DATA FOR DESIGN OF VAPOR RECOVERY UNITS FOR CRUDE OIL
STOCK TANK EMISSIONS
Final Report
EPA/IPEC Award Number R-82-7015-010
Subcontract 14-2-1201270-94844
R.E Babcock, P.I.
J. M. Plaza, Graduate Assistant
Department of Chemical Engineering
College of Engineering
University of Arkansas-Fayetteville
February 6, 2004
ABSTRACT
According to EPA’s Natural Gas STAR program there are about 573000 crude oil storage
tanks in the United States. These tanks are used to keep crude oil after being extracted
from production wells. During loading and storage, lighter hydrocarbons dissolved in the
feedstock separate from the oil and are often vented into the atmosphere. The
composition of these vapors varies, but the largest component is methane followed by
ethane, propane, and butane classified as Vapor Organic Compounds (VOC). Other
heavier compounds that may be present are benzene, ethyl benzene and xylene (BTEX).
These emissions provide a nuisance because of smell and in rare cases, even in the
absence of hydrogen sulfide, actually create an identifiable health hazard. The June 17,
1999 regulations issued by EPA call for control systems to reduce emissions by 95% on
stock tanks containing API gravity oil greater than 40" and having a gas-oil ratio (GOR)
greater than 1750 SCF/STB (Standard Cubic Feet/ Stock Tank Barrel). One way to
comply with these regulations and obtain economic savings is to install vapor recovery
units (VRU) on oil storage tanks. These simple units can capture 95% of the emissions
from stock tanks, which can be disposed for sale or use as fuel on site. However,
feasibility of these units requires close design tolerances.
EPA and API have developed models to estimate emissions, especially for regulation
compliance. These are based on flash vaporization calculations. Yet, it has been
established that in less volatile crude oils (API<40) model predictions tend to be
overestimated. It is believed that solubility is the controlling mechanism for some of
these heavier oil sites. This work presents an approach to emissions based on temperature
driven gas solubility and weather conditions. The model uses the Scatchard Hildebrand
solubility equation combined with the Prausnitz/Shair fugacity chart for fugacities of
gases well above their critical temperature. The only stock tank oil parameters required
are an ASTM D-86 boiling point distribution curve and API gravity. The specific details
of the model are presented and discussed as well as the results of field-testing of the
model in Oklahoma and Arkansas.
ii
TABLE OF CONTENTS
1.
INTRODUCTION .................................................................................................. 1
2.
PROPOSED MODEL............................................................................................. 1
2.1.
Solubility Parameter Calculations........................................................................... 1
2.2.
Molecular Weight Models ...................................................................................... 3
2.2.2.
Heat of Vaporization........................................................................................... 4
2.3.
Weather Conditions .............................................................................................. 10
2.4.
Heating Degree Day.............................................................................................. 10
2.5.
Temperature-Humidity-Sun-Wind Index (THSW Index) .................................... 11
3.
MODEL CALCULATIONS................................................................................. 11
4.
PROJECT EXECUTION...................................................................................... 14
4.1.
Sample Recollection and Laboratory Analysis..................................................... 14
4.1.1.
Liquid Samples ................................................................................................. 14
4.1.2.
Gas Samples...................................................................................................... 15
4.2.
Site Visits. ............................................................................................................. 18
4.2.1.
Site 1: Exxon-Vastar #1 .................................................................................... 19
4.2.2.
Site 2: Marathon Oil-Will Rogers International Airport battery. ..................... 20
4.2.3.
Site 3: ENOGEX – Wellston Stabilizer Facility............................................... 20
4.2.4.
Site 4: Timmins #1............................................................................................ 20
5.
RESULTS ............................................................................................................. 21
6.
CONCLUSIONS................................................................................................... 23
7.
RECOMMENDATIONS...................................................................................... 24
8.
REFERENCES ..................................................................................................... 25
9.
APPENDIX A: CRUDE OIL CHARACTERIZATION RESULTS.................... 27
9.1.
ASTM D86 Results............................................................................................... 27
9.2.
API gravity results. ............................................................................................... 53
10.
APPENDIX B: SITE VISIT RESULTS ............................................................... 54
10.1.
Site 1: Exxon-Vastar #1 .................................................................................... 54
10.1.1. February Visit. .................................................................................................. 54
10.1.2. July Visit. .......................................................................................................... 54
10.2.
Site 2: Marathon Oil-Will Rogers International Airport battery ...................... 56
10.2.1. March Visit. ...................................................................................................... 56
10.2.2. July Visit. .......................................................................................................... 58
10.3.
Site 3: ENOGEX – Wellston Stabilizer Facility............................................... 60
10.3.1. April Visit. ........................................................................................................ 60
10.4.
Site 4: Timmins #1............................................................................................ 62
10.4.1. August Visit ...................................................................................................... 62
11.
APPENDIX C: GAS CHROMATOGRAPHY RESULTS. ................................. 64
iii
1. INTRODUCTION
This document presents the methodology employed and results obtained during the
execution of the project “Data for the Design of Vapor Recovery Units for Crude Oil
Stock Tank Emissions.
Included are the correlations used to estimate the solubility of light compounds
(C1-C6) in crude oil using the ASTM D86 distillation curve and the API gravity.
Field collected data for the four sites visited is presented as well as results from
analytical laboratory analysis of field samples.
In addition, recommendations for future work are presented.
2. PROPOSED MODEL
This project proposes a model to approximate the yearly VOC emissions of crude
oil storage tanks based on the variations in solubility due to changes in temperature
and pressure between ambient tank conditions.
The model has been developed for standard fixed roof crude oil stock tanks (API
202) for sites with medium to heavy crude oil.
Emissions were assumed to be composed of only methane, ethane, propane, ibutane, n-butane, i-pentane, n-pentane.
The following concepts and equations are the basis for the proposed model. They
were used to define the different parameters that were taken into account in the
prediction of tank emissions.
2.1. Solubility Parameter Calculations
Solubility parameters were calculated using the Scatchard-Hildebrand
equation (10) taking into account the considerations presented by Prausnitz and
Shair (10, 13, 14) for gases far from their critical point in a mixed solvent:
1
(
⎛ − v L δ −δ
fG
Oil
X i = L exp⎜ i i
⎜
R ×T
f i
⎝
) ⎞⎟
2
⎟
⎠
δ = the Hildebrand solubility parameter.
fG = the fugacity of the gaseous solute at the initial state.
fiL =the fugacity of the solute (hypothetical) as a pure liquid at the
defined temperature.
Xi = solubility of gas i expressed as mole fraction in the solvent
Subscript “i” refers to component “i”.
