UCID- 19751

Organic antiPyriticSulfur Determination in Oil Shale

Sandra K. FadeffAlan K. Burnham

Jeffery H. Richardson

March 1, 1983

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ORGANIC AND PYRITIC

SULFUR DETERMINATION IN OIL SHALE

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Abstract

Sulfur forms in oil shale are defined according to their reduction rates

to H2S in the presence of hydrogen-donor solvents. A linear increase in

temperature with time is applied to a reaction system of oil shale and

hydrogen-donor solvents. The different temperatures at which H2S is

detected corresponds to specific sulfur-functionality reductions and produces

a reaction profile, or kinetogram. The kinetograms of 10 standards and 13

different oil shales are given. The method of analysis is simple. Aromatic

and aliphatic disulfides, sulfides, thiols, and pyrite can be detected,

however we are not yet sure about the detection of thianthrene structures and

thiophenic structures. Our present results

approach, but improvements in the procedure

analytical technique.

Introduction

indicate that this is a promising

must be made to optimize the

The U.S. has extensive oil reserves as oil shale deposits in both the East

(Kentucky and Ohio) and West (Colorado, Utah, and Wyoming). A significant

problem in the development of a viable oil-producing industry from these oil

shale reserves is the production of hydrogen sulfide, sulfur dioxide, and

other gaseous sulfur compounds during retorting. In order to develop retort

conditions minimizing the emission of these noxious gases, the reactions

producing them need to be minimized (in conjunction with the use of gas

-2-

scrubber systems). To better understand the reactions producing sulfur gases,

the sulfur compounds in the raw oil shale, reaction pathways, and reaction

kinetics need to be characterized.

Sulfur compounds in oil shale are classified as sulfate, pyrite, and

organic. A frequently used method

“Standard Test Method for Forms of

solution of HC1 is used to extract

to define the sulfur speciation is the

Sulfur in Coal” (ASTM).l A dilute

sulfates from the sample (coal and oil

shale). Sulfates are determined gravimetrically by precipitation as BaS04.

Leaching this sample with dilute HN03 is supposed to extract the pyrite,

oxidizing the ferrous iron to ferric iron and sulfide sulfur to sulfate

sulfur. The Fe(III) is determined titrimetrically or via atomic absorption

spectrophotometry and is directly related to the pyrite content. The organic

sulfur content is determined by subtracting the sulfate and iron sulfide

content from the total sulfur content, which can be determined by a Fisher

total sulfur analyzer or other techniques.

Unfortunately, problems are associated with the application of the ASTM

sulfur determination in coal to sulfur determination in oil shale. The pyrite

sulfur content often is found to exceed the total sulfur content in the

sample. Smith et al.z point out that the predominantly inorganic matrix in

oil shale may cause interferences and errors in interpretation of results.

They developed an alternative method for the determination of sulfate, pyrite,

and organic sulfur based on the decomposition of pyrite by lithium aluminum

hydride. This analysis technique is relatively complicated and the lithium

aluminum hydride can be dangerous to handle.

Attar and Dupuis developed a method for organic sulfur determination in

Coa, 3,4,5. It involves reacting the sulfur species with a hydrogen donor

produce H2S. The basic concept of their method is applied here to the

determination of organic sulfur speciation in raw oil shale.

to

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Under favorable conditions, sulfur compounds can be reduced to hydrogen

sulfide and other by-products. A source of hydrogen must be available and the

reaction must be favored kinetically. All sulfur of one functionality will

have similar reaction kinetics and will be reduced at one temperature to form

H2S. Conversely, sulfur of

hydrogen at different rates

reactive sulfur groups will

different functionalities will react with the

and at different temperatures. Since the more

be reduced at a lower temperature than the more

stable sulfur groups, the sulfur reduction reactions can be separated in time

by increasing the temperature of a reaction system with time. The temperature

at which reduction occurs is characteristic of the sulfur functionality.

