Lessons Learned
from Natural Gas STAR Partners
A
NaturalGasfX
EP* KKLUTION PREVENTER '
Reduced Emissions Completions
Executive Summary
High prices and high demand for natural gas have
provided incentive for the natural gas production industry
to develop more technologically challenging (and therefore
more expensive) 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 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 - 2010
estimates that 68 billion cubic feet (Bcf) of methane are
vented or flared 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 $7/Mcf gas prices).
Technology Background
High demand and higher prices for natural gas in the U.S.
have resulted in increased drilling of new wells in more
(Continued on page 2)
Economic and Environmental Benefits
Method for
Reducing
Natural Gas
Losses
Purchased
REC
Equipment
Annual
Program
Volumeof Additional Implemen-
aura as Value of Natural Gas Savings ($) Savings tation Cost
(Mcf)
$3 per Mcf
270,000 per
Vear $810,000
per year
$5 per Mcf
$1,350,000
per year
W W
$7 per Mcf
$175,000 $50Q OOQ
$1,890,000 per year
per year
CostsTs) Payback (Months)
$3 per
$121,250 Mcf
6
$5 per
Mcf
4
$7 per
Mcf
3
Incremental
REC
Contracted
Service
10,800 per
completion
$3 per Mcf $5 per Mcf $7 per Mcf
$32,400 per $54,000 per $75,600 per
completion completion completion
$6,930 per
completion
$32,400
$600 per
completion
$3 per
Mcf
Imme-
diate
$5 per
Mcf
Imme-
diate
General Assumptions:
'" 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.
$7 per
Mcf
Imme-
diate
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Reduced Emissions Completions
(Cont'd)
(Continued from page 1)
expensive and more technologically challenging
unconventional gas reservoirs, including those in low
porosity (tight) formations. These same high demands and
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
(Continued on page 3)
Exhibit 1: Reduced Emissions Completion Equipment Layout
To Dehydrator
or Sales Line
Sand Trap
Wellhead
Reserve Impoundment or Tanks
Adapted from BP.
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Reduced Emissions Completions
(Cont'd)
(Continued from page 2)
velocity water and sand can erode a hole in steel pipe
elbows, creating a "washout" with water, sand,
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
Exhibit 2: Alternate Completion Procedures
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
expelling frac water from pores in the fractured 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, it may be possible to recover the gas
economically. A portable membrane acid gas separation
unit can further increase the amount of methane
recovered for sales after a CC>2 energized fracture.
Compression.
In low pressure (i.e. low energy) reservoirs RECs are often
carried out with the aid of compressors to gas lift the
water column up the tubing string and/or boost the gas
recovered in the REG separator into the sales line. Gas lift
is accomplished by withdrawing gas from the sales line to
route down the well casing and push the frac fluids up the
tubing. This gas becomes part of the normal flowback that
can be recovered during an REG.
When the gas recovered in the REG 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.
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
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
Exhibit 3: Truck Mounted Reduced Emissions
Completion Equipment
Source: Weatherford
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 and is large
enough to carry all the necessary equipment. In a large
basin that has a high level of drilling activity it may be
economic for a gas producer to build their 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.
(Continued on page 4)
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Reduced Emissions Completions
(Cont'd)
(Continued from page 3)
Economic and Environmental Benefits
* Gas recovered for sales
* Condensate recovered for sales
* Reduced methane emissions
* Reduced loss of a valuable hydrocarbon resource
through venting and flaring of gas
* 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 C02 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.
Reduced emissions completions 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
Step 2: Determine costs
Step 3: Estimate savings
Step 4: Evaluate economics
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 REG equipment. Wells that
undergo energized fracture using inert gases require
special considerations because the initial produced gas
State and Local Regulations
The States of Wyoming and Colorado have regulations requiring the
kimplementation 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/
captured by the REG equipment would not meet pipeline
specifications due to the inert gas content. However, as
the amount of inerts decreases, the quality of the gas
might be sufficient to meet pipeline specifications. In the
case of C02 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).
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.
