Short Course Deliquification Basics
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Transcript of Short Course Deliquification Basics
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North American Gas
FIELD OF THE FUTURE
Deliquification Forum 2007:
Deliquification Basics
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Agenda10:00
12:00
Safety/Intro
Production Related Geology
Production Operations
Fundamentals
Problem Solving Liquid Loading
1:00
3:00
Working the Problems
Objectives
How reservoir characteristics define and impact liquidloading
The part the production cycle plays in liquid loading,
pros and cons of artificial lift
Basics of deliquification, what data to consider when
analyzing liquid loading: critical velocity and using
Turner/Coleman unloading curves, casing/tubing
pressures, flow regimes, production trends
Real life NAG liquid loading problems, lessons
learned, best practice sharing
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No Equations
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The Key Elements Of Hydrocarbon Geology
Geology is the study of the Earth, the materials
of which it is made, the structure of thosematerials, and the processes acting upon them; an
important part is the study of how these elements
have changed over time.
Our overview will focus on:
Formation
Migration
Storage
Recovery
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Initially, much of the Earth is covered with water.
Hydrocarbon Formation
Over millions of years, trillions of plants and animals living in the oceans die
and are mixed with and covered by sediment entering the water as
the land
masses erode, building up layer upon layer.
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Heat, Time and Pressure
As these layers are being deposited, they are being changed by the high
temperatures found below the surface, time in millions of years,
and the
pressure created by layer after layer being laid down.
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Gas, Oil, and Water
Trapped with in these layers is the water left by the ancient oceans and the
ooze left over by decaying plants and animals, often buried more
than two
miles down. Time, temperature and pressure cook
the ooze in to gas and oil.
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Coalification
We also will find coal, and the gas trapped with in the coal, in
these layers.
When plant material is preserved fast enough to prevent decay and when
coupled with time, pressure and heat, it turns first to peat and
then to coal.
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Initially the hydrocarbons exist only in tiny pockets. The buoyancy of the
materials, and the pressure of the earth slowly squeeze them out
of the rock
forcing a migration. The moving fluids meet up with others rising to the
surface.
Migration
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Migration contd.
As the hydrocarbons migrate, the lighter gas rises to the top, with oil coming to
rest below it, and water left at the bottom. It is important to note that you may
have all three phases in the reservoir rock, or any combination.
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Storage - Sedimentary Rock
Sedimentary rock, up to 4 miles thick, is formed by the layers of falling
sediment over millions of years. The most common types are chalk, sandstone,
limestone, clay and shale and contain much of the worlds hydrocarbons.
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Source Rock
Reservoir Rock
Seal Rock
Storage Source, Reservoir, and Seal Rock
As the layers were buried, they attained different characteristics. The source
rock is where the hydrocarbons were formed. The reservoir rock is the storage
container of the hydrocarbons with migration only to be stopped by a seal rock,
holding the hydrocarbons in place.
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Coal-bed Natural Gas
Coal bed natural gas is generated and stored in coal beds. Gas in coal seams is
stored in three basic ways: adsorbed to coal particles and held by molecular
attraction, within pore spaces, cleats and fractures of the coal, and dissolved in
water contained within the coal.
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Porosity & Permeability
By definition, reservoir rock must have:
Capacity to store fluids
Ability to transmit fluids
Porosity is fluid storage capacity in a rock or how much you have
Measured as % of rock void space
Tight gas between 3
10%
Permeability
is the measure of ability of the rock to transmit fluids
or how easy fluids will flow through the rock
Measured in units called darcies
or millidarcies
Tight gas < .01 md
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High Porosity
Porosity is the percentage void space within rock that may contain fluids.
Porosity can be primary porosity, such as space between grains that were not
compacted together completely.
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Low Porosity
Low Porosity is the low percentage of void space.
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High Permeability
Permeability is a measure of the ability of a rock or unconsolidated material to
transmit fluids. It is of great importance in determining the flow characteristics
of hydrocarbons in oil and gas reservoirs.
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Low Permeability
Gas reservoirs with lower permeability are still exploitable because of the lower
viscosity of gas with respect to oil. Tight
gas wells typically have
permeabilites of less than 0.01 md.