Experimental Procedures

A schematic of the apparatus used is presented in Figure 1. The test

sample of approximately 10 mg was mixed with three hydrogen donor solvents:

0.15g pyrogallol, 0.2g resorcinol, and 0.2g tetralin. The mixture was placed

in a porcelain reaction boat and covered with a molded quartz cover slip with

a slit at one end for gas escape. The reaction boat was placed in the quartz

reaction tube in the programmable Lindberg oven. A thermocouple rested in an

indentation in the reaction tube near the reaction vessel. The oven was

controlled with the HP85 and HP3497A data acquisition/control system and the

temperature was increased at ll°C per minute. Nitrogen flowed through the

quartz tube over the reaction boat at 62 cm3/min (NTP). The effluent gas

stream passed through a dry ice-acetone cold trap (-77°C) where most organic

compounds were frozen out. The remaining product gases (H2S and lightweight

organic gases) were carried on to the Tracer Instruments flame photometric

detector (FPD). Undoubtable, H2S accounts for essentially all of the sulfur

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content of the gas. Due to the approximately 2.5 minute lag time required for

gases to travel from the reaction boat to the detector, the temperature

recorded is offset about 27°C. This offset is partial ly cancelled by a 10

to 15°C difference between the recording thermocouple and the reaction

vessel. The total temperature uncertainty at the time of FPD measurements is

10° to 20°c. The flame in the detector was fueled with air (170

cm3/min) and hydrogen (77 cm3/min)(NTP). These gas flow rates provided

optimal flame stability and sulfur sensitivity. Sulfur emission from the

flame was detected by a photomultiplier tube (pint)proceeded by a 394 nm

optical filter. The pmt current was converted to voltage by an electrometer.

The voltage was recorded, along

the HP85 system.

The FPD was calibrated with

with the

standard

oven temperature, on magnetic tape by

gases of hydrogen sulfide in

nitrogen: 14.3 ppm H2S, 59 ppm H2S, and 104 ppm H2S (from Matheson Gas

Products). According to the FPD manual, the instrument response increases

approximately with the square of the concentration. The following equation

was derived and used to calculate concentration from electrometer voltage (V):

Concentration (ppm) = 370 x V0”54

The sulfur standards analyzed and their corresponding

listed

the ac”

adding

and dr

functionalities are

made by dissolvingin Table 1. The carboxylic acid sodium salts were

d in ethanol, adding concentrated NaOH until pH7 was reached, and

an excess of IN NaOH. The solution was roto-evaporated to near dryness

ed under vacuum overnight.

Oil shale samples were obtained from Utah (Geokinetics), and Colorado

(Anvil Points and Tract C-a). The sample location, grade, depth of burials

weight percent organic carbon, and weight percent total sulfur (determined by

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9

a Fisher sulfur analyzer) are given in Table 2. Sulfur speciation by the ASTM

method is given in Table 3 for a few selected samples. All oil shale samples

were taken from previously collected and crushed stock stored in closed jars

under air. Each sample was further ground to a talc consistency. The samples

(except as noted below) were placed in a 10% HC1 solution for about one hour,

releasing the carbonates, sulfates and pyrrhotite, and increasing pore space.

The shale was collected” and dried under nitrogen.

Sample sizes for standards ranged from 0.2 mg to 5 mg depending on the

weight percent sulfur. Oil shale sample size ranged from 0.5 mg to 20 mg,

also depending on the total sulfur content. These were mixed with the

hydrogen donors and analyzed as previously discussed. Six samples from

Geokinetics and Anvil Points were also run without added hydrogen donors but

otherwise under identical conditions.

Because of reaction characteristics to be discussed below, four untreated

oil shale samples and the corresponding samples treated with the

were heated under autogenous conditions. A sample was placed in

capillary tube sealed at one end, and a small plug of quartz woo’

HC1 solution

a quartz

was placed

on top of the sample. The tube was positioned so the open end pointed

downstream from the nitrogen flow. The temperature was ramped and H2S was

.monitored as described.

.

