production and operational issues
TRANSCRIPT
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PRODUCTION AND OPERATIONAL ISSUES
Dr. Ebrahim FathiPetroleum and Natural Gas Engineering DepartmentWest Virginia University Audience and Date
March 2, 2016
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Summary• Production and Operational Issues
– Shale gas reservoir production is highly rely on efficiency of hydraulic fracturing treatment and optimum operational conditions
– Deficiencies in planning and execution of either one results in partial or complete loss of reservoir deliverability
– In this lecture major factors impacting reservoir permeability and hydraulic fracture conductivity/geometry will be discussed
– Major production and operational issues are divided in:• Pressure draw down • Liquid loading • Hydrate formation• Infrastructure deficiencies
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PRESSURE DRAW DOWN
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Pinit
Hydraulic fracturing
hfHorizontal well
pJq ∆=Drawdown
ProductivityIndex Pwf
Preservoir
wfreservoir PPp −=∆
Prod
uctio
n ra
te
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Hydraulic fracture Conductivity (Cont.)
2xf
wff
ff
fD kxwk
C =
kf kCfD= Hydraulic fracture conductivityk: Matrix permeabilitykf: Hydraulic fracture permeabilityxf: Hydraulic fracture half lengthwf: Hydraulic fracture width
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Pressure Draw Down
HCU 7-31F
0
200
400
600
800
1000
1200
1400
1600
1800
2000
3/6/
2003
3/20
/200
3
4/3/
2003
4/17
/200
3
5/1/
2003
5/15
/200
3
5/29
/200
3
6/12
/200
3
6/26
/200
3
7/10
/200
3
7/24
/200
3
8/7/
2003
8/21
/200
3
9/4/
2003
9/18
/200
3
10/2
/200
3
10/1
6/20
03
10/3
0/20
03
11/1
3/20
03
11/2
7/20
03
12/1
1/20
03
12/2
5/20
03
1/8/
2004
1/22
/200
4
2/5/
2004
Date
Tub
ing/
Cas
ing
Pres
sure
0
0.5
1
1.5
2
2.5
3
3.5
4
Cas
ing
Tub
ing
Rat
io
Tubing Press (psi)
Casing Press (psi)
Line Press (psi)
Csg/Tbg ratio
Tubi
ng p
ress
ure
time
High pressure draw downHigh flow rate
Surface line pressure
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Pressure Draw Down (Cont.)• Higher pressure draw down
leads to:– Higher production rate– Faster pressure decline
after reaching the surface line pressure
– Lower ultimate gas recovery (UGR)
• Proppant crushing and embedment
• Loosing hydraulic fracture conductivity
– Sand production and surface facility corrosion
• Significantly damage surface facilities specially when Ceramic proppants have been used
q (p
rodu
ctio
n ra
te)
time
High pressure draw downHigh flow rateLow UGR
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Proppant PlacementIdeal proppant placement Real proppant placement
During fracturing During Production During fracturing During Production
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Proppant Crushing Embedment
Early Time (or low pressure drawdown)Slightly impaired Fracture conductivity
Mid Time (or intermediate pressure drawdown)moderate impaired Fracture conductivity
Late Time (or high pressure drawdown)Highly impaired Fracture conductivity
I
II
III
Hyd
raul
ic fr
actu
re d
urin
g pr
oduc
tion
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Optimum Pressure Draw Down
Tubi
ng p
ress
ure
time
Surface line pressure
Optimum pressure draw down
Maximum Ultimate Recovery
• Optimum pressure draw down is a function of:– Fracture closure pressure – Proppant density, size and
strength– Formation mechanical
properties Young's modulus and Poisson’s ratio
– Natural fracture density– Multi-stage hydraulic
fracturing interactions
q (p
rodu
ctio
n ra
te)
Optimum flow rate
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LIQUID LOADING
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Liquid loading in a Gas Well
• Liquid loading is an accumulation of water, gas condensate or both in tubing.
• Liquids can enter the well directly from reservoir or condense from the gas in the wellbore due to pressure drop
• Almost always we do have liquid (water or condensate or both) production
• The major cause of liquid loading is low gas flow rate or velocity
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Typical Gas Well History
TIME
Dead well due toliquid loading
Gas
Rat
e
• There is a critical gas velocity below which liquid can not be transferred to the surface • Liquid will be accumulated at the bottom of the tubing when gas flow rate is not enough• Liquid accumulation “liquid loading” will decrease the production rate and if not corrected kills the
well
Liquid is represented in BlueGas is represented in Red
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Diagnostic of Liquid Loading
• The easiest technique is surface monitoring– High tubing/casing
differential pressure• High flowing bottom hole
pressure • Observed slugging from well• Rapid increase in decline rate
Normal Liquid Loading
300 PSI350 PSI
300 PSI600 PSI
Low Flowing Bottom Hole pressure
High Flowing Bottom Hole Pressure
900 PSI600 PSI
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Liquid Loading Remediation• Using Velocity String
– Running smaller diameter tubing leads to increase in gas velocity and higher liquid lift capacity
Normal
300 PSI350 PSI
600 PSI
Liquid Loading
300 PSI600 PSI
900 PSI
Smaller size
tubing
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Liquid Loading Remediation (Cont.)• Soaping
– Adding surfactant at the bottom of tubing generates foaming that helps removing water build up
– Is not as effective in condensate loading
Liquid Loading
300 PSI600 PSI
900 PSI
surfactant
Liquid Loading
300 PSI400 PSI
650 PSI
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Liquid Loading Remediation (Cont.)• Venting
– Dropping the surface pressure to atmospheric pressure to maximize gas velocity
• Compression– Dropping the surface
pressure below line pressure to increase gas velocity
Liquid Loading
300 PSI600 PSI
900 PSI
Liquid Loading
14.7 PSI100 PSI
650 PSI
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Liquid Loading Remediation (Cont.)• Plunger lift
– Using mechanical plunger to avoid liquid accumulation downhole
• Using Downhole pumps
Liquid Loading
900 PSI
Liquid Loading
900 PSI
Plunger
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GAS HYDRATES
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Fire in Ice
In essence, hydrates are ice with fuel inside – they can be lit by a match! (Naval Research Laboratory)
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What is a Gas Hydrate?• Solid Water Structure
• Methane
• 1ft3 hydrate at res conditions=
160 scf of gas
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Flow Assurance• Suitable conditions for gas hydrate formation commonly occur during hydrocarbon
production, operations, where the hydrates are a major flow assurance problem and serious economic/safety concerns
• The gas hydrates can block pipelines• Gas hydrates can damage valves, elbows, etc
A large gas hydrate plug formed in a sub sea hydrocarbon pipeline (Petrobras, Brazil)(Naval Research Laboratory)
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How to Reduce Gas Hydrate Problems
• At fixed pressure, operate at temperatures above the hydrate formation temperature. This can be achieved by insulation or heating of the equipment
• At fixed temperature, operating at pressures below hydrate formation pressure
• Dehydrate, i.e., reduce water concentration to an extent of avoiding hydrate formation
• Use chemicals such as methanol and salts for the inhibition of the hydrate formation conditions
• Prevent, or delay the hydrate formation by adding kinetic inhibitors
• Prevent hydrate clustering by using hydrate growth modifiers or coating of working surfaces with hydrophobic substances
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INFRASTRUCTURE DEFICIENCIES
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Pipeline Design• Surface pipelines are designed based on production forecasts• Inaccurate production forecast leads to
– large pipe size design that is costly and not economical (optimistic production forecast)
– smaller size pipeline design which is not able to deliver real field production (pessimistic production forecast)