CALIFORNIA STATE UNIVERSITY, NORTHRIDGE
OIL SHALE: AN OVERVIEW ) (
A graduate project submitted in partial satisfaction of the requirements for the degree of Master of Science 1n
Engineering
by
John Page ------
June, 1979 The Graduate Project of John Page is approved:
Jon H.
California State University, Northridge
ii PREFACE
This report deals with various aspects of the oil
shale industry in the United States today. Only that part
of the industry which relates to above ground retorting is
focused on. In situ technology will not be discussed as
such, but will be included only insofar as it adds con-
tinuity to this report. The in situ process is not
focused on because it is still largely in the study phase,
is not yet technically ready for commercialization, and
forms a small part of the overall oil shale industry.
There is much published literature which focuses on particular facets of oil shale. One can find information
on retorting, costs, environmental aspects, and a host of other specialized topics. However, works which treat oil
shale on the whole are few. It is the purpose of this report to fill such a gap; to give the reader an up-to-date overview of the salient aspects of the technology, problems
and prospects for the industry.
].ii TABLE OF CONTENTS
_DPaae__
PREFACE iii LIST OF TABLES vi LIST OF FIGURES viii ABSTRACT ix
Chapter
I RESERVES 1
II RETORTING 6 Bureau of Mines Gas-Combustion Retort 7 Union Oil Company Process 17 The TOSCO-II Process 21 The Paraho Process 24
III REFINING 30 Union Oil Company 30 Applied Systems Corporation 31 Performance Characteristics of the Shale Oil-Based Fuels Refined at Gary Western 47 IV ENVIRONMENTAL ASPECTS OF OIL SHALE DEVELOPMENT 51 Physiography and Climate 51 Water Requirements 52 Water Availability 53 Waste ll/"ater 54 Air Quality 55 Spent Shale Disposal 61
v COSTS OF A COMMERCIAL OIL SHALE FACILITY 67 VI PLANS FOR COMMERCIAL DEVELOPMENT 75 Colony Development Operation 75 Union Oil Company 76 Paraho 76 Superior Oil Shale Project 78 C-b Oil Shale Venture 82 Rio Blanco Oil Shale Company 83 White RiveT Shale Project . 84
iv Industry's Views on Commercialization . 85
VII THE FUTURE 87
FOOTNOTES . 89
REFERENCES 100 LIST OF TABLES
Table
1 Typical Composition of Oil Shale Sections Averaging 25 Gallons of Oil Per Ton in the Mahogany Zone of Colorado and Utah 2
2 Shale Oil Resources in the Green River Formation, in Billions of Barrels . 5
3 Operating Conditions for Evaluation Runs on 150 tpd Plant 14
4 General Data Summary, Evaluation Runs on the 150 tpd Plant 14
5 Raw and Retorted Shale Properties, Evaluation Runs on the 150 tpd Plant 15
6 Product Oil Properties, Evaluation Runs on the 150 tpd Plant 16 ..., I Product Gas Properties, Evaluation Runs on the 150 tpd Plant 16
8 Product Oil Properties for Union Oil Retorts, Models A and B 20
9 Companies Participating in the Paraho Oil Shale Demonstration Project
10 Paraho Retorting Gas Properties (Dry Basis) 28
11 Paraho Retorting Product Oil Quality 29
12 Product Yields from Refining of Commercial Shale Oil
13 Product Properties from Refining of Commercial Shale Oil 34
14 Paraho Retort Crude Shale Oil 35
15 True Boiling Point Distillation of Shale Oil Crude .
16 Physical and Chemical Properties of Nato Gasoline (Blend Line) 42
vi Table
17 Physical and Chemical Properties of JP-4 43
18 Physical and Chemical Properties of JP-5/Jet A 44
19 Physical and Chemical Properties of Diesel Fuel Marine and DF-2 . 45
20 Physical and Chemical Properties of Heavy Fuel Oil 46
21 Emissions and Fuel Economy--Shale Gasoline . 48
22 Energy Processes: Water Consumption Comparison 53 23 Federal Primary Ambient Air Quality Standards 57
24 State Ambient Air Quality Standards 58
25 Results of Modeling Studies for Facilities Producing Between 45,000 and 62,500 Barrels/Dav 60
26 Chemical Properties of Union Oil Spent Shale 62
27 Inorganic Ions Leachable from Freshly Retorted Shales (Kgs/tonne)--Based on Laboratory Tests 62
28 1971 Species Plots 64
29 Capital Investment Summary 69
30 Estimated Annual Operating Cost 70
31 Breakdown of Investment for the Colony Project 72
32 Breakdown of Operating Costs for the Colony Project . 73
33 Oil Shale Reserves, Prototype Tracts 81
vii LIST OF FIGURES Figure
1 Distribution of oil shale in the Green River Formation, Colorado, Utah and Wyoming 4
2 Gas-combustion process 8
3 Isothermal cross section, 6 tpd retort 10
4 Bed temperature profile, 6 tpd gas retort 11
5 Basic 150 tpd retort dimensions and thermocouple locations 13
6 Side view of Union B retort 18
7 Flow diagram for Union B retorting process 19
8 Pyrolysis unit TOSCO II process 22
9 Seventeen-story tall semiworks structure at Parachute Creek . 23
10 Paraho retorting, direct mode 26
11 Paraho retorting, indirect mode
12 Refining commercial shale oil, fluid catalytic cracking case
13 Schematic diagram--gasoline processing 39 14 Refining process schematic diagram 41
15 Union Oil Company's experimental 10,000 tons per day oil shale plant 77 16 Map showing general geographic location of the six oil shale tracts . 80
viii ABSTRACT
OIL SHALE: AN OVERVIEW
by
John Page
Master of Science in Engineering
This report gives an overview of some of the prominent facets of the conventional oil shale industry in the United States today. In situ technology as a separate item is not discussed.
Topics covered include oil shale reserves; and the
U.S. Bureau of Mines gas-combustion, Union Oil Company,
TOSCO-II, and Paraho processes for retorting the oil shale.
Refining experiences of the Union Oil Company and Applied
Systems Corporation are mentioned, and a description of the performance characteristics of some of the refined products of crude shale oil are presented. Environmental aspects dealt with focus primarily on water, air quality, and spent shale disposal including the 1·evegetation operations of two companies on spent shale. Meeting air quality
ix standards is the most difficult environmental problem with which the oil shale industry has to deal.
Recent cost estimates for an oil shale facility follow next, and price ranges for shale oil produced today are presented. Although no commercial oil shale facilities are currently under construction, plans by the major corporations which may lead to commercialization in the future are given, along with views by those in industry on the constraints facing commercialization and what can be done to alleviate them. Finally, some reflections on the outlook for future development follow.
X CHAPTER I
RESERVES
Oil shale may be defined as fine-textured sedi- mentary rock containing organic matter which yields sub- stantial quantities of oil by conventional methods of destructive distillation. About 80% of the organic material is finely divided insoluable matter known as kerogen, the 1 2 rema1ncter. . cons1st1ng. . o· f sou.1 bl e b.1tumen. ' Table 1 gives the composition of typical oil shale from the Mahogany zone of Colorado and Utah. Some oil shales contain appreciable amounts of nahcolite, NaHC0 3 , and dawsonite, NaAl(OH) 2co 3 , both of vihich are sodium carbonate salts. Nahcolite may be processed and refined into baking soda. It also has a high affinity for sulfur dioxide, making it a valuable material for air pollution control. Dawsonite can be processed to yield alumina, the basic material from which alwninium is made, and soda ash (sodium carbonate). Soda ash is used in the manufacture of glass, in the paper and pulp industry, and the production of detergents.
Oil shale reserves in the United States are commonly quoted on the basis of the amount of oil, in gallons per ton, which may be derived from them. High grade deposits contain 25 or more gallons per ton. The United States is
1 2
Table 1
Typical Composition of Oil Shale Sections Averaging 25 Gallons of Oil per Ton in the Mahogany Zone of Colorado and Utah3
Weight-percent
Organic matter: Content of raw shale 13.8
Ultimate composition: Carbon 80.5 Hydrogen 10.3 Nitrogen 2.4 Sulfur 1.0 Oxygen 5. 8 Total 100.0
Mineral matter: Content of raw shale 86.2
Estimated mineral constituents: Carbonates, principally dolomite 48 Feldspars 21 Quartz 13 Clays, principally illite 13 Analcite 4 Pyrite 1 Total 100
particularly rich in deposits, with known resources of 4400 4 billion barrels oil equivalent. The eastern and central parts of the country contain approximately 250,000 square miles of shale underlain deposits up to 800 feet thick. 5 Known resources are estimated at 400 billion barrels. The
average oil yield, however, is low, being less than 10 3 i.
gallons per ton. In certain areas deposits 5 to 20 feet thick yield 10 to 20 gallons per ton. Shale deposits with oil yields greater than 25 gallons per ton are very small.
In Alaska, oil shale deposits are not well defined, how- ever, those yielding over five gallons per ton are thought to be large.
By far the largest known oil shale deposits in the
United States lie in the three-state area of Wyoming, Utal1 and Colorado and constitute what is kno1'-Tn as the Green
River Formation (Figure 1). Of these three states,
Colorado has the highest quality reserves, the Piceance
Basin within the state being particularly rich (Table 2).
The Mahogany zone which underlies more than 2000 square miles largely in the Piceance Basin contains deposits at least 30 and up to 2000 feet think, yielding on the average
30 gallons per ton of oil shale.
So far, mention has been made only of total known reserves. All of these reserves are neither technically nor economically recoverable. Estimates of the total resources recoverable under present methods differ. 6 Duncan and Swanson give a figure of 80 billion barrels of oil equivalent based on deposits 25 or more feet thick averaging 30 to 35 gallons of oil per ton, and lying less than 1000 feet below the surface. A National Petroleum
Counci1 7 estimate gives a figure of 54 billion barrels 8 based on reserves in the Mahogany zone. Parent and Linden 4
EXPL.O.NATION
I · ... I ,... : .. . 1':: . : ·. l
Area underlain by the Green River ~rea underto1n 'Oy c1i shale more Formal ion in which the oi I shale than 10 feet thicll ,Nhich y1o.los is unappraised or low grade 25 golions or more oil par ton ol shale
Figure 1. Distribution of oil shale in the Green River Formation, Colorado, Utah, and Wyoming.9 .)c
Table 2
Shale Oil Resources in the Green River Formation, in Billions of BarrelslO
Range in Grade (oil yield, in 25-65 10-25 5-10 gallons per ton of shale)
Piceance Basin 450-500 800 200 Uinta Basin 90 230 1500 Green River Basin 30 400* 300*
* Includes Washakie Basin.
put the figure at 74 billion barrels. By comparison, proved recoverable reserves, under present methods of con- ventional technology, of crude oil in the United States 11 are estimated at 33 billion barrels. CHAPTER II
RETORTING
Conventional room and pillar or open pit mining
techniques are the primary candidate methods for extracting
the raw oil shale. In room and pillar mining, 60 to 70 12 percent of the shale is extracted from the mine, while
the remainder stays in the form of large pillars to support
the roof. If the shale is close to the surface, open pir
mining may be employed to obtain the shale. Following the
extraction of the shale, it is crushed. Values for the
final size of some crushed shales are given later on in
this report.
After crushing, the oil will be extracted from the
oil shale. A number of different methods exist for accom-
plishing this, all of which involve heating the oil shale
to break down the kerogen. These methods are called
retorting. Some of the more widely-recognized above
ground retorts used or in use in the United States will be
discussed in this chapter and include the Bureau of Mines
gas-combustion, the Union Oil, TOSCO-II, and Paraho retorts.
Primary emphasis will be given to the retort itself, peri- pheral equipment needed to maintain the retorting process
or to remove the retorted oil will not be specifically
6 7 i
described, but will be mentioned if necessary for under- standing the operation of the particular retort in question.
Except for the Bureau of Mines gas-combustion retort, the retorts described herein are utilized by companies whose activities will be described later in this report.
Bureau of Mines Gas-Combusion Retort
From 1944 to 1956 the Bureau of Mines operated the
Oil-Shale Experiment Station at Rifle, Colorado, conducting research on the mining, crushing, and retorting of oil shale and the refining of the shale oil. As part of its studies, the Bureau developed and operated the gas- 13 combusion retort. Figure 2 shows the basic gas-combustion process. The four zones pictured in the figure are not separate physical zones as such, but are so labeled to aid ln understanding the process.
Raw shale, crushed and sized, enters at the top of the retort where it is heated by rising hot gases from the combustion zone. As the shale passes downward it is further heated in the retorting zone where the organic matter in the shale is decomposed to liberate oil vapor and gas. As the oil vapor passes up through the product recovery zone, it condenses into a fine mist, and then passes out through the top of the retort. The shale oil is recovered by oil-mist separators. The gas which leaves the retort is divided into three streams, and depending upon where it eventually ends up, is termed the product, 8
RETORiED S~ALE
. 14 Figure 2 . Gas-combustion process. 9
dilution, or recycle gas. The dilution gas is mixed with
air and fed to the combustion zone where it, and the
carbonaceous residue left on the shale after it leaves the
retorting zone, are burnt to provide the heat for retort-
ing. In the heat recovery zone, recycle gas is injected
at the bottom of the retort. This heats the gas and cools
the shale before it is discharged at a controlled rate.
Product gas is vented to the atmosphere. This gas has a
low heating value, varying from 80 to 100 Btu/std. cu. 15 ft. Even though this gas is low in heating value, plans
are being considered to burn it to produce steam and
generate e 1 ectr1ca. 1 power. 16
Three retort sizes were tested by the Bureau of
Mines: 6-, 25-, and 150-ton-per-day. The 6-ton-per-day
retort was a laboratory device useful for obtaining infor-
mation on basic operating conditions. The 25-ton-per-day
unit served as a pilot to the operation of the 150-ton-
per-day retort, which was run with the hope of providing
engineering data for the possible future design of a
commercial unit. Such a unit would have a capacity of
at least 1000 tons per day. Figures 3 and 4 show tempera-
ture profiles encountered during a ten-day demonstration
run in the 6-ton-per-day retort. In Figure 3, the cone-
like object in the center of the retort is a distribution
device for the dilution gas and air. The rotating disk
seen at the bottom of Figure 4 provides for the smooth 10
----I 5JI) ~
w ...J 5 (/)
17 Figure 3. Isothermal cross section, 6 tpd retort. 13
12 ' ~ I I I I I I" I - -Ill - --- -h
II .. .._.___ ----· ------.____, .. ---+·--·-----
10 ·------··· ------·-·------·- ---- 1- loJ ~ 9 !
CJ w c -·- · al----i ~ ., -·-- -1 0 'I' ~ I ~ 6 .. I / Ll. ~ ~~ ~ s ------~------t------I I I _./
/I, C> 1/ tl ili 4 ------·------·------1- ---! --- .. 1-----+-----f---1--- ,,,0 J:
0!! !/i' '; t I I /, 1 I /! /f ------1------·------·~~ ~ '/. '/ '/.. 0 I__ ------=i~J -- . --- -~ 500 1poo 1500 TEMPERATURE Of SHALE BED, °F •
Figure 4. Bed temperature profile, 6 tpd gas retort. 18
f-' !-·-= 12
discharge of the retorted shale. The basic 150-ton-per- day unit is shown in Figure S. Included in the figure are the locations of the thermocouples used for tempera- ture measurements. A summary of the operating conditions and test results for this unit are given in Tables 3 through 7. Operation of this retort was described as 19 0 Smooth for all tests."
