to obtain thedesired production rate. The capacity of amodule varies with the developer. For Oxy, amodular MIS retort might have a capacity ofonly a few hundred barrels per day of shaleoil; a commercial facility would have severaldozen of these retorts operating simultane-ously in modular clusters, each producingseveral thousand barrels per day. A modularLurgi-Ruhrgas retort would have a capacityof about 2,200 bbl/d. One or two such unitsmight suffice for the mined shale from an MISoperation; a facility that used only AGR mightneed a dozen comparable units. A commer-cial-sized plant that used Paraho retortingmight have seven or eight individual retorts,each producing 7,300 bbl/d. A comparableplant might use seven Union “B” retorts, eachproducing about 9,000 bbl/d. Colony prefersto bypass the modular demonstration phaseand to proceed directly to a commercial-sizefacility, claiming that the TOSCO 11 technol-ogy is ready to be scaled up to such a capacityfor demonstration purposes.

Regardless of these differences, the sev-eral “next steps” that are proposed by thedeveloper’s have two points in common: theproduction units must be large enough to sim-ulate actual commercial practice, and theequipment must be operated long enough toobtain reliable data on its performance undera complete spectrum of operating conditions.


R&D Needs and Present ProgramsR&D Needs

Mining

Room-and-pillar mining and mining in sup-port of MIS operations have been tested withoil shale, and an extensive body of informa-tion has been assembled. To date, however,all of the field tests have been conducted inone area—the southern fringe of the Pice-ance basin. In each case, the deposit wasreached through an outcrop along a streamcourse. The limited area in which miningtests have been conducted is unfortunate be-cause the characteristics of deposits in otherareas are quite different. They may be moreor less favorable to mine development. Forexample, there is little ground water in thesouthern fringe. In contrast, the deposits ontracts C-a and C-b, nearer the basin’s center,lie within ground water aquifers, and the in-flow of water into the mine shafts has been aproblem on tract C-a. Similar problems wereencountered at the USBM shaft in the north-ern part of the basin. Work on this site wasalso impeded by the presence of highly frac-tured zones, which are not common on thesouthern fringe.

Similar surprises could be avoided in fu-ture projects if the suitability of the candi-date mining techniques for developing depos-its throughout the oil shale region were betterunderstood, especially in these areas wherenear-term development is likely. This infor-mation could be obtained through coring androck mechanics studies, mathematical simu-lation, and experimental mining. Field testingof mining methods would be expensive,although overall costs could be minimizedthrough developing a single site that could beused to test many mining alternatives. Asingle shaft or adit, for example, could beused to test room and pillar, longwall, blockcaving, and other methods. It should be notedthat open pit mining, because of the necessityfor costly and large-scale operations, wouldprobably not be amenable to testing in a lim-ited field program.

TIS Retorting

TIS is the most primitive of the processingmethods. It has some potentially valuable fea-tures but these cannot be evaluated becauseof a lack of information. The potential im-pacts on surface characteristics and groundwater quality are especially unclear. TheR&D needs include:

●

●

●

●

●

●

●

●

development of less expensive drillingtechniques;development of efficient and cost-effec-tive fracturing and rubbling techniques;development of methods for determin-ing the success of a rubbling programthrough, for example, surveys of the per-meabili ty increase that has beenachieved;development of ignition methods and ofmethods for maintaining a uniform burnfront;study of the effects of heat-carrier com-position, rate of injection, and tempera-ture on product recovery;study of the effects of creep* on retortstability and product recovery;determination of the effects of groundwater infiltration on retorting; andevaluation of the long-term potential forsurface subsidence.

Valuable information is being obtained in theEquity and Geokinetics projects, but these re-sults are applicable only to specific types ofoil shale deposits— the Equity process toshale in the Leached Zone; the Geokineticsmethod to thin, shallow beds. Additional fieldwork in other types of deposits would aid inevaluating the potential of TIS methods forlarge-scale production. To minimize the costand duration of these tests, they could be sup-plemented with initial theoretical studies andlaboratory programs.

*Creep is the gradual change in the shape of a solid object in-duced by prolonged exposure to stress or high temperatures.