Selecting a Basis for Costs and
Savings
* Estimate the number of
• producing gas wells that will
be drilled in the next year
Evaluate well depth and
reservoir characteristics
Determine whether
additional equipment is
necessary to bring recovered
gas up to pipeline
specifications
Estimate time needed for
each completion
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 recovered and
sold for additional revenue to justify the additional cost of
a REG. If newly drilled wells are in close proximity, they
(Continued on page 5)
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Reduced Emissions Completions
(Cont'd)
(Continued from page 4)
could share the REG equipment to minimize transport, set-
up, and equipment rental costs.
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
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
REC's 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 flow-
back rate does not exceed the capacity of the equipment.
Exhibit 4:
One-time
Transportation and
Incremental Set-up
Costs
$600 per well
Typical Costs for
Incremental REC
Equipment Rental and
Labor Costs
$700 to $6,500 per day
RECs
Well Clean-up
Time
3 to 10 days
Some operators report installing equipment that can be
used in the RECs as a normal part of wellhead equipment,
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
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
(Continued on page 7)
Exhibit 5: Sizing and Fuel
•.I M n u /•« Pressure Required to Lift Fluids
• well Depth (ft) . . .
3,000
5,000
8,000
10,000
a Based on sales line pressures between
1,319 + Sales line pressure
2,323 + Sales line pressure
3,716 + Sales line pressure
4,645 + Sales line pressure
100 — 1,000 psig.
Consumption for Booster Compressor
Gas Required to
Lift Fluids (Mcf)a
195-310
315-430
495 — 610
615 — 730
Compressor Size
(horsepower)3
195 — 780
400 — 1,500
765 - 2,800
1,040 — 3,900
Compressor Fuel
Consumption
(Mcf/hr)a
2-7
3-13
7-24
9 — 33
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Reduced Emissions Completions
(Cont'd)
Exhibit 6: 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 = 8000ft
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
Ps = $7/Mcf
Calculate Total Transportation and Set-up Cost - CTs
CTS = W*CS
ds = 25 wells/yr * $600/well
CTS=$15,000/yr
Calculate Total Equipment Rental and Labor Cost - CEL
CEL = W * (Ts + T0) * Ce
CEL = 25 wells/yr * (1 day/well + 9 days/well) * $2,000/day
CEL = $500,000/yr
Calculate Other Costs - C0
C0 = W * [(O * F) + G] * Pg
C0 = 25 wells/yr * [( 24 hr/well * 10 Mcf/hr) + 500 Mcf/well] * $7/Mcf
C0 = $129,500/yr
Total Annual REC Program Cost - CT
CT = $15,000/yr + $500,000/yr + $129,500/yr
CT = $644,500/yr
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Reduced Emissions Completions
(Cont'd)
(Continued from page 5)
depths for major US basins and engineering calculations,
Exhibit 5 shows various estimates of the volume of gas
required to lift fluids for different well depths.
A REG annual program may consist of completing 25
wells/year within a producer's operating region. Exhibit 6
shows an estimate of typical REG program costs.
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 REG 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 C02. 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 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.
Nelson Price Indexes
In order to account for inflation in equipment and operating & maintenance
costs, Nelson-Farrar Quarterly Cost Indexes (available 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 that by the February 2011 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)
500 to 2,000
Gas-Lift Savings
(Mcf/well)
See Exhibit 4
Condensate
Savings
(bbl/day/well)
Zero to several
hundred
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 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 only
$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 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 $500,000.
(Continued on page 9)
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Reduced Emissions Completions
(Cont'd)
Exhibit 8: Savings of a 25 Well Annual REC Program
Given:
W = Number of completions per year
D = Well depth in feet (ft)
PS = Sales line pressure in pounds per square inch gage (psig)
Sp = Produced gas savings (Mcf/day)
Tc = Time recovered gas flows to sales line in days (days/well)
Sc = Condensate savings (bbl/well)
G = Gas used to lift fluids (Mcf/well), typically used on low energy reservoirs
Pg = Sales line gas price ($/Mcf)
PI = Natural gas liquids price ($/bbl)
W = 25 wells/yr
D = 8000ft
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
PI = $70/bbl
Calculate Produced Gas Savings
SPG = W * (Sp * T0) * Pg
SPG = 25 wells/yr * (1,200 Mcf/day * 9 days/well) * $7/Mcf
SpG = $l,890,000/yr
Calculate Other Savings
S0 = W * [(G * Pg) + (So * Pi)]
S0 = 25 wells/yr * [(500 Mcf/well * $7/Mcf) + (100 bbl/well * $70/bbl)]
S0 = $262,500/yr
Total Savings - ST
ST = SPG + So
ST = $l,890,000/yr + $262,500/yr
ST = $2,152,500/yr
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Reduced Emissions Completions
(Cont'd)
(Continued from page 7)
Purchasing a REG set-up will eliminate equipment rental
costs and leave labor and transportation as the only
operating costs for the duration of the program. The
economics for this example are quite favorable and feature
a very high net present value and rate of return.
