Sonatrachs Problem Well Analysis

Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Introduction to Hydrocarbon Exploitation
©2005 Abalt Solutions Limited. All rights reserved
Problem Well Analysis
Pratap Thimaiah
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Problem Well Analysis
 Surveillance
 Getting Started
 What is a problem well?
 Inflow restrictions
 Outflow restrictions
 Reservoir Problems
 Artificial Lift
 Mechanical Failures
 Sand Control
 Re-completions
 Plug and Abandonment
 Workover Economics
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Surveillance
 Monitoring of the asset to optimally recover the oil and gas
reserves in a timely fashion through safe and profitable
operations
 Critical for the future profitability of the field
Entire Business Unit
Analysis
Identification of well problems
or
field problems
Problem Definition
Production and operating cost problems
Problem Analysis
- Continue to produce well's) with no change,
- Collect additional data,
- Workover and/or stimulation,
- Equipment change,
- Operations procedures changes),
- Re-completion,
- Pressure maintenance,
- Enhanced recovery operation, or
- Shut-in and abandonment
Solutions
Generation
Reservoir A
Reservoir B
Reservoir C
Reservoir D
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Getting Started
 Essential data must be in hand like:
– Well test plots
– Daily production plots
– Wellbore diagram
– Base open-hole log
Production plot, oil, gas, water, and GOR. Exponential decline. Log-log plot of two well tests shows wellbore storage
reduction with downhole shut-in
Plot of the bottom-hole flow rate and pressure
recorded during a drawdown test
©Schlumberger
©Schlumberger
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Getting Started
 Wellbore diagram
– Must include both the measured
and true vertical depths of
tubulars, perforations, packers,
and all subsurface equipment.
– Outer diameter and internal
diameters of each item.
– Tight spots
– Junk in hole
– Potential problem areas
– Reference elevation
– Type connection in the wellhead
for production logging described
©Schlumberger
Typical deepwater well completion
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Getting Started
 Base Openhole Log
– Open perforations must be
shown for each well.
– Cased hole gamma ray
and porosity log could be
of help.
– Casing collar depths and
any radioactive marker
depths should always be
shown at the proper
depths on the base log.
– GOC and WOC should be
shown when available.
GRC
0 150
SPC
MV -160 40
ACAL
6 16
ILDC
0.2 200
SNC
0.2 200
MLLCF
0.2 200
RHOC
1.95 2.95
CNLLC
0.45 -0.15
DT
us/f 150 50
001) BONANZA 1
10700
10800
10900
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Problem Well Defined
 What is a problem well?
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Problem Well Defined
 What is a problem well?
– Low oil or gas production
– High GOR
– High water cut
– Mechanical problems
 Should be differentiated from a reservoir
problem
Development Phase
September – October 2005
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Inflow Restrictions
 Wellbore plugging
 Perforation restrictions
 Formation Damage
Scale deposit in Tubing
Potentially damaging fines
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Inflow Restrictions
 Such damage may be indicated by:
– Production well tests
– Pressure build-up and drawdown tests
– Comparison with offset wells
– Analysis of production history
Effect of wellbore damage on productivity
Difference between pressure drawdown in undamaged and
damaged reservoirs. 50% of p occurs in last 15 ft.
pressure
Damage zone
Development Phase
September – October 2005
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Inflow Restrictions
 Procedure in surveillance for problem wells:
– If the monthly production test rate has decreased more
than 10 percent from normal decline retest the well
immediately.
– Review adjacent wells for abnormal decline. If a number of
wells in an area have significant declines, the problem may
be reservoir related.
– Check the well for mechanical problems; especially if on
artificial lift.
– Check for wellbore fill-up.
– Check for changes in backpressure or operating procedures.
– Consider the need for production logs or pressure surveys
to confirm damage.
– If damage is confirmed, take corrective action.
 Use caution on stimulation if near gas-oil or water-oil contacts
 Recommend bold action for low rate wells
 Use some restrain on high rate wells, however they may offer
the highest potential again.
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Wellbore Plugging
 Flow restrictions in the wellbore is often formation fill or scale.
 For flowing or gas lifted wells, provided the tubing is open-
ended, where there is fill across the formation, a coiled tubing
unit are commonly used for cleanout.
 For pumping wells it may be necessary to pull the tubing before
clean-out.
 Inorganic scale in the wellbore and perforation is a common
problem that can easily reduce production.
