high pressure continuous gas circulation: pressure...

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

2

What is PDP?

Pressure Dependent Permeability caused by:

• Stress dependent permeability

• Proppant embedment

• Proppant crushing

• ?

Results in severe productivity loss


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


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


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


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


Denver, Colorado

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SAME RATE UP TUBING – SAME FBHP


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?


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


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


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.”


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


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


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


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


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


Denver, Colorado

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Compressor Design for 1700 psi

Heading

• Point 1

• Point 2

• Point 3

• Point 4


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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%


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


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)


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


Denver, Colorado

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