### Analysis of Tank Emissions

This discussion describes a revised estimate of tank emissions, as compared to the tank emissions in the current proposed rule. The proposed rule uses U.S. Inventory 1 estimates of greenhouse gas emissions from crude oil a nd condensate stock tank vents. Based on partner experiences shared with Natural Ga s STAR, it is believed that emissions from these sources are under-estimated. Due to insufficient data and time, EPA moved forward with the Inventory estimates in th e threshold and burden analyses for onshore production. However, while finalizing the proposed rule, EPA combined previously published data from the Houston A dvanced Research Center (HARC 2 ) with newly obtained data from the Texas Commi ssion on Environmental Quality (TCEQ 3 ) on tank emissions to independently estimate tank emi ssions and determine the potential effect on the rule.

This independent estimate of emissions from tanks determined an increase in emissions over the U.S. National Inventory of approximately 26.9 million tonnes of CO 2 e (MTCO 2 e). This independent analysis is desc ribed in the appendix to provide detail on the analysis.

The revised tank emissions estimates were i nput to the onshore production threshold and burden models and the results were compared to the current proposed rule. These are presented in Exhibit 1 below.

Exhibit 1. Comparison of Proposed Rule Onshore Production Burden to Revised Tanks Case.

Metric Proposed Rule (Onshore Production) Revised Tanks Case (Onshore Production) Total Emissions (combustion and process) 277.8 MTCO 2 e 304.7 MTCO 2 e

Process Emissions Covered at 25k tonne Threshold 154.9 MTCO 2 e 179.1 MTCO 2 e

Emissions Covered at 25k tonne Threshold (%) 82% 83%

Entities Covered at 25k tonne Threshold (%) 4% 5%
Compliance Cost at 25k tonne Threshold $18.5 million $19.0 million

Cost Effectiveness at 25k tonne Threshold $0.12/tonne $0.11/tonne

While the total U.S. emissions estimate fo r onshore production increases by almost 10%, the cost-effectiveness improves by only 1 cent per tonne, from 12 cents to 11 cents per tonne, and the coverage of total emissions and entities only increase by 1% each: 82 to

1 EPA. U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007 . Available online at: <http://epa.gov/climatechange/emissions/usgginv_archive.html>.

2 HARC. VOC Emissions from Oil and Condensate Storage Tanks . October 31, 2006.
3 TCEQ. Upstream Oil and Gas Storage Tank Project Flash Emissions Model Evaluation . July 16, 2009.83% and 4 to 5%, respectively. Thus, the antic ipated coverage and costs of the proposed rule are not significantly impacted by th is revised estimate of tank emissions.

### Appendix – Tanks Analysis

Crude oil and condensate stock tanks are used to hold oil for brief periods of time in order to stabilize flow between production wells and pipeline or trucking transportation sites. To fill a field stock tank without using a pump, the gas-liquid separator is operated at high enough pressure to overcome flow-line pressure drop plus the head of a full stock tank. When the oil at separator pressure ente rs the stock tank at atmospheric pressure, light hydrocarbons dissolved in the oil— including methane and other VOC’s and hazardous air pollutants HAP’s, and some iner t gases—vaporize or "flash" and vent from the fixed roof of the tank. As the liquid level in the tank fluctuates, and barometric pressure and temperature fluctuate, more light hydrocarbons vapor ize and vent to the atmosphere (called “working” and “standing” losses, respectively).

► U.S. Inventory Estimates The U.S. Inventory recognizes that flashing emissions from tanks are not dependent on the number of tanks, but the throughput of hydrocarbon liquids in those tanks, characteristics of those hydrocarbon liquids (such as API gravity), the pressure and temperature of the equipment immediately upstream of the stor age tank (typically a separator), and the temperature and pressu re of the tank (typically atmospheric).

For its activity factor, the I nventory considers the throughpu t of hydrocarbon liquids. It assumes that all produced condensate passes through storage and all crude oil produced from non-marginal wells (that is wells whic h have production rate s greater than 10 bbl/day) and 20% of crude oil that is produc ed from marginal wells also pass through storage tanks.