– Sodium chloride salt
– Calcium carbonate
– Gypsum
– Barium and strontium chloride
Development Phase
September – October 2005
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Perforation Restrictions
 Cause by perforation plugging or inadequate perforations
 Considerable effort should be made on completion to
ensure that the perforations are open and undamaged
 Avoid loss of dirty water of dirty water into the formation
which may plug both the perforations and the formation
pores.
 Solutions range from re-perforation, wash the
perforations, surge the formation, or to even fracture the
formation.
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Formation Damage
 Impairment of well productivity or injectivity
due to
– Plugging within the perforations
– Formation pores adjacent to the wellbore
– Fractures communicating with the wellbore
 The procedure to follow:
– Determine the degree of well damage (skin)
– Causes of damage
– Approach to alleviate the damage
Development Phase
September – October 2005
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Formation Damage
 Paraffin or Asphaltene Plugging
 Emulsion Blocks
 Water blocking
 Fine Particles
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Outflow Restrictions
 Increase the backpressure
 Limit drawdown
 Reduce production
 Some cases:
– Tubing smaller than optimum will cause extra
friction losses
– Larger than optimum will increase slippage and
may cause the well to load up and die.
– On a pumping well, to small a tubing may restrict
the lift equipment or cause friction, which will
increase lift energy requirements.
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Outflow Restrictions
 Inflow and outflow performance curves can
help determine if a tubing size change is
justified.
Well system analysis. Node selected at perforation outlet
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Outflow Restrictions
 The production well test should report the wellhead pressure. If
it is relatively high, and outflow analysis should be undertaken.
– If the pressure has recently increased, then possible
plugging in the outflow system should be checked.
– If the pressure is normally high, the investigate why it is
high.
 Are there any gas sales pressure limitations?
 Are there compressors that require a fixed suction pressure?
Can it be economically lowered?
 What is the pressure drop between the wellhead and the
separator?
 Is there a surface choke on the well and what is its size?
 On pumping wells, is the annulus vented into the flowline?
 Are there any downhole restrictions?
Development Phase
September – October 2005
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Reservoir Problems
 Low reservoir permeability
 Low reservoir pressure
 Water production problems
 Gas problems in gas wells
 High Viscosity Oil
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Low reservoir permeability
 May be an overall reservoir characteristic or limited to a
specific area.
 Should be considered along with other causes of low
productivity.
 Usually well productivity declines rapidly as fluids near
the wellbore are produced.
 Production tests may aid in differentiating between low
permeability and formation damage.
 Matrix acidizing of low permeability undamaged
reservoirs can only provide a small productivity increase.
Development Phase
September – October 2005
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Low reservoir permeability
 Effect of matrix acidizing an undamaged well.
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Low reservoir pressure
 Should be documented by periodic subsurface measurements.
 Dominant reservoir drives in a particular reservoir should be
considered and how these drive mechanisms are associated
with the real or apparent well problem being investigated.
 Prior to considering workover of wells in a low or partially
pressure-depleted oil reservoir, an effective artificial lift should
be planned.
 Pressure maintenance or an enhanced recovery programme is
usually the best long range approach to increase production
rate and oil or gas recovery from partially pressure-depleted
reservoirs.
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Low Reservoir Pressure
 Typical pressure-production history for various
reservoir-drive mechanisms.
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Water production problems
 May result from:
– Natural water drive or Waterflood, aggravated by
fingering or conning.
– Extraneous sources including casing leaks or
cementing failures.
– Fracturing or acidizing into adjacent water zones
or to below the water-oil contact.
Development Phase
September – October 2005
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Water production problems
 Water encroachment is normal in a water drive reservoir. Three
water-oil contacts may usually be defined in oil wells:
– Lower water-oil contact
– Producing water-oil contact
– Completion water-oil contact
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Water production problems
 Fingering
 Water conning
 Water channelling
Conning of Water
Irregular water encroachment in heterogeneous
reservoir can result in early water breakthrough.
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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– Cements
– Resins and hard set chemicals
– Gel treatments
– Swelling chemicals & particulates
– Relative permeability modifiers
Water Production- Chemical Control Techniques
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Quick reference guide-Treatment options for excess water
Water Production- Chemical Control Techniques
Development Phase
September – October 2005
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 Cement solutions
– Casing & tubing leaks
– Channels behind casing
– If primary cement job fails
– Squeeze cementing
Water Production- Chemical Control Techniques
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 Resins and other hard set chemicals
– Low viscosity chemical mixtures that set up as
solid or hard inert plastic.