The work performed by the Bureau of Mines was experimental in nature. Various shale sizes, dilution gas rates, and air distributor configurations were tested to gain information on their effects on the retorting process.
The Bureau of Mines facilities were closed down in
1956 and reactivated in 1964 under the Anvil Points Lease 20 21 Agreement. ' Th~ facilities were leased to the Colorado
School of Mines Research Foundation for additional studies on oil shale processing techniques. This research was supported by six oil companies: (1) Mobil Oil Corpora- tion; (2) Humble Oil and Refining Company; (3) Pan American
Petroleum Corporation; (4) Sinclair Research, Inc.;
(5) Continental Oil Company; and (6) Phillips PetToleum
Company. Further experimental testing was peTfoTmed on the 6-, 25-, and 150-ton-per-day retorts, the last of which was completely rebuilt. The shale feed rate in the 2 largest retort was raised to 500 lb/ft -hr, about 200 lb/ 2 ft -hr gTeater than that achieved by the Bureau of Mines in 1955. However, many problems were encountered in the fi~~"t_J_j ~-\---7-r--r-.r~ ~-· \ ,. " l '.'. ,' PI] I. .,:·\ .'il ..... \ \ -~1 ~,. /' . '· \/ /' ·~\/1/ \ __ t ... t .. L ~ ;;-e-'--"'1., \tJ~ r'""-'-'~ -11!-~ \ ' ' 'iltl' ~\\ n I !, '~ ~!~y·-.:!i il Ll: [-,,_::J,~ :~ ""'"'" ~C.]\}!,c······, < ~(C:J ~i (~; ---·-·---~!---111 1 p?=l 00 Jn tt ~·;-. 001! ll 00 ~~= ~ :::]·~ oo" 00 ~ ~ ~ -;:.-~ -~·- ~~ ~· !-T:- ; • Tlf ~-1 -~~-!--! ll ... - ·' J-\1 a··al\, ~ H--~ ~- -.--, Irillo":~ :l. ; ) .. ~ I • • • ,;,.. ,.;.,.\11 m ·.• . ·' :. ~h..;: "! :; ~ .• ! a. I ,.~ • y 'il h) .11 ,. •t .~o .u 2 IS 14 I' 'A-·[----,;:-;1& ______t_~i ~~r:i~r-;~ _:~- LL-~;-,.,--"-;-A__ J :.s..:..__ti_Li - __• _ .. _!.Q _ _jL I -"-~~·-..!:__ -~~
~~'"11 'fii!·l4 ~~ n·• ..J I _;._--'--lL I ' I I :------r--F---1--__J._
S.:lUH1 Sll.IE UIH 5!0( NOftl u SIDE WfST SlOE
Figure 5. Basic 150 tpd retort dimensions and thermocouple locations. 22
v<·~ Table 3 () pe1·ating conditions for elllt1uatioll runs on 150 tpd plant. 23 I '!'est uumht~r lh7l':~-~~ [~,: ~-1-=~~~~~ ~~::~~.::~-r~~~"~:,;~:;~;;,-r·---~~~;~ ~:~:~;:/~;,~; r---- B~:~~;.~;;;--·-r-·slj~;,~~c, ------·--- 2fi-1 ...... 2!17 :1,0·10 12,700 2,b21• !J tt 11 iu % tu a 25-~ ... ' .. : ...... :100 •1,0~0 1-1,11()() !!.~60 0 ft ll In % tu il 2~·<1 ...... :!!)r, ~.010 H,!!OO 2,·;r)o ll H 11 in % tn a 2n- .J .....••..••..••.. 30-1 :uno 12,800 2,85U ll ft 11 In % to 3 2fi ··5 .. . ' ...... ~fJ7 :!,:HO 13,1)()1j :l,!Jtli !I It 11 in % to 3 21;-1 ...... ''. '.'.' ~22 •1,2:~n 1!!,200 :!,7:!0 !l ft 11 In ·t to 2 :!H· 2: •...... •••••.. 221 4,2:~0 I :l,t;O(I 3,8'1() I) ft 11 In 1 to 2 :!l.i· 3 .. ' ... ' .. 2!19 :J.[151l 12:10o !!,fJf)O !l ft 11 In 1 to 2 2tj ·I ...... 2!JH a.oou 12,ti00 :l,\1:10 fl ft 11 In I t<>:.! ~n- 5 ...... :Hit :l,f;!l() 12,(\fltl :!,0811 !l fl II lu 1 !to 2 2t'·l ...... ;!50 :uHo l!.U>Oo 11,11 () H ft 11 lu 1 t I 50 tpd plant Tetsl 11~1\l•b':l. 21i(l-2) 1211(:1-5) I ~7(1-3) 128(1 I) I ~!l(fi· I>) } .t:UJ.tl; ,..If ll'!'il .l1dU£'::6. 1~0 413 7'1. 72 \h; 13 Hutcd, twd t 1li(1Htiticl::l: bltul•: Bl:t.l' ...... incl~c~. h~-~:i l·-2 1·-:.! 1-2 L-:! l·:l n,.d l.ei~ H7 Hu ~·• ~ j __ -- ····-- .... ____ .___ I.··- f-1 ~ Table 5 Ram rmd rctm·t,;d /$hal~~ jJ/'OjiCI'Iics, eoalualivn 1'WtS on ilttJ f/il} I jld Jll•wl 2 5 I [)0 L{Hl p hLU L ------·-·· ------··~-----·--·- ···----··· 'fctst nun1ber . ... , ...... , ...... ~5(1- 5) 2ti(1--~) ~6(3-li) 127(1-:l) I 23(\ I) 123(iHi) ------___¥ ___ ------ltaw •hale p&·operties; Fischer """"Y...... -...... , .gal/tun., . 28.9 25.0 2(UI :.!7.8 I Miner .. ! CO,...... _. _...... "'t I•Ct ... 16.5 If'' li15 I 27.31111.5 ~~-HHi.f• I 16.6 I Noruinal p&.rticlj~ flize...... inches . .. H w3 1 t(;·2 I 1 to 2 I to 2 1 t.o 2 I Ill 2, St;rcen nnalysiB, im~het.i; plus a.oo...... -... wt. pet ... Jn.fl l\linus 3.00 plus 2.00...... wt pet ... 21l.O 0.1 !>linus 2.00 plus 1.50...... wt. pet ... 18.5 ... ·-lil.2 ;tR.IJ :lil..S l\linu• 1.51) J>lus 1.050 ...... wLJ>Ct ... 1·1.3 38.1 -13.1 40.3 -l~{: :28.1 Minus 1.050 plus .7-12...... wt pet. 1!.8 !J.tl 15.1 17.4 15.:1 ·lfi.:l f\tinus .7,12 J..llus .525...... wt I'd 7.2 0.8 1.3 1.6 1.0 2:l.fi l\linu~ .IJ25 plua ..171...... , .. wt IH:L. 5.lJ 0.4 0.7 0.!1 uu J.l); Minu• .371pln• .~li3. . ... , ...... wt pd. 2.1 O.:l o.:l 0.5 I) 2 l.a I Minua .2ii.1pluo.J85...... wtpct. 0.8 o.:t ll.J 0.4 0.:\ o.t lllinus .185 plus .till...... wt pet. 0.1 0.3 0 ., O.l I Pim plue lo"S...... _ ...... wt pet ... 1.2 0.0 0.5 1.0 0.1 (J.Il Huto1 t.c:d slialc {)l'fJpcrtic~: Fhwlter Ml::~ny...... g,u.l/ton . .. 0.1~ 0.2fl 0.~0 0.17 11.11:! lJ.IO !.! iu<:ral CO,...... ·...... , .. wt pel ... 15.1 1-1.7 IVj H.fJ }.'), ~~ 15.:1 2.H2 2.-15 2.70 2A7 2.1\fJ :l.t).r.i ~~~~r~~~ t:!~~~~ .. ~::: .. ::::::::: .. :::::::: · ·: :~ :;:~~: .. !H.O 17,.( 17.5 17.:1 1/.B I K.l ...... (J> Table 6 Product oil properti(';s, evaluation run8 on the 1!10 .'f'd planl 26 ------t------150 t.p T~•t munber ... __ . _.- 2fo(l-5) (2•)(1-2) 1 ~n(:J-5) 1 27(1 Gravity ...... ·-·-----·- ---·-·--·-·- .•API 20.!1 2L:.! 21.~ 21.1 :!Ll :!1.-1 l'ourpoint ...... -···- ...... 0 1'. 81 !lt: 85 !H l:il B5 Vist:o8ity 11t 1:10• F- :-: ...... RSII... Ofi.·l 0:\.li ll1.7 ll2.a !l:l.!l 8!>.5 Vi~cosity nt 210° I<' ...... •...... !:iSU... 4U .J:J.!l -t:l.3 4:1.2 ·l:l.ti 4:1.1 F1n•h point, COG ...... __ ... __ ._ .. __ . • F... 210 2o:J 207 2~a :!15 l\15 S,tli~rumt. _ .. - - _...... _ .... - .... _ _ ..... wL pet... O.tH 0.:1:1 O.til 0..17 1.07 l,IJ(f ltotn&hottom c11rbon contomt ...... _...... wt l"'t. _ _ L.W 1.:10 L:lO L2:l 1.21:! L~tl Sulfur ...... v.t pet.. O.fi8 O.til.l 0.118 O.W 0.70 O.tl2 Nitrogen ...... WL{Jct... 2.13 2.13 2.11 2.1:1 2.14 2.0!1 Wl\tcr ...... - ..... - .... -- ____ .- __ ...... vol pet... 0.1 2.5 0.5 0.5 2..1 5.3 Vacuuw diotillation (ASTM D-1160) (onn:cted to 7ii0 tnm): lnili>ll boiling l"'int ... _...... 0 1•'. I :J75 37:1 :111:1 :J70 :\til 375. 2 pcrcc!tl-. .... _...... • F . . 405 ·102 :l!i-1 .JOl :181) :19:1 5 percent...... 0 J.' . 4f,:l 44:\ 4-1-1 -15:1 ·1-10 •13ti lO JU~rccnt...... , ...... ° F. . [)00 fl()f) Table 7 2 7 Product ga.~ prof11ll'lit~8, eoaluation runs on tlw J(j() fj)(t plant ------r------150 tju.l plunt. fl\~e;t nurulwr .. ' ' ...... ' ...... '' ...... , ·- 25(1--5) 21i(l ~) 2ti(3-5) 2"/( 1--:1) ~8(1 -1) ~8(.'Hi) ------·-·------·--~------·------·------·---- Orsu.t tundysio, dry luuda: COa .... --·-···- ·---·--···-·······-·--··voi(H:t. 2~.7 2•1.\l ~fi.2 25.:1 ~:UI :.!:U) lJwutturnted h)•dror.arhon6...... volJlCt. J.IJ 1.5 1.7 !.8 !.0 ·I.S 0.3 0.3 0.2 o.:l 0.2 o.a gb: :: : :: : : : : :: . .. : ...... ::::: ~~~ 2.8 3.1 2.1i :1.0 2.:1 1.8 lla _ .. .. . _. . _. __ . _ ... __ vol pt:t. 4.11 1.7 4.:1 ·1.8 5.:1 ~.2 SnturaleJ hydlot:arhont5 .. , ...... 1:ol JH;t. ·1.:1 3.fi a.!:! 3.1i Cl u N2...... , ...... vol JICt {,;l.() H~.O ft2.2 1'1.2 t~:L~ !iLO \V alt~r VU.iH)f ...... vnll'(:l .. 18.! lli.2 17.0 17.8 111.7 1-1.~ Gro&s h·en.ting vu.lue ...... lltu/ntd cu fl. J:!(J Ill llli liS ·J:l[l 113 ·--~------~------· ·-·-·-·--··-.. -- .. ---~ --" ------ !-" 0\ 17 operation of this new retort, the most persistent of which seemed to be the formation of clinkers, fused lumps of spent shale. Operations at Anvil Points ceased in 28 September of 1967. Although higher shale flow rates had been obtained, it was felt that operating problems had 29 not been fully resolved. Union Oil Company Process Union Oil Company has had a long involvement with oil shale, going back more than 50 years when it began to acquire oil shale bearing lands in Colorado. The company currently owns almost 20,000 acres of land containing some two billion barrels of recoverable oil. "From 1955 through 1958 Union built and operated a retort in the Parachute Creek Valley, processing up to 1,200 tons of ore per day. which is "probably the highest oil shale processing 31 rate to date in the United States.'' Additional research and development since then has led to the current design, the Union Upflow Retort "Nadel B." The Union B Retort (Figures 6 and 7) is of novel design, utilizing a "rock pump" mounted on a moveable bed to transfer the shale from two feed chutes up into the cone-shaped retorting vessel. Union developed the "rock pump" in order to handle a wide size range of shale 32 part1c. 1 es an d c h aracter1st1cs. . . R ecyc 1 e gas, ra1se. d to 950-1000°F outside the unit, is fed into the top of the vessel and provides the heat for retorting. For retort B's 18 B F / " HtCYCL[ ,;A> / _) tlfA!(R --...,..------4~1 11 IIIliI " IIIII !..!..~------. ..------"'1 0 iWJ VENTURIS(ftUBU£ R SliA!..£ hJI.. "-" j _,._R Ot'L-\.IAHR ' . T IIAKE GAS TO ~ __]}- SlPAI\MOR .=; R£T~:S TREATIHG -" (~ 1 r . . rJ . L=-~ rJ2L~ I I '-1- I -- "-' RflORTED StiALl TO ~ ' DISPOSAL l1Gt1T-ENDS OIL HAKE UP \.IAH R ------··------Jo.--~------• - RUtWIJI.HI Oil PRODUCT l,....._ ...,.., ..,~,~ ·••·'-''·"-"-• ''' ''..-"""""~' '"'""'"·"" ·.=,.,,,_·.::•··•·•'''" """"""'=•~ .~·"-''·''"'"'- '"" "'- u.• ,, .. '• <'•" •, :.,;,,...,, ..... ~· "-"~.-.·" •• •.... ,. '""''· "-"'"""'-"'... "'"'"""""" ""'""'""'".-..,v' "'-'·•·'~· '· Figure 7. Flow diagram for Union B retorting process. 34 ,_, '-0 20 predecessor, retort A, heat was supplied by burning the carbonaceous residue on the spent shale. In either case, hot gas flow is downward, countercurrent to that of the shale. Spent shale overflows the retort walls at the top. Product gas from retort B has a heating value of 800 35 36 Btu/scf compared to a value of 83 Btu/scf for its pre- decessor. Retort B produces a product gas of high heating value because combustion does not take place within the retort. Properties of the product shale oil for retort B are given in Table 8. For comparison, those same proper- ties for retort A have also been included. A number of the terms in Table 8 are worthy of explanation. API (American Petroleum Institute) gravity is defined as: 141.5 Degrees API = - 131. 5 sp.gr. wh ere sp. gr. d enotes spec1"f" 1c grav1ty.. 37 The pour point 38 refers to the temperature at \ The Conradson carbon residue is a measure of the amount of 39 carbon in the oi1. Table 8 Product Oil Properties for Union Oil Retorts, Models A & B 40 41 Retort A Retort B Gravity, 0 API 20.7 22.7 Sulfur, wt % • 7 7 .81 Nitrogen, wt go 2.01 1. 7 Pour Point, °F 90 60 Conradson carbon residue, % 4.57 1. 7 5 21 . 42 43 The TOSC0-11 Process ' The TOSCO-II Process was developed by The Oil Shale Corporation and is a refinement of the Aspeco Process, named after Aspegren, a Swedish inventor. A schematic of the process is shown in Figure 8, and a picture of a 1000- ton-per-day semiworks structure appears in Figure 9. As shown in Figure 8, ceramic balls, one-half inch india meter, are heated to approximately 1100°F and fed into a rotating drum. Also fed into this drum is shale of minus one-half inch size preheated to 500°F by the flue gases which exit from the ball heater. Minus one-half inch shale would fit through a grate having a square opening one-half inch on a side. Two tons of balls are present for every ton of shale. The rotating drum, which measures eight feet in diameter by 15 feet in length, is kept under an internal pressure 5 psi greater than atmospheric, so that pyrolysis, at a temperature of 900°F, takes place free of air. The ceramic balls not only heat the shale but pulverize it as well. The spent shale and balls exit from the drum at 900°F. A trammel separates the balls from the shale. Propeities of the crude shale oil are similar to those for the Union Oil Process: gravity, 21°API; sulfur, 0.7 wt %; and nitrogen, 1.9 wt %. I L.lAII <>A~ to AIM(J')I-'IItll£ ·-· .- .~~:~·-~_c;~~:~·.:. - Ho GAS .:>--" - · flft:t,vl in wra.1fll fUJt. bA:l _.. ·At40 I ~CI ('..) [-...) 23 Figure 9 . Seventeen-story tall semiworks structure at Parachute Creek houses the retorting system developed by TOSCO. Crushed oil shale ore is flrst preheated by hot flue gases, then rapidly retorted at about 900°F by mLxing with heated ceramic balls. The system permits virtually 1 00 wt '/.; recovery of contained hydrocarbons. Facility is a 1000 ton/day model of each of the 1 1,000 ton/day retorting units to be used in commercial production. Serni'Works plant was shut down in the spring of 1972, following completion of successful runs wh.icn neet design, operability and emironmental protection objectives. 4 ;J 24 47 The Paraho Process 46 , The Paraho Oil Shale Demonstration Project was launched in September of 1973 and lasted through August of 1976. The program was conducted at the Anvil Points Oil Shale Research Facilities near Rifle, Colorado, under lease from the United States Government. The project was funded by 17 participating companies listed in Table 9. Final cost of the project was $10 million, compared to an initial outlay of $7.5 million. Two retorts were constructed at Anvil Points; one, a 4-1/2 foot outer diameter pilot plant with a capacity of 20 barrels of shale oil per day, and the other a 10-1/2 foot outer diameter semi-works unit with a capacity of 200 barrels per day. The Paraho retort may be operated in either a direct (Figure 10) or indirect (Figure 11) mode. Figure 10 shows the retort itself to be a relatively simple device. Raw shale is fed 1n at the top of the retort and distributed about a circular bed by a rotating spreader. The shale descends by gravity through the retort, the rate of descent being controlled by a hydraulically operated grate. In the direct heating mode carbonaceous residue on the shale is burnt to provide the heat for retorting. Off gas combined with air enters the retort at the two upper level distributors to promote combustion. Gas-air mixture also enters at the bottom of the retort to cool the shale. Table 9 Companies Participating in the Paraho Oil Shale Demonstration Project Atlantic Richfield Company Carter Oil Company (Exxon) Chevron Research (Standard Oil of California)' Cleveland-Cliffs Iron Company Gulf Oil Corporation Kerr-McGee Corporation Marathon Oil Company Arthur G. McKee and Company Mobil Research and Development Corporation Phillips Petroleum Company Southern California Edison Company Standard Oil Company (Indiana) Sun Oil Company Texaco, Inc. Webb-Chambers-Gary-McLoraine (Group) Sohio Petroleum Company Shell Development Corporation Oil vapors formed in the retorting zone pass up through the top of the retort, condense into a mist, and pass out of the vessel with the product gas for final recovery 1n oil mist separators. In the indirect heating mode part of the product gas is burned in an external heater to provide the heat for retorting. No combustion takes place within the retort. Yields for both processes are 97 percent of Figure 10. PAr~AHO !