Technique Development4

Attar and Dupuis used a sulfidized CO-MO catalyst (Harshaw 0402), the

three hydrogen donor solvents, and the organic sulfur-containing sample to●

form the reaction system. They determined that the catalyst promoted the

reduction of the sulfur species to H2S using the hydrogen from the hydrogen

donor solvents. However, in this work, we found that the presence or absence

of the catalyst makes no difference on the kinetogram characteristics.

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Furthermore, the sulfur from the sulfidized catalyst, when mixed with the

solvents, was released as H2S at 220°C. This could cause significant

errors in analyzing the kinetograms. It is also doubtful that two solid

species, the catalyst and the shale particle, and the hydrogen donor solvent

can come into proper chemical contact for reduction to occur. The catalyst

could only catalyze the reaction of the hydrogen donor solvent with bitumen

and pyrobitumen, since they will dissolve allowing for proper intimate

chemica”

species

The

contact between the catalyst, hydrogen donor solvent, and sulfur

oil shale samples were pretreated in a 10% HC1 solution to release

carbonates from the oil shale matrix and increase the pore space. More H2S

was released and more clearly defined reation peaks were obtained when the

pretreatment step was utilized.

The FPD output signal (from H2S detection) increased as the starting oil

shale mass was increased. For Geokinetics 68’-69’ (1.06wt% sulfur), the

function was linear in the low mass range of O mg to 17 mg (O mg to 0.18mg

sulfur), and tapered off for masses above 17 mg (refer to Figure 2). Thus for

best comparisons between the various oil shale samples, the total sulfur

content should not exceed 0.18 mg in each sample analyzed.

Three blanks were run to test if hydrocarbons may give spurious signal

response. One blank consisted of the three hydrogen donor solvents in the

quantities normally used; a second was a 500-ppm methane gas standard in

nitrogen. No signal response was recorded from either sample. However, when

no cold trap was used in a third blank, tetralin at its room temperature vapor

pressure (or an impurity) did give a signal comparable to 30 ppm H2S, thus

uncondensed hydrogen-donor mixture would give an erroneous signal.

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Results and Discussion

The reaction temperatures and peak characteristics for the various

standard functionalities analyzed are presented in Table 4. Representative

kinetograms are shown in Figure 3. The sulfides, disulfides, and thiols,

aromatic or aliphatic, react between 200°C to 260°C. The reaction peaks,

although sharp and distinct by themselves, occur at temperatures only 10°C

apart, which is about a one minute difference in time. Since they are

difficult to resolve from each other, a reaction peak in the 200°C to

260°C temperature range cannot be specifically assigned. (Slowing the

heating rate spreads the peaks out more in time, not improving the

resolution.) Pyrite produces a clear reaction peak at about 280°C as well

as a sharp peak at about 550°C. The relative amounts of H2S generated in

the two peaks depends on the effectiveness of contact with the hydrogen donor,

which in turn depends on the particle size and how evenly distributed the

pyrite is in the boat. The second peak is probably caused by unreacted pyrite

decomposing to pyrrhotite and S2, which subsequently reacts to form H2S.

In oil shales, most, if not all the pyrite reacts at 280°C; the reaction

rate may be enhanced because the pyrite is embedded in kerogen. The reaction

characteristics of marcasite (rhom. FeS2) are quite similar to pyrite (cubic

FeS2). The heterocyclic structures, thianthrene and thiophene, require high

energy to react; hydrogen sulfide is produced at a temperature of at least

400°c. Our results above about 350°C are not always reliable because of

(1) reaction of hydrogen donors with sulfur-containing

runs at the end of the tube and (2) hydrogen-donor fog

through the condenser and giving a false signal.

residue from previous

sometimes passing

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The reaction profile, or kinetogram, of each oil shale examined is

unique. Certain properties are shared between the kinetograms such as peak

position: a reaction peak corresponding to pyrite reduction is present at

260°C to 320°C; a large diffuse peak occurs at 360°C and/or 420°C.

But the presence or absence of a peak at 200°C and the relative intensity of

these peaks vary between the different samples of oil shale. Refer to Figures

4 and 5 for examples of the oil shale kinetograms.