– Resins are phenolic or epoxy base types.
– Used in casing patches
– Plug off cement channels and perforations
Water Production- Chemical Control Techniques
Development Phase
September – October 2005
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 Gel treatments
– Low viscosity chemical mixtures that stiffen at
varying degrees of temperatures.
– Reduce or totally block a channel or high-
permeability rock matrix zone through which
excess water is flowing into wellbore.
– Carried out by mechanically isolating only the
zone, fractures or perforations that are the
source
– Heavy metal cross linkers such as Chrome or
aluminium based
Water Production- Chemical Control Techniques
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Water Production- Chemical Control Techniques
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Placement Techniques
 Bullheading
 Mechanical packer placement
 Chemical packer placement
 Dual injection
 Iso-flow placement
 Transient placement
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 Bullheading
– Injection of chemicals
through existing
Tubulars.
– Used only when it is
determined that
aqueous injection
fluids will only enter
those water
producing zones that
are shut-in
Placement Techniques
Development Phase
September – October 2005
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 Mechanical/Inflatable Packer
– Selective zones are
isolated using packers.
– In complex situations, it
maybe necessary to
isolate perforations that
are producing oil from
both above and below the
zone- Inflatable Dual
Packer System
 Chemical Packers
– In gravel packed or open
hole completions where
mechanical packers
cannot be used.
Placement Techniques
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 Dual Injection Placement
– Compatible fluids are injected down the
tubing and also annulus.
– Packers, bridge plugs, chemical plugs and
other mechanical isolation means can be
used.
– Efficient placement
– To protects critical perforations in
hydrocarbon zones-Non-sealing fluid
compatible with formation is used.
Placement Techniques
Development Phase
September – October 2005
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 Isoflow Placement
– Alternative to dual injection
system.
– Chemicals are directed into
selected intervals while
protecting hydrocarbon
producing or bearing zones
by simultaneous injection of
non-sealing formation
compatible fluid.
– Gamma ray logging tools are
used to locate and track fluid
interface.
– Suited for both wells with
negative surface pressures
and static fluids when shut
in.
Placement Techniques
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 Inner Liners
 Patches
 Packers
 Sliding sleeves
 Plugs
Water Production- Mechanical Techniques
Development Phase
September – October 2005
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 Casing cladding
– Thermally set composite
materials used to form
patches to fix damage
Tubulars.
– Using inflatable systems to
carry composite materials
into the well.
– Materials are usually
thermally setting resins and
carbon fibres built into a
sleeve wrapped around the
device.
– Once device is opposite the
area to be treated, device is
inflated to push composite
sleeve into place moving
upwards.
– After inflation, the sleeve is
heated to harden and
conform to casing.
– Electric resistors provide
heating.
Water Production- Mechanical Techniques
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 Packer straddle
– It’s a combination
of packers, sliding
sleeves and other
tools to isolate
excess water
production zones
or areas of
damaged pipe.
Water Production- Mechanical Techniques
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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 Bridge Plugs
– Run and set to
plug off water
entering the
bottom of well or
perforations.
– Essentially plugs-
off remainder of
well or tubing
from the point of
setting all the
way to bottom of
the well.
Water Production- Mechanical Techniques
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Gas problems in Oil wells
 The primary sources of gas in oil wells are:
– Gas dissolved in the oil
– Primary or secondary gas caps which may expand, and
– Gas flow from zones or reservoirs above or below the oil zone
 Normal GOR behaviour corresponding to the drive mechanism for any
particular reservoir must be considered in problem well analysis.
Characteristic gas-oil performance for various reservoir-drive mechanisms
Development Phase
September – October 2005
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Gas problems in oil wells
 Gas flow from zones above or below the oil
zone may be due to:
– Casing leaks
– Poor cement job
– Natural or induced fractures communicating with
gas zone
 Gas flow due to channel behind the casing
 Reservoir with a gas cap
 Problem due to gas conning
 Problem due to gas cap expansion
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High Viscosity Oil
 High viscosity is sometimes defined as oil with less than
16 API gravity. Viscosities grater than 200 cp often cause
serious flowing and pumping problems.
 Thermal stimulation may be applicable, however
economics should be carefully reviewed.
 It the well tubing, casing, cement job, and packer
installation has not been designed to withstand high
temperature steam, thermal stimulation may cause
severe mechanical damage to the well.
 Alternative to Thermal Stimulation of the Reservoir can
be considered.