MIS Retorting

MIS is more highly developed, but moretesting is needed before its potential applica-tion to other areas of the Green River forma-tion can be determined. The R&D needs aresimilar to those for TIS. They are:

●

●

●

●

●

●

the development of better rubbling tech-niques;the development of improved remotesensing procedures for permeability,fluid flow, and temperature;the development of methods for creatingand maintaining a better burn front;evaluation of the effects of heat-carriercharacteristics;evaluation of the effects of creep andsubsidence; andexamination of the effects of groundwater infiltration, retort geometry, andparticle-size distribution.

Many of these needs will be addressed in theMIS programs on tracts C-a and C-b and theUSBM shaft.

Aboveground Retorting

Several candidate retorting processeshave been tested in Colorado, but only forrelatively short periods, and in small-scalefacilities, More R&D is needed, and particu-lar emphasis should be given to:

evaluating the effects of scaleup on theflow patterns of solids and fluids withinthe retort vessel;determining the reliability and effec-tiveness of peripheral equipment suchas solids-handling systems, pollutioncontrols, and product separators;examining the effects of heat-carriercharacteristics on product recovery andequipment reliability; anddetermining the reliability of mechanicalcomponents such as Union’s rock pump;Tosco’s retort vessel, separation trom-mel, and ball elevator; the Lurgi-Ruhrgasscrew conveyor; and the raw shale dis-tributors and spent shale dischargegrates of all retorts that use gas as aheat carrier.

Some of these needs could be addressed byfurther laboratory-scale and semiworks test-ing. Others could be estimated by theoreticalcalculations and modeling. All of them and es-pecially the need for reliability studies, willeventually have to be addressed in full-scaleretorting modules, either alone or as part of acommercial-size complex.

Upgrading, Refining, and Distribution

Because crude shale oil is sufficientlysimilar to conventional petroleum crude, nosubstantial problems are anticipated in therefining area. R&D on the effects of heavymetals on refining catalysts and of retortingconditions on oil properties could be con-ducted in the laboratory, provided that re-torts were operating that could supply a prod-uct resembling the crude oil that will be pro-duced in commercial operations,

In the upgrading area, the major need is re-lated to the feasibility of using chemical addi-tives to depress the pour point of crude shaleoil. The necessary R&D could be conducted inthe laboratory or in a pilot refinery, againassuming the availability of a representativecrude shale oil.

R&D is also needed to determine the opti-mum distribution pattern for the finishedfuels, which will vary with the size of the in-dustry, the location of the facilities, the needfor various fuels and feedstocks, and theavailability of a transportation system. R&Dis needed to determine optimal plans for like-ly combinations of these factors. Work hasbegun in this area, and more work could beconducted at relatively low cost, since it istheoretical rather than experimental innature. However, it will not be possible todefine an optimum pattern for the actualfuture industry until the sites of the produc-tion facilities are designated.

The System

All manufacturing and processing plantspotentially suffer from a lack of systems reli-ability. Because of the scale of operations andthe need for the coordinated performance of

. — . . — . — — .


many components, it is certainly possible thatoil shale plants will have significant prob-lems. On the other hand, they may not bemore severe than in other, more conventionalindustries. R&D programs, such as mathe-matical simulations and industrial engineer-ing studies, would help to eliminate some ofthe uncertainties regarding the expected per-formance and reliability of oil shale systems.Basic data on the lifetimes of equipment,operating characteristics, and other factorscould be obtained from those minerals proc-essing and refining plants that oil shale facil-ities will resemble. However, because of theunique character of oil shale operations, pre-dictions from these studies will be tentative.It will only be possible to define performancecharacteristics after large-scale oil shaleplants are operated at their maximum pro-duction capacities.