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Conventional
Sands
Free gasFree flowing
Core picture
Tight
Sands
Free gasSlow flowing
Shale
Free & desorbed gasSlow flowing
Coal-bed
Methane
Desorbed gasFree flowing
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Tight Gas Rock Low Porosity, Low Permeability
Shoreface
& Shallow Marine Sand
Average Porosity: 3.5% Best Permeability:0.012
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Types Of Traps
Structural
Structural traps hold oil and gas
because the earth has been bent and deformed insome way. The trap may be a simple dome or big
bump, a crease in the rocks, or it may be a trap
formed by a fault.
Stratigraphic
Stratigraphic traps are depositional
in nature. This means they are formed in place,
usually by sandstone ending up enclosed in shale.
The shale keeps the oil and gas from escaping the
trap.
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Stratigraphic Trap
The stratigraphic trap is a feature that ensures the hydrocarbons remain
trapped in the subsurface. This trap is a feature that contains the hydrocarbons
with a change in rock type like sand to shale.
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Structural Traps - Anticline
An anticline is a fold that is convex with the oldest beds found
in the middle.
Anticlines are favored locations for oil and natural gas
drilling; the
hydrocarbons low density causes it to migrate upward to the higher parts of
the fold, until stopped by an impermeable layer.
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Structural Traps - Faults
Faulted rock commonly forms traps for the accumulation of hydrocarbons.
They often also occur around reef complexes and collapse features such as
ancient sinkholes.
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Structural Traps Salt Dome
An example of this kind of trap starts when salt is deposited by
shallow seas.
Since the density of salt is generally less than that of surrounding material, it
has a tendency to move upward toward the surface. Hydrocarbons can
accumulate on the sides of the large bulbous dome.
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Reservoir Drive MechanismsThe reservoir drive mechanism is the process in which
reservoir fluids are caused to flow out of the reservoir
rock and into a well bore by natural energy. It is alsoreferred to as natural energy drivedriving the
hydrocarbons toward the wells and up to the surfaces
during the early life of a well. It controls the productionof the reservoir.
The 2 main drive mechanisms that we will discuss are:
Water drive
Gas/Depletion drive
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Water Drive - Bottom
Water drive reservoirs depend on water
and rock expansion to force the
hydrocarbons out of the reservoir andinto the well bore. Water drive keeps
the pressure high, so the objective is to
try to produce as much gas as you can
and outrun the water. Water drive is
very rare in tight gas wells. The two
types of water drive are:
Bottom-water drive
The stronger
type of water drive. It forces thehydrocarbons up from the bottom of
the reservoir.
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Water Drive - Edge
Edge-water drive is the weaker of the two types of water drive. It forceshydrocarbons in from the sides of the reservoir.
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Gas/Depletion Drive Reservoir
Depletion drive reservoirs remove
volume, causing the gas to expand,
and as long as pressure is low at thewell, the gas will continue to expand
towards the top of the well head.
Pressure in wells continually drops as
drive energy is depleted, impactinghow liquids will be carried out of the
well.
Additionally, there is no water drive in
depletion drive; water is in the pores of
the rock..
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Gas Drive in a Coal Reservoir
Coal is a depletion drive; the flow
characteristics are vastly different.
In a coal reservoir you normally must remove
water first allowing the gas to expand, the
cleats to shrink, thereby increasing the
permeability.
As long as pressure is low at the well, the
gas will continue to expand towards the top
of the well head.
Pressure in coal wells will also drop asenergy is depleted, just as in tight gas wells,
impacting how liquids will need to be carried
out of the well.
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Sources of Water
Often where there is gas, there is water. There are
principally two ways to deal with this water, lift it
out of the well, or leave it down there. Liquid can
take two primary forms, water and liquid
hydrocarbons such as light oil.
These are the
different ways water can find its way in to a well.
Free Formation Water
Condensation
Water from Another Formation
Water Coning
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Free Formation
Salt water can exist in the hydrocarbon reservoir. It is water trapped in the rock
at the time the rock was deposited. It may be derived either from ocean water
or land water, has persisted with little change in composition since it was
buried with the sediment. Often this water is corrosive.
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Condensation
Water and/or hydrocarbons may enter
the well bore with the gas at depth
where higher temperatures andpressures keep the liquid in its vapor
phase.
