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Lesson 12
Selecting an Appropriate Technique
Read: UDM Chapter 4
pages 4.1-4.54
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Selecting an Appropriate
Technique
• Potential Applications and Candidate
Technique
• Technical Feasibility
• Economic Analysis
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Harold Vance Department of
Petroleum Engineering
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Required data for UBO
Candidate Identification:
•
•
•
•
Pore pressure/gradient plots
Actual reservoir pore pressure
ROP records
Production rate or reservoir characteristics
to calculate/estimate production rate
• Core analysis
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Harold Vance Department of
Petroleum Engineering
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Required data for UBO
Candidate Identification:
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•
•
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•
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Formation fluid types
Formation integrity test data
Water/chemical sensitivity
Lost circulation information
Fracture pressure/gradient plot
Harold Vance Department of
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Required data for UBO
Candidate Identification:
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•
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•
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Sour/Corrosive gas data
Location topography/actual location
Well logs from area wells
Triaxial stress test data on any formation
samples
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Poor candidates for UBD
• High permeability coupled with high pore
pressure
• Unknown reservoir pressure
• Discontinuous UBO likely (numerous trips,
connections, surveys)
• High production rates possible at low
drawdown
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Poor candidates for UBD
• Weak rock formations prone to wellbore
collapse at high drawdown
• Steeply dipping/fractured formation in
tectonically active areas
• Thick, unstable coal beds
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Poor candidates for UBD
• Young, geo-pressure shale
• H2S bearing formations
• Multiple reservoirs open with different
pressures
• Isolated locations with poor supplies
• Formation with a high likelihood of
corrosion
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Good candidates for UBD
• Pressure depleted formations
• Areas prone to differential pressure sticking
• Hard rock (dense, low permeability, low
porosity)
• “Crooked-hole” country and steeply dipping
formations
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Good candidates for UBD
• Lost-returns zones
• Re-entries and workovers (especially
pressure depleted zones)
• Zones prone to formation damage
• Areas with limited availability of water
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Good candidates for UBD
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•
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Fractured formations
Vugular formations
High permeability formations
Highly variable formations
Harold Vance Department of
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Good candidates for UBD
• Once the optimum candidate has been
identified, the appropriate technique must
be selected, based on much of the same data
required to pick the candidate.
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Candidate Decision Tree
Harold Vance Department of
Petroleum Engineering
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Candidate Decision Tree
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Candidate Decision Tree
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Candidate Decision Tree
Harold Vance Department of
Petroleum Engineering
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Harold Vance Department of
Petroleum Engineering
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Harold Vance Department of
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These decision trees can be found on the IADC website
(www.iadc.org).
Click on Committees
Click on Underbalanced Drilling committee
Click on decision tree.
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Potential Applications and
Candidate Technique
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Low ROP through hard rock
• Dry air
• Mist, if there is a slight water inflow
• Foam, if there is heavy water inflow, if the
borehole wall is prone to erosion, or if there
is a large hole diameter.
• Nitrogen or natural gas, if the well is
producing wet gas and it is a high angle or
horizontal hole.
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Lost circulation through the
overburden
• Aerated mud, if the ROP is high (rock
strength low or moderate) of if watersensitive shales are present.
• Foam is possible if wellbore instability is
not a problem
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Differential sticking through the
overburden
• Nitrified mud, if gas production is likely,
especially if a closed system is to be used.
• Aerated mud, if gas production is unlikely
and an open surface system is to be used.
• Foam is possible if the pore pressure is very
low and if the formations are very hard
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Formation damage through a
soft/medium-depleted reservoir
• Nitrified brine or crude
– string injection, if the pore pressure is very low
– parasite injection, if the pore pressure is high
enough and a deviated/horizontal hole needs
conventional MWD and/or mud motor
– Temporary casing injection, if the pore pressure
is intermediate and a high gas rate in needed.
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Formation damage through a
soft/medium-depleted reservoir
• Nitrified brine or crude, con’t
– String and temporary casing injection, if the
pore pressure is very low and/or if very high
gas rates
• Foam, if the pore pressure is very low and
an open surface system is acceptable
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Formation damage through a
normally pressured reservoir
• Flowdrill (use a closed surface system if
sour gas is possible)
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Lost circulation/formation
damage through a normally
pressured, fractured reservoir
• Flowdrill (use an atmospheric system if no
sour gas is possible)
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Formation damage through an
overpressured reservoir.
• Snub drill (use a closed surface system is
sour gas is possible)
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Technical Feasibility
• In evaluating the feasibility of a technique,
a controlling factor is the range of
anticipated borehole pressures which will be
required for each zone to be drilled.