Since a detailed database of separator temp eratures and pressures as well as the associated hydrocarbon liquid char acteristics is not available, the U.S. Inventory uses a set of 101 E&P Tank simulation runs develope d by the American Petroleum Institute in the 1990s to estimate benzene and other hazard ous air pollutant emissions from crude oil and condensate stock tanks. The speciation of emissions from these runs includes methane which was used to develop a methane emissions factor per barrel of hydrocarbon that passes through storage. E& P Tank software was specifically designed to provide an affordable alternative to mo re versatile software packages to estimate flashing emissions from hydrocarbon storag e tanks. The 101 simulations, using field operating data, represent hydrocarbon gravities from 17 to 64  ̊ API and separator pressures and temperatures ranging from 4 to 870 psig and 40 to 180  ̊ F respectively. In total, the API study provided 103 E&P Tank runs; however, 2 were omitted as outliers.

The U.S. Inventory divided these E& P Tank simulations into two ranges:

• API gravities less than 45  ̊ API were considered crude oil

• API gravities greater than or equal to 45  ̊ API were considered condensate

It developed average emission factors of c ubic feet of methane per barrel of hydrocarbon for both ranges, weighting the individual points by the associated production ratesprovided in the simulation inputs. The deve loped emission factors represent uncontrolled emissions due to hydrocarbon flashing in ta nks and are displaye d in Exhibit 5-1.

The two most common control methods for th ese emissions are vapor recovery units (VRU’s) and flare systems. For oil tanks, the Inventory recogniz es that regulations require controls on all tanks in Alaska, so Alaskan crude oil production is deducted from the activity factor, assuming there are no emissions from these tanks.

The Inventory estimates that 50% of condensat e storage tanks are equi pped with emission controls. It adjusts the activity factor such that 50% of condensate is produced to tanks equipped with vapor recovery or connected to flare systems; and the other half of condensate is produced to tanks without controls. It as sumes that for those tanks equipped with emissions control, 80% of th e estimated emissions are captured by the control technologies. After emissions from co ndensate tanks are estimated, the inventory then calculates an incremental portion of those emissions that are affected by the NESHAP regulations, and deducts those from th e total. These values are summarized in Exhibit 5-1.

Exhibit 5-1. Inventory Results for Storage Tank Methane Emissions (2007)
Crude Oil Condensate Total U.S. Production 1,848 MMbbl 123 MMbbl Throughput to Tanks with Controls 264 MMbbl (Alaska) 61.5 MMbbl Volume Not Produced to Tanks 259 MMbbl (80% of marginal well production) - Methane Emission Factor(s) 5.28 scf/bbl 21.87 scf/bbl (uncontrolled), 4.37 scf/bbl (controlled) Incremental Reductions - 0.4 Bcf (NESHAP)

Total Methane Emissions 7 Bcf (2.8 MMTCO 2 e) 1.2 Bcf (0.5 MMTCO 2 e)

The Inventory does not deduct emission re duction reported by Natural Gas STAR Partners like it does for most other sources because it assumes there will be doublecounting of reductions with the vapor recovery and regulation assumptions. For example, it assumes that the 50% of condensate tanks equipped with vapor recovery covers voluntary reductions from Natural Gas STAR and that the voluntary reductions prior to the enactment of the NESHAP regulations would overlap with those attributed to NESHAP in the analysis.

Using the Inventory emission factors for uncontrolled tank em issions and applying them to the total national producti on for both crude oil and conden sate production suggests a worst-case scenario in which approximately 12 Bcf (4.9 MMTCO 2 e) of methane could be emitted from tanks in the U.S. Natural Gas STAR Partners have reported voluntarily reducing over 18 Bcf (7.3 MMTCO 2 e) of methane emissions annually through 2007. That reduction does not include most activity from before 1998, the year in which the NESHAP regulation dictated additional vapor recovery, and it does not include activities from non-Partner companies in industry who also voluntarily install vapor recovery systems. If Natural Gas STAR reported em ission reductions alone were deducted fromthe “worst-case scenario” presented above, U. S. emissions from storage tanks would be less than zero.