In this equation the liquid fugacity and volume of the solute are
hypothetical values taking into account the fact that some vapor components are
well above the critical point. These fugacity values were obtained from the
classical figure and table presented by Prausnitz and Shair in (10), (13), and (14)
for methane and ethane. In the case of C3-C5 compounds the following set of
equations were used (7):
logν 0 = logν (0 ) + ω logν (1)
(
logν (1)
)
A1
+ A2Tr + A3Tr2 + A4Tr3 + A5 + A6Tr + A7Tr2 Pr + ( A8 + A9Tr )Pr2 − log Pr
Tr
1.22060
= −4.23893 + 8.65808Tr −
− 3.15224Tr3 − 0.025(Pr − 0.6 )
Tr
logν (0 ) = A0 +
Table 1 presents the values used for the Ai constants:
Constant
A0
A1
A2
A3
A4
A5
A6
A7
A8
A9
Value
5.75748
-3.01761
-4.98500
2.02299
0
0.08427
0.26667
-0.31138
-0.02655
0.02883
Table 1: Constants presented by Chao et al in (7)
The crude oil solubility parameter δ
Oil
was calculated in two ways. First
using a volume fraction weighted average as follows:
δ = ∑ φi δ i
i =1
2
Here the solubility parameter δi for volume fractions at 20%, 60% and
bottoms of the ASTM D86 curve were calculated and multiplied by the fraction
value (Φi.). The second procedure to calculate the solubility parameter used the
bulk properties of the crude oil
In both approaches the solubility parameter was determined using the
energy of vaporization and the molar volume of the fraction or bulk sample
∆U i
δi =
vi
vap
L
The energy of vaporization ∆Uivap is equal to ∆Hivap-P∆V. At low
pressures it is possible to assume ideality of the vapor in equilibrium with the
liquid (10) so P∆V was replaced with RT thus the final expression for solubility
parameter is:
δi =
∆H i
− RT
vap
vi
L
Where T is the temperature at which the value of solubility is being
estimated. The molar volume was calculated using the following expression:
vi =
L
Mwi
ρi
2.2. Molecular Weight Models
In order to calculate the molecular weight of petroleum mixtures it is
common to use pseudo component correlations. Thus, various
mathematical relationships have been developed to predict pseudo
component molecular weights. (16) These correlations are normally based
on boiling point, specific gravity data, viscosity, and UOP K factor. For
the project calculations a method presented in (2) was used as described
below.
2.2.1. Molecular weight calculations according to API Technical Data Book
Procedure 2B2.1
3
This method is presented in the Procedure 2B2.1 of the API
Technical Data Book (2). It has been selected due to its simplicity for
performing computer calculations. The expression for this method is as
follows:
MW = 20.486[exp (1.165 E − 4Tb − 7.78712 SG + 1.1582 E − 3 ⋅ Tb SG )]Tb1.26007 SG 4.98308
Where:
MW= molecular weight of the fraction
Tb=is the mean average boiling point of the petroleum fraction (oR)
SG=Specific gravity of the cut.
2.2.2. Heat of Vaporization.
As observed in the Scatchard-Hildebrand equation, the heat of
vaporization is another factor necessary to determine the solubility
parameter of the oil fractions.
This variable was calculated using API Technical Data Procedure 7B.4.7
also documented in (2) which can be used to estimate liquid and gas
enthalpies for petroleum fractions.
The method divides calculations according to two regions. The
first region includes reduced temperatures less or equal to 0.8 and reduced
pressures less or equal to 1.0, the equation for the liquid enthalpy is:
(
)
(
H L = A1 (T − 259.7 ) + A2 T 2 − 259.7 2 + A3 T 3 − 259.7 3
)
Where:
HL is the enthalpy of the liquid petroleum in BTU per pound.
⎛
1149.82 − 46.535 ⋅ K ⎞ ⎞
⎛
A1 = 10 −3 ⎜⎜ − 1171.26 + ⎜ 23.722 + 24.907 ⋅ SG ) K +
⎟ ⎟⎟
SG
⎝
⎠⎠
⎝
⎛
13.817 ⎞ ⎞
⎛
A2 = 10 −6 ⎜⎜ (1.0 + 0.82463K ) ⋅ ⎜ 56.086 −
⎟⎟
SG ⎠ ⎟⎠
⎝
⎝
4
⎛
2.3653 ⎞ ⎞
⎛
A3 = −10 −9 ⎜⎜ (1.0 + 0.82463K ) ⋅ ⎜ 9.6757 −
⎟⎟
SG ⎠ ⎟⎠
⎝
⎝
1
K
SG
T 3
is the Watson Characterization factor equal to K = b
SG
is the specific gravity 60F/60F
T is the chosen temperature.
The reduced pressure and temperature were calculated using the pseudo
critical pressure and temperature (Ppc and Tpc) as follows
Pr =
P
Ppc
Tr =
T
T pc
The formulas used to calculate the two pseudo critical properties
will be presented later in this text.
The values of enthalpy for the vapor phase of the first region and
for the liquid and vapor phases of the second region (Pr >1 and Tr > 0.8)
are calculated using the following:
(
)
(
H = H L + B1 (T − 0.8T pc ) + B2 T 2 − 0.64 ⋅ T pc + B3 T 3 − 0.512 ⋅ T pc
~ o ~ ⎞⎞
⎛H
RT pc ⎛
− H ⎟⎟
⎜
⎜
+
4.507 + 5.266 ⋅ ω −
⎜
⎟⎟
MW ⎜⎝
⎝ RT pc ⎠ ⎠
#
2
3
)
Where:
H
HL#
is the enthalpy of the petroleum fraction in BTU per pound.
is the liquid enthalpy at a reduced temperature of 0.8 calculated by
the equation for region 1.
⎛
248.46 ⎞ ⎞
⎛
B1 = 10 −3 ⎜⎜ − 356.44 + 29.72 ⋅ K + B4 ⎜ 301.42 −
⎟⎟
SG ⎠ ⎟⎠
⎝
⎝
⎛
253.87 ⎞ ⎞
⎛
B2 = 10 −6 ⎜⎜ − 146.24 + (77.62 − 2.772 ⋅ K )K − B4 ⎜ 301.42 −
⎟⎟
SG ⎠ ⎟⎠
⎝
⎝
5
B3 = 10 −9 (− 56.487 − 2.95 ⋅ B4 )
⎛ ⎛ 12.8
10.0 ⎞
⎞⎛
4
B4 = ⎜⎜ ⎜
− 1.0 ⎟⎜1.0 −
⎟(SG − 0.885)(SG − 0.70 ) 10
K ⎠
⎠⎝
⎝⎝ K
for 10.0<K<12.8 with 0.70<SG<0.885
⎞
⎟⎟
⎠
( )
2
B4=0 for all other cases.
MW is the molecular weight in lb/lbmol
R is the gas constant, 1.986 BTU/lbmol oR
~o ~ ⎞
⎛H
−H ⎟
⎜
is the dimensionless pressure effect on enthalpy obtained from
⎜ RT ⎟
pc
⎠
⎝
procedure 7B3.2 in (2). It may be disregarded if Pr <0.01
ω is the acentric factor.
The following paragraphs present the remaining terms necessary to evaluate
the enthalpy of vaporization from the previous equations.
2.2.3. Pseudo critical Pressure and Temperature
The pseudo critical temperature and pressure were calculated using
the specific gravity of the fraction and the mean average boiling point
(Procedures 4D3.1 and 4D4.1) in (2). The equations are as follows:
( (
))
T pc = 10.6443 exp − 5.1747 ⋅ 10 −4 Tb − 0.54444 ⋅ SG + 3.5995 ⋅ 10 −4 ⋅ Tb ⋅ SG T 0.81067 S 0.53691
( (
))
Ppc = 6.0162 ⋅ 10 6 exp − 4.725 ⋅ 10 −3 Tb − 4.8014 ⋅ SG + 3.1939 ⋅ 10 −3 Tb SG Tb−0.4844 SG 4.0846
Where:
Tpc is the pseudo critical temperature of the petroleum fraction (oR)
Ppc is the pseudo critical pressure of the petroleum fraction (psia)
Tb is the mean average boiling point (oR)
SG is the specific gravity.