• The upper limit is formation pore pressure
• Lower limit will be determined by wellbore
stability.
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Technical Feasibility
• First step is to determine the anticipated
pressures.
• Step two is to determine which methods are
functional within the anticipated pressure
window.
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Technical Feasibility
• Other considerations are:
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Will there be sloughing shales?
Are aqueous fluids inappropriate?
Will water producing horizons be penetrated?
Will multiple, permeable zones, with
dramatically different pore pressures, be
encountered?
Harold Vance Department of
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Technical Feasibility
• Other considerations con’t:
– What is the potential for chemical formation
damage, due to fluid/fluid or fluid/formation
interaction and is this an overwhelming
problem, regardless of what wellbore pressure
is used?
– Is there a potential for sour gas production?
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Technical Feasibility
• Other considerations con’t:
– Are there features of the well geometry which
dictate specific underbalanced protocols?
– What is the local availability of suitable
equipment and consumables (including liquids
and gases for the drilling fluids)?
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Borehole pressure limits
• Pore pressure
– the wellbore pressure must be maintained
below the formation pressure in all open hole
sections.
– If there is no formation fluid inflow, borehole
pressures with dry gas, mist, foam or pure
liquid will be lower when not circulating.
– With fluid influx, borehole pressure can
increase or decrease when not circulating.
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Borehole pressure limits
• Pore pressure
– Best practice is to use the:
– lower bounds for pore pressure prediction when
choosing a technique
– while surface equipment capacity and drilling
specifics should be based on an upper bound.
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Borehole pressure limits
• Wellbore stability provides the lower limit
to the allowable borehole pressures.
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Borehole pressure limits
• Hydrocarbon production rates can
sometimes set the lower bound, depending
upon the surface equipment available.
• Formation damage may effect the tolerable
drawdown due to fines mobilization in the
producing formation.
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Borehole pressure limits
• Backpressure from a choke can sometimes
be used to protect the surface equipment
from excess production rates or pressures.
• This also increases the BHP.
• This is limited by the pressure rating of the
equipment and formation upstream of the
choke.
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Borehole pressure limits
• When using compressible fluids, it is
usually more cost effective to switch to a
higher density fluid than to choke back the
well.
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Borehole pressure limits
• Applying back pressure will:
– increase the gas injection pressure.
– Increase the gas injection rate required for
acceptable hole cleaning.
– These both will increase the cost of the gas
supply.
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Borehole pressure limits
• With a gasified liquid, BHP can usually be
increased by reducing the gas injection rate.
• When drilling with foam, back pressure
may be necessary to maintain foam quality.
• Holding back pressure is most beneficial
when drilling with liquids.
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Borehole pressure limits
• Once the maximum tolerable surface
pressure is reached, production rate can
only be further reduced by increasing
downhole pressure by increasing the
effective density of the drilling fluid.
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Implications of Drilling
Technique Selection
•
•
•
•
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Pore pressure gradients vary with depth
Formation strength varies with depth
In-situ stresses vary with depth
The tolerable stresses, are affected by by
the inclination and orientation of deviated,
extended reach and horizontal wells.
Harold Vance Department of
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Implications of Drilling
Technique Selection
• Production rates depend on the length of the
reservoir that is open to the wellbore and on
the underbalanced pressure
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Implications of Drilling
Technique Selection
• Once the borehole pressure limits,
corresponding to wellbore instability and
excessive production rate, have been
determined , a first pass evaluation of the
different drilling techniques can be
performed.
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Example 1
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Shallow, normally
pressured well.
No wellbore stability
problems
Surface equipment can
handle the anticipated
AOF.
Minimal water inflow is
expected.
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Example 2
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Depleted sandstone from
3000 to 4000 ft with a pore
pressure gradient of 5 ppg.
Pore pressure above the sand
is 8 ppg.
Lost circulation and sticking
is a problem with mud.
No instability problems
anticipated if borehole
pressure is > 2 ppg.
Production rate is low.
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Example 3
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Pore pressure = 8 ppg
Shale from 6-8000’ requires a
minimum wellbore pressure of
7 ppg
Target zone is 8-9000’
Reservoir itself is competent
unless borehole pressure < 5
ppg
Expect high flow rates w/
minimum drawdown = 500 psi
Pore pressure at 9000’ = 3744 psi, min BHP = 3244 psi or 6.93 ppg
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Example 4
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Maximum drawdown = 100 psi.
equivalent to 7.79 ppg.
Diesel or crude gives a pressure
lower than this. Plain water is
too dense.