Present Programs

Some of the current R&D programs forindividual retorting technologies were de-scribed previously. An effort that has notbeen discussed in detail is DOE’s integratedresearch, development, and demonstrationprogram for oil shale.53 Its major objective isto provide the private sector with the techni-cal, economic, and environmental informa-tion needed to proceed with the constructionof pioneer commercial plants. Its specificgoals are:

● by mid-1981: to provide technical de-signs, cost data, and environmental in-formation for construction and opera-tion of at least one AGR module;

● by 1982: to design at least one commer-cial-size MIS retort that could be used onthe Federal lease tracts or in other loca-tions; and

● by 1985 to 1990: to remove the remainingtechnical uncertainties that impede com-mercial-scale use of the alternate tech-

nologies in the various types of oil shaledeposits.

In situ processing has been given the majoremphasis throughout the program, and muchof the technical R&D will be conducted in the“Moon Shot” project that will address thesecond goal. Initial support of AGR will focuson designing the retort module and on surfaceand underground mines to support singleplants and an industry of 1 million to 3 millionbbl/d. The decision to proceed with construc-tion of AGR modules will be determined bythe economic outlook for shale oil inmid-1980. DOE will consider a cost-sharedprogram if industry has not announced firmplans to proceed without Federal participa-tion. The program will also include resourcecharacterization studies that will help todelineate the portions of the oil shale basinswhere the different types of developmenttechnologies would be most applicable. Otherstudies will include assessments of air,water, land, and socioeconomic impacts; ofoccupational safety and health; and of meth-ods for increasing the efficiency of water use.

These efforts should substantially advancethe understanding of the technological as-pects of oil shale development. The budget ofover $387 million for fiscal years 1980through 1984 should be adequate to addressmost of the R&D needs identified in the previ-ous section. This budget includes about $126million for developing and operating a com-mercial-scale MIS retort, and half of the esti-mated $200 million cost of an AGR module. 54

The demonstration facilities are especiallyimportant to the acquisition of firm engineer-ing and economic data. Unfortunately, onlyone in situ technology and one abovegroundretort will be tested, and it will be difficult toevaluate fully the effects of resource charac-teristics on the feasibility of alternate miningmethods.


Policy OptionsR&D

Some of the remaining technical uncertain-ties could be alleviated with additional small-scale R&D programs. These could be con-ducted by Government agencies or by the pri-vate sector, with or without Federal partici-pation. If full or partial Federal control is de-sired, the programs could be implementedthrough the congressional budgetary processby adjusting the appropriations for DOE andother executive branch agencies, by provid-ing additional appropriations earmarked foroil shale R&D, or by passing new legislationspecifically for R&D on oil shale technologies.

Demonstration

Full-scale demonstrations will be needed toaccurately determine the performance, reli-ability, and costs of development systems un-der commercial operating conditions. In gen-eral, potential developers would prefer to fol-low conventional engineering practice andapproach commercialization through a se-quence of increasingly larger productionunits. Union, Colony, and Paraho have pro-gressed through this sequence to the semi-works scale of operation—about one-tenth ofcommercial size.

If this conservative approach were con-tinued, the next step would be a modulardemonstration facility. Although such a plantwould cost several hundred million dollars, itwould provide the experience and the techni-cal and economic data needed to decide onthe commitment of much larger sums to com-mercial-scale operation. Union has expressedits preference for this path; Rio Blanco andCathedral Bluffs are following it. Colony re-gards a pioneer commercial plant as the bestfacility for proving the TOSCO II technology.

The two general approaches to fundingsuch demonstration programs are discussedbelow. Selecting an option will depend on thedesired balance between information genera-tion and dissemination, Federal involvement,timing of development, and cost.

Private Funding

If left alone, the industry would develop inresponse to normal market pressures and op-portunities, and the Government’s expenseand involvement would be minimized. How-ever, the Government would not be assured ofaccess to the technical, economic, and envi-ronmental information that it needs to formu-late future policies and programs, althoughsome of this information could be obtainedthrough third-party reviewers or through li-censing arrangements. Another disadvantageis that industry may not risk even the relative-ly modest investment of a modular programuntil economic and regulatory conditionsclearly favor development. For example,Union and Colony have announced that theywill not proceed until Federal incentives areprovided and regulatory impediments re-moved. Industry may eventually proceed, butperhaps not in time for the resource to con-tribute substantially to the Nation’s fuel sup-plies within the next decade.