► Methodology This analysis revised the development of th e uncontrolled emission factors usi ng the 101 samples of E&P Tank runs and revised assu mptions pertaining to emission reductions from the Inventory. It also considered an additional phenomenon that contributes to tank venting beyond flashing emissions. The resu lts of several measurement studies have been compared to flashing emissions pr edicted by software models based on thermodynamic equilibrium equations. In some cases the measured emissions were substantially more than the thermodynamic equilibrium software predicted. One Natural Gas STAR Partner shared an anecdotal expe rience that sometimes separator dump valves are set improperly or stick open which will em pty all liquids plus high pressure gas from the separator directly to the stock tank. Another Gas STAR Pa rtner shared data with the program wherein they measured the largest emission from compressor stations was gas blow-by through stuck-open dump valves on co mpressor scrubbers. This gas vented to the atmosphere from the condensate tank.

The independent estimate estimated a range of tank emissions with just flashing as the base and flashing with blow-through as th e high end. It accomplished this in the following steps:

1. Estimate un-weighted flashing emissi on factors for hydrocarbon liquids 2. Estimate tank throughputs for a significant sample of U.S. production 3. Develop new weighted crude oil flashi ng emission factor based on significant sample of U.S. production 4. Develop new weighted conde nsate flashing emission f actor based on significant sample of U.S. production 5. Estimate potential uncontrolled emi ssions from U.S. storage tanks 6. Estimate regulated reductions from NESHAP and Alaska 7. Estimate voluntary reductions from VRU’s 8. Estimate potential effect of blow-thro ugh based on HARC and TCEQ studies.

1. Estimate Un-weighted Flashing Em ission Factors for Hydrocarbon Liquids This analysis used the raw data availabl e through the 101 E&P Ta nk sample runs to develop un-weighted average emission factor s for hydrocarbon liquids within narrow API gravity ranges. It broke the sample runs into ranges of 5  ̊ API, and then took the simple average of the flashing methane emission factor calculated fr om E&P Tank for all simulation runs in those ranges. The resu lts of this are pres ented in Exhibit 5-2.

Exhibit 5-2. Un-Weighted Flashing Met hane Emission Factors by API GravityAPI Gravity Range (  ̊ API) Flashing Methane Emission Factor (scf/bbl) Crude Oil
0 to 19 2.10
20 to 24 3.18
25 to 29 2.67
30 to 34 10.15
35 to 39 6.80
40 to 44 9.06 Condensate
45 to 49 6.62
50 to 54 45.57
55 to 59 106.73

≥ 60 101.89

In step (3) and step (4) these un-weighted em ission factors are applie d to a large sample of U.S. production data to develop new wei ghted EF’s for crude oil and condensate.

2. Estimate Tank Throughputs for a Si gnificant Sample of U.S. Production This analysis used data available in the La sser database on oil pr oduction from Texas, New Mexico, Mississippi, Louisiana, and part s of the Gulf of Mexico to determine a sample of tank throughputs. By production fi eld, the database provides the annual oil production for 2007, the well type (marginal or non-marginal), and the hydrocarbon liquid API gravity.

Using the Inventory assumption that all pr oduction from non-marginal wells and 20% of production from marginal wells pass through cr ude oil storage tanks, the amount of crude oil (hydrocarbons with API gravity less than 45  ̊ API) produced to storage tanks was calculated for each field.

Using the Inventory assumption that all c ondensate production passes through storage tanks, the amount of condensate (hydrocarbons with API gravity greater than or equal to 45  ̊ API) produced to storage tanks was calculated for each field.

3. Develop New Weighted Crude Oil Flas hing Emission Factor Based on Significant Sample of U.S. Production The associated un-weighted flashing meth ane emission factors from step (1) were mapped to each field by matching the fiel d’s average API gravity of produced hydrocarbon liquids with the API gravity ranges presented in Exhibit 5-2. The corresponding flashing methane emission fact or from step (1) was multiplied by the crude oil storage tank throughput calculated in step (2) to estimat e methane emissions from each oil production field in the database . The sum of these emissions was divided by the sum of all oil tank th roughputs to develop a new flas hing methane emission factor for crude oil weighted by a large sample of U.S. production data. This equation is displayed in Exhibit 5-3 below.Exhibit 5-3. Equation for Weighted Flashing Methane Emission Factor 

# ( )



# ∑ ∑ ×

=

i i i i i

oil 

### q q EF
EF

Where, EF oil = weighted flashing methane emission factor for crude oil (scf/bbl) i = index representing field “i” EF i = un-weighted methane emission factor for crude oil corresponding to field “i” (scf/bbl)
q i = throughput of tanks in field “i” (bbl)

The resulting weighted emission factor was 7.06 scf/bbl.