2.2.4. The Acentric Factor
The acentric factor of the fraction is defined as (2):
ω = − log Pr* − 1.000
6
Where:
Pr* is the reduced vapor pressure P*/Ppc
P* is the vapor pressure at 0.7*Tpc
To estimate the vapor pressure procedure 5A.1.19 from (2) was used. This
method uses a correction for boiling point temperatures of hydrocarbons with a
Watson K factor different than 12. The equations are:
log P * =
log P * =
2663.129 X − 5.994296
95.76 X − 0.972546
log P * =
Where:
3000.538 X − 6.761560
43 X − 0.987672
for X>0.0022
for 0.0013≤X≤0.0022
2770.085 X − 6.412631
36 X − 0.989679
for X<0.0013
P* is the vapor pressure (mm Hg)
Tb'
− 0.0002867 ⋅ Tb'
X = T
748.1 − 0.2145 ⋅ Tb'
Where:
Tb’ is the normal boiling point corrected to K=12 (oR)
T is the absolute temperature (oR)
A trial and error is necessary for the K=12 correction. The following set of
equations are used:
∆T = Tb − Tb' = 2.5 f (K − 12 ) log
P*
760
Tb is the normal boiling point (oR)
f is a correction factor. For all sub atmospheric vapor pressures and for all
substances having normal boiling points greater than 400 F. f = 1. For substances
having normal boiling points less than 200 F, f= 0. For super atmospheric vapor
pressures of substances having normal boiling points between 200 F and 400 F, f
is evaluated by:
7
f =
Tb − 659.7
200
2.2.5. Pressure Effect on enthalpy term
~o ~ ⎞
⎛H
−H ⎟
⎜
The dimensionless pressure effect on enthalpy
was
⎜ RT ⎟
pc
⎠
⎝
obtained from procedure 7B3.2 in (2). The equation used was:
~ o ~ ⎞ ⎛ ~ o ~ ⎞ (0 )
⎛H
ω
−H⎟ ⎜H −H⎟
⎜
=
+ (h )
⎜ RT
⎟ ⎜ RT
⎟
ω
pc
pc
⎝
⎠ ⎝
⎠
~ o ~ ⎞ ( h ) ⎛ ~ o ~ ⎞ (0 ) ⎤
⎡⎛ H
H −H⎟ ⎥
−H⎟
⎢⎜
−⎜
⎜
⎟
⎜
⎟
⎢⎝ RT pc ⎠
⎝ RT pc ⎠ ⎥⎦
⎣
Where:
~o ~ ⎞
⎛H
−H⎟
⎜
is the dimensionless effect of pressure on enthalpy of
⎟
⎜ RT
pc
⎠
⎝
the fluid of interest.
~ o ~ ⎞ (0 )
⎛H
−H⎟
⎜
is the effect of pressure on enthalpy for the simple
⎟
⎜ RT
pc
⎠
⎝
fluid.
~ o ~ ⎞ (h )
⎛H
−H ⎟
⎜
is the effect of pressure on enthalpy for the heavy
⎜ RT ⎟
pc
⎠
⎝
reference fluid (n-octane).
ω is the acentric factor calculated for the fraction.
ω(h) is the acentric factor of the heavy reference fluid = 0.3978
The effect of pressure on enthalpy for the simple and heavy fluid is
calculated by the following equation:
~ o ~ ⎞ (i )
⎛H
⎛
⎞
b + 2b3 / Tr + 3b4 / Tr2 c 2 − 3c3 / Tr2
d2
−H ⎟
⎜
= −Tr ⎜⎜ z (i ) − 1 − 2
−
+
+ 3E ⎟⎟
2
5
⎟
⎜ RT
TrVr
2TrVr
5TrVr
pc
⎝
⎠
⎠
⎝
Where:
E=
c4
2Tr3γ
⎛
⎛
⎜β +1− ⎜β +1+ γ
⎜
⎜
Vr2
⎝
⎝
8
⎛ γ
⎞
⎟⎟ exp⎜⎜ − 2
⎝ Vr
⎠
⎞⎞
⎟⎟ ⎟
⎟
⎠⎠
The superscript (i) will be (0) when the equation is applied to the
simple fluid and (h) when it is applied to the heavy reference one.
Tr is the reduced temperature T/Tpc
T is the desired temperature (oR)
The rest of the unknowns were obtained from equations and values found
in Procedure 6B1.8 (2). The main equation to be used from this procedure is:
z (i ) =
PrVr
c
B C
D
= 1+ + 2 + 5 + 3 4 2
Tr
Vr Vr Vr Tr Vr
⎛
γ ⎞ ⎛ −γ
⎜⎜ β + 2 ⎟⎟ exp⎜⎜ 2
Vr ⎠
⎝
⎝ Vr
⎞
⎟⎟
⎠
Where:
The superscript (i) is (0) when the equation is applied to the simple fluid
and (h) when it is applied to the heavy reference one.
Vr =
PpcV
RT pc
V is the molar volume (ft3/lbmol) for the simple or heavy model according
to which z is being calculated.
R is the gas constant (10.731 psia ft3/lbmol oR)
B = b1 −
b2 b3 b4
−
−
Tr Tr2 Tr3
C = c1 −
c 2 c3
+
Tr Tr 3
D = d1 +
d2
Tr
The rest of the constants are listed in the following table for the simple and heavy
reference fluids.
9
Table 2: Constants from procedure 6B1.8 (2)
Heavy
Constant
Simple Fluid
Reference
Fluid
0.1181193
0.2026579
b1
0.265728
0.331511
b2
0.154790
0.027655
b3
0.030323
0.203488
b4
0.0236744
0.0313385
c1
0.0186984
0.0503618
c2
0.0
0.016901
c3
0.042724
0.041577
c4
4
0.155488
0.48736
d1 x 10
4
0.623689
0.0740336
d2 x 10
0.65392
1.226
Β
0.060167
0.03754
Γ
2.3. Weather Conditions
Emissions from crude oil stock tanks are affected by the weather
conditions at the site.(15) The model takes into account the differences
between the crude oil feed temperature and pressure and the stock tank oil
temperature and pressure. In order to include this variable in the model,
two indicators are proposed for analysis: the heating degree-day and the
THSW (Temperature-Humidity-Sun-Wind) index.
2.4. Heating Degree Day
The heating degree-day concept has been proposed as an indicator of the
amount of time the temperature of a geological area is above a certain pre-established
threshold temperature. It has been used by ecologists to measure or predict the effect
of temperature on biological processes, such as plant growth, and used by engineers
as an index of heating fuel requirements. The latter application defines the heating
degree day as the difference between the mean of the high and low temperatures for
one day minus 65 F, which is normally the temperature limit for a building to require
heating to maintain an inside temperature of 70 F.
10
The ecological definition is more complex and approximates better the
behavior of ambient temperature through out a normal day. The calculations are
based on the area under the diurnal temperature curve and between the predefined
thresholds (9). The most commonly used methods are linear; they are identified,
in order of mathematical complexity as: single triangle, double triangle, single
sine, double sine and Huber’s.
2.5. Temperature-Humidity-Sun-Wind Index (THSW Index)
The THSW index uses humidity and temperature to calculate apparent
temperature. It also includes the heating effects of solar radiation and the cooling
effects of wind on the perception of temperature (8). A set of equations (17) has
been developed to describe sultriness given the ambient temperature, humidity,
wind and extra radiation (direct and indirect insolation; terrestrial and sky
radiation). A table with an apparent temperature scale is also available and
applicable in most populated areas of North America (17). However this index
employs different values and correlations that are pertinent to humans, a
modification would be required in order to make it applicable to stock tanks for
the model of interest here.
