Lessons Learned 

from Natural Gas STAR Partners 

Reduced Emissions Completions 

Method for 

Reducing 

Natural Gas 

Losses 

Volume of 

Natural Gas 

Savings 

(Mcf) 

Value of Natural Gas Savings ($) 

Additional 

Savings 

($) 

Implementation Cost 

($) 

Other 

Costs ($) Payback (Months) 

Purchased 

REC 

Equipment 

Annual 

Program 

270,000 per 

year 

$3 per Mcf $5 per Mcf $7 per Mcf $175,000 

per year $500,000 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

$810,000 

per year 

$1,350,000 

per year 

$1,890,000 

per year 

6 4 3 

Incremental 

REC 

Contracted 

Service 

10,800 per 

completion 

$3 per Mcf $5 per Mcf $7 per Mcf 

$6,930 per 

completion $32,400 $600 per completion 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

$32,400 per 

completion 

$54,000 per 

completion 

$75,600 per 

completion 

Immediate Immediate Immediate 

General Assumptions: 

a Assuming 9 days per completion, 1,200 Mcf gas savings per day per well, 11 barrels of condensate recovered per day per well, and cost of $3,600 per well per day for contracted services. b Assuming $70 per barrel of condensate. 

c Based on an annual REC program of 25 completions per year. 

$121,250 

per year 

Economic and Environmental Benefits 

Executive Summary 

In recent years, the natural gas industry has developed 

more technologically challenging unconventional gas

reserves such as tight sands, shale and coalbed methane. 

Completion of new wells and re-working (workover) of 

existing wells in these tight formations typically involve 

hydraulic fracturing of the reservoir to increase well 

productivity. Industry reports that hydraulic fracturing is 

beginning to be performed in some conventional gas

reservoirs as well. Removing the water and excess 

proppant (generally sand) during completion and well 

clean-up may result in significant releases of natural gas 

and therefore methane emissions to the atmosphere. The 

U.S. Inventory of Greenhouse Gas Emissions and Sinks 

1990 - 2009 estimates that 68 billion cubic feet (Bcf) of 

methane are vented or flared annually from 

unconventional completions and workovers. 

Reduced emissions completions (RECs) – also known as

reduced flaring completions or green completions – is a 

term used to describe an alternate practice that captures 

gas produced during well completions and well workovers

following hydraulic fracturing. Portable equipment is

brought on site to separate the gas from the solids and 

liquids produced during the high-rate flowback, and 

produce gas that can be delivered into the sales pipeline.

RECs help to reduce methane, VOC, and HAP emissions

during well cleanup and can eliminate or significantly

reduce the need for flaring. 

RECs have become a popular practice among Natural Gas

STAR production partners. A total of thirteen different 

partners have reported performing reduced emissions 

completions in their operations. RECs have become a 

major source of methane emission reductions since 2000.

Between 2000 and 2009 emissions reductions from RECs 

(as reported to Natural Gas STAR) have increased from

200 MMcf (million cubic feet) to over 218,000 MMcf. 

Capturing an additional 218,000 MMcf represents 

additional revenue from natural gas sales of over $1.5

billion from 2000 to 2009 (assuming $7/Mcf gas prices). 

Technology Background 

High demand and higher prices for natural gas in the U.S.

have resulted in increased drilling of new wells in more

expensive and more technologically challenging

unconventional gas reservoirs, including those in low 

porosity (tight) formations. These same high demands and 

1 
Reduced Emissions Completions

(Cont’d) 

prices also justify extra efforts to stimulate production 

from existing wells in tight reservoirs where the down-hole 

pressure and gas production rates have declined, a process 

known as well workovers or well-reworking. In both cases,

completions of new wells in tight formations and 

workovers of existing wells, one technique for improving 

gas production is to fracture the reservoir rock with very 

high pressure water containing a proppant (generally 

sand) that keeps the fractures “propped open” after water

pressure is reduced. Depending on the depth of the well,

this process is carried out in several stages, usually

completing one 200- to 250-foot zone per stage. 

These new and “workover” wells are completed by

producing the fluids at a high rate to lift the excess sand to 

the surface and clear the well bore and formation to 

increase gas flow. Typically, the gas/liquid separator

installed for normal well flow is not designed for these 

high liquid flow rates and three-phase (gas, liquid and 

sand) flow. Therefore, a common practice for this initial 

well completion step has been to produce the well to a pit

or tanks where water, hydrocarbon liquids and sand are 

captured and slugs of gas vented to the atmosphere or 

flared. Completions can take anywhere from one day to 

several weeks during which time a substantial amount of 

gas may be released to the atmosphere or flared. Testing of 

production levels occurs during the well completion 

process, and it may be necessary to repeat the fracture 

process to achieve desired production levels from a 

particular well. 