~t::TOR11NG, INDIRECT MODE4 8 Feed sha!o ~ 'liiJ~:~,J:!·~ ,,q . ' ~,·. ~"·~~~._ Product Polaling spreader Oil-qas ~eporolor Collecting tubes Shale oil Posklue cooling and ~ gm preheating ,- Moving grofe~ -&t!'-£~·:t-~ --RHlorted shale to disposal be:::ls t'-.) 0'\ Figure 11. PARAHO RETORfiNG, INDII Feed shole ~m~-~.m...!'JI"'•"!'·!"''.~'IIt~'· 1 ~ Product Rotating spreoder 011-gas seporalor Collncling lubes Shale oil Heater Residue cooling ond ~ gas prehnollng P tvlovinq qroles -~1':'-,Vr+:~ !:----Retorted shole to disposal beds j;...j --...:) 28 Fischer assay based on 28-gallon-per-ton shale. Properties of the product gases for the two processes are given in Table 10, while Table 11 presents properties of the product oil. Table 10 Paraho Retorting Gas Properties (Dry Basis) 50 Direct Mode Indirect Mode !\: !\: Volume 0 Volume 0 H.., 2. 5 24.8 t.. N 2 65.7 0.7 oz -0- -0- co 2. 5 2. 6 CH 4 2. 2 28.7 C0 2 24-.2 15.1 C2H4 0.7 9.0 C2H6 0.6 6.9 c3 0. 7 5.5 c4 0.4 2. 0 H2S 2660 PPM 3. 5 NH 2490 PPM 1.2 3 H.H.V. 102 BTU/SCF 885 BTU/SCF 29 Table 11 Paraho Retorting Product Oil Quality51 Direct Heated Indirect Mode Gravity A.P.I. 21.4 21.7 Viscosity sus at 130 degrees F 90 68 Viscosity SUS at 210 degrees F 46 42 Pour Point F 85 65 0, Ramsbottom Carbon Wt '0 1.7 1.3 51: Water Content Vol 0 1.5 1.4 Solids, B.S. Wt % 0. 5 0.6 CHAPTER III REFINING Before crude shale oil is available for use it will have to undergo some process of refining. Although many large oil companies have conducted research on the refining of shale oil, these results are generally proprietary and are not publ 1s. h e d . SZ However, experlence. w1"th t wo 1 arge scale refinery runs, which differ markedly in the amount of data divulged, will be discussed. 53 Union Oil Company In 1961, 20,000 barrels of crude shale oil were run through American Gilsonite's refinery near Fruita, Colorado. Processes used in refining the crude shale oil included delayed coking, thermal cracking, gasoline hydro- genation and catalytic reforming, and light gasoline sweetening. Cracking involves the decomposition of heavy 54 oils by exposure to high temperature, coking is a time 55 lengthened cracking process designed to produce coke, hydrogenation consists of adding hydrogen to unsaturated hydrocarbons, 56 and catalytic reforming utilizes a catalyst for the decomposition of oil. It is noted for 57 t h e long 11·. f e o f t h e catalyst. s weetenlng . 1s . essentla . 11 y 58 a process for the removal of sulfur. The final refined 30 31 products were marketed in the Grand Junction area. Based on the results of this testing, which were not made public, a number of refinery process schemes were proposed by Union for a 25,000 barrel per day commercial facility. One scheme is shmm in Figure 12. Processes involved include primary distillation, hydrodesulfurization and hydrodenitrogenation (Unifining), reforming, and alkylation. Proposed product yields from the refining process are shown in Table 12, while estimated product properties are given in Table 13. \ l. , C' 59 App 1ea ~ystems c orporat1on . The most detailed results found on large scale refining to date, which are publicly available, are those put out by Applied Systems Corporation. Under contract to the Office of Naval Research, 10,000 barrels of crude shale oil were refined into a variety of military opera tional fuels; these being Nato gasoline, JP-4, JP-5/Jet A, Diesel Fuel Marine I DF-2, and Heavy Fuel Oil. Approximately 15,890 tons of shale rock were retorted by the Paraho direct mode process at Anvil Points, Colorado, to produce 10,000 barrels of crude shale oil. Retorting took place over a period of 56 days. Properties of the crude shale oil are presented in Table 14; Table 15 gives true boiling point (TBP) data for the various dis- tillation fractions. Preprocessing studies were performed by Standard z 0 LPG I= " -----BUT--- Ar;~------____:__, ______<10 DUTI!NES )! t· ALKYL. ATE --- r:1 X. _l {) ----- <( C5- C5 ~------l' z FIJEtj n: GAS 0 cr. lLI ILl NAPHTHA ~ OUTliNES z cr. u. 0 1- - lJ. REFOHMATE GASOLINE z bJ '------'- -·--L--''---- ·----- COM,,IEHCIAI_ <1: ::J cr SHALE OIL -' STOVE OIL STOVE OIL -' 1·------'-- _... ____DIESEL ___ _------~SEL ----~ 1- (/) FU_FELl.(~ t J J- 0:: w 0 GAS OIL :..: e:·J ·- s~-·--- CRACKING STOCK 0 {). - <{ cnAcKro GASOLINE ------~------·--··----- u..35 c :..~.'-:.UL'-:.. ------_:::_•_CLURHY __I UJ) FUEL 01 L Figure 12. Refining commercial shale oi1, fluid catalytic cracking case. 60 tN N 33 Table 12 Product Yields from Refining of Commercial Shale Oil61 Fluid Catalytic Cracking Case FEED COMMERCIAL SHALE OIL, 8/D 25,000 PRODUCTS BID LPG 380 GASOLINE 13,635 STOVE OIL 1,300 DIESEL 6~700 FU::L OIL 590 34 Table 13 Product Properties from Refining of Commercial Shale Oil62 Fluid Catalytic Cracking Case PREMIUM REGULAR JP-5 JP-4 STOVE GASOLINE GASOLINE ~i_ ~ ___Ql!:_ DIESEL ·~ Pl AT so•F 58 60 4~.5 49.7 39 32 F-1 + 3 ml 102.5 96.5 F-2 + 3ml 9:<:.5 so.s FLASH POINT. •F 142 130 180 POUR POINi, •F -20 + 20 VISCOSITY ssu A"': IOO'F 38 CENT!STOKES AT -3o•F 8.8 CETANE NUMBER 48 44 SULFUR, '4 BY WEIGHT 0.01 <0.01 0.01 NITROGEN, ·.~ !)Y WE!GHT 0.06 .048 0.04 MERCAP1"AN SULFUR '• !3Y WEIGHT 0.0002 0.0002 AROM:O.TICS. VOL •;., 20 17 FREEZING POINT. •!= -57 -78 HEAT or COMBUSTION AST~ - 1405 19,6~4 35 Table 14 Paraho Retort Crude Sha 1e Oil 6 3 Whole Crude Characteristics and Hemoel Distillation Data Ultimate Analvsis: Gravity ( o API) 19.3 (0287) Carbon wt. percent 84.90 Soec. Gravity (60/60) 0.9383 (0287) Hydrogen wt. percent 11.50 flour Point oF (0 97) Oxygen wt. percent 1.10 Viscosity (c5 ~ 210°F) 5.33 rn44<=1 ~itrogen wt. percent 2.19 Viscosity (c3@ 140°F) 20.15 (o44s) Sulfur wt. percent r~.· h"*... d Tot. C.cid No. *Corrosive Sulfur: mg. KOH/gm. I .959 (0664) (H S-S 248 Lbs/1000 bbl.) (D 96) 2 ~:&w,_vol. percent 0.~. (RSH-S 38 Lbs/1000 bbl.) Hsr~altenes, wt.percent O.tt9 (.i\STI-1 31) ~a~s. Cdrbon, wt per~ent1.333 (C524) Selected 1ieta1 Concentration: Arsenic 19.6 ;:;pm l{i eke 1 2.5 pam Iron 71.2 pprn '/enanoi urn 0.37pom D 285 HE1·1PEL ::JIST:LL:..Tiotl :JF ',JHOL:: CR!JDE SHALE Oil: ( 1BP - 238°F) 'lol. :Jercent rec. 270°F = 0.1 \1"'1 ~ u . . percent rec. 300"F = 0.3 '10 1. percent rec. 3~0°F = 0.7 Vol. cercent rer.. :1Q0°F = 2.0 Vol. percem: rec. ~5iJ°F = 5.1 'lol. percent rec. 500"F =11 .8 Vol. oercent of 500° -;- residue 87.8 'lol. percent distilLltion loss 0.4 Inspections on Hem~el Residue: Gravity ( 0 API) 17.6 (0287) Specific Gravity (50°/e0°) G.9490 (0237) ViscPsity (SUS ~ 100°F) 39.2 (04:15) Rams. Carbon, wt. percent 1. 911 (052.:!) Table 15 True Boiling Point Distillation of Sha)e Oil Crude64 - ~lei ght Cumulative Volume Cumulative Distillation Grav·ity Specific Fraction ~lt. Fraction Fraction Vol. Fraction Fraction--- _j_~ll_ Qravity_ JE_ercen_U _{Qer-cent) i£ercent) ~rcent) 3 Gas 1 . 35 ft -- 0.13 0. 1"3 IBP-165 85. O.n5{e) 0.32 0.45 0.46 0.46 165-380 39.5 0.8275 0.70 1.15 0.80 l. 26 380-480 34.2 0.8540 4.95 6.10 5.40 6.66 480-520 30.3 0.8745 3.10 9.20 3.33 9.99 520-600 28.6 0.8838 9.47 18.67 10.09 20.08 600-650 21.7 0.9117 6.46 25.13 6.67 26.75 650-700 22. 0.9218 6.08 31.21 6. 21 32.96 700-750 20.2 0.9328 6. "13 37.34 6. "18 39.14 750-800 19.7 0.9358 7.55 44.89 7.60 46.74 800-843 17.7 0.9484 15.57 60.46 15.45 62.19 843+ 12. 0.9861 39.54 100.00 37.74 99.93 e = estimated - insufficient sample for testing lf'l C1' 37 Oil of Ohio (SOHIO) "to establish refinery operating conditions and to determine product and by-product yields." 65 Actual refining took place at the Gary Western Refinery located at Gilsonite, Colorado. Results of the preprocessing studies are as follows: 1. Very high-severity coking will be required in actual refinery operation, to attain maximum yield of usable fuels. The severity needed, however, is well within Gary Western's operating capability. 2. All of the coker distillates can be hydro genated within the operating limits of the Gary hydrotreater and hydrogen supply system. In the preprocessing pilot runs, there was no measurable loss in catalyst activity after more than 600 hours of operation. 3. Product TBP cut points were established in the laboratory which defined distillate fuels of specification volatility and low temperature characteristics. These distillation fractions are: Gasoline Naptha IBP-340°F JP-4 IBP-480 JP-5 340-460 Jet A 300-520 Diesel Fuel, DF-2 440-600 Diesel Fuel Marine 440-640 4. Limitations in fractionator flexibility at Gary will dictate the use of alternative cut poi~ts which will optimize overall yield and still provide products of acceptable quality. These product fractions and their individual yields on crude shale oil (C.S.O.) are: Distillation Volume of CSO Product Fraction (Percent) Gasoline IBP-340°F 18.5 JP-4 IBP-460 35.8 JP-5 340-460 17.3 Jet A 340-520 28.7 Diesel Fuel, DF-2 460-600 26.3 Diesel Fuel Marine 460-640 32.6 38 5. Raw distillate material boiling over 665-670°F will not be usable; i.e., the diesel fuels will not meet pour point specifications. 6. The heavy fuel oil ... will ... not meet the MIL-F-859E specification of 15° pour, however, it should be equivalent to a No. 6 bunker fuel. 7. All of the fuel products, with the exception of the reformed gasoline, can be expected to be unstable due to the limited depth of hydro treating that can be effected within the Gary operating constraints. For this reason it is unlikely that the fuels will meet the gum specifications, the thermal stability tests, and possibly the copper corrosion tests. The fuels should meet or_exceed all other required specification tests.b6 Fuels which contain dissolved gaseous hydrocarbons that escape d ur1ng. storage are termed. unsta bl e. 67 Numerous modifications and adjustments were made to the Gary Western Refinery to permit processing of the crude shale oil. Following these, crude shale oil was run through the refinery at the rate of 2500 barrels per day. As shown in Figure 13, gasoline was produced as follows: The naptha coming off the top of the fractionating column passes through a stabilizer. The resulting gas was then passed to an absorber column. The stabilized naptha is passed through a dehexanizing column where the light ends (IBP-190°F) were removed and stored. The bottoms of the dehexanizing column (190-412°F) were fed into a prefractionating column where the feed was split into a light fraction (190-340°F) and a heavy fraction (340-412°F). The light fraction was fed into the hydrotreater and then into the reformer at a rate of 600 bpsd. Approximately 20 percent of the reformer feed was converted to gas. The reformed naptha was then passed to a stabilizer with the output from the stabilizer combined with the light naptha to produce the gasoline.6& COOLING ...... "' _I: ~~.-~!_!______F·:r--·------.!:~~~·!·~------'U nA•E ll tO ltD·l . 1000 SCI .~ ; - OffOI~JUH GAS .... __ {!:---.. Ofi·C.&.S ~ --~:-· [·--:_~"'"""'-c)! ~r::· [ : ~ ... r:=---]::1 __ ,._ -- -- .. - !;: ~ UCUI ~)'"'""'"~[ % & : ,~. f-- _lifO Ill '_, ' ' ,.. IUO--- Ul EAN•)!!!~~-~~ ")!: "'\! t> v·~ <..O 40 For a description of the manufacture of JP-4, JP-5, Jet A, and Diesel Fuel Marine, the interested reader is referred to the original report. An overall flow dia- gram for the refining of the original 10,000 barrels of crude shale oil is given in Figure 14. Actual product yields appear below: 70 Product Actual Yield (barrels) Nato Gasoline 725 JP-4 454 JP-5/Jet-A 650 DFM/DF-2 1965 Heavy Fuel Oil 2760 Total 6554 Physical and chemical properties of the finished gasoline, JP-4, JP-5/Jet-A, Diesel Fuel Marine and DF-2, and heavy fuel oil are given in Tables 16 through 20. A total of 5107 barrels of fuel was shipped to various government agencies for testing and evaluation. Most of the specifications for the various fuels were met by the refined shale oil. Major problem areas included instability, high wax content, high particulate matter, and high gum content. However, it was felt by Applied Systems Corporation that these problems could be overcome by a higher pressure of hydrogenation along with clay treatment, to remove gum, and dewaxing. Not only liquid fuels can be obtained from oil shale. Research has also been conducted on producing Synthetic Natural Gas (SNG) from shale. The Institute of 41 I ~ I • I I ! I I U) U) (]) u 0 I l-1 H I fi~:a~· I ,__... .!Gi I ~~,. _!..... I I t.J11l.Q8\. SlUO'Gt 62! B!\. HIUN SifJ&I.t 011. . Table 16 Physical and Chemical Prcpe~ties of 77 MATO Gasoline {B1end Line) - Specification Requirement 'lalue Value Prooertv 4/'2/75 4/18/75 F-46 RV? 8.3 9.9 9.0 (max) Corrosion 1A @ 3.-'hrs/SO .. C 1A ~ 3. ·hrs/SO"C 1.0 (max) Gravity API 56.1 59.4° AP! Specific gravity 0.7543 Total sulfur 30 PPM 30 PPM 1000 PPM Hercaotan sulfur (2 PPM NOTE: Soth samples water white clear and frae of sediment '! 