3. MODEL CALCULATIONS.
The fundamental hypothesis of this project is that vapor emission rates from
stock tanks can be estimated with greater precision than currently exist in literature by
characterizing the gas solubility of the crude sales oil using parameters commonly
available or easily obtained for lease sites (API gravity and boiling point distribution
curve) and then estimating the rate of individual component vapor emissions released
from the oil as a function of ambient conditions, and residence time in the tank.
Inherent in this hypothesis are the following assumptions:
•
Based on results from (15), vapor emissions are only considered to be VOC
(mainly C1-C5) since HAP’s are assumed to be only 1.3% at the most.
11
•
The crude oil enters the stock tank saturated with the VOC’s listed above at its
heater/treater temperature and pressure. If free gas is present in the feed it
must be accounted for outside the model.
•
The oil characterization parameters mentioned previously are capable of
determining the Hildebrand solubility parameter specific to the oil in question,
which in turn adequately represents the solubility of the VOC’s in the crude
oil as a function of temperature and pressure.
•
The temperature history of the crude oil in the stock tank can be correlated
with the climatic conditions obtained from nominal National U. S. Weather
data for the general region of the lease sites. (5)
•
Gas solubility of the dead oil decreases with temperature so if the oil enters
the stock tank at some temperature and then begins to cool off on a cold
winter day, no gas will be released except volumetric displacement due to oil
production entering the tank.
Based on these assumptions the following system of equations
composes the solubility model proposed:
t
(
)
(
)
n
V = ∫ Q Rsin − RsO dt + N B RSO − max − RSO − min − ∑ Q j RS j + Q * 5.62 * t
j =1
0
Where:
V is the amount of cumulative vent flow in SCF (over a defined time
period, t).
Q is the oil production rate during the time period (in Bbl); h such events
Qj is the amount of oil removed from the tank during a jth unloading event
(in bbl)
NB is the number of barrels present in the tank at time zero.
Rs is the sum of the solubility of the supercritical gases measured in
SCF/Bbl
5.62 SCF/Bbl
The subscripts refer to the following conditions:
sO atmospheric pressure and tank temperature
sin heater/treater conditions.
sO-max, sO-min maximum and minimum values during the accounting
period.
12
sj unloading conditions during the j time. (Atmospheric pressure
and Tj temperature)
The first term represents the emissions generated due to change in solubility of
the oil entering the tank during the accounting period because of varying tank conditions.
The second term describes the emissions produced during the observation period due to
the impact of fluctuations in tank temperature upon the crude oil initially in the tank at
time zero (breathing losses). The following term is the sum of the gas that leaves the tank
as soluble gas in the sales oil. The last term is the working displacement term due to
displacement as oil comes in.
For year round calculations the second term of this equation is assumed small
compared to the other two so it will normally be omitted from the model calculations.
Furthermore, using weather conditions the gas solubility will be averaged for the
accounting period so the final model equation will be
(
)
n
V = Q Rsin − RsO ∆t − ∑ Q j Rs j + Q * 5.62 * t
j =1
Where:
Rsin , RsO are average gas solubilities for the accounting period.
∆t is the length of the accounting period.
As presented before, solubilities (Rs) for each compound in the emissions in
crude oil was estimated using regular solution theory following the established work of
Prausnitz and Shair (10),(13),(14) including the necessary modifications for which:
⎛ ρ
Rsi = 132.86 × ⎜⎜ oil
⎝ Mwoil
Here
⎞ ⎛⎜ P
⎟⎟ ×
L
⎠ ⎜⎝ f pure
(
L
⎛
⎞
⎟ × exp⎜ − vi δ i − δ
⎟
⎜
R ×T
⎠
⎝
)
2
⎞
⎟
⎟
⎠
Rsi is the solubility of one of the vent gas components in Scf / bbl.
ρoil is the density for the stored crude oil in kg/m3.
Mwoil is the molecular weight of the crude oil
P is pressure of the crude oil (bar)
13
fpureL is the fugacity of the solute (hypothetical) as a pure liquid at the
defined temperature (bar)
vL is the hypothetical molar liquid volume of the solute. (cm3/gmol)
δ is the solubility parameter of the gaseous solute (J)
δ is the solubility parameter for the crude oil at the established
temperature (J)
R is the universal gas constant
T is absolute temperature.
132.86 is a unit conversion constant.(SCF/BBl)
The fugacity parameter of the gas at the initial state fG was considered to
be equal to the product of the gas fraction and the total pressure of the system. For
each compound in the gas the solubility was calculated independently. The final
equation for each component then becomes:
⎛ ρ
Rsi = 132.86 × ⎜⎜ oil
⎝ Mwoil
⎞ ⎛⎜ P
⎟⎟ ×
L
⎠ ⎜⎝ f pure
(
L
⎛
⎞
⎟ × exp⎜ − vi δ i − δ
⎟
⎜
R ×T
⎠
⎝
)
2
⎞
⎟
⎟
⎠
The total solubility was then obtained by adding the values of Rsi calculated for
each of the C1-C5 compounds mentioned previously.
4. PROJECT EXECUTION.
4.1. Sample Collection and Laboratory Analysis.
4.1.1. Liquid Samples
Crude oil liquid samples were collected twice during each site
visit: at the beginning and end of the data recollection period. For this
purpose a Boston bottle mounted on a brass cage was introduced in the
tank through the thief hatch. A sample was collected at approximately the
middle of the liquid level present in the tank at the time of collection.
These samples were sealed, transported and then stored in the bottles until
analysis occurred in the lab.
Samples were analyzed using standard ASTM D-86 simulated
distillation to obtain the boiling point curve (3) and a hydrometer was used
for measuring the API gravity of each combined (4).
14
API gravity measurements for the combined sample were performed
using one of three hydrometers acquired, depending on the interval of
measurement desired. Available hydrometers had the following ranges: 10 to
40, 30 to 50 and 45 to 90 API.
For the ASTM D-86 distillations a PRECISION distillation
apparatus was acquired using 125 ml flasks with taper joint neck
according to the method and a pair of 7C and 8C ASTM E1 thermometers.
Thermometer
Condenser water line
Distillation Flask
Graduated Cylinder
(Distillate recollection)
Figure 1: ASTM D86 Simulated Distillation Apparatus
Weight of the distillate was measured during the first ASTM D86
distillations to try to estimate the density of the volume percentage cuts of
the method by using the difference in volume and weights of each cut.
However, this idea was discarded because results were inconsistent. (see
Appendix A)
Cumulative samples at 20%, 60% and final cut volume were taken
for density measurement using a pycnometer. These data was used to
emulate the components of the crude oil to be introduced in the model
calculations. (Appendix B)
4.1.2. Gas Samples
Gas samples were collected using 6-liter TO-14 canisters and a Veriflo
SC423XL flow controller metering valve. The system was connected to the vent
pipe of the tank and flow was regulated by the metering valve to fill the canister
15
in approximately six hours. Some instantaneous grab sample of vent gas were also
collected. (Figure 2)
Quick-change connection
Vacuum gauge
Vent gas
P
Crude Oil
inlet
Dry gas meter
Flow controller
TO-14
Canister
Figure 2: Crude oil stock tanks gas sampling set up
Previous to each site visit TO-14 canisters were evacuated to
approximately -26 in.Hg in the laboratory. Once in the field they were connected
to a segment of pipe added to the vent pipe through the flow controlling system.