Government Support

The alternatives are full Government fund-ing of demonstration facilities, indirect fund-ing through incentives to industry, and asharing of the costs with industry. The op-tions are discussed in detail in chapter 6 andsummarized in chapter 3. In brief, Federalownership would provide the Governmentwith the maximum amount of experience andinformation. It would also maximize Govern-


ment intervention and the commitment ofpublic funds, and it might discourage privatedevelopers from proceeding with independ-ent demonstrations. Also, industry and Gov-ernment would design, finance, and operate ademonstration project in very dissimilarways. The Federal experience with a Govern-ment-owned facility may have little relevanceto the problems that would be encountered bya private developer with the same productiongoal, The Government’s experience wouldtherefore provide little guidance for evaluat-ing oil shale as a private investment oppor-tunity.

Incentives programs could involve taxcredits, purchase agreements, price sup-ports, or other types of support, either singlyor in combination. They could be structuredto encourage the participation of specifictypes of firms and could be combined withregulatory changes, and possibly land ex-changes or additional leasing, to control boththe growth and the nature of the ultimatecommercial industry. They would cost lessthan Government ownership. They would alsotend to provide the Government with less in-formation and with no operating experience.However, disclosure requirements could beinserted into the leases or the incentives legis-lation as a prerequisite for project eligibility y.

The cost sharing of demonstration facilitieswould entail intermediate expenditures ofpublic funds and intermediate levels of infor-mation. The receptivity of industry to suchproposals would depend on how much theGovernment would intervene in designing andoperating the projects. If industry responded,the Federal investment that would be neededfor a single Government-owned plant could bespread over several projects, thereby in-creasing the total amount of information gen-erated.

Program Alternatives

Demonstration will require designing,building, and operating full-size productionunits, either as separate modules or incorpo-rated in pioneer plants.

A single module on a single site.—This op-tion would provide comprehensive informa-tion about one process on one site. Eitherunderground or surface mining experimentscould be performed, but probably not both.The costs would be small overall but large ona per-barrel basis, because there would be noeconomies of scale. Some of the shale minedcould be wasted because the single retortmight not be able to process all of it economi-cally. If the site could subsequently be devel-oped for commercial production (e. g., a pri-vate tract, a potential lease tract, or a can-didate for land exchange), the facility wouldhave substantial resale value. Otherwise, itwould be valuable only as scrap.

Several modules on a single site.—Thisprogram might consist of an MIS operation,coupled with a Union retort for the coarseportion of the mined oil shale and a TOSCO IIfor the fines. As with the single-module op-tion, either surface or underground miningcould be tested, depending on the site, orpossibly both if the plant had a sufficientlylarge production capacity. The total costswould be larger than for the single-moduleprogram, but unit costs would be lower. Forexample, a three-module demonstration plantwould cost about 2. I times as much as asingle-module facility; a six-module plantabout 3.7 times as much. Different technol-ogies could be combined to maximize re-source utilization, and detailed informationcould be obtained for each. However, all ofthe information would be applicable to onlyone site. If many modules were tested, thedemonstration project would be equivalent toa pioneer commercial plant, except that atrue pioneer operation would probably notuse such a wide variety of technologies.

Single modules on several sites.—Severaltechnologies might be demonstrated, each ata separate location. For example, an un-derground mine could be combined with aTOSCO II retort on one site; a surface minewith a Paraho retort at another. Total costscould be large, as would unit costs, whichwould be comparable with those of the single-

Ch. 5–Technology 175

module/single-site option. The principal ad-vantage would be that different site charac-teristics, processing technologies, and miningmethods could be studied in one comprehen-sive program.

Several modules on several sites.—Foreach site, a mix of mining and processing

methods would be selected that would bemost appropriate for the characteristics ofthe site and the nature of its oil shale de-posits. The maximum amount of informationwould thus be acquired, in exchange for themaximum amount of investment. Each projectwould resemble the several-module/single-site option; the collection would constitute apioneer commercial-scale industry.

Chapter 5 References‘T. Ertl, “Mining Colorado Oil Shale, ” Quarter-

ly of the Colorado School of Mines, vol. 69, No. 3,July 1965, pp. 83-92.