4. ,) Table 17 Physical and Chemical Properties of ,.. JP-4 7 .::; Specification Requirement Prooert'l HIL-T-5624J RVP 2.0 2.0 (min), 3.b {max) Corrosion lB @ 3 hr/212° lB Freeze point -91.3F 72 (max) Gravity API 57.0°API 45 (min) Sp. Gravity 0.7507 Acidity 0.010 mg KOH/g 0.015 ictal nitrncen 140 PPM Basic nitrogen 115 PPM Tot a 1 su !fur 13 PPM 4000 PPM Merc3Ptan sulfur <2 PPH 10 PPM Particulate matter (a) 10.6 1.0 WISM 46 ?ntantial gum 10 mg/100 ml Existent gum 3.5 mg/100 m1 Gross heat of combustion 19,496 8TU/1b Net heat of combustion 18,337 8TU/1b 18,400 (min) Anti-icing 0.003% 0.10 (min), 0.15 (max) Water Reaction Volume change 0.0 Ratino ,d) - Water seoaration index 70 FIA Analysis Saturates 87.9 Vol % 70.0 (max) 01 ifins 0.4 Vol % 5.0 (max) Aromatics 11.7 Vol:!: 25.0 (max) Lumir:omett:r No. 60 Thermal stability 4 plus 3 . a - 1 ga i in 10 min: 44 Table 18 Physical and Chemical Properties of JP-5/Jet A7 4 Specification Requirement ?rcoertv ~!L-T-56245 Jet A RVP Corrosion 18 @ 3 hr/212°F 18 2 Fr-eeze point -26.0°F -51 48.0 (max) -35 Gravity API 44°API 35.0(min)48.0(max)39 - 51 Specific gravity ---- ' 0.8299-0.7753 Acidity 0.047 mg KQH/gm 0.015 0.1 Flash point 140°F 140 105 (rnin)-150 (max) Viscosi~y @ -30°F 14.8 cs 15.0 (max) 16.5 .(max) Tol:al nitrogen 960 PPM Basic nitrogen 895 PPM Tota 1 sulfur 27 PPM 4000 PPM (max) 3000 PPM Mercaptan sulfur .<2 PPM 10 PPM (max) 30 PPM Gross heating value 19,249 STU/lb Net heating value 18.150 BTU!-lb i8,300 {min) 18,400 Existent oum 116.2 mg/100 ml 7.0 7.0 ?otantial-gu:n 137.8 mg/100 m1 Par:iculate matter 107.7 (a) 1.0 '.iSIM 59 l!.!minometer No. 43.5 50 (min) 45 Anti-Icing 0.004 ! 0.1-0.15 FIA Analysis Saturates 74.7 Vol % . Olefins 4.3 Vol ::; 5.0 Aromatics 21.0 Vol ~ 25.0 20.0 Explosivenes 50 {max) l{a ter s eo a radon i r:dex 85 water to i era nee 1 ml change Water interface rating lB Thermal stability 3.0 (b) 3.0 3 (c) a - 1 gal in 825 min b - before contamination c - 300-400°F with max pressure drop of 12 in Hg 45 Table 19 Physical and Chemical Properties of Diesel Fuel Harine and DF-27 5 Specification Require:nent (DFM} (DF-2) Prooertv Value HIL-F-16884G VV-F-800a Gravity APr 32.8"API Record Record Specific Gravity 0.8612 Conradson {10: btm) 1.21 Wt ~ Ramsbottom (10: bt~) 0.60 rit ~ 0.2 (max) 0.2 (max} Total sulfur 0.44 Wt % 1.00 (max) 0.5 (max) Total nitrogen 0.233 Wt % Basic nitrooen 651 PPM Co1·rcs i en - lA @ 3hr/212"F No. 1 ASTM 1 Ash 0.0000 ~t :: 0.005 (max) 0.005 (max) .:l.niline point 120.2"F Record SSt.\.! 0.1 Wt% 0.01 Cloud point To dark to see 30 (max) 10°above pour (me. Pour point 50°F 20"F (rnax) -10 (rr.ax) Viscosity @ 100°F 5.54 cs 1.8-4.5 cs 2.0-4.3 Flash point 168"F 140 (min) 122 (mini Acid No. 0. 7 mg KOH/gm 0.30 {max) Gross heat of combustion 18,974 BTU!lb Net heat of combustion 17,962 STU/lb Cetane No. 55.7 45 (min) 45 (min) Cetane index 57.3 ~leutrality Report a. Distillation Residue Neoative ·Neutral b. Original Sample Negative Neutral Oemulsibility 10 min (max) Color 8+ 5 (max) Analysis Saturates 59.6 01efins 11.5 Aromatics 25.3 Othe1· 3.6 Appearance free from visible put iculate :r.atter Accelerated storaoe stability (a) (Total [nsolublesj 2.5 mg/100 m1 2.5 iota1 wax 0.93 Wt ;; a - Filtration discontinued after 2 hr. due to severe plugging 46 Table 20 Physical and Chemical Properties of · Heavy Fue1 Oil 7 6 Specification Requi rem en t Prooertv Value MIL-F-859E Pour point 95°F" 15 (max) Gravity API 18.8.. API n.s (min) Specific· gravity 0.9415 Ca rboo residue 1.50 Wt % 15 (max) Ramsbottom carbon 1.10 Wt :: Viscosity @ 122 4 F 142 ssu 225 (max) Ash 0.0009 Wt % 0.1 (maxj Flash Point. (a) 305°F 150 (min) Fire point (a) 435°F 2CO (min) Total nitrogen 1. 73 Wt: :: Total sulfur 0.25 lit ~ 3.5 Gress heat of combustion 18,003 STU/lb Net heat of c~mbustion 17,263 STU/lb Corrosion lA @ 3 hr/2l2°F Aniline jJOint 129.6°F Thermal s:ability #1 - stable ?.!SS (d) Explosiveness 5% 50 (max} Sediment by ex~raction 0.013% a. 12 ~ater by distillation 0,0 Vol % 0.5 Analysis Saturates 26.2 Olefins 19.7 Aromatics 54.1 Fluidity at 32°F (c) Pass BSt.W 0.5 (max) Wax content 5.23 Wt ~ a - closed cup b - Bauxite silica gel separation c - Probably would not pass based on high pour point d . - NSTL heater 47 Gas Technology (IGT), under the sponsorship of the American Gas Association (A.G.A.), has done much work on a hydro- 77 gasification process, whereby either gas or liquid pro- ducts can be obtained with high organic carbon conversion. Meanwhile, results of studies at the Laramie Energy Research Center report obtaining gases with a heating value 3 78 as high as 1300 Btu/ft . Performance Characteristics of the Shale Oil Based Fuels Refined at Gary Western. As has been mentioned, 5107 barrels of fuel were shipped from the Gary Western Refinery to different government agencies for testing. Test results from some of those agencies are presented here. Gasoline was evaluated at the Bartlesville Energy 79 Research Center. Comprehensive engine testing did not take place because of the high gum content and poor stability characteristics of the fuel. Service testing was confined to a one-car test of 7000 miles. Emissions and fuel economy measurements were also made in two late model (1974 and 1975) vehicles. The measured results are presented in Table 21. In that table, CID stands for cubic inch displacement and Ald denotes aldehydes. Engine knock was encountered during the service test, but outside of this, no significant difference between the shale-based gasoline and a reference fuel was discernible. Disassembly of the engine following the service test revealed extensive, coke-like deposits, consistent with Table 21 Emissions and Fuel Economy--Shale Gasoline 80 ~~-==------Emissions, gm/mile Fuel Economy, mEg Vehicle Fuel co HC NOx Ald Urban Highway 1974 Model Shale gasoline 2 5. 8 2. 2 2. 6 .14 11.2 17.4 351-CID Indolene* 25.9 2.3 2.7 .15 10.9 17.7 1975 Model Shale gasoline 7.4 1.3 2. 7 .18 12.3 21.1 318-CID Indolene*:~ 8. 7 1.2 2. 5 .17 12. 2 20.6 * Values represent results of one test, all other data represent average of three replicates. ** Proprietary product widely used as reference motor fuel in the auto and associated service industries. -+>· co 49 the fuel 1 s physical characteristics. A total of 14,000 gallons of JP-4 and 3000 gallons of JP-5 were sent to the Air Force Aero-Propulsion Labora- tory at lifnr1g • h t- P atterson A.1r F orce Base 1n . Oh"10. Sl Portions of the JP-4 and JP-5 were subjected to a process of clay filtration. Following this treatment, the JP-4 met all fuel specifications, whereas the JP-5 still did not meet requirements for flashpoint, freeze point, gum con- tent, and aromatic content. Petroleum based JP-4 and JP-5, and the shale-based fuels before and after clay filtration were tested in a T56 Series III single co~bustor. Little difference was seen among the fuels in measurements involving the com- bustor liner temperature, and HC and CO emissions. How- ever, NOx emissions for the synthetic fuels were consistent- ly higher than those for the petroleum-based fuel due to the synthetic fuel 1 s high nitrogen content. Also, higher smoke emissions with the synthetic JP-5 fuel were found; consistent with the fuel's high aromatic content. Approximately 2000 gallons of clay treated JP-4 were tested in a J85-5 afterburning turbojet engine in a five-hour run and compared with the petroleum-based standard. Engine thrust, airflow main combustor fuel flow, afterburner fuel flow, turbine exit temperature, compressoT discharge pressure, and engine oil temperature and pressure were all measured during the testing. 50 p . Differences between the performance characteristics of the synthetic and petroleum-based fuels were deemed not significant. However, in the idle mode of operation, NOx emissions were significantly higher for the synthetic fuel as shown below: Engine EI Fuel Condition NOx Petroleum JP-4 1.1 (average of two runs) Idle Oil Shale JP-4 1.6 lbm pollutant where EI (Emission Index) = 10 3 lbm fuel burned Finally, on June 18, 1975, in what is believed to be the first flight of an oil shale fueled jet aircraft, a T-39, fueled with clay-treated JP-4, flew from Wright- Patterson AFB to Carswell AFB, near Fort Worth, Texas. The flight to and from Dayton was described as "uneventful" by those on board the plane. Tests on oil shale-based Marine Diesel FuelBZ,B 3 have also taken place. Major differences between the petroleum and oil shale-based fuels included higher levels of oxides of nitrogen and exhaust smoke for the synthetic fuel. CHAPTER IV ENVIRONMENTAL ASPECTS OF OIL SHALE DEVELOPMENT Today, environmental considerations play an impor- tant part in any large scale development. This is also the case for the oil shale industry. Some of the prominent environmental aspects will be dealt with in this section. 84 ~]1ys iog:_raphy and Climate The oil shale lands of Colorado, Utah, and Wyoming are in sparsely settled, semiarid to arid country, at elevations of 5,000 to 10,000 feet above sea level. The region is part of the high Colorado Plateau Province of the Upper Colorado River Basin and the high plains of the Wyoming Basin. The terrain varies from dissected, wooded plateaus bounded by prominent oil shale cliffs to sparsely vegetated plains with low escarpments, commonly exposing the ledge and cliff forming oil shale. The region is drained by the Upper Basin tributaries of the Colorado River. Geologic up lift, stream erosion, and varying degrees of resistance of the rock layers control the land forms. Annual precipitation varies from about seven inches in the Wyoming Plains areas to 24 inches in the high plateau areas in Colorado. Much of the precipitation falls as snow during the December-to-April period. Summer thunder showers with occasional flash floods, sweep local areas. Temperatures of the region are moderate during Spring, SummeT and Fall. Maximum temperatures in the lower elevations may reach 100 degrees F during mid-Summer. Winter temperatures may drop to 40 degrees below zero. The number of frost free days varies from 50 in the higher elevations to 125 in the lower elevations. 51 Water Requirements The amount of water required by a commercial oil shale plant will vary based on the type of mining, retort- ing, and crude oil upgrading processes employed. Based on the direct mode of retorting, Paraho estimates a demand of 10,000 acre-feet per year (acre-ft/yr) for a plant produc- . 85 ing 100,000 barrels per day. Of this amount, 2,860 acre-ft/yr are used for retorted shale management and vegetation, 1,190 consumed in refining and power generation, 1,260 used for dust control in mining and crushing, 6,530 lost through evaporation in a water cooling tower, and 160 used for \vater treating sludge. The above numbers add up to 12,000 acre-ft/yr. Additional water comes from the oil shale itself which yields 1,530 acre-ft/yr, while use of 470 acre-ft/vr of boiler blowdown aids in the retorted shale precessing. The indirect mode requires 14,000 acre- ft/yr. The requirement here is larger because no water is produced during combustion of the shale, and the retorted shale contains about twice the amount of carbon as the direct mode, requiring a correspondingly larger amount of water for dust control and vegetation. Atlantic Richfield estimates 10 to 12 cubic feet per second (7,246 to 8,696 acre-ft/yr) based on a facility producing 50,000 barrels/day. 86 Added to this would be another two cubic feet per second (cfs) for use by the population associated with the commercial shale facility, 53 and two cfs for power requirements for the plant. For comparison, the average flow of the Colorado River 1 from which the water would be taken, past the plant site is 87 3 ' 6 0 0 c f s. A Department of the Interior estimate gives a range of 121,000 to 189,000 acre-ft/yr based on a 1-million- b arre 1 -per- d ay 1n. d ustry. 88 Table 22 gives a comparison of the water requirements for various energy-related industries. Table 22 .,...tnergy P rocesses: llTnater c onsumpt1on• c ompar1son• 8 9 Acre-ft/yr for a Gallons per 100,000 barrel/ million btu day plant (or equivalent) Uranium Reactor Fuel 14 9,400 '"1 Oil Refining I 4,700 Coal Gasification (SNG) 58 39,000 Oil from Coal so 34,000 Oil from Shale 24 10,000 * ------* Paraho Estimate (Direct Mode) Water Ayailability The average annual supply of surface water in the Upper Colorado River Basin available for consumption has been estimated at 5.8 million acre-ft/yr. 90 ~h1ch of this 54 water is committed to present agricultural and industrial needs, while an international treaty with Mexico as well as various state compacts also take a share. Taking into account all present and probable future demands, the amount of water available for an oil shale industry is estimated at 167,000 acre-ft/yr for Colorado, 107,000 for Utah, and 67,000 for Wyoming or a total of 341,000 acre-ft/yr in the 91 three-state area. Ground water resources are not as well known as are those for the surface. Major quantities are thought to exist primarily in the Piceance Creek Basin and are 92 estimated to be as high as 25 million acre-feet. One estimate of the total supply of water available for use by an oil shale industry is 427,000 acre-ft/yr. 93 It would seem there should be sufficient water available to support even a fairly large (1-million barrel/day) oil shale industry. Waste Water Various sources exist within an oil shale facility which will produce waste water. Direct sources include waste water from retorting and oil upgrading operations, air emissions control and gas cleaning systems, cooling water and boiler water blowdowns, water treatment systems, m1ne. d ewater1ng, . an d san1tary . uses. 94 Indirect sources are "leachate from retorted shale disposal areas, runoff and eros1on resulting from construction and site use activi ties, and runoff from mining and transpoTt activities."95 Most of the major oil shale developers plan no discharge of their waste water into receiving streams. This is due to the possibility of future more stringent pollution control regulations, and well-established control technologies of the oil refining industry which may be suitably applied to the waste water generated in oil shale processing. Waste water will eventually be lost through evaporation or incorporated into the retorted shale. Air nuality -~---- Air pollutants will come from a large number of sources. Dust and larger particulates will be generated in blasting, mining, and crushing the raw shale as well as transporting it from the mine to the retorts. More dust will be dispersed into the air as the retorted shale is hauled to disposal sites. To minimize pollutants from dust and large particu- lates, a number of steps will be taken. 