The dry gas meter was installed at the end of this pipe segment.
Gas samples were analyzed using gas chromatography to determine the
composition of the emissions collected. The method for analysis was based on
GPA 2261. The method was initially implemented for the analysis of air,
methane, ethane, propane and butane by using pure gas standards of the first three
components and a 10% in helium standard for the butane. Analysis of additional
components was accomplished by utilizing a natural gas standard with a fixed
composition (Table 3).
16
Component
Mole Faction %
Nitrogen
5.01
Carbon Dioxide
0.999
Helium
0.501
Methane
70.44
Ethane
9.01
Propane
6.00
i-Butane
3.02
n-Butane
3.00
i-Pentane
1.01
n-Pentane
1.01
Table 3: Composition calibration standard for GC analysis.
Carrier Gas line
Vacuum
Pump
Sampling loops
(30µl)
PI
10 port switching
valve
Gas sample canister
TCD inlet
FID inlet
Figure 3: Set up for Gas Chromatography analysis
To draw the sample for analysis, a vacuum of 100 mmHg was pulled on
two 30µl sampling loops hooked up to a 10 port-sampling valve. The sample
canister was connected to the valve and once the vacuum pressure in the system
was reached the sample was allowed to enter the loops. Later it was injected into
17
two columns in the GC. One was a 2-meter x 1/16 stainless steel packed column
with mesh 80/100 Carboxen 1004 packing connected to the TCD and dedicated to
the analysis of permanent gases (air in this case). The second column was a 15 ft.
x 0.04 in stainless steel column with a 25% SP-2100 phase and 80/100 mesh
Chromosorb PAW packing, used for analysis of the hydrocarbons present by
using the FID.(See Figure 3) The established operating conditions for the method
are presented in Table 4
Variable
Value
Injection loop Pressure
350 mmHg
Injection Temperature
230 oC
Detector Temperature
230 oC
Initial Temperature
35 oC
Initial time
2 min.
24 oC / min.
Temperature ramp rate
Final Temperature
225 oC
Final Time
3 min.
Carrier gas
Helium
Carrier gas flow TCD
0.096 ml/s
Carrier gas flow FID
0.093 ml/s
Table 4: Gas Chromatography Analysis conditions.
Calibration runs were performed by connecting the standard cylinder
instead of the sample canister to the sampling valves. For air the sampling valves
were left open at the inlet and the vacuum pump was started so that the loops
filled with ambient air.
4.2. Site Visits.
During execution of the project 6 field site visits were made at locations in
Oklahoma and Arkansas. During each site visit the following variables were
monitored:
18
•
Temperature of the oil: measured from a sample taken from the middle of
the tank or in some cases using a thermocouple so located connected to a
wireless transmitter that sent the signal to the recording weather station.
•
Heater/Treater temperature and pressure.
•
Level of oil in the tank. This variable served as a measurement of the
amount of feed oil that had entered the tank. It was monitored using a gauge
tape.
•
Temperature of the tank wall. To monitor this variable a thermometer was
taped on the side of the tank.
•
Vent gas flow: quantified using a dry gas meter connected to the vent line of
the stock tank.
•
Ambient weather Conditions. Weather variables were obtained from a
Davis Instruments wireless portable weather station. The main variables
monitored were wind speed and direction, ambient temperature, humidity and
solar radiation, although temperature was the most pertinent parameter
4.2.1. Site 1: Exxon-Vastar #1
This site is located in South Arkansas situated approximately 45
minutes southeast of El Dorado, AR. operated by Shuler Drilling Co. The
well was put online about one year ago with production averaging around
30 BPD. The lease setup is relatively simple with one well, a heater/treater
with no heat input and a 30 psia pressure swing flash to the stock tank.
The thief hatches were set to hold a backpressure of 2 oz.
Two visits were made to this site one in March and a second in mid
July. During both visits oil flow was halted due to well operation
problems, which in turn obviously affected the collected data.
Additionally, it was not possible to completely isolate the tank under
analysis. The thief hatch had sealing problems and the tank was connected
to a second oil stock tank, a brine tank in addition to a return line to the
wellhead for fuel to the pump jack engine. Data collected from these visits
are presented in Appendix C
19
4.2.2. Site 2: Marathon Oil-Will Rogers International Airport battery.
Located near Oklahoma City, Marathon Oil is the operator; it is
located just off site of the Will Rogers International Airport
It is set-up with 26 wells online (some operating and some shut-in)
pumping into five stock tanks. Dual heater/treaters are inline as well as a
vacuum vapor recovery unit drawing vapor from a surge tank between the
heater/treaters and the stock tanks. Thief hatches were set to hold 2 oz
backpressure and the vent gas fluctuated widely apparently due to well
head operating conditions.
This site was visited twice during the project. The first site visit
was conducted at the end of March. During this visit the vapor recovery
unit was not online because of insufficient gas flow to maintain its
operation (the unit shuts off if the unit creates vacuum pressure at the
suction point at the surge tank.). Even with the VRU operating this lease
site was characterized by noticeable vent gas flow fluctuations.
The second visit was scheduled in mid July. During this visit the
VRU unit was kept online most of the time. Again gas flow during the
monitoring period was characterized by large flow surges. (See Appendix
C)
4.2.3. Site 3: ENOGEX – Wellston Stabilizer Facility.
This site is located off the Wellston exit of Interstate HY 44. It
consists of upstream processing of condensate gas yielding a high gravity
(60 to 90 API) oil, feeding three stock tanks with production of 600-700
BPD. This site was monitored at the beginning of April. (See Appendix C)
4.2.4. Site 4: Timmins #1
This site is also operated by Shuler Drilling Co. and is located near
Strong, Arkansas, in the vicinity of Site 1. This site was monitored in mid
August. It is a simple set up consisting of one oil well connected to a
single heater/treater with two storage tanks and three brine tanks.
20
During this visit difficulties in isolating the system were encountered.
An uncapped recycle gas line was discovered midway through the site
visit. As a result of this, very small gas flow readings were observed. (see
Appendix C). However, results from lab analysis show this to be a
promising site. API gravity was around 330 and gas composition shows
high content of methane.
5. RESULTS
The results obtained for the analysis of each of the samples from the field are
presented in this section.
Data from site 1 reflect the wellhead problems that were faced during field
visits.(high air content due to either low or non existent oil feed flow). Sites 2 and 3
demonstrate higher concentrations of C3+ hydrocarbons. Site 4 has the highest
concentration of methane of all studied sites.
Component
Site 1
Site 2
Site 3
Site 4
Air
90.5-83.1
66.4-20.0
30.7-12.6
63.6-50.7
Methane
3.4-0.8
14.8-3.6
23.1-18.5
41.1-33.0
Ethane
0.9-0.3
19.6-9.8
6.3-4.1
1.9-1.1
Propane
0.5-0.1
26.7-14.3
12.2-6.3
0.3-0.1
i-Butane
2.2-1.0
3.6-2.0
n-Butane
1.1-0.5
11.3-6.0
i-Pentane
2.4-1.3
2.1-1.1
n-Pentane
2.2-1.3
2.8-1.4
C6+
6.0-4.7
2.0-0.6
24.7-18.0*
1.1-0.6
1.1-0.5
0.8-0.3
25.5-21.1*
0.8-0.3
2.2-0.4
* Site 3 data only available using initial pure component GC calibration
Table 5: Data results for GC analysis. For sample-by-sample data see AppendixC
Results from the ASTM D86 distillation analysis show little variation in the
characteristics of the oil for a given site. (See Table 6 and Appendix A) Deviation of
21
results in most cuts are below 10% between visits and even smaller between samples
taken during a given site visit.
