DATA FOR DESIGN OF VAPOR RECOVERY UNITS FOR CRUDE OIL STOCK TANK EMISSIONS

Transcription

1 DATA FOR DESIGN OF VAPOR RECOVERY UNITS FOR CRUDE OIL STOCK TANK EMISSIONS Final Report EPA/IPEC Award Number R Subcontract R.E Babcock, P.I. J. M. Plaza, Graduate Assistant Department of Chemical Engineering College of Engineering University of Arkansas-Fayetteville February 6, 004

2 ABSTRACT According to EPA s Natural Gas STAR program there are about 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

3 TABLE OF CONTENTS 1. INTRODUCTION PROPOSED MODEL Solubility Parameter Calculations Molecular Weight Models Heat of Vaporization Weather Conditions Heating Degree Day Temperature-Humidity-Sun-Wind Index (THSW Index) MODEL CALCULATIONS PROJECT EXECUTION Sample Recollection and Laboratory Analysis Liquid Samples Gas Samples Site Visits Site 1: Exxon-Vastar # Site : Marathon Oil-Will Rogers International Airport battery Site 3: ENOGEX Wellston Stabilizer Facility Site 4: Timmins # RESULTS CONCLUSIONS RECOMMENDATIONS REFERENCES APPENDIX A: CRUDE OIL CHARACTERIZATION RESULTS ASTM D86 Results API gravity results APPENDIX B: SITE VISIT RESULTS Site 1: Exxon-Vastar # February Visit July Visit Site : Marathon Oil-Will Rogers International Airport battery March Visit July Visit Site 3: ENOGEX Wellston Stabilizer Facility April Visit Site 4: Timmins # August Visit APPENDIX C: GAS CHROMATOGRAPHY RESULTS iii

4 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.. 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 0) for sites with medium to heavy crude oil. Emissions were assumed to be composed of only methane, ethane, propane, i- butane, 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..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

5 X i = f f G L i v exp L i ( δ δ ) i R T Oil δ = the Hildebrand solubility parameter. f G = the fugacity of the gaseous solute at the initial state. f i L =the fugacity of the solute (hypothetical) as a pure liquid at the defined temperature. X i = 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 A T log 0 ν = logν + ( 0) ( 1) ω logν ( 0) 1 3 = A + + A Tr + A Tr + A Tr + ( A + A Tr + A Tr ) Pr + ( A + A Tr ) Pr log Pr logν 0 r 3 4 () T 3.154T 0.05( P 0.6) T = r r r r Table 1 presents the values used for the A i constants: Constant A 0 A 1 A A 3 A 4 A 5 A 6 A 7 A 8 A 9 Value 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 = i= 1 φ i δ i

6 Here the solubility parameter δ i for volume fractions at 0%, 60% and bottoms of the ASTM D86 curve were calculated and multiplied by the fraction value (Φ i. ). 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 δ = i U v vap i L i vap The energy of vaporization U i is equal to H vap i -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: δ = i vap i L vi H RT Where T is the temperature at which the value of solubility is being estimated. The molar volume was calculated using the following expression: v L i Mwi = ρ i.. 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 () was used as described below...1. Molecular weight calculations according to API Technical Data Book Procedure B.1 3

7 This method is presented in the Procedure B.1 of the API Technical Data Book (). It has been selected due to its simplicity for performing computer calculations. The expression for this method is as follows: MW [ exp( 1.165E 4T SG E 3 T SG) ] T = SG b b b Where: MW= molecular weight of the fraction T b =is the mean average boiling point of the petroleum fraction ( o R) SG=Specific gravity of the cut.... 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 () 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 3 3 ( T 59.7) + A ( T 59.7 ) + A ( 59. ) = A T Where: H L is the enthalpy of the liquid petroleum in BTU per pound. A A K = SG) K + SG = ( K ) SG 4

