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transcript
Gas Well Deliquification Workshop
Sheraton Hotel, Denver, Colorado
February 20 – 22, 2017
Bill Elmer, P.E.
Encline Artificial Lift Technologies LLC
High Pressure Continuous Gas Circulation: A solution for the Pressure Dependent Permeability of the Haynesville Shale?
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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What is PDP?
Pressure Dependent Permeability caused by:
• Stress dependent permeability
• Proppant embedment
• Proppant crushing
• ?
Results in severe productivity loss
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Where is this PDP observed?
Documented in the Haynesville Shale by SPE papers:
• SPE 147623: Estimated Ultimate Recovery as a Function
of Production Practices in the Haynesville Shale,
Mangha et al, 2011
• SPE 166152: Diagnosing Pressure-Dependent-
Permeability in Long-Term Shale Gas Pressure and
Production Transient Analysis, Vera & Ehlig-
Economides, 2013
• SPE 178722: Integrated Haynesville Production
Analysis, Hao et al, 2015
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Normal deliquification practices hurt shales with PDP
Haynesville wells produce salty water and lean gas
• Normally flow at high rate on initial completion into
1000 psi gathering system
• Exhibit liquid loading when rates fall to 1000 to 1200
MCFPD up 2-7/8” tubing, as expected with salty water
• Normal practice of reducing tubing pressure to restore
critical flowrate causes further permeability reduction
– Also exacerbates salt formation problems, fuel intensive
• Liquid loading occurs again within 12 months as rate
falls below 400 MCFPD
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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CGC - “CO” Operating Mode This slide and next two are courtesy of Jim Hacksma, industry’s CGC expert – “CO” = Circulate Only
– Does Not Reduce FTP
When Should “CO” Mode Be Used?
• When LP Is Already Relatively Low
OR..
• When Little Production Is Gained By Reducing FTP
This is the Haynesville Shale, due to PDP
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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CGC “EXAMPLE” (Courtesy Jim Hacksma, modified for Haynesville Shale)
• Well Capable Of Only 100 MCFD Sales
• Critical Rate Is 1000 MCFD (loading problem)
• Design Compressor To Circulate 1000 MCFD
• Total Flow Up Tubing Is 1100 MCFD
• Now Above Critical – Carries Out Liquids
• If Sales Decline To “0”, Still Carries Liquids
• Thus, A Permanent Solution
Separator
Compressor
Sales Meter
Motor
Valve
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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SAME RATE UP TUBING – SAME FBHP
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Is CGC a better way to solve loading issues than reducing pressure?
For a reservoir with PDP like the Haynesville, with
repeatedly demonstrated productivity decreases as
FBHP is lowered, most certainly.
The real question is: What is the minimum FBHP target
desired to minimize the impact of PDP
What do the three SPE papers say about this?
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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SPE 147623 Conclusion - 2011
“ For reservoirs which are significantly overpressured as
in the case of the Haynesville Shale, it should be kept in
mind that permeability would likely decrease as a
function of reservoir pressure. Higher drawdown would
cause higher effective stress fields, which would
decrease productivity. Under these circumstances,
controlling or better managing drawdown could be a
solution to prevent severe production loss.”
• Paper did give pressure drawdown guidelines
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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SPE 166152 Conclusions- 2013
• Made point that PDP is best diagnosed with pressure
buildup transient tests
• Suggested using permanent downhole pressure gauge
or casing pressure data during shut-ins
• Attributed productivity losses to both hydraulic fracture
and shale effective permeability reductions
• Paper did give pressure drawdown guidelines
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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SPE 178722 - 2015
• Paper reviewed multiple models used to predict EUR’s
• Concluded that permanent downhole pressure gauges
and PLT were needed for Pressure Transient Analysis
and Rate Transient Analysis
• Never offered insight into how to mitigate PDP
“ It is evident that pressure depletion is confined mostly to
the fractures and does not extend deep within the
formation, as would be expected in a tight shale system. It
indicates the strong geomechanical effects and low
permeability are the dominant production mechanisms
that prevent the unstimulated volume from producing
effectively.”
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Operators left to trial and error to manage drawdown versus productivity
It is very important to realize that low FBHP does not equal
low BHP in the formation
• Low FBHP not seen by formation, as fracture permeability
and formation permeability reduced
• Conventional gas well deliquification logic does not apply
– BHP reductions normally access more reserves, not less
– PDP is the reason why
– Necessary to maintain high FBHP’s for many years
– Blowing well down could reduce reserves by multiple BCF
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Is CGC a better way to solve loading issues than reducing pressure?