The API gravity analysis deviations are less than 5% between samples of a given
site (Table 7)
Temperature (C.)
Volume%
Site 1
Site 2
Site 3
Site 4
IPB
63.3
45.25
29
76
5
79.34
64.03
29.7
99.82
10
96.44
94.92
36.8
138.26
15
107.22
115.4
39.4
171.48
20
118.23
135.0
42
199.56
30
144.29
177.5
46.4
257.96
40
174.76
227.1
51.5
301.74
50
207.83
281.7
57.1
332.42
60
242.39
329.6
63.3
349.12
70
279.72
352.5
71.0
357.58
80
322.57
362.9
81.4
362.18
85
350.13
367.4
87
363.34
90
373.27
368.4
94
95
383.13
FBP
383.13
111.7
368.4
111.7
363.34
Table 6: Average results for the ASTM D86 Analysis. (Site 4 were
averaged between the initial and final sample.
Cut %
Site 1
Site 2
75.2
69.4
20
57.6
44.0
60
41.8
33.2
Bottoms
Whole
52
38.9
sample
Table 7: Average results for API gravity tests.
22
Site 3
Site 4
94.4
86.8
70.6
62.5
41.8
33.1
81.5
33
An emission model pre-run with simulated site conditions was carried out for each
site. For this pre run heater/treater conditions were set at temperature of 90oF and a
pressure of 35 psi. Tank temperature was defined at 100 F with atmospheric pressure
(14.7 psi.). An inlet flow of 34.41 Bbl/hr was used. Results are presented in Table 8.
These calculations demonstrate the possibility of calculating solubilities using only API
gravity and the D86 curve using both approaches: whole sample as a single cut and three
distillation cuts for a weighted average. However, field monitoring verification is
incomplete.
Liquid
Fractions
Whole sample
Site 1
Site 2
Site 3
Site 4
2700
2640
4620
2250
2780
2690
4530
2350
Table 8: Model calculated solubilities. Results in SCF/Bbl of solubility difference
between heater/treater and tank conditions.
6. CONCLUSIONS
It was demonstrated that a model can be developed that yields vent gas estimates by
summing individual vent gas component solubility changes in the sales oil
characterized by API gravity and boiling point distribution curves.
Data collected from visits to sites 1-3 serve as guiding point for future trips. It was
possible to observe that Site 1 and especially Site 3 present values well above the
applicability of the proposed model because of high API gravity. The system layout in
site 2 is too complex making difficult the analysis of the operation. However, Site 4
seems promising for future study since it has a simple layout with one heater/treater unit
and a two-tank battery for oil recollection. Also, oil characteristics in this site are within
the model range.(See Table 7).
An additional site in central Oklahoma is under
consideration.
23
There were no noticeable variations in oil characterization at any of the sites
during the monitoring period in that API gravity and the boiling point distributions of the
ASTM D86 curve showed very little variation between samples of a given lease oil.
Field data gathered relating ambient weather conditions and tank temperature
behavior is inconclusive. Work is being directed towards determining the best way to
correlate this variable in the field with the national weather reports and the model
calculations. A final model will include all this variables as proposed in order to yield an
estimate of yearly vent gas emissions for each field site.
7. RECOMMENDATIONS
Results obtained from the project although not conclusive, demonstrate the
importance and potential of the model. However it is necessary to modify some aspects
and field verification protocol This can be done by the following actions:
•
There is a need to schedule longer site monitoring periods. A month long period is
recommended for future studies since it will give a more representative set of data for
each season.
•
Continuous gas flow readings are required due to the considerable fluctuations of this
variable on site during monitoring periods. A thermal dispersion meter with a
continuous wheel chart recorder is the suggested option for flow monitoring. It
creates very low backpressure and may record fluctuating flow rates continuously.
•
It is necessary to carefully isolate the tank under analysis leaving only one inlet for oil
feed and two outlets for vent gas and sales oil. This will assure accurate
representation of vent gas flow data.
•
Comparison with other simulators is recommended, especially the Vasquez and
Briggs model and the E&P Tanks software because of their widespread use in the
industry for both regulatory purposes and VRU design purposes.
24
8. REFERENCES
(1)
Allen, J.C “Modified Sine Wave Method for Calculating Degree Days”
Environmental Entomology. 5(3) pp. 388-396 (1976)
(2) API Technical Data Book. American Petroleum Institute, Washington D.C. 5th ed.
(1992).
(3)
ASTM D86 –00,”Standard Test Method for Distillation of Petroleum Products
at Atmospheric Pressure”, August, 2000.
(4)
ASTM D 1298 “Standard Practice for Density, Relative Density (Specific
Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by
Hydrometer Method”, May 1990
(5) Babcock R. Data for the Design of Vapor Recovery Units for Crude Oil Stock
Tank Emissions. IPEC Project document. Department of Chemical Engineering
University of Arkansas-Fayetteville. (2002)
(6) Baskerville, G.L. Emin, P. “Rapid estimation of heat accumulation from
maximum and minimum temperatures”, Ecology, 50(3) pp. 514-517 (1969)
(7) Chao K.C, Seader J.D. “A general correlation of Vapor-Liquid Equilibria in
Hydrocarbon Mixtures” AICHE Journal Vol.7 No.4, pp. 598-605 (1961)
(8)
Console Manual. Davis Vantage Pro-Weather Station. Davis Instruments (2001)
(9) “Degree Days and Phenology Models”. University of California. Statewide
Integrated Pest Management Program. (Revised September 13, 2002)
http://www.ipm.ucdavis.edu/WEATHER/ddconcepts.html
(10) Hildebrand J.H. Prausnitz J.M. and Scott R.L. Regular and Related
Solutions. The solubility of gases, liquids and solids. Van Nostrand Reinhold Co.
(1970)
(11) Moretti E., “Reduce VOC and HAP emissions”,Chem. Eng. Progress,98 (6),
pp 30-40 (June 2002)
(12) Peress J., “Estimate Storage Tank Emissions”, Chem. Eng. Progress, 97 (8),
pp. 44-45 (Aug. 2001)
(13) Prausnitz J.M. and Shair F.H. “A Thermodynamic Correlation of Gas
Solubilities”. A.I.Ch.E Journal , 7, pp 682-687 (1961)
25
(14) Prausnitz J.M. Lichtenthaler R. N. and Gomes de Azevedo E. Molecular
Thermodynamics of Fluid-Phase Equilibria. 3rd Ed. Prentice Hall. (1999)
(15) Radian International LLC, “Evaluation of a Petroleum Production Tank
Emission Model” American Petroleum Institute Publication Number 4662,
Washington, D. C., 1997.