Natural gas lost during well completion and testing can be

as much as 25 million cubic feet (MMcf) per well depending 

on well production rates, the number of zones completed,

and the amount of time it takes to complete each zone. 

This gas is generally unprocessed and may contain volatile

organic compounds (VOCs) and hazardous air pollutants 

(HAPs) along with methane. Flaring gas may eliminate 

most methane, VOC and HAP emissions, but open flaring 

is not always a preferred option when the well is located 

near residential areas or where there is a high risk of 

grass or forest fires. Moreover, flaring may release

additional carbon dioxide and other criteria pollutants 

(SOx, NOx, PM and CO) to the atmosphere. 

Natural Gas STAR partners have reported performing

RECs that recover much of the gas that is normally vented

or flared during the completion process. This involves 

installing portable equipment that is specially designed 

and sized for the initial high rate of water, sand, and gas 

flowback during well completion. The objective is to 

capture and deliver gas to the sales line rather than

venting or flaring this gas. 

Sand traps are used to remove the finer solids present in

the production stream. Plug catchers are used to remove

any large solids such as drill cuttings that could damage

the other separation equipment. The piping configuration 

to the sand traps is critical as the abrasion from high

velocity water and sand can erode a hole in steel pipe

elbows, creating a “washout” with water, sand, 

Exhibit 1: Reduced Emissions Completion Equipment Layout 

Adapted from BP. 

2 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Reduced Emissions Completions

(Cont’d) 

hydrocarbon liquids and gas in an uncontrolled flow to the 

pad. Depending on the gas gathering system, it may be

necessary to dehydrate (remove water from) the produced

gas before it enters the sales pipeline. The gas may be 

routed to the permanent glycol unit for dehydration or a

portable desiccant/glycol dehydrator used for dehydration

during the completion process. 

Free water and condensate are removed from the gas in a 

three phase separator. Condensate (liquid hydrocarbons)

collected during the completion process may be sold for

additional revenue. Temporary piping may be used to 

connect the well to the REC skid and gathering system if

the permanent piping is not yet in place. Exhibit 1 shows a

typical layout of temporary REC portable equipment, and 

Energized Fracturing

Based on Natural Gas STAR partner experiences, RECs

can also be performed in combination with energized

fracturing, wherein inert gas such as CO2 or nitrogen is

mixed with the frac water under high pressure to aid in

the process of fracturing the formation. The process is

generally the same with the additional consideration of

the composition of the flowback gas. The percent of inert

gases in the flowback gas is, at first, unsuitable for

delivery into the sales line. As the fraction of inerts

decreases, the gas can be recovered economically. A

portable membrane acid gas separation unit can further 

increase the amount of methane recovered for sales after a 

CO2 energized fracture. 

Compression 

Two compressor applications during an REC have been

identified or explored by Natural Gas STAR partners. 

1) Gas Lift. In low pressure (i.e. low energy) reservoirs

RECs are often carried out with the aid of compressors for 

gas lift. Gas lift is accomplished by withdrawing gas from

the sales line, boosting its pressure, and routing it down

the well casing to push the frac fluids up the tubing. The 

increased pressure facilitates flow into the separator and

then the sales line where the lift gas becomes part of the 

normal flowback that can be recovered during an REC. 

2) Boost to Sales Line. When the gas recovered in the 

REC separator is lower pressure than the sales line, some

companies are experimenting with a compressor to boost

flowback gas into the sales line. This technique is

experimental because of the difficulty operating a

compressor on widely fluctuating flowback rate. Coal bed

methane well completion is an example where additional

compression might be required. 

Exhibit 2: Alternate Completion Procedures 

Exhibit 2 explains some alternate, emerging, and/or 

experimental procedures for a well completion and REC. 

The equipment used during RECs is only necessary for the 

time it takes to complete the well; therefore, it is essential

that all the equipment can be readily transported from site 

to site to be used in a number of well completions. A truck

mounted skid, as shown in Exhibit 3, is ideal for 

transporting the equipment between sites. In a large basin

that has a high level of drilling activity it may be economic

for a gas producer to build its own REC skid. Most 

producers may prefer contracting a third party service to

perform completions. 