96 Wetting agents mixed with water will hold down dust during mining opera- tions. Covered conveyors will carry the shale in crushing and retorting plants. Filters will capture the dust from crusher units as it is being pulverized. Gaseous emissions will include sulfur dioxide, oxides of nitrogen, carbon monoxide, and hydrocarbons. Sources for these pollutants include the retorting and 56 refining operations, electric power generation, and the numerous vehicles used in extracting and hauling the shale. To control these gaseous emissions, various procedures may be employed. 97 Fuels will be treated to remove sulfur before being used to heat the raw shale. Also, sulfur will be removed from the retorting and output gases by well-established techniques. In underground mining, diesel equipment will be equipped with devices to reduce emissions of nitrogen oxide and particulates. Despite the methods used for control, air pollutants will be dispersed into the atmosphere. A shale facility with a production of 50,000 barrels per day would be expected to have hourly emissions within the range of 100-150 Kg S0 , 400-800 Kg NOx, 80-150 Kg total hydro 2 carbons, and 250-400 Kg of particulate matter. 98 The pollutants dispersed into the atmosphere must not exceed federal and state air quality standards, values of interest for which are given in Tables 23 and 24. In addition to the primary federal and state standards, it is seen from Table 24 that Colorado has additional standards limiting the increment above ambient for each pollutant. To comply with the applicable state and federal regulations, measurements are made at any proposed site location to determine current air quality conditions. Modeling studies are conducted to determine how the 57 Table 23 99 Federal Primary Ambient Air Quality Standards Particulate Concentration 3 (ug/m ) Annual geometric mean 75 24-h max concentration 260 (not to be exceeded more than once/year) Annual average 80 (0.03 ppm) 24-h max 365 (0.14 ppm) NO 2 Annual aveTage 100 co 8-h max 10 1-h max 40 Photochemical oxidant 1-h max 160 Hydrocarbons 30-h max 160 where h denotes hour predicted pollutants from the facility will be dispersed throughout the surrounding area. Important variables to be considered in modeling include number, location, height, and diameter of exhaust stacks; efflux velocity from the stacks; gas temperature; emissions rate; terrain; and 58 i Table 24 State Ambient Air Quality Standards100 COLORADO Particulate in Air Quality Control Areas Annual arithmetic mean of 3 24-h concentrations 55 ug/m3 24-h max 180 ug/m Particulate in Non-Air Quality Control Areas Annual arithmetic mean of 3 45 24-h concentration ug/m3 24-h max 150 ug/m Visibility is not to exceed 20% opacity so~ -- Maximum allowable increment (Category I) L.. I 3 Annual mean 3 ug,m~ 24-h max 15 ug/m~ 3-h max 75 ug/m so -- rllaximum allowable increment (Category II) 2 Annual mean 15 ug/m~ 100 24-h· max ug/m3 3-h max 700 ug/m - .. Maximum allowable increment (Category III) so 2 3 Annual mean 60 ug/m3 24-h max 260 ug/m, 3-h max 1300 ug/m"'' UTAH Particulate Annual geometric mean 90 ug/m3 Not to be exceeded 1% of the days 3 between April 1 & October 1 200 ug/m Not to be exceeded 5% of the days <. between November 1 & March 31 200 ug/m~ , N0 , photochemical oxidents, hydro so 2 2 carbons, and CO are same as federal standards WYOI'-HNG Particulate 3 Annual geometric mean 60 ug/m 24-h max (not to be exceeded more 7:: than once/year) 150 ug/m"' 59 Table 24 (continued) WYOMING (continued) 3 Annual average 60 ug/m 24-h max (not to be exceeded 'Z more than once/year) 260 ug/m-' 3-h max (not to be exceeded 3 more than once/year) 1300 ug/m Sulfate (measured as a sulfation rate) Annual average 0.25 mg/100 cm 2/day .... 30-day max 0.50 mg/100 cm~/day For N0 , photochemical oxidants, CO, 2 and hydrocarbons, federal standards apply. meterological conditions. Because of the complexities involved, long-range predictions are assumed accurate within a factor of two, whereas short-term predictions . 101 (three or 24 hours) have an even larger marg1n of error. Particulate levels in some areas already exceed legal standards. At Middle Fort Parachute Creek in Colorado, particulate concentration over a 15-month period "' , 0 2 (3/71-5/72) averaged between 300-1000 ug/m~.~ Results of modeling studies for facilities producing between 45,000 to 62,500 barrels/day are given in Table 25. Colorado . . . has classified most of the state as Category I with a 24-h SOz standard of 15 ugjm3. This standard effectively precludes construction of a major energy conversion facility in or near the areas where it applies. It now applies to the Piceance Creek; Green River and Washakie, Colorado; and Four Corners, Colorado, resource 60 Table 25 Results of Modeling Studies for Facilities 103 Producing Between 45,000 to 62,500 Barrels/Day Range of Maximum Incremental Con Averaging Pollutant centrations Time Predicted by Modeling (ug/m3) Sulfur Dioxides Annual 10- 11 24-hour 6- 50 3-hour 103-240 1-hour 300 Nitrogen Oxides Annual 10-125 24-hour 28-157 Particulates Annual 20- 22 24-hour 29-171 Hydrocarbons 3-hour 4-129 (6-9 am) areas, and to most of Eastern Colorado as well. Colorado has thus created a situation such that energy development cannot take place in the resource areas until the classification is changed. . . There is a great disparity between the number of production facilities required if oil shale is to provide an appreciable part of the nation's future liquid fuel and the limited number of such facilities permitted by air quality standards. Development in the Piceance Creek area is effec tively blocked by Colorado air quality standards, but even if the area is reclassified from Category I to Category II or III, the number of plants possible will be only a few percent of those required to make oil shale a major liquid fuel supplier by the end of the century. More plants can be built in the Uinta Basin and in South western Wyoming, but still the total falls far short of the number that will be wanted if production costs become low enough to make this an attractive process. 61 These conclusions are based on the emissions shown in the Colony Development Corporation 1 s reports on the Parachute Creed development. They indicate that a major research and development program should be undertaken to reduce the emissions per unit of product produced during shale oil extraction. Low air emissions should be a major criterion for an acceptable process, even though there may be some conflict with low produc tion costs. The only alternative seems to be dispersal of processing facilities over an area greatly exceeding that in which the oil shale is locatifr4 This dispersal would be very expensive. Spen~ Shale Disposal The question of what to do with the shale after it has been retorted is one of some concern because of the large quantities involved. For a facility producing 50,000 barrels/day of oil from shale assaying 30 gallons/ton, approximately 62,000 tons of retorted shale will have to be disposed of daily. Depending upon the retorting process, spent shale will vary in consistency from a gravel like substance to that of talcum powder. Chemical pro perties of spent shale from Union Oil Retorts A and B are given in Table 26. The retorted shale from retort B has 105 a bulk density of 61 lb/ft3 . Retorted shale also con- tains a significant amount of leachable salts as seen in Table 27, about five times that of raw shale. Most of the major developers plan to dispose of the spent shale in gullies or canyons. As the spent shale is 3 106 laid down, it will be compacted to 80 - 90 lbs/ft . This compaction makes the shale largely impermeable to the 62 Table 26 Chemical Properties of Union Oil Spent Shale 107 Components, Wt % Retort A Retort B Si02 35.3 31. s CaO 27.2 19.6 MgO 9.0 5. 7 A1 2o3 8.5 6.9 Fe 2o3 7. 3 2. 8 Na')O 5.5 2. 2 .:.. K 0 2 2.8 1.6 0.1 so 3 1.9 Pzos 2.2 0.4 Mineral C0 2 1.6 22.9 Organic c 0.5 4.3 Trace Elements <0.5 <0.5 Nitrogen 0. 2 --- 100.0 100.0 Table 27 Inorganic Ions Leachable from Freshly Retorted Shales (Kgs/tonne)--Based on Laborat~ry Testsl08 Ion Raw Shale TOSCO II GCR (USBM) K+ 0.24 0.32 0.72 Na+ 0.48 1. 65 2.25 Ca++ 0.1 1.15 0.42 Mo-++ 0.01 0.27 0.04 C> - HCO 3 0.75 0.20 0.38 Cl- 0.22 0.08 0.13 so=4 0.79 7. 3 6.0 Total (Kg/tonne) 1.95 10.96 9.94 (1bs/ton) 3.9 22 20 where GCR denotes the U.S. Bureau of Mines Gas Combustion Retort. 63 flow of water. A drainage system will carry any runoff from rain or snow to a catchment basin. When the desired height of the shale pile has been reached, salts from the top of the pile will be leached, and a program of re- vegetation begun. Studies are currently underway on the possibility of returning the retorted shale to the mine from which it was originally obtained. However, initial mining and crushing increases the volume of the shale by 30 to 40 109 percent, and, although retorting shrinks the shale somewhat, even under heavy compaction it occupies a volume 110 about 15 percent greater than the original rock. There is also the problem of being able to control leach- ing once the retorted shale is back in the mine. One of the important aspects 1n spent shale dis- posal concerns the feasibility of establishing good plant growth on the retorted shale. Revegetation studies have been and ar~ continuing to be conducted by a number of developers in this area. Research on TOSCO II spent shale . . . 111 has been go1ng on s1nce 1965. This shale has a pH ranging from 7.7 to 8.5. Soluble salt concentrations, measured in terms of electrical conductivity, vary from 2.4 to 26 .mmhos/cm. A value of 4 mmhos/cm is the maximum tolerated by field crops. Nitrogen and phosphorous content is low. Spent shale also has a low infiltration rate, ranging from 1 cm/hr to 2.7 cm/hr, while those for 64 native soils are as high as 7 cm/hr.ll2 Leaching is the primary method employed to remove salts from spent shale, and to facilitate this irrigation is necessary. During 1971, in a test plot averaging 15 mmhos/cm, 30 inches of water were applied to the spent shale in addition to the annual rainfall of 15 inches. Results of this leaching are shown in Table 28. Table 28 113 19 ~11 S pec1es . Pl ots Ec oc=Electrical Conductivity, mmhos/cm at 25°C 25 Depth (inches) ECzsoc 0 - 4 1.9 4 - 8 3. 5 8 - 12 4.1 12 - 16 5.4 16 - 20 7. 5 20 - 24 11.0 24 - 34 11.4 Plant growth would be impossible without the application of nitrogen and phosphorous. Some type of initial cover is also required for seedling survival and erosion control as surface temperatures may reach 140 to 114 150°F on naked shale. These high temperatures inhibit 65 germination and seedling establishment. Straw has proven to be well suited as a cover because of its availability and low cost. The application of a layer of native soil has proven beneficial in reducing high surface tempera tures, holding moisture, lowering pH, aiding the downward movement of soluble salts, as well as blending the dis posal pile in with the native terrain. However, the availability of such soil may pose a problem in the oil shale areas. Through 1977 over 75 plant species had been tested in study plots. This testing has shown plant growth may successfully prosper on retorted shale. Studies in this vein will continue, seeking those species and management practices most suitable for effective growth. Union Oil Company has conducted revegetation studies 115 since 1958. As was the case with TOSCO II retorted shale,phosphorous and nitrogen are required for the establishment of growth. The application of sulfur has proven beneficial in reducing alkalinity (pH). Sulfur was applied to some test plots at the rate of five tons per acre. Studies are currently underway to investigate growth under conditions of varying slope, orientation, and thickness of soil cover. Only a small portion of the environmental impacts from oil shale development have been considered in this section. Plant and animal life will also be affected. 66 The oil shale region has a population density of approxi- mate 1 y t h ree peop 1 e per square m1.1 e. 116 Deve 1 opment Wl"11 insure a large population influx bringing with it the associated urban problems of any city. CHAPTER V COSTS OF A CmflviERCIAL OIL SHALE FACILITY The purpose of this section is to give the reader some idea of the costs involved in constructing and operating a commercial oil shale facility. Costs will be broken down into categories. Also presented will be the selling price of the shale oil necessary to secure a return on the initial investment in the facility. Because they change so rapidly with time, only relatively recent cost appraisals will be presented here. Additional cost estimates as they relate to specific projects will appear in a later section. In 1975 the Morgantown Process Evaluation Group of the U.S. Bureau of Mines published detailed results on an economic study for a shale oil facility producing 50,000 11 7 ,oarre 1 s per ca 1 en d ar d ay ot- s h a 1 e 01 . 