8 A 3 = ( K ) SG K SG is the Watson Characterization factor equal to is the specific gravity 60F/60F K 1 Tb = 3 SG T is the chosen temperature. The reduced pressure and temperature were calculated using the pseudo critical pressure and temperature (P pc and T pc ) as follows P = r P P pc T = r 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 (P r >1 and T r > 0.8) are calculated using the following: H = H RTpc + MW # L + B ( T 0.8T ) + B ( T 0.64 T ) + B ( T 0.51 T ) pc ~ o ~ H H ω RTpc pc 3 pc Where: H H L # 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. B B = K + B SG = K K B SG ( ) 5

9 B ( ) 9 3 = B B 4 = SG 10 K K for 10.0<K<1.8 with 0.70<SG<0.885 ( )( )( ) 4 SG B 4 =0 for all other cases. MW is the molecular weight in lb/lbmol R is the gas constant, BTU/lbmol o R ~ o ~ H H is the dimensionless pressure effect on enthalpy obtained from RTpc procedure 7B3. in (). It may be disregarded if P r <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...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 (). The equations are as follows: T P pc pc ( ( T SG T SG ) T = exp S = b ( exp( T SG T SG ) T b b b SG b Where: T pc is the pseudo critical temperature of the petroleum fraction ( o R) P pc is the pseudo critical pressure of the petroleum fraction (psia) T b is the mean average boiling point ( o R) SG is the specific gravity...4. The Acentric Factor The acentric factor of the fraction is defined as (): ω = r log P *

10 Where: P r * is the reduced vapor pressure P * /P pc P * is the vapor pressure at 0.7*T pc To estimate the vapor pressure procedure 5A.1.19 from () was used. This method uses a correction for boiling point temperatures of hydrocarbons with a Watson K factor different than 1. The equations are: log X P * = 43X for X> log X P * = 95.76X for X log X P * = 36X for X< Where: P * is the vapor pressure (mm Hg) X = ' Tb T T T ' b ' b Where: T b is the normal boiling point corrected to K=1 ( o R) T is the absolute temperature ( o R) A trial and error is necessary for the K=1 correction. The following set of equations are used: T = T b T ' b =.5 f ( K 1) * P log 760 T b is the normal boiling point ( o R) 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 00 F, f= 0. For super atmospheric vapor pressures of substances having normal boiling points between 00 F and 400 F, f is evaluated by: 7

11 = b T f..5. Pressure Effect on enthalpy term The dimensionless pressure effect on enthalpy pc o RT H H ~ ~ was obtained from procedure 7B3. in (). The equation used was: ( ) ( ) ( ) ( ) + = 0 0 ~ ~ ~ ~ ~ ~ ~ ~ pc o h pc o h pc o pc o RT H H RT H H RT H H RT H H ω ω Where: pc o RT H H ~ ~ is the dimensionless effect of pressure on enthalpy of the fluid of interest. ( ) 0 ~ ~ pc o RT H H is the effect of pressure on enthalpy for the simple fluid. ( ) h pc o RT H H ~ ~ is the effect of pressure on enthalpy for the heavy reference fluid (n-octane). ω is the acentric factor calculated for the fraction. ω (h) is the acentric factor of the heavy reference fluid = The effect of pressure on enthalpy for the simple and heavy fluid is calculated by the following equation: () () = E T V d T V T c c T V T b T b b z T RT H H r r r r r r r r r i r i pc o 3 5 / 3 / 3 / 1 ~ ~ Where: = 3 4 exp 1 1 r r r V V T c E γ γ β β γ 8

12 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. T r is the reduced temperature T/T pc T is the desired temperature ( o R) The rest of the unknowns were obtained from equations and values found in Procedure 6B1.8 (). The main equation to be used from this procedure is: z () i = P rvr B C D c γ γ = β + exp 5 3 T r Vr Vr Vr Tr Vr 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. V = r P pc RT V pc V is the molar volume (ft 3 /lbmol) for the simple or heavy model according to which z is being calculated. R is the gas constant ( psia ft 3 /lbmol o R) b B = b1 T r b T 3 r b T 4 3 r c C = c1 + T c 3 3 r T r D = d d 1 + T r The rest of the constants are listed in the following table for the simple and heavy reference fluids. 9

13 Table : Constants from procedure 6B1.8 () Heavy Constant Simple Fluid Reference Fluid b b b b c c c c d 1 x d x Β Γ 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..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