When using a third party to perform RECs, it is most cost 

effective to integrate the scheduling of completions with 

the annual drilling program. Well completion time is 

another factor to consider for scheduling a contractor for

RECs. Some well completions, such as coal bed methane, 

may take less than a day. On the other hand, completing

wells which fracture various zones, such as shale gas

wells, may take several weeks to complete. For most wells, 

it takes about 3 to 10 days to perform a well completion

following a hydraulic fracture, based on partner 

experiences. 

Exhibit 3: Truck Mounted Reduced Emissions 

Completion Equipment 

Source: Weatherford 

Economic and Environmental Benefits 

 Gas recovered for sales 

 Condensate recovered for sales 

 Reduced methane emissions 

3 
 

 

 

Reduced Emissions Completions

(Cont’d) 

 Reduced loss of a valuable hydrocarbon resource 

 Reduced emissions of criteria and hazardous air 

pollutants 

Emissions from well completions can contribute to a 

number of environmental problems. Direct venting of

VOCs can contribute to local air pollution, HAPs are

deemed harmful to human health, and methane is a 

powerful greenhouse gas that contributes to climate 

change. Where it is safe, flaring is preferred to direct 

venting because methane, VOCs, and HAPs are 

combusted, lowering pollution levels and reducing global 

warming potential (GWP) of the emissions as CO2 from 

combustion has a lower GWP than methane. RECs allow 

for recovery of gas rather than venting or flaring and

therefore reduce the environmental impact of well 

completion and workover activities. 

RECs bring economic benefits as well as environmental

benefits. The incremental costs associated with the rental 

of third party equipment for performing RECs can be offset 

by the additional revenue from the sale of gas and 

condensate. As this technology is being perfected and

equipment becomes commonplace, the revenues in gas and 

condensate sales often exceed the incremental costs. 

Decision Process 

Step 1: Evaluate candidate wells for Reduced 

Emissions Completions. 

When setting up an annual RECs program it is important 

to examine the characteristics of the wells that are going to

be brought online in the coming year. Wells in 

conventional reservoirs that do not require a reservoir 

fracture (frac job) and will produce readily without 

stimulation can be cleared of drilling fluids and connected 

to a production line in a relatively short period of time

with minimal gas venting or 

flaring, and therefore usually 

do not economically justify Decision Process 

Step 1: Evaluate candidate wells REC equipment. Wells that Step 2: Determine costs undergo energized fracture Step 3: Estimate savings 

using inert gases require Step 4: Evaluate economics 

special considerations because 

the initial produced gas

captured by the REC equipment would not meet pipeline 

specifications due to the inert gas content. However, as 

the amount of inerts decreases, the quality of the gas will

likely meet pipeline specifications. In the case of CO2 

energized fracks, the use of portable acid gas removal 

membrane separators will improve gas quality and make it

possible to direct gas to the pipeline (see Case Studies 

section for more information). 

State and Local Regulations 

The States of Wyoming and Colorado have regulations requiring the 

implementation of “flareless completions”. Operators of new wells in this 

region are required to complete wells without flaring or venting. These 

completions have reduced flaring by 70 to 90 percent. 

For more information, visit: 

http://deq.state.wy.us 

http://www.cdphe.state.co.us 

Exploratory and delineation wells in areas that do not yet

have sales pipelines in close proximity to the wells are not 

candidates for RECs as the infrastructure is not in place to 

receive the recovered gas. In depleted or low pressure

fields with low energy reservoirs, implementing a RECs 

program would most likely require the addition of 

compression to overcome the sales line pressures–an 

approach that is still under development and may add

significant cost to implementation. 

Wells that require hydraulic fracturing to stimulate or 

enhance gas production may need a lengthy completion,

and therefore are good candidates for RECs. Lengthy

completions mean that a significant amount of gas may be

vented or flared that 

could potentially be 

Selecting a Basis for Costs and recovered and sold for 

Savings additional revenue to 

 Estimate the number of justify the additional cost producing gas wells that will of a REC. If newly drilled be drilled in the next year wells are in close 

proximity, they could  Evaluate well depth and 

reservoir characteristics share the REC equipment

to minimize transport, set  Determine whether 

-up, and equipment additional equipment is 

necessary to bring recovered rental costs. gas up to pipeline

specifications 

 Estimate time needed for 

each completion Step 2: Determine the 

costs of a REC program. 

