# Lessons Learned

from Natural Gas STAR Partners



# Reduced Emissions Completions for Hydraulically Fractured Natural Gas Wells

Executive Summary

In recent years, the natural gas industry has developed more technologically chal lenging 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. Removi ng 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 completion s (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 delive red 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 pe rforming 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

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)

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

Mcf $5 per

Mcf $7 per

Mcf

Purchased

REC Equipment

Annual Program 270,000 per

year $175,000

per year $500,000 $121,250

per year $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 $32,400 per completion $54,000 per completion $75,600 per completion $6,930 per completion $32,400 $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 re covered per day per well, an d 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. 

### Economic and Environmental Benefits

1

# Reduced Emissions Completions
(Cont’d)

prices also justify extra effo rts 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. Dependin g 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 ve nted 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 necessa ry 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 fe et (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) an d hazardous air pollutants (HAPs) along with methane. Flaring gas may eliminate most methane, VOC and HAP em issions, 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. Mo reover, 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 sa les 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 CO 2 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
CO 2 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 we ll; 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 CO 2 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 work over 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 wi ll 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 CO 2 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 Partner Experiences section fo r 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 infr astructure 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 th e 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 br ing 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 transp orting 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 incre mental 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. Equipm ent 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 installe d 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 ta ke 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.



### 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

For low energy reservoirs, gas from the sales line may be routed down the well casing to create artificial gas lift, as 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)

P

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

T

s = Time required for transpor tation and set-up (days/well)

T

c = 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

C

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

C

e = Equipment and labor cost ($/day)

P g = Sales line gas price ($/Mcf)

W = 25 wells/yr

D = 8000 ft

P

s = 100 psig

T

s = 1 day/well

T

c = 9 days/well

O = 24 hr/well

F = 10 Mcf/hr G = 500 Mcf/well (See Exhibit 5)

C

s = $600/well

C

e = $2,000/day

P g = $7/Mcf

Calculate Total Transportation and Set-up Cost, C TS

C TS = W * C

s

C TS = 25 wells/yr * $600/well

C TS = $15,000/yr

Calculate Total Equipment Rental and Labor Cost, C EL

C EL = W * (T

s + T

c ) * C

e

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

C EL = $500,000/yr

Calculate Other Costs, C O

C O = W * [(O * F) + G] * P g

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

C O = $129,500/yr

Total Annual REC Program Cost, C T

C T = C TS + C EL + C O C T = $15,000/yr + $500,000/yr + $129,500/yr

C T = $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 depe nds 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 fo r 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 ener gize 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 us ed to recover methane rich gas from CO 2 . 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 sa ved 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 reserv oir conditions and fluid



### Nelson Price Indexes

In order to account for inflation in equipment and operating & maintenance costs, Nelson-Farrar Quarterly Cost Indexes (avail able in the first issue of each quarter in the Oil and Gas Journal ) are used to update costs in the Lessons Learned documents.

The “Refinery Operation Index” is used to revise operating costs while the “Machinery: Oilfield Itemized Refining Cost Index” is used to update equipment

costs.

To use these indexes in the future, simply look up the most current Nelson-Farrar index number, divide by the February 2006 Nelson-Farrar index number, and, finally multiply by the appropriate costs in the Lessons
Learned. 

### 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 5 Zero to several

hundred

compositions. Condensate may al so be lost if fluids are produced directly to the frac tank before switching to the REC equipment.

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 6) resulting in an annual theoretical profit of $1,508,000. To maintain a profitable REC program, it is important to move ef ficiently from well to well within a producing field so that there is little down time when paying for equipment rental an d 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 withou t 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 retu rn 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

7

# Reduced Emissions Completions
(Cont’d)

Given W = Number of completions per year D = Well depth in feet (ft)

P

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

S p = Produced gas savings (Mcf/day)

T

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

S

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

P g = Sales line gas price ($/Mcf)

P l = Natural gas liquids price ($/bbl)

W = 25 wells/yr

D = 8000 ft

P

s = 100 psig

S p = 1,200 Mcf/day

T

c = 9 days/well

S

c = 100 bbl/well G = 500 Mcf/well (See Exhibit 5)

P g = $7/Mcf

P l = $70/bbl

Calculate Produced Gas Savings

S PG = W * (S p * T

c ) * P g

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

S PG = $1,890,000/yr

Calculate Other Savings

S O = W * [(G * P g ) + (S

c * P l )]

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

S O = $262,500/yr

Total Savings, S T

S T = S PG + S O S T = $1,890,000/yr + $262,500/yr

S T = $2,152,500/yr 

### Exhibit 8: Savings of a 25 Well Annual REC Program

8

# Reduced Emissions Completions
(Cont’d)

contract it out to other operators to maximize usage of the important to examine the economics of undertaking a REC equipment. program as natural gas prices change. Exhibit 10 shows an economic analysis of performing the 25 well per year REC When assessing REC economics, the gas price may program in Exhibit 8 at different gas prices. influence the decision making process; therefore, it is



### 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 8.

b See Exhibit 6.

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 experien ces 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 cons isted 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 combin ation of activities in the Wamsutter and Jo nah/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 CO 2 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 Partne r Profile Article in the Spring 20 11 Natural Gas STAR Partner Update

available at: http://epa.gov/gasstar/n ewsroom/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 reduce d emissions completions. Methane emissions reductions achieved through performing RECs may be re ported 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, 4 th

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,

7

th

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 Vent ed Flowback Emissions from CO2 Fractured Gas Wells Using Membrane Technology”. Available on the
web at: http://epa.gov/gasstar/documents/workshops/2010-annual

conf/01wadas.pd f

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

11

# Reduced Emissions Completions
(Cont’d)

United States Environmental Protection Agency Air and Radiation (6202J) 1200 Pennsylvania Ave., NW Washington, DC 20460

2011

EPA provides the suggested methane em issions estimating methods contained in this do cument as a tool to develop basic methane e missions estimates only. As regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in t his document may not conform to the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations.

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