14 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..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

15 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: V n ( s Rs ) dt + N B ( RS R ) in O O max SO min t = Q R 0 j= 1 Q j R S j + Q *5.6 * t 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 Q j is the amount of oil removed from the tank during a j th unloading event (in bbl) N B 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 5.6 SCF/Bbl The subscripts refer to the following conditions: s O atmospheric pressure and tank temperature s in heater/treater conditions. s O-max, s O-min maximum and minimum values during the accounting period. 1

16 s j unloading conditions during the j time. (Atmospheric pressure and T j 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 Where: V n ( R ) t Q R + Q *5.6 t = Q Rs so j s * in j j= 1 R s in, R so 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: Rs i ρ = Mw oil oil f P L pure v exp L i ( δ δ ) i R T Here Rs i is the solubility of one of the vent gas components in Scf / bbl. ρ oil is the density for the stored crude oil in kg/m 3. Mw oil is the molecular weight of the crude oil P is pressure of the crude oil (bar) 13

17 f pure L is the fugacity of the solute (hypothetical) as a pure liquid at the defined temperature (bar) v L is the hypothetical molar liquid volume of the solute. (cm 3 /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 is a unit conversion constant.(scf/bbl) The fugacity parameter of the gas at the initial state f G 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: Rs i ρ = Mw oil oil f P L pure v exp L i ( δ δ ) i R T The total solubility was then obtained by adding the values of Rs i calculated for each of the C1-C5 compounds mentioned previously. 4. PROJECT EXECUTION Sample Collection and Laboratory Analysis 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

18 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 15 ml flasks with taper joint neck according to the method and a pair of 7C and 8C ASTM E1 thermometers. Thermometer Distillation Flask Condenser water line 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 0%, 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) Gas Samples Gas samples were collected using 6-liter TO-14 canisters and a Veriflo SC43XL 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

19 in approximately six hours. Some instantaneous grab sample of vent gas were also collected. (Figure ) Vacuum gauge Quick-change connection Vent gas P Crude Oil inlet Dry gas meter Flow controller TO-14 Canister Figure : Crude oil stock tanks gas sampling set up Previous to each site visit TO-14 canisters were evacuated to approximately -6 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 61. 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

20 Component Mole Faction % Nitrogen 5.01 Carbon Dioxide Helium Methane Ethane 9.01 Propane 6.00 i-butane 3.0 n-butane 3.00 i-pentane 1.01 n-pentane 1.01 Table 3: Composition calibration standard for GC analysis. Carrier Gas line Sampling loops (30µl) PI Vacuum Pump 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

21 two columns in the GC. One was a -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 5% SP-100 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 30 o C Detector Temperature 30 o C Initial Temperature 35 o C Initial time min. Temperature ramp rate 4 o C / min. Final Temperature 5 o C Final Time 3 min. Carrier gas Helium Carrier gas flow TCD ml/s Carrier gas flow FID 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.. 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

22 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 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 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

23 4... Site : 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 6 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 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) 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 BPD. This site was monitored at the beginning of April. (See Appendix C) 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. 0

24 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 33 0 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 and 3 demonstrate higher concentrations of C3+ hydrocarbons. Site 4 has the highest concentration of methane of all studied sites. Component Site 1 Site Site 3 Site 4 Air Methane Ethane Propane i-butane * n-butane i-pentane n-pentane * C * 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 1

25 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 Site 3 Site 4 IPB FBP Table 6: Average results for the ASTM D86 Analysis. (Site 4 were averaged between the initial and final sample Cut % Site 1 Site Site 3 Site Bottoms Whole sample Table 7: Average results for API gravity tests.