4. Develop New Weighted Condensate Flashi ng Emission Factor Based on Significant Sample of U.S. Production Similar to step (3) for crude oil, the asso ciated un-weighted flashing methane emission factors from step(1) were mapped to each field by matching the field’s average API gravity of produced hydrocarbon li quids with the API gravity ranges presented in Exhibit 5-2. The corresponding flashing methane emi ssion factor from step (1) was multiplied by the condensate storage tank throughput calcu lated in step (2) to estimate methane emissions from each gas and condensate produc tion field in the database. The sum of these emissions was divided by the sum of all condensate tank throughputs to develop a new flashing methane emission factor for cond ensate weighted by a large sample of U.S. production data. This equation is displayed in Exhibit 5-4 below.

Exhibit 5-4. Equation for Weighted Flashing Methane Emission Factor 

# ( ) 

# ∑ ∑ ×

=

i i i i i

condensate 

### q q EF
EF

Where, EF condensate = weighted flashing methane emission factor for condensate (scf/bbl) i = index representing field “i” EF i = un-weighted methane emission factor for crude oil corresponding to field “i” (scf/bbl)
q i = throughput of tanks in field “i” (bbl)

The resulting weighted emission factor was 71.02 scf/bbl.

5. Estimate Potential Uncontrolled Emissions from U.S. Storage Tanks The emissions from this sample set of data fr om Lasser were extrapolated to the U.S. by multiplying the weighted emission factors calc ulated in step (3) and step (4) to the corresponding oil tank throughput and condensat e tank throughputs for the entire U.S.

Crude oil tank throughput was estimated using EIA data for U.S. Crude Oil Production 1 in 2007 by state, less the 80% of strippe r well production calculated by the U.S. Inventory. This resulting crude oi l tank throughput was 1,585 MMbbl in 2007.Condensate tank throughput was estimated by using EIA data for Lease Condensate Proved Reserves and Production 2 in 2007 by state. At this point in the analysis no controls were assumed to be on the tanks since regulatory and voluntary reductions are later calculated in step (6) and step (7). The resulting condensa te throughput was 181 MMbbl in 2007.

Exhibit 5-5 summarizes the results as of this step in the analysis.

Exhibit 5-5. Summary of Results be fore Accounting for Reductions (2007)

Service Tank Throughput Emission Factor Emissions (uncontrolled) Crude Oil 1,585 MMbbl 7.06 scf/bbl 11 Bcf Condensate 181 MMbbl 71.02 scf/bbl 13 Bcf *NOTE: Voluntary and regulatory emission reductions have not been deducted from these totals.

6. Estimate Regulated Reductions from NESHAP and Alaska This analysis used the same methods as the U.S. Inventory to estimate emission reductions from the NESHAP regulation. The Inventory estimates and assumed the following:

• Estimated 66.18% of all emissions were impacted by NESHAP

• Estimated 88.89% of the throughput from those tanks is affected

• Assumed that 10% of the affected throughput will have emission flared

o Assumed flares have 98% combustion efficiency

• Assumed 90% of affected throughput will have vapor recovery

o Assumed that vapor recovery recovers 95% of emissions

It combined those estimates and assumpti ons into the equatio n in Exhibit 5-6:

Exhibit 5-6. NESHAP Emission Re ductions from Condensate Tanks (2007) 

## ( ) ( ) () ( ) 

# [ ] % 95 1 % 90 % 98 1 % 10 % 89

. 88 % 18

. 66 13 7

− × +

− × × × × = = Bcf Bcf R NESHAP

Thus, this analysis estimates that 7 Bcf of emissions from condensate tanks were reduced in 2007 due to the NESHAP regulation.