(16) Schneider D. “Select the Right Hydrocarbon Molecular Weight Correlation”
Chem Eng Progress pp.40-44. (December 1998)
(17) Steadman, R.G. “The Assessment of Sultriness, Part II: Effects of Wind, Extra
Radiation and Barometric Pressure on Apparent Temperature” Journal of Applied
Meteorology. (July 1979)
(18) Twu, C.H. “An Internally Consistent Correlation for Predicting the Critical
Properties and Molecular weights of Petroleum and Coal Tar Liquids”, Fluid
Phase Equilibria,16, pp. 137-150 (1984)
(19) U.S Environmental Protection Agency, “Emission Factor Documentation for
AP-42, Section 7.1, Organic Liquid Storage Tanks. Final Report” US EPA ,
Office of Air Quality Planning and Standards, Emission Factor and Inventory
Group (Sept. 1997) found at http://www.epa.gov/ttn/chief/ap42
(20) Vasquez, M., Beggs H.D. “Correlations for Fluid Physical Property
Prediction”. Journal of Petroleum Technology. pp.968-970 (1980)
26
9. APPENDIX A: CRUDE OIL CHARACTERIZATION RESULTS
9.1. ASTM D86 Results.
The following pages present the results obtained for the ASTM D86 Distillation
analysis.
27
D86 DISTILLATION CURVE
Site 1-March Visit-Sample 1
(First Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
28
60
70
80
85
D86 DISTILLATION CURVE
Site 1-March Visit- Sample 1
(Second test)
400
350
Temperature (.C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
Volume Percentage
29
50
60
70
80
85
D86 DISTILLATION CURVE
Site 1-March Visit- Sample 1
(Second Test)
1.8
1.6
Density (g/ml)
1.4
1.2
1
0.8
0.6
0.4
0.2
0
0
5
10
15
20
30
40
50
60
Volume Percentage
30
70
80
85
90
95
D86 DISTILLATION CURVE
Site 1- July Visit-Sample1
(First Test)
400
350
T em p eratu re (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
31
60
70
80
85
D86 DISTILLATION CURVE
Site 1 - July Visit- Sample 1
(Second Test)
450
400
Temperature (C)
350
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
60
Volume Percentage
32
70
80
85
90
95
D86 DISTILLATION CURVE
Site 2- April Visit-Sample1
(First Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
60
Volume Percentage
33
70
80
85
90
95
D86 DISTILLATION CURVE
Site 2- April Visit-Sample 1
(First Test)
0.95
0.9
Density (g/m l)
0.85
0.8
0.75
0.7
0.65
0.6
0.55
0.5
0
5
10
15
20
30
40
50
60
Volume Percentage
34
70
80
85
90
95
D86 DISTILLATION CURVE
Site 2 - April Visit - Sample 1
(Second Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
60
70
Volume Pe rce ntage
35
80
85
90
95
D86 DISTILLATION CURVE
Site 2 - April Visit - Sample 1
(Second Test)
1
0.95
0.9
Density (g/m l)
0.85
0.8
0.75
0.7
0.65
0.6
0.55
0.5
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
36
70
80
85
90
95
D86 DISTILLATION CURVE
Site 2- April Visit- Sample 2
(First Test)
400
350
T em p eratu re (C )
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
60
Volume Percentage
37
70
80
85
90
95
D86 DISTILLATION CURVE
Site2- April Visit- Sample 2
(Second Test)
0.95
0.9
Density (g/ml)
0.85
0.8
0.75
0.7
0.65
0.6
0.55
0.5
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
38
70
80
85
90
95
D86 DISTILLATION CURVE
Site 2 - July Visit - Sample 1
(First Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
39
60
70
80
85
90
D86 DISTILLATION CURVE
Site 2- July Visit- Sample1
(Second Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
40
60
70
80
85
90
D86 DISTILLATION CURVE
Site 2- July Visit - Sample 2
(First Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
41
60
70
80
85
90
D86 DISTILLATION CURVE
Site 2-July Visit - Sample 2
(Second Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
42
60
70
80
85
90
D86 DISTILLATION CURVE
Site 3 - April Visit - Sample 1
(First Test)
160
140
Temperature (C)
120
100
80
60
40
20
0
0
5
10
15
20
30
40
50
60
70
Volume Percentage
43
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit - Sample 1
(First Test
0.8
Density (g/ml)
0.75
0.7
0.65
0.6
0.55
0.5
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
44
70
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit- Sample 1
(Second Test)
140
120
Temperature (C)
100
80
60
40
20
0
0
5
10
15
20
30
40
50
60
70
Volume Percentage
45
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit - Sample 1
(Second Test)
1.3
1.2
Density (g/ml)
1.1
1
0.9
0.8
0.7
0.6
0.5
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
46
70
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit -Sample 2
(First Test)
160
140
Temperature (C)
120
100
80
60
40
20
0
0
5
10
15
20
30
40
50
60
70
Volume Percentage
47
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit -Sample 2
(First Test)
1
0.9
0.8
Density (g/ml)
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
48
70
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit - Sample 1
(Second Test)
160
140
Temperature (C)
120
100
80
60
40
20
0
0
5
10
15
20
30
40
50
60
70
Volume Percentage
49
80
85
90
95
D86 DISTILLATION CURVE
Site 3 - April Visit - Sample 1
(Second Test)
0.8
Density (g/ml)
0.75
0.7
0.65
0.6
0.55
0.5
0
5
10
15
20
30
40
50
60
Volume Pe rce ntage
50
70
80
85
90
95
D86 DISTILLATION CURVE
Site 4 - August Visit - Sample 1
(First Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
51
60
70
80
85
90
D86 DISTILLATION CURVE
Site 4 - August Visit - Sample1
(Second Test)
400
350
Temperature (C)
300
250
200
150
100
50
0
0
5
10
15
20
30
40
50
Volume Percentage
52
60
70
80
85
90
9.2. API gravity results.
Site
Month
Distillation Volume Cut
20%
60%
Bottoms
Whole sample
measurement
1
73.9
56.7
42.1
52.0
2
74.0
56.5
39.2
52.0
1
77.7
59.7
44.2
52.0
1
69.4
44.4
33.0
38
2
69.2
43.3
33.9
39
1
70.0
44.4
33.8
39.3
2
69.2
43.9
32.1
39.3
1
93.9
87.7
72.5
81.0
2
94.8
86.1
68.7
82.0
1
62.5
41.8
33.1
33.0
Sample
March
1
July
April
2
July
3
4
April
August
53
10. APPENDIX B: SITE VISIT RESULTS
Presented in this section is the data collected during monitoring of the different sites
under study.
10.1.
Site 1: Exxon-Vastar #1
10.1.1. February Visit.
Temperatures (oC)
Day
Time
Tank
wall
Oil
1
2
10:00
AM
11:00
AM
2:00
PM
5:00
PM
9:00
AM
1:00
PM
2:00
PM
Ambient
Heater
/Treater
15
Gas Flow
(sfcm)
Pressure
Heater
/Treater
(psi)
Tank
Oil
Level
(ft)
0.0
34
9.25
11
11
11.5
21.1
0.0
33
9.17
11
7.5
8
21.1
0.0
34
9.67
10.5
6.5
7
20.0
0.0
5.0
9.71
6
4
4.5
15.6
0
6
9.68
9
8.5
10
16.7
1.3
14
9.83
8
10
11.5
17.2
1.3
18
9.75
10.1.2. July Visit.
Day
1
2
Time
Gas Flow
(SCF)
Pressure
Heater
/Treater (psi)
Tank Oil
Level
(ft)
10:00AM
0.0
30
10.83
11:00AM
0.0
29
10.42
1:30PM
0.0
29
10.42
2:30 PM
0.0
29
10.42
6:37PM
0.0
29
10.42
9:00AM
0.0
29
10.42
10:55PM
0.0
29
10.42
1:20PM
0.0
29
10.42
54
10:00
10:30
11:00
11:30
12:00
12:30
1:00
1:30
2:00
2:30
3:00
3:30
4:00
4:30
5:00
5:30
6:00
6:30
7:00
7:30
8:00
8:30
9:00
9:30
10:00
10:30
11:00
11:30
12:00
12:30
1:00
1:30
2:00
2:30
3:00
3:30
4:00
4:30
5:00
5:30
6:00
6:30
7:00
7:30
8:00
8:30
9:00
9:30
10:00
10:30
11:00
11:30
12:00
12:30
1:00
1:30
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
PM
PM
PM
PM
Temperature (C)
Temperature Profiles
Site 1- July Visit
50
45
40
35
30
25
Toil
Tamb
T wall
T heater
20
15
10
Time
55
10.2.