Development Phase
September – October 2005
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INTRODUCTION TO HYDROCARBON EXPLOITATION
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Artificial Lift
 Most wells will probably require some sort of artificial lift before
abandonment to increase drawdown and thus production.
 Selection
– Revenue due to oil and gas production
– Operating costs, and
– Initial capital costs
Factors contributing to economics of
artificial lift systems
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Sucker Rod Pumping
Walking Beam
Pitman Arm
Saddle Bearing
Horsehead
Bridle
Hanger
Ladder
Wrist
Pin
Crank Arm
Counterweight
Prime
Mover
Brake
Lever
Base
Samson
Post
Equalizer
Bearing
Brake
Cable
Polished Rod
Stuffing Box Seal
Flow Line
Flow Tee
Rod String
Downhole Pump
Production Tubing
Production Casing
Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas
Development Phase
September – October 2005
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Sucker Rod Pumping
 Analysis:
– Check the well test production rates. Is the rate limited by the
pump displacement.
– If the well cannot be pumped off, or pumped down to a low intake
pressure with the existing equipment on the well, determine if a
larger unit is justified.
– If the well is pumped off, use time cycle to alter displacement to
match formation inflow.
– If test rates suddenly decline on a well, check for mechanical
problems.
– If decline in test rate is not a mechanical problem, then formation
damage, fill in annulus or perforation plugging may be the problem.
– Gas interferences is a common problem on many pumping wells.
Where feasible vent the gas up the annulus and pump the oil and
water up the tubing.
– Corrosion and scale are often major problems in pumping wells.
– Paraffin deposition is another common problem.
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Gas Lift
 Continuous Flow
 Intermittent lift
Gas Lift Systems
Injected
gas
Injected
gas
Continuous gas lift
Intermittent gas lift
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Gas Lift
Liquid
Gas entry
Tubing
Casing
Production
Gas in
Liquid
Tubing Casing
Gas in
Production
Annular gas injection
Tubing gas injection
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Gas Lift Surveillance and Operating
Problems
 Good well tests are essential to gas lift operation.
 Periodic flowing pressure bottom-hole pressure surveys are
recommended.
 Temperature surveys are often beneficial for both design
purposes and troubleshooting.
 Sonic devices can be used to shoot fluid levels in the annulus of
gas lifted wells.
 To produce at maximum rates, the injection gas depths should
be at maximum depths.
 If there is a decrease in production test rate, the data should
be carefully reviewed.
 In intermittent gas lift there are additional producing problems
to consider.
 Check the flowing wellhead test pressures. High back pressure
is normally very detrimental to gas lift operations.
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Electrical Submersible Pumping
Perfs.
Seal
Pump intake
Pump
Tubing
Check valve (optional)
Drain valve (optional)
Casing
Motor
Pothead
Motor flat splice
Motor flat cable
Primary cable
Production
Wellhead
Junction
box
Motor
controller
Transformers
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ESP Motor Problems
 Major causes of motor
overheating
– Overloading
– Well pumped off
– Gas locked
– Stuck pump
– Lack of cooling
 tubing or casing leak, scale,
motor laying against the
casing
Bearing
Motor thrust bearing
components & complete
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Problems with ESP's
 Cable failure (generally due to fluids penetrating the covering)
 Protector leakage (fluids may contact motor)
 Too much free gas
 Burnt motor can be caused by:
– Contact with fluids due to protector leakage
– Poor fluid circulation around motor for cooling
– Corrosion of motor housing
 Pump failure can be caused by
– Solids
– Pumping at rates/pressures outside of designed range
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Identifying problems with ESPs
 May notice gradual increase in power usage and gradual
decrease in flow rate as indicators of pump problems
 Power spikes and frequent automatic shut-downs may
indicate electrical leakages or other problems
 Check for solids in fluid
 Tubing, cable, and pump must be pulled to find exact
cause of a problem. Spool required to handle cable
 Pump, seal, motor, and cable must be sent to
manufacturer for testing in order to locate the exact
problem
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Electrical Submersible Pumping
 Requires a rather precise design
 Good operating practices
 Careful equipment selection and repair
 Reliable field electrical system
 Stable operating conditions, and only
moderately high temperatures for successful
operation over well life
 Selection of the electrical cable should provide
five years or longer trouble-free operating life.
 ESP are adversely affected by free-gas, sand,
scale, and corrosion.