It should be, as CGC simply keeps velocity up the tubing
at critical rate, regardless of the pressure
• Will show that High Pressure CGC uses far less
Horsepower than lowering line pressure
• Offers a permanent solution for liquid loading, not a
twelve month solution
• Saturated gas injection should reduce salt problems
• Offers method to transport corrosion and scale
chemicals, and fresh water downhole
• Due to low velocities, can be performed down
concentric tubing instead of tubing-casing annulus
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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How high is the pressure requirement?
Production data from the Haynesville showed that 1600 -
1700 psi casing pressure with 1000 psi tubing pressure
common prior to loading at critical rate of 1000 MCFPD
• High pressure CGC would require compressing gas
from 1000 psi up to 1700 psi, which is only 1.7
compression ratios
• Simple single stage compressor job, no gas cooler
required
• Low horsepower lends itself to running off single phase
grid electricity
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Won’t this high casing pressure keep the bottom hole pressure elevated?
Yes, we are counting on this to prevent loss of
permeability and reserves!
• Haynesville initial reservoir pressures above 10000 psi
• Can PDP be mitigated by keeping FBHP above
– 5000 psi ?
– 4000 psi ?
– 3000 psi ?
– 2000 psi ?
– 1700 psi ?
• Don’t know the answer, just that CGC can do this today
• Will give use 1700 psi as an example
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Horsepower Comparison
Turning loaded up well into lower pressure pipeline is
common place, but requires 130 HP per MMSCFD
• Two stage compression normally costs 10 to 20 cents
per MCF
• All produced gas is compressed reducing reserves by
2.38% for fuel associated with 130 HP per MMSCFD
High Pressure CGC, only the circulated gas is compressed
• Circulated gas only requires 35 HP per MMSCFD
• Single stage compressor, especially electric, is simple
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Compressor Design for 1700 psi
Heading
• Point 1
• Point 2
• Point 3
• Point 4
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Fuel Use as a percentage of Well Rate
Only when rate falls below 300 MCFPD does fuel use with
CGC exceed lower wellhead pressure fuel use of 2.38%
However, the lower pressure well loads up at 400 MCFPD
Well Rate Injection Rate Total Rate Fuel at
0.672%
Fuel as a
percentage of
Well Rate
700 MCFPD 500 MCFPD 1200 MCFPD 3.36 MCFPD 0.48%
600 600 1200 4.03 0.67%
500 700 1200 4.70 0.94%
400 800 1200 5.38 1.35%
300 900 1200 6.05 2.02%
200 1000 1200 6.72 3.36%
100 1000 1100 7.39 7.39%
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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How much Horsepower required for CGC with no well contribution?
These numbers are based on the assumption of 700 psi of
friction and fluid gradient across the tubing
Casing
Pressure
Tubing
Pressure
Compress
Ratios
HP/ MM Coleman
Critical rate
HP
Required
1000 300 3.23 75 0.490 MM 36.8
1700 1000 1.7 35 0.894 MM 31.3
2700 2000 1.35 22.5 1.258 MM 30.3
3700 3000 1.23 17 1.497 MM 25.5
4700 4000 1.18 12 1.647 MM 19.8
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Compressor Design for High Pressure
CGC at high pressures up to 4700 psi is possible because:
• Production casing no longer rated to 2000 psi, but 10000
• Advent of CNG caused development of high pressure
compressor cylinders (just need to build compressors)
• Since HP requirements are so low with CGC (< 50 HP),
reliable electric power is ideal
– VFD technology can convert readily available single phase
power to three phase power at negligible cost
– VFD can change compressor speed to deliver exactly critical
flow from the well, no more (causing friction) or no less (causing
loading)
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Conclusions
• Pressure Dependent Permeability that is present in the
Haynesville Shale requires that we dispense with
previous ideas on using lower pressure to maintain
critical velocity
• Since Haynesville operators attempt to avoid huge
productivity losses (and drastically lower EUR’s) by
maintaining higher FBHP’s, High Pressure CGC offers
the ability to permanently solve liquid loading issues
without endangering completion competency
• High Pressure CGC will require building compressors
that are not currently available for rent
Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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Feb. 20 - 22, 2017 2017 Gas Well Deliquification Workshop
Denver, Colorado
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