Producers with high levels of localized drilling and
workover activity may benefit from constructing and
operating their own REG equipment. As illustrated above,
even though large capital outlay is required to construct a
REG 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.
When assessing REG economics, the gas price may
influence the decision making process; therefore, it is
important to examine the economics of undertaking a REG
(Continued on page 10)
Exhibit 10: Gas Price Impact on Economic Analysis of Hypothetical 25 Well Annual REC Program with
Purchased Equipment
1 Gas Price |
Total Savings
Payback (months)
IRR
r™,
$3/Mcf
$985,000
7
172%
$2,522,084
$5/Mcf
$1,525,000
5
280%
$4,383,015
$7/Mcf
$2,065,000
4
389%
$6,243,947
$8/Mcf
$2,335,000
3
443%
$7,174,413
$10/Mcf
$2,875,000
3
551%
$9,035,345
Exhibit 9: Economics for Hypothetical 25 Well Annual REC Program with Purchased Equipment
IYear 0 Year 1
Volume of Natural Gas Savings ,7n mn
(Mcf/yr)a ^/u,uuu
Value of Natural Gas Savings 1 SQn nnn
($/year)a i,asu,uuu
Additional Savings ($/yr)a 175,000
Set-up Costs ($/yr)b (15,000)
Equipment Costs ($)b (500,000)
Labor Costs ($/yr)c (106,250)
(Net Annual Cash Flow ($) (500,000) 1,943,750
a See Exhibit 7.
"See Exhibit 5.
c Labor costs for purchased REC equipment estimated as 50% of Equipment
d Net present value based on 10% discount rate over five years.
Year 2 Year 3
270,000 270,000
1,890,000 1,890,000
175,000 175,000
(15,000) (15,000)
(106,250) (106,250)
1,943,750 1,943,750
Year 4
270,000
1,890,000
175,000
(15,000)
(106,250)
1,943,750
YearS
270,000
1,890,000
175,000
(15,000)
(106,250)
1,943,750
Internal Rate of Return = 389%
NPV (Net Present Value)d= $6,243,947
Payback Period = 3 months
Rental and Labor costs in Exhibit 3.
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Reduced Emissions Completions
(Cont'd)
(Continued from page 9)
program as natural gas prices change. Exhibit 10 shows an
economic analysis of performing the 25 well per year REG
program in Exhibit 8 at different gas prices.
Partner Experience
This section highlights specific experiences reported by
Natural Gas STAR Partners.
(Continued on page 11)
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
Partner Company B
Implemented RECs in the Jonah/Pinedale Fields in
Wyoming
RECs performed on 242 wells, which included
energized hydraulic fracturing using C02 and N2 at
an average cost of $110,000 per REG.
Average 119,000 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 $500,000 per
well
From 2001 to 2006, recovered 29 Bcf of gas from
the wells in these fields.
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 CCh rich stream that was vented
and the residue was primarily hydrocarbons
which were recovered.
Total cost of $325,000.
Total gas savings of 170 MMcf.
Estimated net profits to be $340,000
For more information, see the Partner Profile
Article in the Spring 2011 Natural Gas STAR
Partner Updated available at:
http://epa.gov/gasstar/newsroom/
partnerupdatespring2011.html
10
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Reduced Emissions Completions
(Cont'd)
(Continued from page 10)
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 REG 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.
REG can be used with portable membrane acid gas
separators for COz energized fractures.
* 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 C02
Fractured Gas Wells Using Membrane Technology". Available on the
web at: http://epa.gov/gasstar/documents/workshops/2010-annual-
conf/01wadas.pdf
Waltzer, Suzanne. U.S. EPA. Gas STAR Program Manager
Appendix
11
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