ZRio Blanco oil Shale Project, ~etailed ~eVe~oP-ment Plan: Tract C-a, Gulf Oil Corp. and StandardOil Co. (Indiana), March 1976, pp. 7-2-1 to 7-2-20.

‘J. B. Miller, President of Rio Blanco Oil ShaleCo., letter to G. Martin, Assistant Secretary forLand and Water Resources, Department of the In-terior, Oct. 26, 1979.

‘U.S. Energy Outlook—An I~terim Report, TheNational Petroleum Council, Washington, D, C.,1972.

‘H. E. Carver, “Oil Shale Mining: A New Possi-bility for Mechanization, ” Quarterly of the Col-orado School of Mines, vol. 60, No. 3, July 1965.

“J. J. Reed, “Rock Mechanics Applied to OilShale Mining,’” Quarterly of the Colorado Schoolof Mines, vol. 61, No. 3, July 1966.

‘R. O. Bredthauer and T. N, Will iamson,“Mechanization Potential in Oil Shale Mining, ”Quarterly of the Colorado School oj Mines, vol. 61,INO. 3., July 1966.

8P. T. Allsman, “A Simultaneous Caving andSurface Restoration System for Oil Shale Min-ing, ” Quarterly of the Colorado School of Mines,vol. 63, No. 4, October 1968.

‘W. N. Hoskins, et al., “A Technical and Eco-nomic Study of Candidate Underground MiningSystems for Deep, Thick Oil Shale Deposits, ”Quarterly of the Colorado School of Mines, vol. 71,No. 4, October 1976, pp. 199-234.

‘“C. E. Banks and B. C. Franciscotti, “ResourceAppraisal and Preliminary Planning for SurfaceMining of Oil Shale, Piceance Creek Basin, Col-o r a d o , ” Q u a r t e r l y of the C o l o r a d o School ofMines, vol. 71, No. 4, October 1976, pp. 257-286.

IIJ. H. East and E, D. Gardner, “Oil Shale Min-ing, Rifle, Colorado, 1944 -1956,” Bulletin 611, U.S.Bureau of Mines, 1964.

‘2P. W. Marshall, “Colony Development Opera-tion Room-and-Pillar Oil Shale Mining, ” Quarterlyof the Colorado School of Mines, vol. 69, No. 2,April 1974, pp. 171-184,

“C-b Shale Oil Project, Detailed DevelopmentPlan and Relatea’ Materials, Ashland Oil, Inc., andShell Oil Co,, February 1979, p. IV-2.

“Oil Shale R, D, & D—Program ManagementPlan, Department of Energy, Washington, D. C.,June 25, 1979, p. C-3.

151bid.‘bIbid., p. C-2.“Ibid.18R. D. Ridley, “Progress in Occidental’s Shale

Oil Activities,” Eleventh Oil Shale Symposium Pro-ceedings, Colorado School of Mines Press, Golden,Colo., November 1978, pp. 169-175.

“D. R. Williamson, “Oil Shales: Part 5—OilShale Retorts, ” Mineral Industries Bulletin, vol. 8,No. 2, March 1965.

‘(’J. L, Ash, et al., Technical and Economic Studyof the Modified In Situ Process for Oil Shale, re-port prepared for the U.S. Bureau of Mines by Fe-nix and Scission, Inc., under contract No.SO241O73, November 1976.

“J. H, Campbell, et al., “Dynamics of Oil Gen-eration and Degradation During Retorting of OilShale Blocks and Powders, ” Tenth Oil Shale Sym-posium Proceedings, Colorado School of MinesPress, Golden, Colo., July 1977, pp. 148-165,

22R. L. Braun and R. C. Y. Chin, “Computer Mod-el for In-Situ Oil Shale Retorting: Effects of Gas In-troduced Into the Retort, ” Tenth Oil Shale Sym-posium Proceedings, Colorado School of MinesPress, Golden, Colo., July 1977, pp. 166-179.

