PRODUCTION AND OPERATIONAL ISSUES

Dr. Ebrahim FathiPetroleum and Natural Gas Engineering DepartmentWest Virginia University Audience and Date

March 2, 2016

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

PRESSURE DRAW DOWN

Pinit

Hydraulic fracturing

hfHorizontal well

pJq ∆=Drawdown

ProductivityIndex Pwf

Preservoir

wfreservoir PPp −=∆

Prod

uctio

n ra

te

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

Pressure Draw Down

HCU 7-31F

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2003

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/200

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2004

Date

Tub

ing/

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ing

Pres

sure

0

0.5

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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

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

Proppant PlacementIdeal proppant placement Real proppant placement

During fracturing During Production During fracturing During Production

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

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

LIQUID LOADING

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

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

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

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

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

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

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

GAS HYDRATES

Fire in Ice

In essence, hydrates are ice with fuel inside – they can be lit by a match! (Naval Research Laboratory)

What is a Gas Hydrate?• Solid Water Structure

• Methane

• 1ft3 hydrate at res conditions=

160 scf of gas

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)

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

INFRASTRUCTURE DEFICIENCIES

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)