Page 1 of 8 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON, D.C. 20460

OFFICE OF AIR AND RADIATION

Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule Docket: EPA-HQ-OAR-2009-0923

Title: Change to Equation W-7: Time to Vent Gas

Summary: The purpose of this analysis is to appropriately account for the duration of time required for wells to expel the natural ga s contained within the casing at shut-in pressure, so that the prescribed monitoring methodology under §98.233(f) does not double count emissions during that period.Page 2 of 8 Change to Rule Equation W-7: Time to Vent Gas from We ll Liquids Unloading

The purpose of this analysis is to appropria tely account for the dur ation of time required for wells to expel the natural gas contained w ithin the casing at shut -in pressure, so that the prescribed monitoring methodol ogy under §98.233(f) does not double count emissions during that period. Additionally, it develops appropriate engineering equations to be used for wells equipped with plunger lif ts and the time to expel the natural gas contained in the tubing above the plunger lift.

Background
In mature gas wells, the accumulation of fluids in the well tubing can impede and eventually halt gas production. On e barrel of water will stand 260 feet in a 2 inch inside diameter tubing, exerting 130 psi back pressure in addition to the sales line pressure on the reservoir. Hence a few barrels of water can choke a well flow alt ogether. As the water accumulates in the tubing, and the back pressu re increases, gas flow into the well from the reservoir slows and reservoir pressure at th e well perforations rises, eventually to near shut-in pressure when accumulated liquids vi rtually stop gas flow. The well casing at this point will be pressured up to near shut-in pressure, just the same as if the well were shutin at the well head. Some operators remove accumulated fluids through the use of a beam pump or remedial treatments, such as swabbing, soaping, or venting the well to atmospheric pressure (referred to as “blo wing down” the well). This latter method, blowing wells to the atmosphere, while least expensive, expels larg e volumes of natural gas and methane to the atmosphere. This is a common practice 1 . However, one Natural Gas STAR Partner company 2 reported a study of the effec tiveness of this well “blow down” technique for removing accumulated water. They found that the practice expelled a low amount of the accumulated water. Th is is because the water “plates-out” on the tubing walls and allows the gas to bypass it. After blowing off the high pressure (shut-in pressure) bubble of gas in the well casing, the well returns to normal flowing velocity which allows the water to drains back down the tubing.

The most effective period for expelling liqui ds is the maximum gas flow up the tubing. This will occur when the sales line is shut-i n and the high-pressure bubble of gas in the casing is vented to atmospheric back pressu re. The volume of this gas can be estimated by the well depth, shut-in pressure and casing inside diameter. This is the method in subpart W, § 98.233 Calculating GHG emissions, section (f) equation W-7 alternative to metering the well venting flow, as described in the Natural Gas STAR Lessons Learned study on plunger lifts 3

. Some operators may allow their wells to vent to atmosphere longer than necessary to expell this casing gas bubble, which is anal gous to producing the well to the atmosphere. This may be conservatively approximated by th e sales flow rate. Total emissions from the well blowdown can be approximated by the su m of the volume of natural gas contained

1 http://epa.gov/gasstar/documents/workshops/2008-tech-transfer/denver3.pdf
2 http://www.epa.gov/gasstar /documents/desaulniers.pdf
3 http://www.epa.gov/gasstar/d ocuments/ll_plungerlift.pdfPage 3 of 8 within the well casing at shut-in pressure and the additional volume of gas that is produced to the atmosphere after the casing vo lume is expelled but before the vent is closed so that the gas is produced to the sales line. Equation W-7 in Section §98.233(f) of the proposed rule accounted for the time ope rators may leave their wells producing to the atmosphere, which commenters correc tly pointed out could double account for the time the casing gas is vented down to producti on pressure. Therefor e the time of venting needed to be adjusted for the time to blow down the higher pressure casing gas.
Commenters also correctly pointed out that the proposed equation did not account for the much more efficient liquids unloading using a plunger lift. The plunger acts like a swab or “pig” to use the higher pressure gas accumu lated in the casing to efficiently push the plunger and liquid column up the tubing, minimi zing liquid flow back on the tubing walls and gas bypass of the liquid column. Whether with a mechanical timer, “smart automation” programmable logic controlled timer or manual venting, a plunger lift properly operated will vent considerably less gas to the atmosphere: minimally the tubing volume at sales line pressure. As with we ll blowdown without a pl unger lift, if the well is left open longer than the time it takes the pl unger to rise to the wellhead, excessive gas will vent to the atmosphere. Although this gas flowrate will be higher than normal production rate, a conservative estimate of the gas flow, not requiring measurement or simulation, would be the averag e sales flow rate. Then the time of venting needs to be adjusted for the amount of time it takes to push the plunger from the bottom catcher to the wellhead. Plunger operation is tuned to a maximum plunger velocity to avoid damage to the plunger catcher at the well head. Ther efore, the minimum time to vent the tubing gas from a well with a plunger lift is dete rmined by the recommended speed of the plunger traveling up the well tubing.