26 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 90 o F and a pressure of 35 psi. Tank temperature was defined at 100 F with atmospheric pressure (14.7 psi.). An inlet flow of 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 Site 1 Site Site 3 Site Whole sample 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 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. 3

27 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. 4

28 8. REFERENCES (1) Allen, J.C Modified Sine Wave Method for Calculating Degree Days Environmental Entomology. 5(3) pp (1976) () API Technical Data Book. American Petroleum Institute, Washington D.C. 5 th ed. (199). (3) ASTM D86 00, Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure, August, 000. (4) ASTM D 198 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. (00) (6) Baskerville, G.L. Emin, P. Rapid estimation of heat accumulation from maximum and minimum temperatures, Ecology, 50(3) pp (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 (1961) (8) Console Manual. Davis Vantage Pro-Weather Station. Davis Instruments (001) (9) Degree Days and Phenology Models. University of California. Statewide Integrated Pest Management Program. (Revised September 13, 00) (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 (June 00) (1) Peress J., Estimate Storage Tank Emissions, Chem. Eng. Progress, 97 (8), pp (Aug. 001) (13) Prausnitz J.M. and Shair F.H. A Thermodynamic Correlation of Gas Solubilities. A.I.Ch.E Journal, 7, pp (1961) 5

29 (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 466, Washington, D. C., (16) Schneider D. Select the Right Hydrocarbon Molecular Weight Correlation Chem Eng Progress pp (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 (1984) (19) U.S Environmental Protection Agency, Emission Factor Documentation for AP-4, 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 (0) Vasquez, M., Beggs H.D. Correlations for Fluid Physical Property Prediction. Journal of Petroleum Technology. pp (1980) 6

30 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. 7

31 D86 DISTILLATION CURVE Site 1-March Visit-Sample 1 (First Test) Temperature (C) Volume Percentage 8

32 D86 DISTILLATION CURVE Site 1-March Visit- Sample 1 (Second test) Temperature (.C) Volume Percentage 9

33 D86 DISTILLATION CURVE Site 1-March Visit- Sample 1 (Second Test) Density (g/ml) Volume Percentage 30

34 D86 DISTILLATION CURVE Site 1- July Visit-Sample1 (First Test) Tem perature (C) Volume Percentage 31

35 D86 DISTILLATION CURVE Site 1 - July Visit- Sample 1 (Second Test) Temperature (C) Volume Percentage 3

36 D86 DISTILLATION CURVE Site - April Visit-Sample1 (First Test) Temperature (C) Volume Percentage 33

37 D86 DISTILLATION CURVE Site - April Visit-Sample 1 (First Test) Density (g/ml) Volume Percentage 34

38 D86 DISTILLATION CURVE Site - April Visit - Sample 1 (Second Test) Temperature (C) Volume Percentage 35

39 D86 DISTILLATION CURVE Site - April Visit - Sample 1 (Second Test) Density (g/ml) Volume Percentage 36

40 400 D86 DISTILLATION CURVE Site - April Visit- Sample (First Test) Tem perature (C) Volume Percentage 37

41 D86 DISTILLATION CURVE Site- April Visit- Sample (Second Test) Density (g/ml) Volume Percentage 38

42 400 D86 DISTILLATION CURVE Site - July Visit - Sample 1 (First Test) Temperature (C) Volume Percentage 39

43 D86 DISTILLATION CURVE Site - July Visit- Sample1 (Second Test) Temperature (C) Volume Percentage 40

44 D86 DISTILLATION CURVE Site - July Visit - Sample (First Test) Temperature (C) Volume Percentage 41

45 D86 DISTILLATION CURVE Site -July Visit - Sample (Second Test) Temperature (C) Volume Percentage 4

46 D86 DISTILLATION CURVE Site 3 - April Visit - Sample 1 (First Test) Temperature (C) Volume Percentage 43

47 D86 DISTILLATION CURVE Site 3 - April Visit - Sample 1 (First Test Density (g/ml) Volume Percentage 44

48 140 D86 DISTILLATION CURVE Site 3 - April Visit- Sample 1 (Second Test) Temperature (C) Volume Percentage 45

49 1.3 D86 DISTILLATION CURVE Site 3 - April Visit - Sample 1 (Second Test) Density (g/ml) Volume Percentage 46

50 160 D86 DISTILLATION CURVE Site 3 - April Visit -Sample (First Test) Temperature (C) Volume Percentage 47