In addition to the NESHAP regulation fo r condensate tanks, Alaska has permitting regulations that require all crude oil storage tanks have emissions control. The total crude oil production in Alaska for 2007 was 527 MMbbl. If emissions from this production were mitigated, then 527 MMbbl multiplied by the crude oil uncontrolled emission factor, 7.06 scf/bbl, equals approxima tely 2 Bcf of emission reductions from crude oil tanks.

7. Estimate Voluntary Reductions from VRU’s Voluntary emission reduction by installing VRU’s on storage tanks were estimated using iSTAR summary reports on Natural Gas STAR Partner reported activities. For internal purposes, Natural Gas STAR implements a “sunsetting” policy. When an emissions reduction technology continually reduces emission, like a VRU, Natural Gas STAR onlygives credit for ten years to account for the no rmal cycle of technology improvement. For example, the data in the iSTAR reducti ons report for VRU’s stops crediting annual reductions after 10 years. In reality, these VRU’s are still functioning and continuing to reduce emissions from storage tanks. This an alysis removed the sunsetting effect from the iSTAR report.

When the NESHAP regulations were immine nt, it is believed that many companies implemented vapor recovery systems before the regulation began in preparation for it. At the initiation of the project, the reductions were voluntary, but after NESHAP went into effect in 1998, those emissions were no longe r voluntary. Thus, it was assumed that the emissions reductions from condensate stor age tanks due to NESHAP in 1998 would overlap with reported voluntary VRU projects prior to 1998. Th is analysis subtracted the 1998 NESHAP tank emission reductions from the un-sunsetted reduction data from Natural Gas STAR prior to 1998. The remain ing emissions reductions are from projects implemented before 1998 which were still voluntary in 2007.

Finally, this analysis removed sunsetting fr om the voluntary emission reductions after the start of NESHAP in 1998 to account for vol untary emission reductions from project that initiated after NESHAP (assuming they were applied to tanks not subject to the NESHAP).

The total voluntary emission reductions in 2007 are then the sum of voluntary reductions from projects that started after 1998 and curre ntly voluntary reductions from projects that started before 1998. These results are presented in Exhibit 5-7.

Exhibit 5-7. Voluntary Reductions of Storage Tank Emissions (2007) Category Annual Emissions Reductions VRU additions after NESHAP (sunsetting removed)* 14 Bcf
VRU projects before NESHAP (sunsetting removed)* + 6 Bcf
NESHAP initial year reductions** - 2 Bcf Total annual voluntary reductions (2007) 18 Bcf * Source: iSTAR **Source: U.S. Inventory

8. Estimate Potential Effect of Blow-through Steps (1) through (6) only estimate emissions due to flashing from hydrocarbon liquids; however, there is evidence that suggests in many cases high pressure gas from the separator either vortexes through the liquid drain and into the tank or the dump valves allow the liquids to em pty entirely and gas blows direc tly through to the tank. This analysis considered data from two meas urement studies, one conducted by Houston Advanced Research Center (HARC) 3 and another by Te xas Commission on Environmental Quality (TCEQ) 4

.

The studies measured tank emissions from a combined 69 crude oil and condensate storage tank batteries. The TCEQ study also compared its measured results to those obtained from other quantification methods – such E&P Tank. The HARC study did notprovide E&P Tank simulation results, so th is study performed a back-of-the-envelop calculation to make a comparison. It used the Vasquez-Beggs Equation on the data provided for the 36 batteries in TCEQ and determined the average ratio of E&P Tank results to Vasquez-Beggs results for the gas-oil ratio (GOR) of the flash emissions. It then performed the same Vasquez-Beggs corre lation to 32 of the 33 tank batteries in HARC and used the ratio to back-calculate an estimate of E&P Tank results. This analysis excluded one of the 33 data points because the HARC study states that a well was completed with the gas routed through the tank battery duri ng measurement; thus, highly skewing the results.

The average ratio of measured emissions to the E&P Tank simulated (or estimated) emissions was calculated separa tely for crude oil and condensate tanks. In some tank batteries, the simulation of flashing emissi ons corresponded reasonably well (within 100%) with the measured emissions. However, in 30 of the 68 accepted cases, or 44% of the cases, the measured emissions were much different; typically higher.