Method – Liquid Unloading Wihout a Plunger Lift
The time for a well to blowdown its casing vo lume without a plunger lift was estimated by dividing the volume of the casing gas, V c , from Equation 1 below, into increments and calculating the pressure in the casing as each increment of volume flowed up the tubing string, summing the time increments until the casing pressure dropped to normal flowing pressure (approximated by sales line pressure). The flow rate of gas up the tubing string was estimated using the Weymouth equati on from the Pipeline Rules of Thumb Handbook 4 . This analysis ignores the gas vented from the tubing string above the liquid in the tubing because relative to the gas in the casing it is negligible. The volume of the gas inside the well casing is ca lculated in Equation 1 below.


# ( )

s c c 

## LP D V 2 3 

## 10 37

. 0
− 

## × = Equation 1

where,

4 Pipe Line Rules of Thumb Handbook , Fourth Edition, Gulf Publishing Company, Houston, Texas, 1998.Page 4 of 8 V

c = volume of the well casing gas at shut-in pressure, cubic feet 0.37×10 -3 = {pi(3.14)/4}/{(14.7*144) psia conver ted to pounds per square feet} P s = Shut-in pressure (psig). D c = inner diameter of the well cas ing, assumed to average 5 inches L = well depth, feet

The Weymouth formula, shown below, is used to calculated the flow rate of gas through a pipeline and assumes the gas is at 60 degr ees Farenheit and has a specific gravity of 0.60. For the purposes of this analysis it wa s assumed that the Weymouth formula would provide an adequate approximation.



## 24 871 2 2 2
1 3 / 8



## × − × ×

= L P P D Q Equation 2

where,

Q = cubic feet of gas per hour D = inner diameter of the pipeline, inches P 1 = inlet pressure (psig) P 2 = outlet pressure (psig) L = well depth, miles 871 = constant 24 = hours per day

The flow rate of gas from the casing thr ough the tubing is mostly dependent on the well depth, casing diameter, and the pressure grad ient as the column of liquid moves up and out of the well.

As the casing gas is vented, the well casing pressure decreases, approaching the well’s down hole normal production pressure. The decrem ented casing pressures can be used to estimate the increments of casing volume as gas flows up the tubing to the atmosphere. To calculate the total time needed to ve nt the casing gas during a well blowdown, the pressure drop from shut-in pressure, P s , to normal flowing pressure, assumed to be the sales line pressure, P SL , was divided into ten interv als for which the flow rate, Q , was calculated using Equation 2 above. The volume of gas in the well casi ng at each interval decreases from the total casing ga s volume at shut-in pressure, V c , proportionately with the pressure of the cas ing at each interval, P i . The difference in the casing gas volume between interval i and the previous interval, i- 1, is the volume of ga s vented during that interval, V i . This is shown below in Equations 3 and 4.Page 5 of 8 

## n P P P P SL s i i 

## −

− =

− 1 , s 

## P P =

0 Equation 3


# ( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− =

− = 

# ∑

1 1 

## 1

i i i

v v i c i 

## P P V V V Equation 4

where,

P i = the casing pressure at each interval n , pounds per square inch P i-1 = the casing pressure at the previous interval before P i P 0 = the initial casing pressure, equal to the shut-in pressure, pounds per square inch P s = Shut-in pressure, pounds per square inch P SL = sales line pressure, poun ds per square inch V

i = the volume of casing ga s vented per interval i , cubic feet V

c = volume of the well casing gas at shut-in pressure, cubic feet see Equation 1

n = the total number of intervals; selected 10 for this analysis i = the current interval

The casing gas vented at each interval, V i , was divided by the calculated flow rate at each interval to give the venting time for that in terval. Although some of the standing liquid is unloaded at the surface, most of it is a ssumed to remains along the tubing wall. Therefore, an eighth-inch was subtracted fr om the average 2-inch tubing diameter to estimate the flow rate, Q . The sum of the venting times fr om each interval gives the total time to vent the entire casing. This summation is shown below in Equation 5.