1 . .,.,h1 e s h a 1 e 1s . mined by the room and pillar method, and is assumed to assay an average of 30 gallons per ton. Six 56-foot dia- meter units of the U.S. Bureau of Mines Gas Combustion type are used to retort the shale. The crude shale oil is pumped from storage tanks located at the facility to a refinery near De Beque, Colorado. The product from the refinery will be a semi-refined oil with a specific gravity of 42° API. 67 68 Table 29 summarizes the initial capital investment required to develop the mine and install the equipment necessary to process the oil shale. Amounts are in January 1975 dollars. Total capital investment is esti mated at $567.8 million. A few of the terms in the table are worthy of explanation. Briquetting involves compres- sing the very fine crushed shale into blocks using crude shale oil as a binder. Hydrogen sulfide is removed from ,, the excess retort gas, and the purified product is used as a plant fuel. Ammonia and sulfur are recovered from the hydrogenation, delayed coking, and distillation units during refining. Interest during construction assumes a three-year construction period. Estimated annual operating costs are $93.2 million, a detailed breakdown of which appears in Table 30. Operating costs amount to $5.11 per barrel. Byproduct credit listed in Table 30 encompasses profits from the sale of sulfur, coke, and ammonia. Annual wages for the 1,431 employees needed to run the facility are $18.4 million. Based on an operating plant life of 20 years and assuming a 12-percent discounted cash flow (DCF) rate of return, a selling price of $9.19 per barrel would be required to balance the present (January 1975) value of the initial cash flow. The discounted cash flow technique is a method for evaluating the profitability of capital 69 Table 29 118 Capital Investment Summary ~~ine {initial investment only ) .••.•••••••••••••••••• $22,436,500 Retort plant: · Cl"ttshi r.g and scl"eening ...... 22,313 'j co Sriquetti ng •..•.••••..•.••••.••••••••••••••.••.• 2,969,400 Retorting .•••..••••••.•••••••••.••••.•.•.•.••••• 138,319,400 So1 id •,;aste and <;as removal: Hydrogen s~ ifi de re.r:1ova 1...... 7,434,800 Solid waste disposal •.....••...••.••..•••...•..• 9,460,200 Amiloni a and su 1fur recovery ••.••.•••••••••.••..• 9,211,000 Refi ner1 ••.••••.•••••.••••••••••••••••.•••••••••••••• 120,597,i00 Utilities •••••.•.•••..••••••••••••...•••••••••••••••• 79,532,200 facilities ••••.•.••••.•••••••••••••.••••••••••••••••• Total _construction ...... 437,229,500 Initi a 1 ca ta 1yst and che.'l'li ca 1s ...... 8,602,800 Total plant cost (insurance and tax base) ....••• 445,332,300 Intey·est during construction (pi ant) ...... 62,340,000 Interest during development (mine) ..••••.••••..••.••• 2,720,900 Startup expenses •.••.•••••••••• - ..••••••••••••••••••. l5,604.J 00 Subtota 1 for depro:ci a ti on ...... ~ ...... 526,497,30() Hor!dng capital .••••••••••••••••••••••••••••••••••••• 41 ,315,000 Total capital investnent ...... 567,812,300 70 Table 30 119 Estimated Annual Operating Cost Natura 1 gas ••••••••- •• 1,805 f·lscf /CD x 365 x SO. 75/l~scf ~ ... $494,100 \·/a ter use ch-urge ••• •• • 390 tl gph x 8,760 hr/yr x $0.025/l! gal. ••• 88,800 Annual catalyst und ch~icals •••••••••.•••••••••••••••••• 5,233,100 Direct 1nbor, plant •.•••••••••••••••••• ; ...... 3,523,800 Direct labor supervision, plant •••••••••••••••••••••••••• 493,500 t1aintcnancc lilbcr, pli!nt ••••••••••••••••••••••••••••••••• 3,888,900 Maintenance labor supcr~isicn, plant ••• ~ •••••••••••.••• :. 318,500 ~laintcnance ruterials, plant. 100;; of r.aintanar.cc labor •• 3,388,900 Direct labor, nine ••••••••••••••••••••••••••••••••••••••• 5,716,300 Direct labor supervision, ~ine ••••••••••••••••••••••••••• 476,300 Maintenance labor, nine •••••••••••••••••••••••••••••••••• 1,674,300 11a i nternncc 1.:bar 5 uoe r·1~ s ion, ~~ ne ...... 157,500 Operating supplies, ~ir.e ••••••••••••..••••••••••••••••••• 8,910,300 Operating suppii~s. ~1ant ••• .•• 2Ci. of plant naintenance labor ••• 777,800 Payro11 overhand, piitnt ••• ... (30'; of plant 1ubor and super'lision). 2,467 ,4!JO Payro11 overhead, nine ••• .•• (35?; nf nine lahm· ;;nd S11nP.r•li!'inn) .. ?..RM,!iC1f1 /\dr.1in'!~t~·~ticn ar:d Gr;~cr!1 0'/erhe?:.d ...... •...... 2, 1ll1,2C~ Taxes (la~d va!ued.at Sl ,OCO/acre, 4 sq ri), 68 ni11s per dolli!r or •taiuc ...... 174,100 Taxes on ir.:croverents, ::'!ine, ilt 68 ni lls per doi lar on 1/3 !:if ·inves~nnt ...... ; -~ .•..•...•.... 685,300 Insurance, r.inc, ot 2:; of inves~cnt ...... 604,700 Taxes, at Gl3 i.li 11s per dollar on 1/3 of investrcnt ...... - 5, 13G,GOO Insurance (rctortin0) etc.), at 2~~ of investr1ent ...... 4,534,100 Taxes (rcfine~t}, at GO nills per dollar on l/3 of invcstnent ...... 4,281,700 Instrrance (refinery), at 2:; nf inHeStr~ent ...... 3,777,900 Royalty, at ~0.12/tcn of shale rlined ...... 3,400,200 Dcpr(!ci uti on ...... 34,904,300 Annual operating cos~ ••••••••••••••••••••••••••••••••••• 100,533,100 7,303,200 93,229,900 71 120 projects. This method, which is being adopted by many major companies, takes into account the value of the dollar over time, and considers the cash flow of the original investment plus some given rate of return on that investment. For DCF rates of return of 15 and 20 percent, the selling price of the oil would be $11.04 and $14.49 per barrel, respectively. By comparison, in 1975 the oil from the Middle East sold for a typical price of $11.50 per barrel, while operating costs (exploration and pro- 121 duction) were $.25 per barrel. A more recent cost analysis is presented for the Colony Development Operation, a joint venture of The Oil 122 Shale Corporation and Atlantic Richfield Company. Costs are given in September 1977 dollars for a facility pro- ducing 50,000 barrels of shale oil per day. Retorting is accomplished by means of the TOSCO II process. Project life is estimated at 30 years. Crude oil upgrading is performed principally to reduce the high nitrogen content. The total investment is estimated at $1050 million, Table 31, while operating costs amount to $92 million per year, Table 32, or $5.85 per barrel of saleable product. Based on a post-tax discounted cash flow rate of return of ten percent on the initial investment, the selling price of the oil would have to be $16.10 per barrel. At 13 and 15 percent DCF, the selling price would be $20.75 and $24.50 respectively. In September 1977 it was felt that Table 31 123 Breakdown of Investment for the Colony Project (Basis: September 1977 Dollars) ~-.=x::: ...: Capital Investment pescripti~ $ Million CONTRACTOR ES'fiHA'l'ES ~rng;-crushing and Spent Shale Disposal 113 l?yrolysis and Oil Recovery 266 Oi.l Upgrading and Hydrogen Plant 102 By-Product Recovery 59 Utilities and General Facilities 177 Subtotal 717 RESERVE COS'fS 131 OTHER 0\~NER COS'f'S -Mine and :.,pent-Shale Disposal Hobile Equipment 28 ~atalysts and Chemicals 16 Spare Parts 4 Project Management and Plant Staffing 30 Taxes and Insurance During Construction 7 Community Assistance Costs 30 Pre-Commitment Costs 10 Mine Predevelopment Costs 11 Prepaid Process Licenses 2 Miscellaneous Other Costs 10 Harking Capital 22 Plant Fixit and Startup Allowance 32 Subtota 1 202 GRAND •ro•rJI.L INV£S'l'l-1.EN'l' 1,050 -.J 1'-.l 73 Table 32 Breakdown of Operating Costs for the Colony Project12 4 (Basis: September 1977 Dollars) SlBbl* COST C:£i:!'!.'ER $ ~housand/Y.r ~ining, Crushing and SS Disposal** 35' 600 2.27 Plant Ope.n.ting Laber 2,300 .15 Plant Maintenance (Excluding Mining) 12,500 .so Electrical Power Costs (Ex. Mining) 1.5, aoo 1.00 Catalysts and Chemicals 7,800 ; 50 Administrati•;e 2,300 .18 Taxes and Insurance 7,600 • 48 Miscellaneous Other 1,500 .08...,.., !.. icense E'ee 3.600 . """' 2,500 .16 C~ntit:gency - 5.85 TOTAL OFERAT~iG COSTS s:::,ooo BY-PRODUCT C?~D!TS -~ 0.40 A.1l!llon i a 6,300 2,900 0.19 Sulfur 0.15 Coke :2, ~00 0. 74 TOT.~ r;?~r;I':'S ll,600 *15.7 Million Bbls/yr *.,. IncJ..•.ldes :naintenance and pc•fler costs for mining, c::•..1shing, and spent shale disposal as well as continganc] allowances for these operations. 74 the oil produced could have been sold for $15 per barrel. This would have corresponded to a DCF of nine percent. Other cost estimates exist. Cameron Engineers, Inc. indicates a price range of $12 to $18 per barrel for production of a premium quality feedstock, 125 while a Department of Energy estimate gives a spread of $20 to $30 per barrel of upgraded shale oil. 126 Combining these two, a range of from $12 to $30 per barrel is obtained. Needless to say, there is a large variance in this cost estimate, reflecting the economic uncertainties of commercial operations. For comparison, for the first quarter of 1978, Prudhoe Bay crude sold for $12.65 to $12.86/bbl on the West Coast, Arabian Light 34°-gravity oil so1d.at $12.70/bbl, and Indonesia's Sumatra Light cost $14.90 to $14.00/bbl on the West Coast, being one of the h lg1est. 1 prlce . d cruae , Ol"1 s. 127 CHAPTER VI PLANS FOR COMMERCIAL DEVELOPMENT This section will present a summary of recent oil shale operations and/or the plans of major companies which may lead to commercialization in the future. Thoughts by those in industry regarding commercialization will also be given. It should be pointed out that, as of today, no commercial oil shale facilities, either.ex situ or in situ, are under construction. Colony Development Operation As has been pointed out, the Colony Development Operation is a joint project of the Oil Shale Corporation and Atlantic Richfield Company. In 1972 it appeared commercialization was feasible, so Colony commissioned C. F. Braun and Company in conjunction with Fluor-Utah to conduct a study on the costs of a large scale facility to be located at Parachute Creek north of Grand Valley, . 128 Co 1 ora d o on 1 an d owne d b y t h e two compan1es. Production would amount to 50,000 barrels per day. Over 400,000 man- hours were spent on the study at a cost of $12 million. The cost of the facility was projected at $450 million in 1973, but, due to the Arab oil embargo, these costs sky- rocketed to $800 million by mid-1974, causing plans for 75 76 construction to be dropped. Current costs (see section describing costs for a co@nercial facility) are bver $1 billion. In connection with its plans for a commercial facility, Colony has spent over $3 million from 1969 to 1975 conducting more than 100 separate environmental stuc.lies. "These included preparation of a 20-volume, 6,500-page Environmental Impact Analysis describing in detail the existing environment and assessing the effects 9 o f commerc1a. 1 operatlons. . "lZ Th us, Co 1 any lS . rea d y to proceed with commercialization should future conditions prove favorable. Union Oil Company Union Oil plans a facility utilizing a single full scale retort. This is seen as the next logical step before commercialization. Known as the Long Ridge Experi- mental Shale Oil Project (see Figure 15), plans call for processing 10,000 tons of raw shale to produce 9,000 barrels of crude shale oil per day on the company's land in Colorado. Cost of the facility is estimated at $100 million. Start of construction is contingent upon pro- posed federal assistance to the oil shale industry, namely a $.~-per-- b arre 1 tax ere d'1t. 130 Paraho Paraho is currently seeking sponsors for the Thic; ~lo.etch !-hows tJmon·!\ E!XP(~rlrnr>nlal oil $hJI(- ~llfJjt~r.l lfUril•q ,,p .... r:th:ws ~-~~~~~n~d anrl scwruert !\hale ftl\r~ rtnwn IO lht'! tnth.ll\l of 1hJJ vl'dluy fnr Spr..,aotrt~ •Uld V"QP.tJ~Iion. f, dfahl3Q@' (lond (l(lWOt left) will r:3plure will mnv•• foim ttlco undcrl_l">Un("l mlnu ouln a fi"ll"·ltf:rr• hnnch o;ih·. lhr.u br• IP•I h1to lh•• U!~''" lo P.lltr;.clthR 11HtOft w~tm h•)n! lh•! ~~~cnt ;.I:Ftlc £kpoc:'t" flloug with rair'l end os.nnw lor ustlin·n,~ retOttiog proce:o;s Ef'sl sh;:tlr> c•i'. lhe !-;flO'IIf' oil f1<.1w~ inlo ~lr-rr:;q~ t1Jak~~ r.n:i rl!lont.~r1 ~hal(' mov•·~ IJy rorwnyor 10 H101 Pnr:lo·~r>d.f!•lll .. rnlll. f'3(~r·hu!r-~ Cr•wh. (I(IWfH dr;hl) will t •• , {JfO!r~r;lr:d ltOr'l:lllllCYc·lr-rt W;lter ftiii10thet c:oui.CHhfnant'l 131 F1gure 15. .. -J '--l 78 construction of one full-sized retort at Anvil Points. The retort would have a yield of 4,000 barrels of shale oil per day, 20 ',such retorts being needed for a commercial 13 2 f ac1· 1 1· t y. .. Two sponsors are a 1 rea d y comm1· tt e d to t h e project estimated to cost between $85 to $100 million and. three more are desired. 