For extremely low sulfur containing oil shales (Geokinetics 78’-79’,

80’-81’, 56’-57’), the pyrite signal peak constitutes less than 5% of the

total signal output. The major portion of the sulfur appears to react at

temperatures above 400°C. Unfortunately, this signal may not be completely

real because of the problems discussed above. In oil shales of higher sulfur

content (Geokinetics 63’-64’, 47’-48’, 73’-74’ and 68’-69’; Anvil Points 24

and 60; and Tract C-a 18 and 25), the pyrite reduction peak is more

significant. Geokinetics 63’-64’, 47’-48’, 73’-74’, 68’-69’ and Anvil Points

24 also have a reaction peak at 200°C to 250°C, probably the reduction of

a sulfide, thiol, or disulfide.

To demonstrate the effect of hydrogen donors on H2S evolution and to

provide a comparison with previous work, seven treated oil shale samples were

run without the hydrogen donors. The kinetograms shown in Figure 6 are

similar to those obtained previously in a flowing argon atmosphere. The

peak at 480°C-5500C was attributed to “loose” pyrite (in contrast to

pyrite surrounded by kerogen), and the peak(s) around 400°C were attributed

to kerogen pyrolysis and the reaction of “surrounded” pyrite with organic

matter. The peak at 200°C was not previously observed. By comparison of

the kinetograms in Figure 6 with those in Figures 4 and 5, it can be seen that

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the pyrite peak shifts completely with added hydrogen donors, but the peaks at

200°C and around 400°C are affected substantially less. No significant

sulfur evolution occurs above 600°C without added hydrogen donors.

Hydrogen used to form H2S originates from the hydrogen-donor solvents

and/or from the kerogen. The H2S peaks at 200°C, 360°C, and 400°C are

from sulfur species mostly reduced by the hydrogen in the kerogen. These

peaks are nearly identical in shape and position whether the oil shale sample

is run in the absence or presence of hydrogen-donor solvents. (Compare

kinetograms in Figures 4, 5 and 6.) Therefore, the reaction kinetics are

unchanged for these species, indicating an internal source of hydrogen.

Conversely, the reaction kinetics of pyrite is altered in the presence of

hydrogen-donor solvents. When oil shale is run alone, pyrite reacts to form

H2S at 510°C; with the solvents, pyrite reacts to form H2S at 280°C.

The presence of an active hydrogen source may increase the frequency factor

and/or decrease the activation energy for pyritic sulfur reduction at 280°C.

It has been previously shown6 that the pyrite will react more

effectively with the native organic matter if no sweep gas is used. To check

those experiments and to gain further insight into the peak at 200°C, four

oil shale samples were run both before and after HC1 treatment in capillary

tubes as described above to more closely simulate autogenous conditions. The

results from the untreated samples

but the treated samples again

at 200°C. We do not know why

It may be either that organic

that they give H2S at a lower

are scrubbing the H2S, giving

show

this

agree well with previous experiments,6

the appearance to varying extents of a peak

peak appears after the HC1 pretreatment.

sulfur groups are being hydrolyzed by the HCl so

temperature, or that the carbonate minerals

metal sulfides and C02. Much more total

-1o-

sulfur, presumably H2S, is given off from the treated samples. The general

kinetogram shape in the region of 350°C to 500°C closely resembles that of

the untreated oil shales.

The percentage of sulfur reduced to H2S is in the

determined by the Fisher total sulfur analyzer (refer

graphical representation). The very low sulfur-conta

0.35% sulfur) give substantially greater total sulfur

general range of that

to Figure 8 for

ning samples (less than

values than obtained by

the Fisher sulfur analyzer. This is probably due to an erroneous signafl

created by the mist bypass and reaction with residue at the end of the tube.

Conversely, the samples of greater sulfur content give values below those

obtained from the Fisher sulfur analyzer. In this latter case, the pyrrhotite

may not be completely reduced or hydrocarbon gases may be quenching the sulfur

emission signal.