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Example 5
Reservoir is depleted to
6.5 ppg. Maximum
drawdown is 500 psi. The
tolerable range for ECD
through the reservoir would
be 5.4-6.5 ppg. A gasified
liquid would be required.
This would not supply
sufficient support for the
shale above.
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Evaluating Highly Productive
Formations
• Require detailed numerical analyses of
circulating pressures.
• Formation fluid influx interacts with drilling
fluids which effect borehole pressure effecting influx rate.
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Evaluating Highly Productive
Formations
• When circulation stops, the influx lifts mud
from wellbore.
• This changes the borehole pressure and the
production rate.
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Evaluating Highly Productive
Formations
• Choking back the well returns further
complicates the calculation of borehole
pressures and production rate.
• If the fluid is incompressible, backpressure
changes BHP by the amount of pressure
applied.
• If the fluid is compressible, backpressure
changes density, velocity, and BHP
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Evaluating Highly Productive
Formations
• Uncertainty of input parameters in
simulators leads to uncertainty in output.
• In many cases these uncertainties can make
simulations in technique selection
unjustified.
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Water production
• Production of small quantities of water
makes dry gas drilling difficult.
• If offset wells have a history of water
production, dry gas drilling below the water
zone is probably impractical.
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Water production
• When misting, higher gas rates are required
to prevent slug flow.
• Slug flow can damage the borehole and
surface equipment.
• Higher injection rates and the increased
density in the annulus may require boosters
on the compressors.
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Water production
• Large water influxes may require foams.
• High disposal costs can sometimes make
mist drilling impractical.
• Higher density foams can decrease water
influx, however the increased volume of
make-up water may make disposal still
impractical.
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Water production
• If high water influx makes gas and foams
impractical, aerated mud or low density
liquids may be required.
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Multiple permeable zones
• If all zones are to be drilled UB, the
circulating pressure must satisfy the
borehole pressure requirements for all open
permeable zones, simultaneously.
• Several factors can prevent this from
happening.
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Factors preventing UB in all
zones
• The ECD of compressible fluids increases
with increasing depth.
• In vertical wells, it is possible for a
permeable zone close to the bit to be
overbalanced when a permeable zone higher
up hole, with the same pore pressure
gradient, is UB
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Factors preventing UB in all
zones
• This effect is more pronounced in high
angle and horizontal wells.
• AFP increases along the borehole even if
HSP remains relatively constant along the
borehole.
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Factors preventing UB in all
zones
• Changes in pore pressure gradient along the
wellbore may be present.
• This can be due to abnormally pressured
formations, or partially depleted formations.
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Multiple permeable zones
• The major concern with multiple permeable
zones is the potential for underground
blowouts.
• Extreme care must be taken to prevent this
from happening when pressure changes
occur such as tripping, or connections.
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If cross flows cannot be tolerated:
• Use a different drilling technique that
allows all permeable zones to remain UB, if
possible
• Kill the well before suspending circulation.
• Change the casing scheme so that the upper
formations are isolated behind pipe before
penetrating the producing zone.
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Sour gas
• There must be no possibility of releasing
hydrogen sulfide into the atmosphere while
the well is being drilled or completed.
• If any is produced during drilling it must be
disposed of in a suitable flare.
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Sour gas
• H2S can become entrained in any liquid in
the wellbore, and must be completely
removed from the fluid and flared before
any of the liquids are returned to any open
surface pits.
• The separation process should be completed
in a closed vessel.
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Sour gas
• Sour gas can become entrained in foams.
• The foam must be completely broken prior
to separation.
• Unless effective defoaming can be
guaranteed foams cannot be used in closed
systems, and should not be used in the
presence of Hydrogen Sulfide.
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Drilling/Reservoir fluid
incompatibility
• It can be difficult to prevent temporary
overbalance.
• Drilling fluids should be tested for
compatibility with formation fluids.
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Hole geometry
• A compressible fluid will have a greater
ECD in deep wells than in shallow wells.
• Annular gas injection only reduces the
density of the fluids above the injection
point. In deep wells drillstring injection
may be required.
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Hole geometry
• Increasing ECD with depth may make it
impossible to maintain the proper foam
quality in deep wells. Backpressure may be
required, increasing the gas supply needed.
• Increasing hole size makes hole cleaning
more difficult.
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Hole geometry
• Large hole sizes may require larger
diameter surface equipment. Larger surface
diverter equipment may not have the
pressure rating of smaller resulting in lower
back pressure capabilities.
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Naturally fractured formations
• In fractured formations, high viscosity
drilling fluids, circulating at low rates may
prevent hole enlargement and still maintain
UB.