# ∑ ∑

=

= 

## − = = n

i A i T i n

i i 

## P P D L V
t t

1 2 2 3 8 1 

## 871 5280 24 Equation 5

where,

t = Hours needed to vent the entire casing volume

t i = Hours needed to vent V i

n = the total number of intervals; selected 10 for this analysis D T = inner diameter of the well tubing adjusted for an 1/8 inch of water running along the tubing wall, assumed to be 1.875 inches P i = the casing pressure at each interval n , pounds per square inch P

A = atmospheric pressure, 14.7 pounds per square inch L

= well depth, feet 871 = constant 24 = hours per dayPage 6 of 8 5280 = feet per mile

Method – Liquid Unloading With a Plunger Lift

EPA’s expert opinion is that pl unger lifts are operated such th at the plunger travels at no faster than 700 feet per minute to avoid damaging the well head. The time to vent the tubing gas with a plunger lift is dependent on the speed of the pl unger traveling up the well tubing. The speed of the plunger depends on the amount of liquids accumulated above the plunger, shut-in pressure of th e well, and the well depth. Operators are assumed to use historical well unloading expe rience to determine the plunger travel time, and from that the travel velocity, and from these the time increment between well venting. Smart Automation timers use this in formation, along with casing pressure and sales line back pressure to optim ize the plunger launch frequency.

Results – Without Plunger Lifts

Equation 5 above was solved for shut-in pr essures ranging from 300 to 1,000 psia at well depths of 12,000, 6,000, and 2,000 feet. The HPDI database, which collects well information from states, indicates that in the U.S. the average well depth is 6,000 feet with a maximum around 12,000 feet and a mi nimum around 2,000 feet. The results for each permutation of well depth and shut-in pressure is displayed in the Figure 1.

Figure 1. Time to vent the casing gas at shut-in pressures ranging from 300 psi to 1000 psi at well depths of 12,000 feet, 6,000 feet, and 2,000 feet.

Time for Well Liquids Unloading

0 200 400 600 800 1000 1200

‐ 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80

Time to Vent (hours)Shut‐InPressure(psi) 12000 feet 6000 feet 2000 feet

The average well depth of 6,000 feet with a cas ing of 5 inches requi res an average of 0.5 hours to unload its liquids. The maximum, 12,000- foot well, with a 5-inch casing requiresPage 7 of 8 about 1.25 hours to unload its liquids. The minimum, 2,000-foot well, with a 5-inch casing requires about 0.1 hours to unload it s liquids. One hour was selected as a conservative estimate for the amount of time a well without a plunger lift would take to vent its casing gas. Since the well flow rate to the atmosphere will approach average sales flow, to the extent that this venting time is too short or too long will only result in that difference being accounted for at average sales flow rate.

Equation W-7 in Section §98.233(f)(ii) of the Final Subpart W Rule was adjusted using this estimate to avoid double counting vented emissions from well liquids unloading at the sales production rate. The adju sted equation is shown below.

E s,n = {(0.37×10 -3 )*CD 2 *WD*SP*N v }+{SFR*(HR-1.0)*Z} (Eq. W-8)

where:

E s,n = Annual natural gas emissions at standard conditions, in cubic feet/year. 0.37×10 -3 = {pi(3.14)/4}/{(14.7*144) psia conver ted to pounds per square feet} CD = Casing diameter (inches). WD = Well depth (feet). SP = Shut-in pressure (psig). N v = Number of vents per year. V = Number of vents per year. SFR = Sales flow rate of gas well in cubic feet per hour. HR = Hours that the well was left ope n to the atmosphere during unloading. 1 = Hours for average well to blowdown casing volume. Z = If HR is less than 1.0 then Z is equal to 0, otherwise Z is equal to 1.

Results – With Plunger Lifts

This analysis assumes plungers travel on av erage 700 feet per minute up the tubing based on EPA’s expert information. For wells with depths of 12,000, 6,000, and 2,000 feet it would take 20, 10, and 3 minutes respectively for the plunger to reach the surface and vent the tubing gas. Because the plunger ma ximum velocity is an upper limit, and EPA assumes operators will deviate on the safe side (lower velocity) the rule assumes half an hour as a conservative estimate for the time to vent the tubing gas above the plunger. If the well is left open to the atmosphere longer, it is assumed that the well is venting at the sales flow rate, which is also very conserva tive given the casing pr essure would be near shut-in pressure during mo st of the excess venting.
Equation W-8 in Section §98.233(f) of the Fina l Subpart W Rule was added to account for these wells separately while avoiding double counting vented emissions from well liquids unloading at the sale s production rate. The additiona l equation is shown below.

E a,n = {(0.37×10 -3 )*TD 2 *WD*SP*N v }+{SFR*(HR-0.5)*Z} (Eq. W-9) where:Page 8 of 8 E a,n = Annual natural gas emissions at act ual conditions, in cubic feet/year. 0.37×10 -3 = {3.14 (pi)/4}/(14.7*144) psia conver ted to pounds per square feet TD = Tubing diameter (inches). WD = Tubing depth (feet). SP = Sales line pressure (psia). N v = Number of vents per year. V = Number of vents per year. SFR = Average sales flow rate of gas well in cubic feet per hour. HR = Hours that the well was left ope n to the atmosphere during unloading. 0.5 = Hours for average well to blowdown tubing volume. Z = If HR is less than 0.5 then Z is equal to 0. If HR is greater than or equal to 0.5 then Z is equal to 1.