2tJ. H. Raley, et al., “Results From Simulated,Modified In Situ Retorting in Pilot Retorts, ”Eleventh Oil Shale Symposium Proceedings, Col-orado School of Mines Press, Golden, Colo., No-vember 1978, pp. 331-342.

—

176 ● An Assessment of Od Shale Technologies

“G. L. Baughman, Synthetic Fuels Data I-Iand-book, 2nd Edition, Cameron Engineers, Inc., Den-ver, Colo., 1976,

25R. D, Ridley, “A Marketing Perspective forShale Oil,” paper presented at the meeting of theCommercial Development Association, MarcosIsland, Fla,, 1979.

zbR. F, Sullivan, et al., “Refining Shale Oil, ”paper presented at the 43rd Midyear Meeting ofthe Refining Department of the American Petro-leum Institute, Toronto, Ontario, May 10, 1978.

‘71bid.2W.S. patent Nos. 3,804,750: 3,876,533; and

4,029,571.2YR. F. Sullivan, et al., Refining and Upgrading of

Syn~uels From Coal and Oil Shale by AdvancedCatalytic Processes, report prepared for the De-partment of Energy by Chevron U.S.A. under con-tract No. EF-76-C-01-2315, 1978.

1{)W. L. Nelson, “Visbreaking as Pour Point Re-ducer,” The Oil and Gas journal, Nov. 10, 1969, p .229.

“J. D, Lankford and C. F. Ellis, “Shale Oil Refin-ing, ” Industrial and Engineering Chemistry, vol.43, No. 1, January 1951, pp. 27-32.

%upra No. 29.‘] Supra No. 31.‘%upra No. 29.“E. T. Robinson, “Refining of Paraho Shale Oil

Into Military Specification Fuels, ” Twelfth OilShale Symposium Proceedings, The ColoradoSchool of Mines Press, Golden, Colo., August1979, pp. 195-212.

‘“H. Bartick, et al., The Production and Refiningof Crude Shale Oil Into Military Fuels, report pre-pared for the Office of Naval Research by AppliedSystems Corp. under contract No. NOOO14-75-C-0055, 1975.

“R. F, Sullivan and B. E. Strangeland, “Convert-ing Green River Shale Oil to TransportableFuels, ” Eleventh Oil Shale Symposium Proceed-

ings, The Colorado School of Mines Press, Golden,Colo,, November 1978, pp. 120-134.

‘%upra No. 28,‘%upra No. 29,‘OH. C, Carpenter, et al., “A Method for Refining

Shale Oil,’* Industrial and Engineering Chemistry,vol. 48, pp. 1139-1145.

“Applied Systems Corp., Compilation of Test Re-sults, report prepared for the Office of Naval Re-search under contract No. NOO014-76-C-0427,1976,

‘2 Supra No. 35,‘]H, A. Frumkin, et al., “Cost Comparisons—Al-

ternative Refining Routes for Paraho Shale Oil, ”paper presented at the 86th National Meeting ofthe American Institute of Chemical Engineers,Houston, Tex., Apr. 1-5, 1979.

%upra No. 25.“’Pace Company Consultants and Engineers,

Inc., Shale Oil Refining Analysis, report preparedby the Pace Co. for the Department of Energy andOccidental Oil Shale, Inc., 1978,

%upra No. 25.‘7 Supra No, 43.‘“Purvin and Gertz, Inc., Markets for Crude

Shale Oil in Central U. S., report prepared for Oc-cidental Oil Shale, Inc., 1977.

“yIbid,5’]C. F. Griswold, et al., “Light Olefins From Hy-

drogenated Shale Oil,” Chemical EngineeringProgress, September 1979, pp. 78-80,

“Prospects for Oil Shale Development—Colora-do, Utah, and Wyoming, Department of the Interi-or, Washington, D, C., May 1968, p, 47.

52M. A. Weiss, et al., ShaJe Oil: Potential Econo-mies of Large Scale Production, Workshop Phase,The Massachusetts Institute of Technology, Ener-gy Laboratory report No. MIT-EL-79-031-WP, July1979, pp. 6-7.

‘] Supra No. 14, at pp. 1-6.5%upra No. 14, at pp. viii-ix.

shale processing

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