Reducing the pressures the vapor rises
with the gas, cooling as it does,changing to liquid in the tubing.
Water from condensation is very fresh
and calculations can tell us the
maximum quantity that can be
expected.
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Water From another Formation
Water can also enter the well bore somewhere away from the perforations
because of a casing leak caused by corrosion
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Water Coning
The upward encroachment of water caused by pressure drawdown from
production. If the gas rate is high enough, water may be sucked
from a
water zone below, or from an aqueous zone above or below the producingzone.
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Ways Reservoir Characteristics Impact Liquid Loading
Reservoir Characteristics
Formation: Tight Gas
Porosity: 3 -
10%
Permeability:
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Drilling: putting a hole in the ground
Completing a Well: activities and methods of preparing a well for theproduction of gas.
Casing: series of metal pipes that turn hole
into well
Completion & Completion Techniques: finishing a well so it isready to produce
Well Testing: determine the potential of the well, pressure/raterelationship during shut-in, flowing times, productivity testing,formation information
Production: process by which reservoir fluids are brought to surface
Maintenance & Repair (Workover): repairing/ replacing productiontubing and packers, repairing artificial lift, cleaning out wellbore,stimulation, swabbing, recompletion, etc.
Processing & Testing Reservoir Fluids: treating and measuring fluid
production/injection, separation of fluids, water disposal
Production Cycle of Well
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DrillingThis is the first of all firsts, drilling a hole in the ground.
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Although most wells deviate at leastslightly from the vertical, well boregeometry is important to how awell is produced, completed and
what artificial lifts may be used.
It
can also affect well from a flowregime perspectivethe greater theangle in a well, the less efficient thelifts because the gas outruns
the
liquid.
Well Bore Geometry Types:
Straight
Directional
Deviated
Highly Deviated
Lateral/Straight
Multilateral
Well Bore Geometry
Deviated
Highly
Deviated
Lateral/Horizontal
Multilateral Well
Slotted Liner Completion
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Well Bore Geometry - Multilateral
Deviated
StraightHighly Deviated
Horizontal/ Lateral
Advantages:
reduce footprint, more contact with reservoir,
accelerated production, better wellbore
placement, less drill sites
Disadvantages:
production allocation, testing & diagnostics, high
angle wells speed up liquid load
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Multi-Well Pad
Advantages: reduce footprint, reduce facility costs, generate ownpower, allows for simultaneous operationsDisadvantages:
high angle wells start to liquid load faster
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Well Completion
The process of finishing a well so that itis ready to produce natural gas. Itencompasses the activities and
methods of preparing a well for theproduction of gas.
A well casing
is what segregates the
formations from each other, through
cement. Well casing refers to a seriesof metal tubes that are installed to turna hole
into a well.
Conductor casing
Surface casing
Intermediate or Liner String orProduction Casing
Tubing
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Well completion is the process of finishing a well so that it is
ready to
produce natural gas.
There are 3 basic methods of completing a well:
Open-Hole
Cased-Hole
Slotted-Liner
Well Completions
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Completions
Open Hole Cased Hole
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Completions, cont.
Slotted Liner
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Various Well Completions Lateral WellsConcrete Packand Perforations
Gravel Pack and
Slotted Liner
Gravel Pack andWire Screen
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Completion Techniques
Wire Wrapped
Gravel Pack
Hydraulic
Stimulation
Perforations
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Well Head
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Extraction, Treatment, Selling
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Maintenance and Repair (Workover)
Service and work over rigs aresimilar to drilling rigs butsmaller in size and they usuallydo not have circulation or rotarysystems. Common jobs suchas depth measurements andlogging
are performed with
tools suspended on a wire line.
The most commonmaintenance jobs arerepairing/replacingproduction tubing andpackers, repairing artificiallifts, cleaning the well bore
and stimulation. Also,selecting the artificial lifts to beused in a well is consideredmaintenance.
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Well Stimulation
Process to enlarge old channels or create new ones in theproducing formation to enhance production. Two examplesare fracturing
and acidizing:
Hydraulic fracturing
occurs when a fracturing fluid is
injected at high pressures to cause fractures in the productionzone; it works well in low permeability, sandstone reservoirs.Because most NAG gas is produced from low porosity &permeability tight gas wells, hydraulic fracturing is done toincrease the amount of reservoir exposure to the well.