Conclusion

Hydrogen sulfide is successfully formed from the reaction of pyritic and

organic sulfur with hydrogen donor solvents and kerogen. The reactions are

qualitatively consistent in mass of H2S detected (peak area) and kinetics

(or temperature) of reaction. From the reaction profile, the approximate

distribution of

thiophene types

This method

Little time and

sulfides or thiols, pyrite, and perhaps thianthrene types, and

of sulfur in oil shale may be determined.

for sulfur determination in oil shale is simple in principle.

effort is required for sample preparation, reactions, and data

analysis. Sulfides or thiols and pyrite can be qualitatively distinguished in

the oil shale. Unfortunately, contamination of the reactor tube made the

results above 350-400°C unreliable. Further work also needs to be done to

eliminate the hydrogen-donor mist from giving a false signal. After these

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problems can be solved, the approximate distribution between these different

sulfur types can be determined from H2S peak area. The analysis method

could also be applied to specially treated oil shales to analyze reactions and

reaction products of these sulfur types. More work needs to be done for

quantitative conversion of sulfur to H2S, and to understand the complex

sulfur chemistry involved. Further work along these lines is currently in

progress.

Acknowledgments

We would like to express our thanks to Linda Ott for providing the

computer programs needed for data collection and processing, to Joseph

Ronchetto for setting up the electronics, to Jim Taylor and Cal Hall for

constructing the special hardware, to Melvin Bishop for making the specialized

glassware, to Eugene Bissell for helping synthesize the sulfur standards and

for many useful comments, to Robert Taylor for providing the pyrite standards,

and to Lew Gregory for providing the sulfur analyses.

References

1. Gaseous Fuels; Coal and Coke; Atmospheric Analysis, Part 26, (American

Society of Testing and Materials, 1977) PP 322-326.

2. Smith J. W., Young, N. B and Lawler, D. L., “Direct Determination of

Sulfur Forms in Green River Oil Shale,” Anal. Chem. ~, 618-622, 1964. .

3. Attar, A., “Sulfur Groups in Coal and Their Determinations,” Analytical

Methods for Coal and Coal Products, Vol. 3 (Academic Press, Inc., 1979),

pp 585-624.

4. Attar, A. and Dupuis, F., “On the Distribution of Organic Sulfur

Functional Groups in Coal,” Prepr. ACS Div. Fuel Chem., 23 (2), 44-53,—

1978.

—

5.

6.

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Attar, A. and Dupuis, F., “Data on the Distribution of

Functional Groups in Coal,” Prepr. ACS Div. Fuel Chem,

1979.

Organic Sulfur

24 (l), 166-177,—

Burnham, A. K., Kirkman Bey, N. and Koskinas, G. J., “HydrogenSUlfide

Evolution from Colorado Oil Shale,” ACS Symposium Series, No. 163, Oil

Shale, Tar Sands and Related Materials, (American Chemical Society) 61-77,

1981.

0

Standard

$

L-Cystine

# Dibenzothiophene

2,2’-Dithiodibenzoic acid

disodium salt

Pyrite

Resorcinol sulfide

Thianthrene

Thienylacrylic acid

sodium salt

Thiodipropionic acid

disodium salt

Thioglycolic acid

sodium salt

Thiosalicylic acid

sodium salt

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Table 1. Sulfur Standards

Formula

[H02C CH(NH2)CH2S]2

(C6H4)2S

[(C6H4)C02Na]2S2

FeS2

[C6H3(OH)2]2S

(C6H4)2S2

(C4H3S)C2H2C02Na

(C2H4C02Na)2S

‘HcH2c02Na

SH(C6H4)C02Na

Functionality

Aliphatic disulfide

Thiophenic

Aromatic disulfide

Inorganic

Aromatic sulfide

Thianthrene type

Thiophenic

Aliphatic sulfide

Aliphatic thiol

Aromatic thiol

&

●

Source

Anvil Points

Anvil Points

Tract C-a

Tract C-a

Tract C-a

Geokinetics

Geokinetics

Geokinetics

Geokinetics

Geokinetics

Geokinetics

Geokinetics

Geokinetics

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Table 2. Oil Shale Sample Properties