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ESP Surveillance and Analysis
 Well production test are the basic surveillance
method
 A pump size should be chosen that will not
pump the well off. Minimum pump intake
pressures of 250 psig may be feasible, but 500
psig is a more realistic design.
 Electrical problems are common and must
receive prompt attention. Good lighting
protectors are essential in many areas.
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Hydraulic Pump and Jet System
Power fluid
Pump tubing
Casing
Nozzle
Production inlet
chamber
Throat
Diffuser
Combined
fluid return
Well production
Jet pump
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Hydraulic Pump and Jet System
Engine
Pump
Power fluid
injection
Power fluid return
Production
(A)
Closed power
fluid system
Engine
Pump
Production and return
Power fluid
injection
(B)
Open power
fluid system
Production and
return
Pump
Engine
Power fluid injection
(C)
Open power
fluid system
(free pump)
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Hydraulic Pump and Jet Systems
 The user has several options in the design and
installation of hydraulic reciprocating pumps:
– Individual well units, or a central system
– Standard fixed pumps, or free pumps
– Open, or closed power oil systems, and
– Vented, or non-vented gas systems
 Clean power fluid, normally oil, is essential to
good pump runs.
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Hydraulic Pumping Surveillance
 Well production tests are the primary means of
surveillance. The test data includes the oil, water and,
gas rates plus the injection power fluid rate and pressure
and the wellhead pressure.
 A significant decline in production rate my result from
formation damage (skin) or be from inadequate pump
displacement, pump wear, pump gas interference
problems, or leaks.
 Leaks are more likely in hydraulic systems since
pressures are higher and there is more exposure due to
the use of power oil lines and power fluid tubing.
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Mechanical Failure in Wells
 Different types of mechanical failures can cause
loss of production and/or increase costs in well
operation. More common problems are:
– Primary cement channelling
– Casing, tubing, and packer leaks,
– Artificial lift equipment, and
– Well equipment, like wellheads, subsurface
valves, sliding sleeves, etc.
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Sand Control
 Wells that sand-up or produce more than 0.1
percent sand are often good candidates for
sand control.
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Unconsolidated Consolidated
Zero strength Very very weak Very weak Consolidated
Dry sand Damp sand Weakly-cemented Stronger cement
Sand Control
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In weak but consolidated formations:
Stage 1
Failure
Stage 1
Failure
Stage 2
Transportation
Stage 2
Transportation
Failure of reservoir
rock due to shear
stresses (failure of
bonds between grains)
Transportation of
failed material due to
flow
Sand Control
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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 Overburden
 Friction
 Differential Stresses
 Cementing Material
 Degree of Consolidation
 Fluid Viscosity
 Production Velocity
 Water Production
Factors Affecting Sand Production
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 Failure may occur
due to:
– Non uniform
lateral loading as
rock is produced.
– High axial
compressive load
due to slumping of
the overlying
casing-bearing
formation.

Sand Problems-Casing / Liner Collapse
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Sand production can cause erosion in both surface and downhole
equipment such as :
 Downhole
 Blast Joints
 Chokes
 Gas lift Equipment
 Elbows / Tees
 Standing Valves
 Pumps
 Valves
 Metering Devices
 Circulating sleeves
 Flanges
 Nipples
 Wellhead
 Tubular
Sand Problems- Erosion
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 Bridges may form in casing
or tubing and obstruct well
flow.
 They must be removed by
bailing or washing with
concentric strings.
 If bridging is severe sand
control will be required.
Sand Problems- Erosion
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Sand Control Methods
 Restrictive Production Rate
 In Situ Consolidation
 Resin Coated Gravel
 Gravel Pack
 Screens - Natural Sand Packing (OH)
 Expandable Sand Screens
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Restrictive Production Rate
 Some weak formations have enough
strength to produce sand-free at low
rates.
 Selective perforations placed in the
strongest formation (based on logs)
 Rock properties may change during the
production (i.e., water production).
In Situ Consolidation
 Resin material is pumped into the
formation.
 Furan Resin “glues” formation grain-
grain into a consolidated structure
 Compressive strength >1,000 psi with
60-75% retained permeability.
Sand Control Methods
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Resin Coated Gravel
 Proppant ( Gravel ) is pre-
coated with resin
material.
 Particles are mixed with
viscous gel and pumped
into the formation.
 Particles are contacted
grain-to-grain.
 Temperature + H2O fuses
the particles together into
a consolidated permeable,
drillable network.