1 33 Superior Oil Shale Project134 , 135 The Superior Oil Company owns 6,500 acres of oil shale bearing lands on the northern edge of Colorado's Piceance Creek basin. In addition to the oil shale, significant quantities of nahcolite and dawsonite are also present, and the company plans to recover these two miner- als in conjunction with the processing of the oil shale. Plans call for the retorting of the shale in a large 140- foot in diameter retort. Nahcolite would be recovered mechanically by secondary screening before retorting. Dawsonite will be converted to alumina and sodium carbonate in the retort and recovered in a leaching plant. It is proposed to send the spent shale back into the mine in the form of a wet cake. Development will be by a series of stages or modules, each module having a capacity of about 20,000 tons of ore per day. From this ore the following yields are estimated: 10,000 to 15,000 barrels of shale oil 3,500 to 5,000 tons of nahcolite ,- 500 to 800 tons OI alumina 1,300 to 1,600 tons of soda ash 79 It would seem Superior's commercial plans must lie some- where in the future, as only recently (1976) was a small pilot retort (10 to 20 tons/hour) reported to be under construction. Of the more than 11 million acres of oil shale land potentially suitable for commercial develop ment in Colorado, Utah, and Wyoming, about 72 percent are public lands administered by the Department of the Interior. These public lands 136 contain 80 percent of the high-grade oil shale. Oil shale is a leaseable mineral and with such large hold- ings it would seem inevitable that the federal government would eventually lease some of these lands for development. This occurred in 1973 when the Department of the Interior put up for bid two 5,210-acre tracts in each of the three western oil shale states. The objectives of the leasing program were to: 1. Provide a new source of energy that will increase the range of energy options available to the Nation by stimulating the timely development of commercial oil shale technology by private industry; 2. Insure the environmental integrity of the affected areas, and concurrently, define, describe, and develop a full range of environmental safe guards and restoration techniques that can be reasonably incorporated into the planning for a possible mature oil shale industrv in the future; - 3. Permit an equitable return.to all parties in the development of this public resource; and 4. Develop management expertise in the leasing and supervision of oil shale resource development in order to provige the basis for future administra tive procedures.lj7 Figure 16 shows the location of the tracts and Table 33 gives their estimated recoverable oil shale reserves. Bids were received on all leases except for the two in Wyoming. 80 fiock Springs W Y 0 M N G FLAMING W-a GORG£ ,'?[SERVO f R \V-b ~------~------__..,,,..., ...... ,.,_ !...-~.' ' COLORADO UTA H C·a" Grand Junction \ 0 1!:0 I I Scala or Mtle5 Figure 16. Map showing general geographis location of the six oil shale tracts.lj8 81 Table 33 139 Oil Shale Reserves, Prototype Tracts Tract Extraction Method Estimated_ Recoverable Oil-Shale Reserve~ Colorado Underground 1,857,000,000 tons in mineable C-a beds containing 30 or more gallons per ton. Colorado Underground 1,012,000,000 tons in mineable C-b beds containir.g 30 or more gallons per ton. Utah U-a Underground 342,000,000 tons in mineable _beds containing 30 or more gallo'ns per ton. Utah U-b Underground 372,000,000 tons in_mineable beds containing 30 or more gallons per ton. ~.J'yoming In Situ 354,000,000 tons in mineable W-a beds containing 20 or more gallons per ton. ltlyoming In Situ 352,000,000 tons in mineable H-b beds containing 20 or more gallons per ton. 82 This section continues with a description of the results of the successful lease offerings. C-b Oil Shale Venture The lease on Tract C-b was awarded in April 1974 to a group composed of Ashland Oil, Inc., the Atlantic Richfield Company, Shell Oil, Inc., and The Oil Shale Corporation (TOSCO) for a bonus bid of $118 million. 140 In December 1975 Atlantic Richfield and TOSCO withdrew from the venture citing an uncertain political climate concerning development. As required by the lease, a Detailed Development Plan (DDP) was submitted to the Department of the Interior for review in February 1976. Before this development plan could be approved, a suspen sion of the lease agreement was requested and granted on September 1, 1976, because of high background air quality parameters which exceeded the standards of the Clean Air Act. In November 1976 Shell Oil withdrew from the project because of uncertainties regarding commercialization. In December 1976 Occidental Petroleum Corporation (OXY) acquired a 50-percent interest in Tract C-b in exchange for their technology on a modified in situ or "in placen process. OXY has been experimentally retorting oil shale since 1972 and more than 50,000 barrels of shale 141 oil have been produced to date. A new DDP, utilizing OXY's in situ technology, was approved for Tract C-b in September 1977. Initial plans called for a full production 83 of 57,000 barrels/day by 1983. This target date has since 142 been postponed to 1985. An initial cost estimate of $400 million made by OXY and the Ralph M. Parsons Company 143 h as s1nce. r1sen . LO. $600 m1"11" 10n. Rio Blanco Oil Shale Company The Rio Blanco Oil Shale Company is a general partnership of Gulf Oil Corporation and Standard Oil 144 Company of Indiana. This partnership acquired access to lease Tract C-a in January 1974 with a bid of $210 million. In March 1976 a DDP was submitted outlining a method of open pit mining and surface retorting for the development of the tract. However, as with Tract C-b, background air quality parameters were high. Also, it was initially felt that the Department of the Interior had the right to permit spent shale to be disposed of off the tract. A subsequent legal opinion has shown this not to be the case, and legislation to remedy the problem 14 5 dl. d not mater1a. 1 1ze.. ~s" a resu 1 t o f sue h pro b 1 ems, a one-year lease suspension was granted starting September 1, 1976. In September 1977 a revised DDP was approved outlining a program of modified in situ technology for shale processing. These plans called for the startup of a modular facility in 1979. Commercial construction would begin in 1982 if warranted by the results of the modular facility. The commercial complex would take about five years to complete. Full scale production would amount to 84 L between 50,000 and 76,000 barrels per day. 146 White River Shale Project The White River Shale Project is a group consisting of the Sun Oil, Phillips Petroleum, and Sohio Oil Companies formed to develop Tracts U-a and U-b in Utah. Total bids on these tracts amounted to $122 million. A DDP was sub mitted for the tracts in July 1976. However, as with Tracts C-a and C-b, ambient air quality exceeded federal standards, so a suspension of the lease was requested and granted in November 1976. Problems also arose concerning ownership of the land. Up until 1920 oil shale was con sidered a locatable mineral and a person could file a claim on land containing oil shale deposits. The Mineral Leasing Act of 1920 made oil shale a leaseable material. Approxi mately 43,000 acres of land were claimed under the old law, and recent court decisions in Colorado have ruled in favor of the claimants. These rulings have affected Tracts U-a and U-b making the ownership of them unclear. In view of these legal developments, the White River Shale Project was granted an injunction against the federal government, who had thought the pre-1920 claims would be invalid, suspending enforcement of the terms of the lease until the question of ownership is resolved. The legal problems notwithstanding, the DDP of 1976 called for the development of the tract in a number of phases. Phase I calls for the mining by room and pillar 8 5 i method of 30,000 tons of shale to be used for crushing and retorting evaluations. Mining will be increased to 10,000 tons per day during Phase II. Processing of this shale will take place in a single large retort. The purpose of the second phase is to gain practical information on mining, retorting, oil and gas quantities to be expected, environmental effects, and costs. All this information will be used in the construction of a commercial facility, the final phase, which, when completed, would have a production of 100,000 barrels per day of high quality refinery feedstock. The total cost for the White River Shale Project was estimated at $1.6 billion in 1975. Based on a commercial plant life of 20 years and assuming a 15-percent return on equity, the selling price of the oil would be $20 per barrel. 's 1r ·eb•s c m · . t. 147,148,149,150,151, Indllstrv._ v 1 " on om erc1a 1 1za 10n JS? ~- 1-4 . ~, 1 ;:~.), ::, The views by those in industry center on a number of prominent factors which inhibit development, as well as items which could be taken to promote it. Commonly cited problems which discourage development include: --A myriad of government regulations to deal with. Some 60 federal, state, and local agencies must be dealt with and the required permits number in the hundreds for a single facility. There is also a large delay time in securing these permits. --Uncertain OPEC prices. 86 --Government regulations which hold the price of domestic crude oil and petroleum products below world market level. The industry is not operating in a free market. --An unstable economy, inflation. --Stringent environmental requirements to be met, particularly as regards air quality. --The threat of environmental lawsuits. --Lack of a coordinated national energy policy. --An extremely large initial capital investment for a pioneer industry. The projected return from shale oil production is not high enough to justify the risks of a new technology. Anything done to alleviate these problems would encourage development. Other actions suggested are: --A tax credit on oil produced. --Government assistance in financing the construc- tion of a large facility. This may take the form of sharing the initial costs of construction or involve an agreement to buy the oil produced at a premium above world market values. --Leasing of additional oil shale tracts. CHAPTER VII THE FUTURE There have been many estimates as to when a commercial shale industry will exist in the United States. In 1973, the Department of the Interior talked of a total 155 production of one million barrels per day by 1985. The National Petroleum Council in the same year gave a range of 100,000 to 750,000 bbl/day by 1985, with the most probable production being 400,000 bbl/day. 156 Cameron Engineers, Inc. figured it would be six to ten years from now (March 1978) before the start of commercial production unaer1 opt1mum• con d"1t1ons, - 157 an d 1n - a recent news 1 etter Chevron estimated 200,000 to 500,000 barrels per day by lr:~ 1990. ~a The first two of the above predictions would seem to be particularly optimistic in light of today's conditions. However, trying to foretell the future in any field has always been a risky business. Nevertheless, some personal reflections are given here. Under present conditions, a commercial oil shale industry cannot exist in this country. Shale oil produced today would just be too costly to compete in the worldwide petroleum market. The near future does not look promising either. There is currently a surplus of oil in the world 87 88 which is expected to last for three to five years.l59 This surplus should keep petroleum prices low, and as long as it does, no commercial facility would be profitable. Two situations would lead to the commercialization of oil shale. One is a commitment by the government that it is in the national interest to utilize the large natural resources this country has in oil shale, along with the passage of the necessary legislation, enabling commercial processing to proceed. The second situation is a large rise in the price of petroleum. Should world petroleum prises rise high enough, it would become worthwhile to process oil shale even if it means meeting tough environ mental standards and putting up with government red tape. However, in all probability it will be parts of both of the above factors occurring together which will lead to commercialization. As time goes on, the worldwide supply of petroleum will diminish with a corresponding increase in price, and an energy-thirsty nation will find oil shale an increasingly attractive form of energy. Government assistance, whether in monetary form or by a relaxation of the rules and regulations to be followed in the construction of a commercial facility, to the industry will follow. However, basing a prediction on the situation as it exists today, an oil shale industry producting a total of 50,000 barrels of shale oil per day will not exist in this century. FOOTNOTES 1. C. D. Duncan and V. E. Swanson, 11 0rganic-Risk Shale of the United States and World Land Areas,'' Geological Survey Circular 523 (Washington, D.C.: U.S. Govern ment Printing Office, 1965), p. 3. 2. T. F. Yen and G. V. Chilingar, "Introduction to Oil Shales," Oil Shale (Amsterdam: Elsevier Scientific Publishing Company, 1976), p. 1. 3. L. W. Schramm, "Shale Oil, 11 U.S. Department of the Interior, Bureau of Mines Bulletin ~50 (Washington, D.C.: U.S. Government Printing Office, 1970), p. 185. 4. Geological Survey Circular 523, op. cit., p. 9. 5. Ibid. 6. Ibid., p. 9. 7. National Petroleum Council, U.S. Energy Outlook: Oil Shale Availability (National Petroleum Council, 1973), p. 10. 8. J. D. Parent and H. K. Linden, "Fossil Fuel Resources- Where Do We Stand?", Pipeline and Gas J. 202, 60, October 1975, as read in A Survey of United States and Total World Production, Proved Reserves and Remaining Recoverable Resources of Fossil Fuels and UTanium as of December 31, 1975 by J. D. Parent and H. K. Linden 1Institute of Gas Technology, 1977), p. 24. 9. Geological Survey Circular 523, op. cit., p. 12. 10. Ibid., p. 13. 11. "Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada and United States Productive Capacity," AGA, API, and CPA, Tables I, III, XIII-1; May 1976, as read in Energy Reserves by R. G. Tessmer, et al. (Brookhaven National Laboratory, 1977), p. 15. 12. D. 1. Meyers, et al., Environmental Impacts of Oil Development (Stanford Research Institute International, November 1977), p. 4. Prepared for the U.S. Environ- 89 90 mental Protection Agency, EPA-600/9-77-033. 13. A. Matzick, et al., "Development of the Bureau of Mines Gas Combustion Oil-Shale Retorting Process," U.S. Department of the Interior, Bureau of Mines BUITetin 635 (Washington, D.C.: U.S. Government Printing Office, 1966). 14. Ibid., p. 22. 15. Ibid., p. 23. 16. Cameron Engineers, Inc., Shale Oil Status Report (Denver, Colorado, March 1978), p. 32. 17. U.S. Department of the Interior, Bureau of Mines Bulletin 635, op. cit., p. 34. 