Most Natural Gas STAR partners report using third party 

contractors to perform RECs on wells within their 

producing fields. It should be noted that third party 

contractors are also often used to perform traditional well

completions. Therefore, the economics presented deal with 

4 
 

 

 

Reduced Emissions Completions

(Cont’d) 

incremental costs to carry out RECs versus traditional

completions. 

Generally, the third party contractor will charge a

commissioning fee for transporting and setting up the 

equipment for each well completion within the operator’s 

producing field. Some RECs vendors have their equipment 

mounted on a single trailer while others lay down

individual skids that must be connected with temporary 

piping at each site. The incremental cost associated with

transportation between well sites in the operator’s field 

and connection of the REC equipment within the normal

flowback piping from the wellhead to an impoundment or 

tank is generally around $600/completion. 

In addition to the commissioning fee, there is a daily cost

for equipment rental and labor to perform each REC. As

mentioned above, when evaluating the costs of well 

completions, it is important to consider the incremental

cost of a REC over a traditional completion rather than

focusing on the total cost. REC vendors and Natural Gas

STAR partners have reported the incremental cost of 

equipment rental and labor to recover natural gas during 

completion ranging from $700 to $6,500/day over a

traditional completion. Equipment costs associated with 

RECs will vary from well to well. High production rates 

may require larger equipment to perform the REC and will

increase costs. If permanent equipment such as a glycol 

dehydrator is already installed at the well site, REC costs 

may be reduced as this equipment can be used rather than

bringing a portable dehydrator on-site, assuming the flowback rate does not exceed the capacity of the equipment.

Some operators report installing permanent equipment

that can be used in the RECs as part of normal well 

completion operations, such as oversized three-phase 

separators, further reducing incremental REC costs. Well

completions usually take between 1 to 30 days to clean out

the well bore, complete well testing, and tie into the 

permanent sales line. Wells requiring multiple fractures of

a tight formation to stimulate gas flow may require 

additional completion time. Exhibit 4 shows the typical

costs associated with undertaking a REC at a single well. 

For low energy reservoirs, gas from the sales line may be 

routed down the well casing to create artificial gas lift, as 

Exhibit 4: Typical Costs for RECs 

One-time 

Transportation and 

Incremental Set-up 

Costs 

Incremental REC 

Equipment Rental and 

Labor Costs 

Well Clean-up 

Time 

$600 per well $700 to $6,500 per day 3 to 10 days 

mentioned in Exhibit 2. Depending on the depth of the 

well, a different quantity of gas will be required to lift the

fluids and clean out the well. Using average reservoir

depths for major U.S. basins and engineering calculations, 

Exhibit 5 shows various estimates of the volume of gas 

required to lift fluids for different well depths. 

A REC annual program may consist of completing 25

wells/year within a producer’s operating region. Exhibit 6 

shows a hypothetical example of REC program costs based 

on information provided by partner companies. 

Exhibit 5: Sizing and Fuel Consumption for Booster Compressor 

Well Depth (ft) Pressure Required to Lift Fluids 

(psig) 

Gas Required to 

Lift Fluids (Mcf)a 

Compressor Size 

(horsepower)a 

3,000 1,319 + Sales line pressure 195 to 310 195 to 780 

5,000 2,323 + Sales line pressure 315 to 430 400 to 1,500 

8,000 3,716 + Sales line pressure 495 to 610 765 to 2,800 

10,000 4,645 + Sales line pressure 615 to 730 1,040 to 3,900 

a Based on sales line pressures between 100 to 1,000 psig. 

Compressor Fuel 

Consumption 

(Mcf/hr)a 

2 to 7 

3 to 13 

7 to 24 

9 to 33 

5 
 

 

 

 

 

 

Reduced Emissions Completions

(Cont’d) 

Exhibit 6: Hypothetical Example Cost Calculation of a 25 Well Annual REC Program 

Given 

W = Number of completions per year 

D = Well depth in feet (ft) 

Ps = Sales line pressure in pounds per square inch gauge (psig) 

Ts = Time required for transportation and set-up (days/well) 

Tc = Time required for well clean-up (days/well) 

O = Operating time for compressor to lift fluids (hr/well) 

F = Compressor fuel consumption rate (Mcf/hr) 

G = Gas from pipeline routed to casing to lift fluids (Mcf/well), typically used on low energy reservoirs 