51 D86 DISTILLATION CURVE Site 3 - April Visit -Sample (First Test) Density (g/ml) Volume Percentage 48

52 D86 DISTILLATION CURVE Site 3 - April Visit - Sample 1 (Second Test) Temperature (C) Volume Percentage 49

53 D86 DISTILLATION CURVE Site 3 - April Visit - Sample 1 (Second Test) Density (g/ml) Volume Percentage 50

54 400 D86 DISTILLATION CURVE Site 4 - August Visit - Sample 1 (First Test) Temperature (C) Volume Percentage 51

55 D86 DISTILLATION CURVE Site 4 - August Visit - Sample1 (Second Test) Temperature (C) Volume Percentage 5

56 9.. API gravity results. Site Month Sample Distillation Volume Cut 0% 60% Bottoms Whole sample measurement 1 March July April July April August

57 10. APPENDIX B: SITE VISIT RESULTS Presented in this section is the data collected during monitoring of the different sites under study Site 1: Exxon-Vastar # February Visit. Day 1 Time 10:00 AM 11:00 AM :00 PM 5:00 PM 9:00 AM 1:00 PM :00 PM Oil Temperatures ( o C) Tank wall Ambient Heater /Treater Gas Flow (sfcm) Pressure Heater /Treater (psi) Tank Oil Level (ft) July Visit. Day Time Gas Flow (SCF) Pressure Heater /Treater (psi) Tank Oil Level (ft) 10:00AM :00AM :30PM :30 PM :37PM :00AM :55PM :0PM

58 Temperature Profiles Site 1- July Visit 10:00 AM 10:30 AM 11:00 AM 11:30 AM 1:00 PM 1:30 PM 1:00 PM 1:30 PM :00 PM :30 PM 3:00 PM 3:30 PM 4:00 PM 4:30 PM 5:00 PM 5:30 PM 6:00 PM 6:30 PM 7:00 PM 7:30 PM 8:00 PM 8:30 PM 9:00 PM 9:30 PM 10:00 PM 10:30 PM 11:00 PM 11:30 PM 1:00 AM 1:30 AM 1:00 AM 1:30 AM :00 AM :30 AM 3:00 AM 3:30 AM 4:00 AM 4:30 AM 5:00 AM 5:30 AM 6:00 AM 6:30 AM 7:00 AM 7:30 AM 8:00 AM 8:30 AM 9:00 AM 9:30 AM 10:00 AM 10:30 AM 11:00 AM 11:30 AM 1:00 PM 1:30 PM 1:00 PM 1:30 PM Time 55 Toil Tamb T wall T heater Temperature (C)

59 10.. Site : Marathon Oil-Will Rogers International Airport battery March Visit. Day Time Gas Flow (SCF) Pressure Heater /Treater (psi) Tank Oil Level (ft) 9:45AM :45AM N.A 11:45AM :45PM :45PM N.A :45PM N.A 3:45PM :45PM :45PM N.A 9:30PM N.A 7:45AM N.A 8:45AM :45AM :45PM :45PM :45PM N.A :15PM N.A 10:45PM N.A 56

60 Temperature Profile Site - March visit 9:45 AM 10:45 AM 11:45 AM 1:45 PM 1:45 PM :45 PM 3:45 PM 4:45 PM 5:45 PM 6:45 PM 7:45 PM 8:45 PM 9:45 PM 10:45 PM 11:45 PM 1:45 AM 1:45 AM :45 AM 3:45 AM 4:45 AM 5:45 AM 6:45 AM 7:45 AM 8:45 AM 9:45 AM 10:45 AM 11:45 AM 1:45 PM 1:45 PM :45 PM 3:45 PM 4:45 PM 5:45 PM 6:45 PM 7:45 PM 8:45 PM 9:45 PM 10:45 PM Time 57 T oil Tamb. T heater Temperature (C)

61 10... July Visit. Day Time Gas Flow (SCF) Pressure Heater /Treater (psi) Tank Oil Level (ft) 8:45AM :45AM :45AM :45PM :30PM :30PM :00AM :00AM :00AM :00AM :00AM :00PM