Signification to deliquification
is that the types of
deliquification
methods used could be impacted by
proppant
flowback. Depending on the deliquification
technique, the fracture may, and will most likely, become part
of the wells storage capacity. This causes the well to havedifferent characteristics for build up and flow periods.
Acidizing
has much less affect on deliquification
thanfracturing. The acid reacts chemically with the rock to dissolve
it, thus enlarging the existing flow channels and opening newones to the well bore. The reservoirs most commonly acidizedare the carbonate reservoirs, limestone and dolomite.
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Processing and testing the reservoir fluids includes treating and measuring
fluid productions/injection and also allows for water disposal.
In processing and testing, gas and water samples are very useful. Daily
water samples are used to test for corrosion, calcium, chloride and other
compounds and elements.
When a well is drilled through multiple formations, gas samples are also
used to test which formation is producing the gas.
Processing and Testing the Reservoir Fluids
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Primary Methods of Unloading a WellThere are various ways of unloading a well that has filled with water; some
techniques require mechanical devices and are referred to as artificial lifts.
Artificial lifts are required to raise gas to the surface after natural energy
becomes weak and the well ceases to flow. The following are the 5 mainmethods of unloading a well:
Cycling
Foam
Plungers
Beam Pump
Compression
Other ones that BP uses
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Rate,MCFD
Time
Normal Decline
Loading
Goal of Artificial Lift
Unloading Well to Mitigate Production Loss
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CyclingAs the reservoir
pressure depletes, we
use cycling to returnthe well into its own
natural rhythm.
Closed/
UnloadingLoaded FlowingOpen
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Cycling
Advantages
Low initial cost
Capable of being automated
Used on wells with limitations and
in combo with other remedies
Easy, doesnt require tech
expertise
Unloads well & keeps it producing
with minimal cost
Effective in early life of well
Disadvantages
Wastes energy that could be
utilitzed
more efficiently, typically
results in liquid fallback
Unless automated, cant adjust
with changing conditions requiring
operator time to optimize
Cannot reach maximum production
without mechanical interface
Works for limited time and then
must be replaced
Cant reach low bottom hole
pressures
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Foaming
Foaming is a relatively inexpensive
initial cost solution for gas well
deliquification; it is a type of liquid
and gas emulsion.
The primary benefit of foaming is
that the liquid is held in the bubble
film and exposed to more surface
area which in turn leads to a low-
density mixture and less gasslippage. Two operating limitations governthe application of foam to theunloading of low rate gas wells:
the success of foam surfactants in
reducing bottomhole
pressure and
economics.
OpenClosed
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Foaming
Advantages
Helps minimize
venting
Capable of being automated or
truck treated
Useful in wells not capable of
using other remedies (eg. offshore)
Simple & inexpensive for low rate
wells
Disadvantages
Cost, especially if automated or
truck treated. Ongoing.
Some water must be present to
make this work
Can plug tubing, particularly when
no water is present
Scale enhancer
Valuable operator time is used
When automated, cant adjust withchanging conditions
Safety; chemical handling, MSDS,
PPE, electrical equip safety
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PlungersA plunger is a mechanical device dropped in well and utilized to
push the liquids out.The well is shut in to allow the plunger to fall through the liquid;the well is then flowed allowing the critical velocity developed
while the well was shut in to push the plunger to the top of the well, lifting the fluids out of the well bore.We are mainly concerned with three types of Plungers:
Conventional
Two Piece
Flow-through
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Plunger Cycle
The compromise
that usually yields
the greatest
production is
found when
balancing the
plunger cycle
frequency andplunger velocity
that is not so fast
that it damages
the equipment orso slow that the
plunger does not
surface
(approximately
750 ft per minute).
Loaded Shut in Flow Loading
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Two Piece Plunger
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Flow-through and Conventional Plungers
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Plungers
Advantages
Low cost to purchase, install,
move
Low maintenance
Can be automated to adjust for
changing well conditions
Works well in standard to large
tubing strings
With adequate GLR (gas liquid
ratio) and pressure (400
scf/bbl/1000 ft) can lift high liquidrates
Disadvantages
Under wrong conditions, plunger is
a projectile and can blow off top oftree
Requires more analytical
capabilities of operator, so requires
more time and attention
Stalls out at low bottom hole
pressure
Hard to operate in small tubing and
with sand
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Beam Pump
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Beam Pump Cycle
Beam pumps may
be the most
common methodto remove liquids
from gas wells.