Cs = Transportation and set-up cost ($/well) 

Ce = Equipment and labor cost ($/day) 

Pg = Sales line gas price ($/Mcf) 

W = 25 wells/yr 

D = 8000 ft 

Ps = 100 psig 

Ts = 1 day/well 

Tc = 9 days/well 

O = 24 hr/well 

F = 10 Mcf/hr 

G = 500 Mcf/well (See Exhibit 4) 

Cs = $600/well 

Ce = $2,000/day 

Pg = $7/Mcf 

Calculate Total Transportation and Set-up Cost, CTS 

CTS = W * Cs 

CTS = 25 wells/yr * $600/well 

CTS = $15,000/yr 

Calculate Total Equipment Rental and Labor Cost, CEL 

CEL = W * (Ts + Tc) * Ce 

CEL = 25 wells/yr * (1 day/well + 9 days/well) * $2,000/day 

CEL = $500,000/yr 

Calculate Other Costs, CO 

CO = W * [(O * F) + G] * Pg 

CO = 25 wells/yr * [( 24 hr/well * 10 Mcf/hr) + 500 Mcf/well] * $7/Mcf 

CO = $129,500/yr 

Total Annual REC Program Cost, CT 

CT = CTS + CEL + CO 

CT = $15,000/yr + $500,000/yr + $129,500/yr 

CT = $644,500/yr 

6 
 

 

Reduced Emissions Completions

(Cont’d) 

Step 3: Estimate Savings from RECs. 

Gas recovered from RECs can vary widely because the

amount of gas recovered depends on a number of variables

such as reservoir pressure, production rate, amount of

fluids lifted, and total completion time. Exhibit 7 shows 

the range of recovered gas and condensate reported by

Natural Gas STAR partners. Partners also have reported 

that not all the gas that is produced during well 

completions may be captured for sales. Fluids from high 

pressure wells are often routed directly to the frac tank in 

the initial stages of completion as the fluids are often being

produced at a rate that is too high for the REC equipment. 

Where inert gas is used to energize the frac, the initial gas

production may have to be flared until the gas meets

pipeline specifications. Alternatively, a portable acid gas

membrane separator may be used to recover methane rich

gas from CO2. As the flow rate of fluids drops and gas is 

encountered, backflow is then switched over to the REC 

equipment so that the gas may be captured. Gas 

compressed from the sales line to lift fluids (by artificial 

gas lift) will also be recovered in addition to the gas 

produced from the reservoir. The volume of gas needed to

lift fluids can be estimated based on the well depth and

sales line pressure. Gas saved during RECs can be 

translated directly into methane emissions reductions 

based on the methane content of the produced gas. 

In addition to gas savings, valuable condensate may also

be recovered from the REC three-phase separator. The 

amount of condensate that can be recovered during a REC

is dependent on the reservoir conditions and fluid 

compositions. Condensate may also be lost if fluids are 

produced directly to the frac tank before switching to the 

REC equipment. 

Exhibit 7: Ranges of Gas and Condensate Savings 

Produced Gas 

Savings 

(Mcf/day/well) 

Gas-Lift Savings 

(Mcf/well) 

Condensate 

Savings 

(bbl/day/well) 

500 to 2,000 See Exhibit 4 Zero to several 

hundred 

Exhibit 8 shows typical values of gas and condensate 

savings during the REC process. 

Step 4: Evaluate REC economics. 

The example application of an REC program to 25 wells

within a producing field can yield a total theoretical

revenue of $2,152,500 based on the assumptions listed 

above from the sale of natural gas and condensate.

Equipment rental, labor, and other costs associated with 

implementing this program are estimated to be $644,500 

(see Exhibit 5) resulting in an annual theoretical profit of 

$1,508,000. To maintain a profitable REC program, it is

important to move efficiently from well to well within a 

producing field so that there is little down time when 

paying for equipment rental and labor. Other factors that

affect the profitability of an REC program include the 

amount of condensate recovery and sales price, the need

for additional compressors, the amount of gas recovered,

and gas sales price. 

Exhibit 9 shows a five year cash flow projection for 

carrying out a 25 well per year REC program. In this

example, the equipment necessary to perform RECs has 

been purchased by the operator rather than using a third 

party contractor to perform the service. The capital cost of 

a simple REC set-up without a portable compressor has 

been reported by British Petroleum (BP) to be $500,000. 