62 Temperature Profiles Site -July visit 8:45 AM 9:15 AM 9:45 AM 10:15 AM 10:45 AM 11:15 AM 11:45 AM 1:15 PM 1:45 PM 1:15 PM 1:45 PM :15 PM :45 PM 3:15 PM 3:45 PM 4:15 PM 4:45 PM 5:15 PM 5:45 PM 6:15 PM 6:45 PM 7:15 PM 7:45 PM 8:15 PM 8:45 PM 9:15 PM 9:45 PM 10:15 PM 10:45 PM 11:15 PM 11:45 PM 1:15 AM 1:45 AM 1:15 AM 1:45 AM :15 AM :45 AM 3:15 AM 3:45 AM 4:15 AM 4:45 AM 5:15 AM 5:45 AM 6:15 AM 6:45 AM 7:15 AM 7:45 AM 8:15 AM 8:45 AM 9:15 AM 9:45 AM 10:15 AM 10:45 AM 11:15 AM 11:45 AM Time 59 T oil Tamb. T heater T wall Temperature (C)

63 10.3. Site 3: ENOGEX Wellston Stabilizer Facility April Visit. Day Time Gas Flow (SCF) Tank Oil Level (ft) 8:45AM :45AM :45AM :45AM :45PM :45PM 310 N.A :45PM 370 N.A 3:45PM 300 N.A 4:30PM 30 N.A 8:45AM 4140 N.A 9:45AM 160 N.A 11:00AM 00 N.A 11:50AM 160 N.A 1:30PM 150 N.A :30PM 490 N.A 3:30PM 10 N.A 4:30PM 60 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

64 Temperature Profiles Site-3 April visit 8:45 AM 9:30 AM 10:15 AM 11:00 AM 11:45 AM 1:30 PM 1:15 PM :00 PM :45 PM 3:30 PM 4:15 PM 5:00 PM 5:45 PM 6:30 PM 7:15 PM 8:00 PM 8:45 PM 9:30 PM 10:15 PM 11:00 PM 11:45 PM 1:30 AM 1:15 AM :00 AM :45 AM 3:30 AM 4:15 AM 5:00 AM 5:45 AM 6:30 AM 7:15 AM 8:00 AM 8:45 AM 9:30 AM 10:15 AM 11:00 AM 11:45 AM 1:30 PM 1:15 PM :00 PM :45 PM 3:30 PM 4:15 PM 5:00 PM 5:45 PM 6:30 PM Time 61 T oil Tamb. T wall Temperature (C)

65 10.4. Site 4: Timmins # August Visit Day Time Gas Flow (SCF) Pressure Heater /Treater (psi) Tank Oil Level (ft) 1 5:4 PM :49 AM :09 PM :45 PM :40AM :5PM

66 Temperature Profiles Site 4 August visit 5:45 PM 6:30 PM 7:15 PM 8:00 PM 8:45 PM 9:30 PM 10:15 PM 11:00 PM 11:45 PM 1:30 AM 1:15 AM :00 AM :45 AM 3:30 AM 4:15 AM 5:00 AM 5:45 AM 6:30 AM 7:15 AM 8:00 AM 8:45 AM 9:30 AM 10:15 AM 11:00 AM 11:45 AM 1:30 PM 1:15 PM :00 PM :45 PM 3:30 PM 4:15 PM 5:00 PM 5:45 PM 6:30 PM 7:15 PM 8:00 PM 8:45 PM 9:30 PM 10:15 PM 11:00 PM 11:45 PM 1:30 AM 1:15 AM :00 AM :45 AM 3:30 AM 4:15 AM 5:00 AM 5:45 AM 6:30 AM 7:15 AM 9:00 AM 9:45 AM 10:30 AM 11:15 AM 1:00 PM 1:45 PM Time 63 T oil Tamb. T heater T wall Temperature (C)

67 11. APPENDIX C: GAS CHROMATOGRAPHY RESULTS. Mol Percentages Site Month No Air Methane Ethane Propane i-butane n-butane i-pentane n-pentane C6+ Remarks July Instantaneous Sample March July VRU on March Instantaneous Sample 4 August