Resin
Formation
(Unconsolidated)
Gravel
Sand Control Methods
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Natural Sand Packing (Screens)
 Installation of a screen system (no particles) in cased or open hole.
 Main horizontal completion option.
 Screen system can be :
– slotted liner
– pre-pack screen
– wire wrapped
 Annular is eventually filled with formation sand.
Sand Control Methods
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Slotted liners
 One of the older methods of sand control.
 They are tubing sections with a series of slots cut through the tubing
wall in an axial orientation.
 The slot width is designed to initiate inter-particle bridging across the
slot. It was originally considered that it should be twice the diameter of
the 10 percentile sand grains .
 There are two types of slot available, keystone and straight
Sand Control Methods
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Wire Wrapped
 There are three main types of wire-
wrap screen; rod-based screens, pipe-
based slip-on and pipe-based direct
build screens.
 Normally made from triangular shaped
wrap wire
 The gap between the edges of the
wrap wire is sufficient to allow quite
large sand grains to pass through.
Sand Control Methods
Gap
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Pre-packed screens
 Similar configuration to the wire
wrap but use a different filtering
media.
 A layer of resin-coated gravel is
placed around the internal
screen assembly and is
supported by a shroud or
external screen.
 The thickness of the filtering
medium layer, and hence the
outside diameter of the screen
depends on the specific well
requirements.
 Limitations in mechanical
strength
Sand Control Methods
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Premium screens
 typically an all-metal design, with a metal mesh filtration media and
a protective outer metal shroud.
 The metal mesh can be either a metal weave or metal fibres or
powder particles embedded within a square metal mesh.
 The apertures (called pore throats) generally very from 60 micron
to 300 micron.
 The concept is that the mesh will prevent the larger sand particles
from travelling through and allow the formation fines to pass.
 Premium screens are typically run in long horizontals, often behind
gravel packs and have similar sand control properties to pre-pack
screens.
Sand Control Methods
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Gravel pack
 The annulus between the
wellbore and a sand control
screen (wire wrapped, or
premium) is filled with gravel
that is sized to prevent sand
from the formation passing
through the pack.
 Gravel packing in open-hole
(EGP – External Gravel Pack) is
useful for preventing annular
flow and controlling sand in
heterogeneous formations.
 Gravel packing in cased-holes
(IGP – Internal Gravel Pack) is
useful for protecting the sand
screens from erosion flow. After
the liner is run and perforated,
the sand face completion is
run. The perforations may then
be washed and the GP packer
set.
Sand Control Methods
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Frac pack
 Improve the productivity of
a well by creating a short,
wide fracture close to the
wellbore.
 A proppant is placed inside
the fracture that will both
hold open the fracture and
control sand production.
 Frac packs are also termed
‘high permeability fractures’
(HPF)
 In Frac packing the fractures
tend to be shorter but much
wider.
 Typical frac pack crack
widths can be 1 inch or
potentially larger.
 The lengths vary depending
on the design and are
usually in the region of 20 to
50 feet.
Fracture filled
with gravel
/proppant
wellbore packed
with screen in
wellbore
Wellbore free of
equipment
Fracture filled
with resin coated
gravel /proppant
Sand Control Methods
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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 ESS (Expandable
Sand Screens)
Sand Control Methods
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Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Re-completion
 Can be avoided by careful planning and anticipation of
problems on the initial well completion.
 The usual workover procedure for changing zones or reservoirs
in perforated casing completion is merely to squeeze cement
and re-perforate in the new zone in the reservoir.
 In open hole, it may be necessary to deepen or plug back, or to
cement a liner and selectively perforate a specific zone in the
reservoir.
 Changing the producing interval in both single and multiple
completions are relatively simple operations if the operation
can be carried out through-tubing.
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Plug and Abandonment
 Most zones or reservoirs must be eventually plugged and
abandoned.
 Most governmental regulating bodies have specific
guidelines that must be followed.
 Careful considerations should be given to all options
before plugging a well.
 If a well is no longer economical to produce, has no use
as a service well, or has no use as a service well, or has
serious mechanical conditions, then immediate steps
should be taken to plug and abandon the zone.
Development Phase
September – October 2005
©abalt solutions limited - 2005
INTRODUCTION TO HYDROCARBON EXPLOITATION
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Workover Economics
 The team concept is a significant factor in
optimizing creative skill and imagination in:
– Fact finding
– Analysis
– Experimentation
– Job execution, and
– Evaluation of results
 Considering workover on programme basis
 Profitability analysis