Producers with high levels of localized drilling and

workover activity may benefit from constructing and 

operating their own REC equipment. As illustrated above,

even though large capital outlay is required to construct a

REC skid, a high rate of return can be achieved if the 

equipment is in continuous use. If the operator is unable to

keep the equipment busy on their own wells, they may

contract it out to other operators to maximize usage of the 

equipment. 

7 
 

 

 

 

 

Reduced Emissions Completions

(Cont’d) 

Given 

W = Number of completions per year 

D = Well depth in feet (ft) 

Ps = Sales line pressure in pounds per square inch gage (psig) 

Sp = Produced gas savings (Mcf/day) 

Tc = Time recovered gas flows to sales line in days (days/well) 

Sc = Condensate savings (bbl/well) 

G = Gas used to lift fluids (Mcf/well), typically used on low energy reservoirs 

Pg = Sales line gas price ($/Mcf) 

Pl = Natural gas liquids price ($/bbl) 

W = 25 wells/yr 

D = 8000 ft 

Ps = 100 psig 

Sp = 1,200 Mcf/day 

Tc = 9 days/well 

Sc = 100 bbl/well 

G = 500 Mcf/well (See Exhibit 4) 

Pg = $7/Mcf 

Pl = $70/bbl 

Calculate Produced Gas Savings 

SPG = W * (Sp * Tc) * Pg 

SPG = 25 wells/yr * (1,200 Mcf/day * 9 days/well) * $7/Mcf 

SPG = $1,890,000/yr 

Calculate Other Savings 

SO = W * [(G * Pg) + (Sc * Pl)] 

SO = 25 wells/yr * [(500 Mcf/well * $7/Mcf) + (100 bbl/well * $70/bbl)] 

SO = $262,500/yr 

Total Savings, ST 

ST = SPG + SO 

ST = $1,890,000/yr + $262,500/yr 

ST = $2,152,500/yr 

Exhibit 8: Savings of a 25 Well Annual REC Program 

8 
 

 

 

Reduced Emissions Completions

(Cont’d) 

When assessing REC economics, the gas price may economic analysis of performing the 25 well per year REC

influence the decision making process; therefore, it is program in Exhibit 8 at different gas prices. 

important to examine the economics of undertaking a REC 

program as natural gas prices change. Exhibit 10 shows an 

Exhibit 9: Economics for Hypothetical 25 Well Annual REC Program with Purchased Equipment 

Year 0 Year 1 Year 2 Year 3 Year 4 Year 5 

Volume of Natural Gas Savings 

(Mcf/yr)a 270,000 270,000 270,000 270,000 270,000 

Value of Natural Gas Savings 

($/year)a 1,890,000 1,890,000 1,890,000 1,890,000 1,890,000 

Additional Savings ($/yr)a 175,000 175,000 175,000 175,000 175,000 

Set-up Costs ($/yr)b (15,000) (15,000) (15,000) (15,000) (15,000) 

Equipment Costs ($)b (500,000) 

Net Annual Cash Flow ($) (500,000) 1,943,750 1,943,750 1,943,750 1,943,750 1,943,750 

Internal Rate of Return = 389% 

NPV (Net Present Value)d

= $6,243,947 

Payback Period = 3 months 

a See Exhibit 7. 

b See Exhibit 5. 

c Labor costs for purchased REC equipment estimated as 50% of Equipment Rental and Labor costs in Exhibit 3. 

d Net present value based on 10% discount rate over five years. 

Labor Costs ($/yr)c (106,250) (106,250) (106,250) (106,250) (106,250) 

Exhibit 10: Gas Price Impact on Economic Analysis of Hypothetical 25 Well Annual REC Program with 

Purchased Equipment 

$3/Mcf $5/Mcf $7/Mcf $8/Mcf $10/Mcf 

Total Savings $985,000 $1,525,000 $2,065,000 $2,335,000 $2,875,000 

Payback (months) 7 5 4 3 3 

IRR 172% 280% 389% 443% 551% 

NPV 

(i = 10%) $2,522,084 $4,383,015 $6,243,947 $7,174,413 $9,035,345 

Gas Price 

9 
Reduced Emissions Completions

(Cont’d) 

Partner Experience 

This section highlights specific experiences reported by Natural Gas STAR partners. 

