short course deliquification basics

7/27/2019 Short Course Deliquification Basics

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North American Gas

FIELD OF THE FUTURE

Deliquification Forum 2007:

Deliquification Basics


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2007 North America Deliquification Forum - Denver 2

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



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.



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.



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.



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.



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



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.



Low Porosity

Low Porosity is the low percentage of void space.



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.



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.



Conventional

Sands

Free gasFree flowing

Core picture

Tight

Sands

Free gasSlow flowing

Shale

Free & desorbed gasSlow flowing

Coal-bed

Methane

Desorbed gasFree flowing



Tight Gas Rock Low Porosity, Low Permeability

Shoreface

& Shallow Marine Sand

Average Porosity: 3.5% Best Permeability:0.012



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.



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.



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.



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.



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.



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



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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2007 North America Deliquification Forum - Denver

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

short course deliquification basics

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