Grade

!@@!l

24

60

25

36

18

5.65

25.4

52.3

14.21

28.8

11.2

5.80

10.57

Depth ofBurialfeeta

Mz

Mz

432 ‘

432’

560 ‘

47‘-48’

56’-57’

61‘-62’

63’-64’

68’-69’

73’-74’

78’-79’

80’-81 ‘

Wt%Organic C

10.4

27.0

11.0

15.97

8.98

2.73

11.48

22.46

6.62

12.48

5.23

2.405

5.04

Wt%s

0.66

0.98

1.12

1.03

1.69

0.84

0.11

0.34

0.65

1.06

0.94

0.05

0.06

a Mz denotes from an unspecified depth in the Mahogany zone.

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Table 3. Sulfur Speciationa of Selected Samples

% of Total Sulfur asSource Designation Sulfate m -b

Anvil Points 24 gpt o 69 31

Tract C-a 18 gpt 17 81 2

Geokinetics 47’-48’ 0 68 32

Geokinetics 56’-57’ 0 60 40

Geokinetics 68’-69’ 3 90 7

Geokinetics 80’-81 ‘ o %100 Oc

a ASTM method.

bBy difference.

c Some sulfur was detected in the HN03-leached shale which would account

for z35% of the original sulfur.

-16-

Table 4. Standard Kinetogram Results

Temperature (C) Functionality Structure Peak Characteristics\

200

200

230

240

250

260

280

>4130

Moo

Aliphatic disulfide

Aliphatic thiol

Aromatic sulfide

Aliphatic sulfide

Aromatic disulfide

Aromatic thiol

Pyrite

Thianthrene type

Thiophenic

R-S-S-R

R-SH

Q-S-Q

R-S-R

@-s-s-@

o0 -SH

Cubic

cms

6..4)

.

Sharp

Sharp

Sharp

Sharp

Sharp

Sharp

Sharp

Long, drawn out

Long, drawn out

-17-

Vent

Organic Lindberg oven /TCI

<_- Flame photometric

detector < (d~i&/ < I n l<:::~;acetone) reaction boat:

sample andI1 hydrogen donorsI

III

IJ

III

II 1 I

11

I “ectrometert----i~:~1:~l

FIGURE 1 - Schematic of the apparatus used for the reduction of

sulfur compounds to form H2S.

-18-

4

2

0

.

I I I I

0 5 10 15 20

mg of Geokinetics 68’ - 69 ‘

FIGURE 2 - Output signal from the FPD in parts per million as a

function of milligrams of oil shale (Geokinetics 68’-69’)

analyzed.

-19-

.

2’m

NxgD1

600‘ I I I I I 1

L-Cystine

400-

200.

0, t I 1 1100 300 500 700

20 I 1 I I 1 I

2, 2’-dithiodibenzoicacid15- disodium salt

10-

5-

t I 1100 300 500 700

40-

100 300 500 700

80 -

40 -

0 “ t I/. I 1 I100 300 500 700

Dibenzothiophene~

10

5

0LLm:

100 300 500 700

L

80 -

40 :

0- 1 I100 300 500 700

40‘~ [ I I I i I4

t- -1

30 L Thianthrene d

20 -

10j-

0.~ ~

100 300 500 700

200‘ I ? I 1 I I

150 - Thioglycolic acid,Sodium salt

100-

50-

0 t I I I I 1100 300 500 700

Temperature (°C)

FIGURE 3 - Kinetograms of H2S response as a function of temperature

of the various standards heated at ll°C/min in the

presence of hydrogen donor solvents under N7.