The main
components of abeam pump are: a
sucker rod, a
sucker rod pump
and a walking
beam.
LoadingFlow/LoadingUp StrokeDown stroke
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Beam Lift
Advantages
Simple, efficient and easy to use
Capable of achieving absolute
minimum FBHP
Use up to PxA
Can be automated with pump off
controllers to make changes as
well conditions change
Disadvantages
High cost to purchase, install,
maintain
High maintenance
Prime movers
gas engines high
maintenance, difficult to control;
electric motors expensive tooperate
Gas locking worse than normal in
high GLR wells
Safety
more moving parts, more
opportunity for error
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CompressionIn general, compression lowers the
surface pressure of a well with the
intent of lowering bottom-hole
pressure and increasing the gasvelocity to equal or greater than the
critical unload velocity
It also lowers the pressure on the
formation.
Compression helps artificial lift
methods to various degrees.
Compression is a technique that isoften used to assist in unloading the
wells.
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Compression Types
Wellsite
(permit).
Satellite
Echo SpringsPlant
new 140
MMSCFD
Train Jan.
2002
Patrick Draw
Plant
Bypass
Processing/Bypassing
Plant A
Plant B
Bypass
Export
Export Pressure =1000 psiSatellite DischargePressure =600 psi
Wellsite
Discharge
Pressure =300 psi
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Compression
Advantages
Increases rate by lowering suction
(line) pressure and unloads
Very attractive when small
changes in pressure give big
changes in rate
Can be rented and maintained byvendor
Can be used on wells with
mechanical limitations
Can be used with plungers, stopclocks, and recirc
Disadvantages
Wont kick off a well. Often a
short term fix and downhole
solution is later required
Purchase/rental and operation
costs; high maintenance
Safety
fire hazards, moving parts
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Other Artificial Lift OptionsESP PCP
http://en.wikipedia.org/wiki/Image:Electrical_Submersible_Pump.pnghttp://en.wikipedia.org/wiki/Image:Electrical_Submersible_Pump.png -
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Surface handling of Gas Well Fluids
Gas, Oil and Water go to
Production Unit (Tpak)
which heats and separates
gas from liquid
Separator inside Production Unit
Dehydration unit removes water vapor and meters gas
Water and oil stored for trucking
Orifice Meter inside
Dehydrator
Fluctuations in pressure or flow at different points can cause loading
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Mechanics Of Gas Well Liquid Loading
Pressure
Velocity
Friction
Gravity
Critical velocity
Pressure Velocity
FrictionGravity
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Critical Velocity/Rate
Every gas well has a critical
gas velocity below which
liquid cannot be effectivelytransported from the well
bore.
Below the rate or critical
velocity, liquids are noteffectively removed from the
well bore and will settle to
the bottom of the tubing
creating a plug
of liquid.
Pressure Velocity
FrictionGravity
Critical Velocity
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Activity Mechanics of Gas Well Liquid LoadingActivity 1
Challenge
The blue elements, water,
would fall to the bottom of
the tubing loading the wellwith water.
Pressure Velocity
FrictionGravity
Critical Velocity
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Understanding Unloading Curves
The gas velocity at which liquids accumulate is predictable and can
be related to flow rates in various tubing sizes; unloading curves
show this relationship.
Using these curves, you can predict if a well may be liquid loaded.
At lower surface-flowing pressures, a lower flow rate is required to
keep a well unloaded.
At higher flowing pressures, a higher flow rate is required. With this
in mind, the goal is to keep a well unloaded and operate at the
lowest possible flowing pressure.
Also important to remember is that there difference betweenTurner and Coleman unloading curves. It is recommended that
when surface flowing pressure is less than a 1000 psi, use
Coleman curves; above 1000 psi, use Turner curves.
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0
100
200
300
400500
600
700
800900
1000
0 200 400 600 800
Flowing (Tubing) Pressure, PSIA
MinC
riticalVelo
cityRate,m
cfd
2.375
2.016
1.90
1.66
Unloading Rates for Various Tubing Sizes -Turner
Tubing Size
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The Inflow Performance Relationship (IPR)
A tool used in production engineering to assess well performance
by plotting the well production rate against the flowing bottom-holepressure (BHP).