BP Experience in Green River Basin 

 Implemented RECs in the Green River Basin of Wyoming 

 RECs performed on 106 wells, which consisted of high and low pressure wells 

 Average 3,300 Mcf of natural gas sold versus vented per well 

– Well pressure will vary from reservoir to reservoir 

– Reductions will vary for each particular region 

– Conservative net value of gas saved is $20,000 per well 

 Natural gas emission reductions of 350,000 Mcf in 2002 

 Total of 6,700 barrels of condensate recovered per year total for 106 wells 

 Through the end of 2005, this partner reports a total of 4.17 Bcf of gas and more than 53,000 barrels of condensate

recovered and sold rather than flared. This is a combination of activities in the Wamsutter and Jonah/Pinedale 

fields. 

Noble Experience in Ellis County, Oklahoma 

 Implemented RECs on 10 wells using energized fracturing.
 

 Employed membrane separation in which the permeate was a CO2 rich stream that was vented and the residue was 

primarily hydrocarbons which were recovered. 

 Total cost of $325,000. 

 Total gas savings of approximately 175 MMcf. 

 Estimated net profits to be $340,000 

 For more information, see the Partner Profile Article in the Spring 2011 Natural Gas STAR Partner Update 

available at: http://epa.gov/gasstar/newsroom/partnerupdatespring2011.html 

Partner Company A 

 Implemented RECs in the Fort Worth Basin of Texas 

 RECs performed on 30 wells, with an incremental cost of $8,700 per well 

 Average 11,900 Mcf of natural gas sold versus vented per well 

– Natural gas flow and sales occur 9 days out of 2 to 3 weeks of well completion 

– Low pressure gas sent to gas plant 

– Conservative net value of gas saved is $50,000 per well 

 Expects total emission reduction of 1.5 to 2 Bcf in 2005 for 30 wells 

10 
 

 

Reduced Emissions Completions

(Cont’d) 

Lessons Learned 

 Incremental costs of recovering natural gas and 

condensate during well completions following 

hydraulic fracturing result from the use of additional

equipment such as sand traps, separators, portable 

compressors, membrane acid gas removal units and

desiccant dehydrators that are designed for high rate 

flowback. 

 During the hydraulic fracture completion process,

sands, liquids, and gases produced from the well are

separated and collected individually. Natural gas and 

gas liquids captured during the completion may be 

sold for additional revenue. 

 Implementing a REC program will reduce flaring

which may be a particular advantage where open 

flaring is undesirable (populated areas) or unsafe 

(risk of fire). 

 Wells that do not require hydraulic fracturing are not

good candidates for reduced emissions completions. 

Methane emissions reductions achieved through 

performing RECs may be reported to the Natural Gas

STAR Program unless RECs are required by law (as 

in the Jonah-Pinedale area in WY). 

References 

Alberts, Jerry. Williams Company. Personal contact. 

American Petroleum Institute. Basic Petroleum Data Book, Volume XXV,
 

Number 1. February 2005. 

Bylin, Carey. U.S. EPA. Gas STAR Program Manager 

Department of Energy. GASIS, Gas Information System. Release 2 – 

June 1999. 

Fernandez, Roger. U.S. EPA. Gas STAR Program Manager 

McAllister, E.W., Pipeline Rules of Thumb Handbook, 4th Edition, 1998. 

Middleman, Stanley. An Introduction to Fluid Dynamics, Principles of 

Analysis and Design. 1998. 

Perry, Robert H., Don W. Green. Perry’s Chemical Engineers Handbook, 

7th Edition. 1997. 

Pontiff, Mike. Newfield Exploration Company. Personal contact. 

Process Associates of America. “Reciprocating Compressor Sizing.” 

Available on the web at: http://www.processassociates.com/process/ 

rotating/recip_s.htm. 

Smith, Reid. BP PLC. Personal contact. 

Smuin, Bobby. BRECO, Incorporated. Personal contact. 

U.S. EPA. “The Natural Gas STAR Partner Update – Spring 2004.” 

Available on the web at: http://www.epa.gov/gasstar/pdf/ 

partnerupdate.pdf 

Wadas, Janelle. Noble Energy Inc. 2010 Annual Implementation Workshop 

Presentation titled “Reducing Vented Flowback Emissions from CO2 

Fractured Gas Wells Using Membrane Technology”. Available on the 

web at: http://epa.gov/gasstar/documents/workshops/2010-annualconf/01wadas.pdf 

Waltzer, Suzanne. U.S. EPA. Gas STAR Program Manager 

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