18. Ibid., p. 35. 19. Ibid., p. 70. 20. J. R. Ruark; H. W. Sohns; and H. C. Carpenter, "Gas Combustion Retorting of Oil Shale Under Anvil Points Lease Agreement: Stage I," U.S. Denartment of the Interior, Bureau of Mines Report of Investigations 7303 (Washington, D.C.: U.S. Government Printing Office, 1969). 21. J. R. Ruark; H. W. Sohns; and H. C. Carpenter, "Gas Combustion Retorting of Oil Shale Under Anvil Points Lease Agreement: Stage II, 11 U.S. Department of the Interior, Bureau of Mines Report of Investigations 7540 (Washington, D.C.: U~S. Government Printing Office, 1971). 22. U.S. Department of Interior, Bureau of Mines Bulletin 635, op. cit., p. 85. .-,~ .:. J. Ibid. , p . 67 . 24. Ibid. 25. Ibid., p. 68. 26. Ibid. 27. Ibid. 28. J. R. Ruark; H. W. Sohns; and H. C. Carpenter, Bureau of .t-Iines Report of Investigations 7540, op. cit-.-,---- p. 39. ~---~------91 l 29. Ibid.> p. 16. 30. Union Oil Company of California, Long Ridge Experi mental Shale Oil Project (Los Angeles, Calif.: Union Oil Company of California, no date), p. 10. Pamphlet. 31. Cameron Engineers, Inc., op. cit., pp. 57-58. 32. H. C. Reed and C. Berg, "Engineering Features of the Union Oil-Shale Retort," Transactions of the ASME, ~:3, April 1953, p. 454. 33. H. M. Hopkins, et al., "Development of Union Oil Company Upflow Retorting Technology," Slst National Meeting of the American Institute of Chemical Engineers (Kansas City, Missouri, April 11-14, 1976). Actual figures taken from: K. W. Crawford, et al., A Pre liminary Assessment of the Environmental Im¥acts from 9il Shale Developments (Redondo Beach, Cali . , and Denver, Colorado: TRW Environmental Engineering Division, July 1977), p. 31. Prepared for the Industrial Environmental Research Laboratory, Cin cinnati, Ohio, Contract 68-02-1881. 34. Ibid., p. 34. 35. J. H. Duir; R. F. Deering; and H. R. Jackson, "Continuous Upflow Retort Improves Shale Processing," Hydrocarbon Processing ~:5, May 1977, p. 147. 36. H. C. Reed and C. Berg, op. cit., p. 457. 37. W. L. Nelson, Petroleum Refinery Engineering (McGraw Hill, 1958), p. 21. 38. Ibid., p. 27. 39. Ibid., p. 64. 40. H. C. Reed and C. Berg, op. cit., p. 456. 42. T. A. Hendrickson, "Oil Shale Processing Methods," Quarterly of the Colorado School of Mines, 69:2, April 1974, pp. 56-61. -- 43. J. A. Whitcombe and G. R. Vavvter, "The TOSCO-II Oil Shale Process," Science and Technology of Oil Shale, edited by T. F. Yen (Ann Arbor Science Publisher, 1976), pp. 47-64. 92 l 44. J. F. Nutter and C. S. Waitman, "Oil Shale Economics Update." Prepared for American Institute of Chemical Engineers, Southern California Section, 14th Annual Technical Meeting, April 18, 1978 in Anaheim, California, p. 9. 45. J. A. Whitcombe and G. R. Vawter, op. cit., p. 50. 46. J. B. Jones, Jr., "Paraho Oil Shale Retort/' Quarterly of the Colorado School of Mines, 2.1_:4, October 1976, pp. 39-48. 47. Cameron Engineers, Inc., op. cit., pp. 39-42. 48. U.S. Environmental Protection Agency, Environmental Sampling of the Paraho Oil Shale Retort Process at Anvil Points (U.S. Environmental Protection Agency, October 1977), p. 7. EPA-625/9-77-002. 49. Ibid., p. 9. SO • .J. B. Jones, Jr., op. cit., p. 46. 51. Ibid., p. 47. 52. H. M. Hopkins, et al., op. cit., p. 149. 53. H. E. Carver, "Conversion of Oil Shale to Refined Projects,'' Quarterly of the Colorado School of Mines, 59:3, July 1964, pp. 19-38. 54. W. L. Nelson, op. cit., p. 217. 55. Ibid., p. 679. 56. Ibid., p. 699. 57. Ibid. , p. 810. 58. Ibid. , p. 298. 59. H. Bartick, et al., Final Report: The Production and Refining of Crude Shale Oil into Military Fuels (Under contract to: Office of Naval Research, 800 North Quincy Street, Arlington, Virginia 22217; by Applied Systems Corporation, 216 Mill Street, Vienna, Virginia 22180; Contract N00014-75-C-0055, August 1975). 60. H. E. Carver, op. cit., p. 30. 61. Ibid.] p. 31. 93 62. Ibid., p. 32. 63. H. Bartick, et al., op. cit., p. 5-3. 64. Ibid., p. S-4. 65. Ibid., p. 6-1. 66. Ibid., p. 6-90 through 6-92. 67. W. L. Nelson, op. cit., p. 242. 68. H. Bartick, et al., p. 7-6. 69. Ibid., p. 7-7. 70. Ibid., p. 7-19. 71. Ibid., p. 7-16. 72. Ibid. , p. AS. 73. Ibid., p. A2. 74. Ibid. , p. A4. 75. Ibid. , p. A6. 76. Ibid., p. AlO. 77. F. C. Schara, et al., The IGT/A.G.A. Oil Shale Process for Oil and/or Gas Production (Chicago, Ill.: Institute of Gas Technology, 1977). 78. E. L. Burwell and I. A. Jacobson, Jr., "Pipeline Gas from Oil Shale," Quarterly of the Colorado School of Mines, .zl_:4, October 1976, p. 144. 79. R. W. Hurn, "Performance Characteristics of a Motor Gasoline Produced from Oil Shale," Quarterly of the Colorado School of Mines, 71:4, October 1976, pp. 33- 38. -- 80. Ibid., p. 37. 81. W. S. Blazowski, et al., Combustion Characteristics of Oil Shale Derived Jet Fuels (Wright-Patterson AFB, Ohio: Air Force Aero-Propulsion Laboratory, 1975). 82. S. A. Mosier, et al., "Comparative Combustion Charac teristics of Petroleum and Shale Oil Base Diesel Fuel MaTine," Monograph on Alternate Fuel ResouTces, edited 94 by Dr. Frank J. Hendel (American Institute of Aero nautics and Astronautics, 1976), Vol. 20, pp. 136-151. 83. M. C. Hardin, "The Combustion of Shale Derived Marine Diesel Fuel at Marine Gas Turbine Engine Conditions,'' Mongraph of Alternate Fuel Resources, edited by Dr. Frank J. Hendel (American Institute of Aeronautics and Astronautics, 1976), Vol. 20, pp. 152-177. 8 '+'1 • U.S. Department of the Interior, "Regional Impacts of Oil Shale Development," Final Environmental Statement for the Prototype Oil-Shale Leasing Program, Volume I (Washington, D.C.: Department of the Interior, 1973), pp. I I-4, I I- 7. 85. J. M. McKee and S. K. Kunchal, "Energy and Water Requirements for an Oil Shale Plant Based on Paraho Processes," Quarterly of the Colorado School of Mines, l!:4, October 1976, pp. 58-64. 86. D. K. McSparran, Water and Oil Shale. Presentation to Colorado River Water Users Association, November 19, 1974 in Las Vegas, Nevada, p. 2. 8 7. Ibid. 88. U.S. Department of the Interior, Final Environmental ?tatement for the Prototype Oil-Shale Leasing Program, op. cit., p. III-55. 89. "Water Use for Energy Development Surveyed: C&EN," Chemical and Engineering News, July 22, 1974, p. 17, as read in J. M. McKee and S. K. Kunchal, op. cit., p. 64. 90. Hearings before the subcommittee on Irrigation and Reclamation of the Committee on Interior and Insular Affairs, House of Representatives, 90th Congress, 2nd Session, on H. R. 3300 and S.l004, January 30, 1968, p. 751, as read in U.S. Department of the Interior, Final Environmental Statement for the Prototype Oil Shale Leasing Program, op. cit., p. II-23. 91. U.S. Department of the Interior, Final Environmental Statement for the Prototype Oil-Shale Leasi~ Progra~, op. cit., p. II-27. 0'"' J L.. • Ibid., p. II-48. 93. U.S. Department of the Interior, Federal Energy Admin istration, Project Independence Blueprint, Final Task Force Report, Potential Future Role of Oil ~hale: 95 Prospects and Constraints (November 1974). As read in H. M. Hopkins, op. cit., p. 122. 94. H. M. Hopkins, op. cit., p. 78. 95. Ibid. 96. D. L. Meyers, et al., Environmental Impacts of Oil Shale Development (Stanford Research Institute Inter national, November 1977), p. 11. Prepared for U.S. Environmental Protection Agency, EPA-600/9-77-033. 97. Ibid., p. 12. 98. H. M. Hopkins, op. cit., p. 109. 99. G. Hinman and E. Leonard, Air Quality and Energy Development in the Rocky Mountain West (Los Alamos Scientific Laboratory, September 1977), p. 42. 100. Ibid., pp. 43-45. 101. G. E. Fosdick and M. W. Legatski, "Prediction of Air Quality Impacts for a Commercial Shale Oil Complex," Dispersion and Control of Atmospheric Emissiorts, New Energy-Source Po!lution Potential, edited by R. L. Byers, et al., AIChE Symposium Series, No. 165, Vol. 73, 1917' p. 287. 102. lV. Marlett,. The Colony Environmental Study, Parachute Creek (Garfield County, Colorado: Thorne Ecological Institute, January 1973), as read in G. Hinman and E. Leonard, op. cit., p. 9. 103. Taken from: H. M. Hopkins, op. cit. A number of different sources are used for the values given in Table 23 and include: (1) Colony Development Opera tion, Draft Environmental Impact Statement (EIS), U.S. Department of the Interior, Bureau of Land Management, December 1975; (2) Detailed Development Plan, Vols. I and 11, Federal Oil Shale Lease Tract C-b, submitted to Area Oil Shale Supervisor, February 1976; (3) Battelle Pacific Northwest Laboratories and Dames and Moore: Air Studies Environmental Impact Analysis, Appendix 13, prepared for Colony Development Operation, October 1973; (4) Federal Energy Administra tion, Project Independence Blueprint, Final Task Force Report, Potential Future Role of Oil Shale: Prospects and Constraints, under direction of U.S. Department of the Interior, November 1974; and (S) Detailed Develop ment Plan, Vols. I-V, Federal Oil Shale Lease Tract C-a (Rio Blanco Oil Shale Project), submitted to Area 96 Oil Shale Supervisor, March 1976, p. 112. 104. G. Hinman and E. Leonard, op. cit., p. 40. 105. S. C. Lipman, "Union Oil Company Revegetation Studies," Quarterly of the Colorado School of Mines, 70:4, October 1975, p. 169. 106. D. L. Meyers, et al., Environmental Impacts of Oil Shale Development, op. cit., p. 17. 107. S. C. Lipman, op. cit., p. 168. 108. J. E. Ward, et al., "Water Pollution Potential of Rainfall on Spent Shale Residues," prepared for the EPA under grant #14030EDB by Colorado State Univer sity, December 1971, as read in H. M. Hopkins. op. cit., p. 90. 109. D. L. Meyers, et al., Environmental Impacts of Oil Shale Development, op. cit., p. 16. 110. Colony Development Operation, "What About All That Processed Shale? ·can It Be Revegeta ted?" Pamphlet, not dated. 111. E. B. Baker, "Reclamation Potential of TOSCO-II Processed Shale," Pac. Chern. Eng. Congr. 1977, 2nd· Proc., Denver, Colorado, August 28-31, 1977 LNew York: AIChE, v-1, p. 403. 112. Personal communication, J. R. Meiman to E. B. Baker, August 22, 1973, as read in E. B. Baker, op. cit., p. 404. 113. E. B. Baker, op. cit., p. 404. 114. W. R. Schmehl and B. D. ~lcCaslin, "Some Properties of Spent Oil Shale Significant to Plant Growth," in R. Hutnik and G. Davis (Eds.), Ecology and Reclama tion of Devastated Land (London: Gordon and Breach, in press). As r~ad in E. B. Baker, op. cit., pp. 404-405. 115. S. C. Lipman, op. cit., p. 167. 116. U.S. Department of the Interior, Final Environmental Statement for the Prototype Oil-§hale Leasing Prqgram, op. cit., p. II-96. 117. U.S. Department of the Interior, Bureau of Mines, Oil Shale--197~: An Economic Evaluation Using 30- 97 Gallon Shale and Producing 50,000 Barrels Per Calendar bay of Shale Oil (Morgantown, W.Virginia: Process Evaluation Group-~~1RD, March 1975). 118. Ibid., p. 13. 119. Ibid., p. 41. 120. J. L. Brown and L. R. Howard, Principles and Practice of Management Accountancy (MacDonald and Evans, 1975), pp. 641-658. 121. Exxon Corporation, Middle East Oil (background paper, August 1976), p. 15. 122. J. F. Nutter and C. S. Waitman, op. cit. 123. Ibid., p. 14. 124. Ibid., p. 15. 125. Cameron Engineers, Inc., op. cit., p. 8. 126. "Oil Shale: Company Attitudes May Be Barrier," Inside D.O.E. (July 1978), p. 12. 127. "World Oil Flow Slumps, OPEC Crude Crowded Out," The Oil ___ andGas_Jou.rna1_7_6:_22,___ ~1C1Y 29, 19_7~, ___ £· 20. 128. Cameron Engineers, Inc., op. cit., p. 34. 129. Ibid., p. 35. 130. Testimony of J. M. Hopkins, President of Union Syn thetic Fuels Division, Union Oil Company of California before the House Appropriations Subcommittee for Interior and Related Agencies, April 18, 1978, p. 1. 131. Union Oil Company of California, op. cit., pp. 6-7. 132. Paraho Development Operation, What Everyone Should Know About Oil Shale, 1977, p. 16. Pamphlet. 133. Chevron, Inc., Chevron Alternate Energy Newsletter No. 6, May 1978, p. 2. Released .July 14, 1978. 134. H. M. Hopkins, et al., op. cit., pp. 36-40. 135. Cameron Engineers, Inc., op. cit., pp. 48-52. 136. U.S. Department of the Interior, Final Environmental Statement for the Prototype Oil-Shale Leasing 9 8 i. Program, op. cit., p. II-102. 137. U.S. Department of the Interior, "Description of Selected Tracts and Potential Environmental Impacts," Final Environmental Statement for the Prototype Oil Shale Leasing Program, Vol. III (Washington, D.C.: U.S. Department of the Interior, 1973), pp. I-1, I-2. 138. Ibid., p. II-2. 139. Ibid., p. I-9. 140. Cameron Engineers, Inc., op. cit., p. 30. 141. A. Hammer, "Oil from Shale: A Solution to America's Energy Crunch," Value Line Selection & Opinion, March 17, 1978, p. 811. 142. Information submitted by Occidental Oil Shale, Inc., September 1978. 143. A. Hammer, op. cit., p. 813. 144. Cameron Engineers, Inc. , op. cit. , p. 43. 145. D. Jv[atthews, "Shale Oil--All Dressed Up But No Place To Go," Developing the Many Sources of Energy (Exxon Company Public Affairs Department, not dated), pp. 58-59. 146. Cameron Engineers, Inc., op. cit., pp. 61-64. 147. Ibid. 148. A. Hammer, op. cit. 149. "Oil Shale: Company Attitudes May Be Barrier,:' op. cit. 150. Testimony of J. M. Hopkins, op. cit. 1·s1. Statement by Charles H. Brown, Senior Vice President, TOSCO Corporation, to Committee on Energy and Natural Resources, Subcommittee on Energy Research and Water Resources, United States Senate, March 11, 1977. 152. P. Wellman, "Oil Shale Development," 11th Intersociety Energy Conversion Engineering Conference Proceedings, 1976, pp. 331-335. 99 153. Personal communication from :P.L IV. Legatski, Colony Development Operation, to J. Page, August 8, 1978. 154. Personal communication from G. W. Morrison, Phillips Petroleum Company, to J. Page, August 18, 1978. 155. 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