• Stiff foams may be the preferred candidate.
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Logistics
• Water supplies may be limited in some
areas, and a technique that limits water use
may be chosen.
• Availability and access to the gaseous phase
can influence the choice of gas used.
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Logistics
• Offshore locations generally do not have the
same space available as land locations.
• Equipment used on surface locations may
not be suitable for offshore locations.
• Modular closed systems must be used
offshore.
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Logistics
• The high production rates necessary for
offshore wells to be economically viable
may make them unlikely candidates for
UBD.
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Economic Analysis
• Rules of thumb
– UBO increases costs 1.25 - 2.0 times the cost
per day over conventional
– but may be accomplished in 1/4 to 1/10 of the
time.
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Economic Analysis
• Rules of thumb
– In permeable rock ROP may be increased from
30% to 300% as well goes from overbalanced
to balanced
– Below balance ROP will increase another 1020%
– In impermeable rock, ROP will increase 100200%
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Steps for Economic Analysis
1. Determine the expected penetration rate or
drilling time of each candidate holeinterval, if the operation were to be carried
out conventionally
2. Estimate the daily cost of conventional
drilling operations for each prospective
hole-interval based on empirical data.
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Steps for Economic Analysis
3. Multiply the conventional daily cost by an
underbalanced factor (1.3-2.0, depending on
difficulty of the operation) to get the
expected daily cost of UBO
4. Apply the expected underbalanced
operating cost by the anticipated
underbalanced drilling ROP to get the total
cost for each interval.
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Factors that Effect the Economics
of Underbalanced Drilling
•
•
•
•
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Penetration rate
Bit selection
Bit weight and rotary speed
Mud weight
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Completions and Stimulation
• UBO does not save completion time
• but, if you are going to drill UB to prevent
formation damage, you better complete UB
• Mitigation of formation damage in wells
that will need to be hydraulically fractured
(except naturally fractured) may be a poor
and unnecessary economic decision.
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Formation Evaluation
• Real time formation evaluation possible
• UB coring possible
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Environmental Savings
• Closed systems make smaller reserve pits
and locations possible, but there is
additional costs of rental of the systems.
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Fluid Type
• The bottom line controlling factor may be
the specific fluid system adopted. Each
fluid type has technical and economic
advantages and limitations.
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Harold Vance Department of
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Harold Vance Department of
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Harold Vance Department of
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Harold Vance Department of
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Harold Vance Department of
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Harold Vance Department of
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Cost Comparisons - Case 1
Nitrogen vs. Pipeline Gas
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PETE 689 UBD
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Cost Comparisons - Case 1
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PETE 689 UBD
Cost Comparisons - Case 2
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PETE 689 UBD
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Economic Analysis
• On the basis of available technology, select
the potential drilling systems to be
evaluated.
• Tabulate the tangible and intangible costs
for each system
• Rely on previous history and recognize the
inevitability of statistical variation
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Economic Analysis
• Perform basic cost/ft drilling evaluations.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Assess Drilling Costs
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Accelerated Production
• Earlier production can improve the NPV
1
t
NPV 
 1  DR 
t
1  DR 
NPV  Net Present Value (discounte d value
of asset)
DR  Discount rate
t  discount t ime, years
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Improved Production/Reserves
• The absolute and relative increase in
production should be calculated, or
estimated.
• Productivity Index, PI should be calculated
based on whether the well is vertical,
horizontal, oil, gas, radial, transient flow, or
pseudo-steady state flow (see page 4.48)
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Improved Production/Reserves
• Well Inflow Quality Indicator, WIQI, is the
ratio of the PI for an impaired to that for an
undamaged well.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Improved Production/Reserves
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Improved Production/Reserves
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Improved Production/Reserves
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Example
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Oil well
Revenue Interest
= R = 0.375
Working Interest
= WI = 0.5
Gross Income (per net bbl)
Crude Price
= $20.00/bbl
Less
Transportation
= $1.00/bbl
Production taxes
= $6.00/bbl
Leaves
Gross Income (per net bbl) = $13.00/bbl
Estimated Op. Expense
= $5000/well month
Number of wells
=5
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Case 1
• All five wells drilled in the first year with a
conventional mud system.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Case 2
• Same as Case 1 with the exception that
there is higher production to reduced
formation damage from UBD.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Case 3
• Same as case 2 with the exception that
development costs for the five wells are
$150,000 less, due to improved drilling
while underbalanced.
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
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Summary of Examples
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Harold Vance Department of
Petroleum Engineering
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PETE 689 UBD
Summary of Examples
Harold Vance Department of
Petroleum Engineering
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