The data required to create the IPR are obtained by measuring the
production rates under various drawdown pressures, or calculating
the difference between the average reservoir pressure and the
flowing bottom-hole pressure.
The reservoir fluid composition and behavior of the fluid phases
under flowing conditions determine the shape of the curve.
The IPR clearly shows that we will need to constantly adjust in
order to maximize production.
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0
100
200
300
400
500
600
700
800
0 50 100 150 200 250 300
Production Rate, mcfd
Flo
wingBottom-hole
Pressure,psia
Higher Pressure Gas Well
Lower Pressure Gas Well
Typical IPR Curves for Low/high Pressure Wells
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Rate,MCFD
Time
Normal Decline
Loading
Goal of Artificial Lift
Unloading a Well to Mitigate Production Loss
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Tubing and Casing Pressures Open AnnulusNormal Loaded100 PSI
Flowing Tubing
Pressure
130 PSI Casing
Pressure
100 PSI
Flowing Tubing
Pressure
220 PSI Casing
Pressure
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Tubing and Casing Pressures LeaksTubing Leak Casing Leak
100 PSI
Flowing Tubing
Pressure
100 PSI Casing
Pressure
100 PSI
Flowing Tubing
Pressure
80 PSI Casing
Pressure
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Casing and Tubing Pressure-Plot
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Tubing and Casing Pressures Packer UnloadedNormal 1 Min. Shut In100 PSI Flowing
Tubing Pressure
0 PSI Casing Pressure
130 PSI Flowing
Tubing Pressure
0 PSI Casing Pressure
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Tubing and Casing Pressures Packer LoadedFlowing Loaded 1 Min. Shut In
0 PSI
0 PSI Casing Pressure 0 PSI Casing Pressure
100 PSI Flowing
Tubing Pressure101 PSI Flowing
Tubing Pressure
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Flow RegimesMist Annular Slug Bubble
Decreasing Gas Velocity
GasFlow
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Four Flow Regimes Mist
The gas phase is continuous and most of the liquid
is entrained in the gas as a mist. The pipe wall is
coated with a thin film of liquid and creating friction,
but pressure gradient is determined predominately
from the gas flow.
Gas flow rates are still high.
IPR curve is being followed
Production rates are smooth
Mist
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Four Flow Regimes Plot Mist FlowMist Flow
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Four Flow Regimes Annular Flow
Some liquid may be entrained as droplets in the gas and
pipe wall friction may increase. Gas dominates the pressure
gradient, but liquid accumulation is becoming significant.
Gas rates begin to decline.
Velocity approaching critical rate
Tubing and casing pressure gradient increases (can be not
considerable)
Production rates are more erratic
Liquid production may be constant or falling.
Bottom-hole pressures increase
Production trend may fall below decline curve projections
Annular
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Four Flow Regimes Plot Annular FlowAnnular Flow
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Four Flow Regimes Slug Flow
Gas bubbles expand as they rise and coalesce into
larger bubbles, then form slugs. Liquid phase is now
the continuous phase. The liquid film around the slugs
may fall downward. Both gas and liquid significantly
affect the pressure gradient.
Velocity shows marked decline.
Liquid production may show a marked decrease.
Gas production may increase
Bottom-hole pressures may show marked increase
Production trend falls below decline curve projections
Slug
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Four Flow Regimes Plot Slug FlowSlug Flow
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Four Flow Regimes Bubble Flow
The tubing is almost completely filled with liquid. Free
gas is present as small bubbles, rising in the liquid. Liquid
contacts the wall surface and the bubbles serve only to
reduce the density.
Velocity shows marked decline.
Liquid production may shows marked decrease.
Gas production may suddenly improve with outintercession for a short period
Production at this very low rate may continue as bubbles
continue to rise through the liquid.
Bubble
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Four Flow Regimes - BubbleBubble Flow
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Decreasing Gas Rate TIME
Well
Dead
Initial
Production
Unstable FlowStable Flow Stable Flow
Rate
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High Rate Data- 4 Hour to 1 Minute Data Scan8:30 11:00