Since the proportion of tanks which experience some sort of blow -through or vortexing was not known and had not been studied, it was assumed that up to 44% of tanks in the U.S. also experience these incremental emi ssions in addition to flashing. Thus, the average ratio of measured emissions to si mulated flashing emissions for the entire population of 68 tank batteries was calculated for crude oil and condensate, then applied to the flashing emission estimates to provide an upper-bound of emissions. The resulting ratios of measured emissions to E&P Ta nk estimated flashing emissions was 2.17 for crude oil and 4.26 for condensate. This uppe r-bound was calculated using the equation in Exhibit 5-8.

Exhibit 5-8. Equation to Estimate Incremental Non-Flashing Emissions 

# ( ) ER R E E flash

upper 

### − × = Where, E upper = tank emissions upper-bound, includes flashing emissions and vortexing or blow-through E flash = uncontrolled emissions from flashing (Exhibit 5-5) R = average ratio of measured emissions to flashing emissions, 2.17 for oil and 4.26 for condensate ER = emission reductions from NESHAP, Alaska, and voluntary reductions (Exhibits 5-6, 5-7, and step (6))

Using the equation in Exhibit 5-8, the total upper-bound emissions from storage tanks in the U.S. was estimated to be 26 Bcf.

► Results The results of the analysis outlined in the st eps above are compared along side the results of the U.S. Inventory in Exhibit 5-9.Exhibit 5-9. Comparison of U.S. Inventory to Revised Analysis (2007)

U.S. Inventory Revised Analysis: Flashing Only Revised Analysis: Upper-bound Uncontrolled Methane Emissions 12 Bcf 24 Bcf 75 Bcf Regulatory Reductions 9 Bcf 35 Bcf Voluntary Reductions (Gas STAR) 4 Bcf 18 Bcf 14 Bcf

Total Estimated Methane Emissions 8 Bcf N/A 26 Bcf (11 MMTCO 2 e)

Note that the regulatory and voluntary reductions changed with method. In the case of the U.S. Inventory, the key assumption is that deducting Natural Gas STAR reported voluntary reductions would be double-counting; and thus, a very large portion of actual reported emission reductions ar e not considered. If these reductions were included, the inventory would yield nega tive total emissions.

In the case of the revised analysis for fl ashing emissions only, the conclusion is that flashing emissions alone do not fully desc ribe emissions from tanks. Regulatory reductions are scaled from the total estimated uncontrolled emissions from Alaskan crude and a proportion of emissions from condensat e tanks mitigated by NESHAP. Since these are scaled from the uncontrolled emission estimates; as those increase, so do the estimated regulatory reductions.

The revised analysis upper-bound captures incremental emissions beyond gas flashing out of a liquid hydrocarbon solu tion. It represents a case where high pressure gas from the separator is bypassing the separator dum p valve and being vented from the storage tank. As these uncontrolled emissions estimates greatly increase, so do the regulatory reductions because those emissions must be ca ptured or flared. Vo luntary reduction from Natural Gas STAR; however, are less than the revised analysis’ estimates. This is unintuitive, but the emission re ductions due to the first ye ar of NESHAP increase to much larger than the annual reductions fr om Natural Gas STAR prior to NESHAP’s enactment. It is assumed that all such re ductions stopped being voluntary once NESHAP came into effect and are capture d under regulatory reductions.

1 EIA. U.S. Crude Oil Production . Annual data for 2007. Available online at <http://tonto.eia.doe.gov/dnav/pet/pet_crd_crpdn_adc_mbbl _a.htm>. Revised data as of June 29, 2009.

2 EIA. Lease Condensate Proved Reserves and Production . Annual data for 2007. Available online at: <http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/histori cal/2007/cr2007.html>. Revised data as of February 10, 2009.
3 HARC. VOC Emissions from Oil and Condensate Storage Tanks . October 31, 2006.

4 TCEQ. Upstream Oil and Gas Storage Tank Project Flash Emissions Model Evaluation . July 16, 2009.