Site 2: Marathon Oil-Will Rogers International Airport battery
10.2.1. March Visit.
Day
1
2
Time
Gas Flow
(SCF)
Pressure
Heater
/Treater (psi)
Tank Oil
Level
(ft)
9:45AM
0
27
5.82
10:45AM
380
25
N.A
11:45AM
427.3
25
4.92
12:45PM
122.0
23
4.00
1:45PM
346.7
25.5
N.A
2:45PM
471.9
22.5
N.A
3:45PM
429.9
22.0
2.94
4:45PM
76.1
26.0
2.92
5:45PM
507.7
24
N.A
9:30PM
133.2
21.5
N.A
7:45AM
221.0
20.5
N.A
8:45AM
325.4
21.0
6.67
9:45AM
357.8
21.0
6.85
10:45PM
383.2
24.0
7.21
11:45PM
418.0
22.5
7.38
12.:45PM
286.0
26.0
N.A
2:15PM
446
24.5
N.A
10:45PM
427.7
25.0
N.A
56
9:45
10:45
11:45
12:45
1:45
2:45
3:45
4:45
5:45
6:45
7:45
8:45
9:45
10:45
11:45
12:45
1:45
2:45
3:45
4:45
5:45
6:45
7:45
8:45
9:45
10:45
11:45
12:45
1:45
2:45
3:45
4:45
5:45
6:45
7:45
8:45
9:45
10:45
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
Temperature (C)
Temperature Profile
Site 2- March visit
60
50
40
T oil
30
Tamb.
T heater
20
10
0
Time
57
10.2.2. July Visit.
Day
1
2
Time
Gas Flow
(SCF)
Pressure
Heater
/Treater (psi)
Tank Oil
Level
(ft)
8:45AM
0
23
6.00
9:45AM
150
22.5
5.08
10:45AM
140
23
4.67
12:45PM
730
25.5
3.42
2:30PM
430
24.5
3.58
6:30PM
1100
25.5
4.27
7:00AM
2850
24.0
6.25
8:00AM
200
25.6
6.25
9:00AM
120
25.0
6.08
10:00AM
160
25.0
5.42
11:00AM
50
26.5
5.00
12:00PM
170
26.0
4.16
58
8:45
9:15
9:45
10:15
10:45
11:15
11:45
12:15
12:45
1:15
1:45
2:15
2:45
3:15
3:45
4:15
4:45
5:15
5:45
6:15
6:45
7:15
7:45
8:15
8:45
9:15
9:45
10:15
10:45
11:15
11:45
12:15
12:45
1:15
1:45
2:15
2:45
3:15
3:45
4:15
4:45
5:15
5:45
6:15
6:45
7:15
7:45
8:15
8:45
9:15
9:45
10:15
10:45
11:15
11:45
AM
AM
AM
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
Temperature (C)
Temperature Profiles
Site 2 -July visit
60
50
40
T oil
30
Tamb.
T heater
T wall
20
10
0
Time
59
10.3.
Site 3: ENOGEX – Wellston Stabilizer Facility.
10.3.1. April Visit.
Day
1
2
Time
Gas Flow
(SCF)
Tank Oil
Level
(ft)
8:45AM
0
2.17
9:45AM
230
2.67
10:45AM
330
2.67
11:45AM
340
2.67
12:45PM
390
4.33
1:45PM
310
N.A
2:45PM
370
N.A
3:45PM
300
N.A
4:30PM
320
N.A
8:45AM
4140
N.A
9:45AM
160
N.A
11:00AM
200
N.A
11:50AM
160
N.A
12:30PM
150
N.A
2:30PM
490
N.A
3:30PM
210
N.A
4:30PM
260
N.A
6:00PM
180
N.A
6:30
90
N.A
*Tank level data is limited due to difficulties to gauge the tank
60
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
7:15
8:00
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
7:15
8:00
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
AM
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
Temperature (C)
Temperature Profiles
Site-3 April visit
30
25
20
T oil
15
Tamb.
T wall
10
5
0
Time
61
10.4.
Site 4: Timmins #1.
10.4.1. August Visit
Day
Time
Gas Flow
(SCF)
Pressure
Heater
/Treater (psi)
Tank Oil
Level
(ft)
1
5:42 PM
0.00
38
7.05
7:49 AM
0.30
40
7.65
1:09 PM
0.00
38
7.88
7:45 PM
0.00
37
8.15
8:40AM
0.45
43
8.82
12:52PM
1.55
42
8.91
2
3
62
5:45
6:30
7:15
8:00
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
7:15
8:00
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
7:15
8:00
8:45
9:30
10:15
11:00
11:45
12:30
1:15
2:00
2:45
3:30
4:15
5:00
5:45
6:30
7:15
9:00
9:45
10:30
11:15
12:00
12:45
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
PM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
AM
PM
PM
Temperature (C)
Temperature Profiles
Site 4 August visit
40
35
30
25
T oil
20
Tamb.
T heater
T wall
15
10
5
0
Time
63
11. APPENDIX C: GAS CHROMATOGRAPHY RESULTS.
Mol Percentages
Site
1
Month
July
No
Air
Methane
Ethane
Propane
i-Butane
n-Butane
i-Pentane
1
90.5
0.8
0.3
0.1
2
87.0
3.4
0.6
0.2
1.0
0.5
1.3
1.3
4.7
3
83.1
1.8
0.9
0.5
2.2
1.1
2.4
2.2
6.0
1
23.2
9.1
19.6
26.7
10.9
2
66.4
3.6
9.8
14.3
5.8
1
57.7
6.2
10.2
15.0
2.0
6.0
1.1
1.4
0.6
2
20.0
13.3
18.4
26.6
3.6
11.3
2.1
2.8
2.0
3
30.2
14.8
16.1
20.7
2.8
8.7
1.7
2.3
1.7
1
12.6
23.1
6.3
12.2
24.7
21.1
2
30.7
18.5
4.1
6.3
18.0
22.4
3
20.5
22.9
4.4
6.3
20.4
25.5
1
50.7
41.1
1.9
0.3
1.1
1.1
0.8
0.8
2.2
2
61.3
34.1
1.5
0.2
0.8
0.8
0.5
0.4
0.4
3
63.6
33.0
1.1
0.1
0.6
0.5
0.3
0.3
0.4
0.3
n-Pentane
C6+
Remarks
8.0
Instantaneous
Sample
10.48
March
2
July
3
4
March
August
64
VRU on
Instantaneous
Sample
65