-20-

1 I I I I I I 1

40- Thiosalicylic acid,

2\WXN 20 -~CL

o100 300 500 700

200

100

0

r 1 1 1 I I

Thienylacrylic acid,Sodium salt

r:

.,\- -

-%**,. 1

[. 1 I I 1, I

100 300 500

1. -\.lu

J— I d700

Temperature (’C)

FIGURE 3 (cent)

-21-

1 I I I I I

8“- 78’ - 79’

4

500 700

-1

4 -

Ml IE

o “ I I AI100 300 500 700

WImlzg I I 1 1 I I

Q

8 - 63’ - 64’

r

L’”’””’I 1 1

8~ 80’ - 81’ 1t -1

4 -

0’-a100 300 500 700

I I I I I I

8 - 61’ - 62’

4 -

0 . I t100 300 500 700

8Tl_AclJ :‘-C; o

100 300 500 700 100

[“1’ ’’’’ ’’’”18 - 73’ - 74’

4 -

.u

100 300 50CI 700

“’v:&.

100 300 500

Temperature (°C)

FIGURE 4 - Kinetograms of H2S response as a function of temperature

of the Geokinetics samples heated in the presence of

hydrogen donor solvents under N2 at ll°C/min.

-22-

r I I I I 1 1 1i i

8 Anvil Points 24

4

0 . t I I I

100 300 500 700

15

10

5

0

1“’’”’’’’’”Tract C-a 36

100 300 500 700

15

10

5

0

[“’’”’’’’’””!8- Anvil Points 60

4-

0 I t 1 I I I

100 300 500 700

15

10

5

0

I I I I I I

Tract C-a 25

100 300 500 700

* I I 1 I I I

Tract C-a 18

100 300 500 700

Temperature (“C)

J

FIGURE 5 - Kinetograms of H2S resPonse as a function of temperature

of Anvil Points and Tract C-a samples heated in the

presence of hydrogen donor solvents under N2 at

ll°C/min.

-23-

r I 1 I 1- 1 I 1

,

J

f 1 t I I I 1 I

8 Geokinetics 58’ - 57’

4 -

0 I 1100 300 500 700

r I I I I I I 1f

8 Geokinetics 73’-74’

4 -~CnXN~o 1 I

nl 100 300 500 700

~’

8 Anvil Points 24

4

0.100 300 500 700

8 - Geokinetics 47’ - 48’

4 -

0 I

100 300 500 700

1 I I I 1 I

8 Geokinetics 68’ - 69’J

4

0100 300 500 700

I I I I 1 I

8 Anvil Points 60

4

0, I

100 300 500 700

b I I I I I

15 - Tract C–a 18

10 -

5 -

>0

I100 300 500 700

c

Temperature, (°C)

FIGURE 6 - Kinetograms of H9S response as a function of temperature ofIL

Geokinetics, Anvil Points

absence of hydrogen donor

and Tract C-a samples heated in the

solvents under nitrogen at ll°C/min.

-24-

Untreated~., .,r, ,., .l. :

*r Geokinetics 68’ - 69’L 2

4

0100 300 500 700

8

4

0 .-----100 300 500 700

I 1 I I I I

8 Anvil Points 24

4“-

r

o~100 300 500 700

I I I I 1 I .

8 Anvil Points 60

4

(-l100 300 500 700

HC1 treatedI I I I 1 I

8 Geokinetics 68’ - 69’

100 300 500 700

10

5

0100 300 500 700

t 1

I_JxfL3100 300 500 700

I I I I I I

8- Anvil Points 60

r

100 300 500 700

Temperature (“C)

FIGURE 7 - Kinetograms of H2S response as a function of temperature of

HC1 treated and untreated samples heated under autogenous

atmosphere at ll°C/min.

-25-

nONL!

I I 1 I ! t I I1.2

;/

0

cC-a 18

c C-a 360.8 ● GK61_62 .

/

.C-a 25

. GK63-64● GK80-81

.

/

● GK47-48

●AP24 ● AP60

0.4 “ ●GK73_74GK78-79

● ●] .GK68-69GK56-57

0.4 0.8 1.2 1.6

Sulfur content (wt%)

.

FIGURE 8 - The total weight percent sulfur obtained from sulfur

reduction to H2S is presented as a function of the total

weight percent sulfur determined from the Fisher sulfur

analyzer. The solid line indicates 100% sulfur detection

using the assumption of 50% weight loss during acid

pretreatment.

*

L