Lesson 12Lesson 12Selecting an Appropriate Selecting an Appropriate
TechniqueTechnique
Read: UDM Chapter 4 Read: UDM Chapter 4
pages 4.1-4.54pages 4.1-4.54
PETE 689PETE 689 Underbalanced Drilling Underbalanced Drilling
(UBD)(UBD)
Harold Vance Department of Petroleum Engineering
Selecting an Appropriate Selecting an Appropriate TechniqueTechnique
• Potential applications and Potential applications and candidate technique.candidate technique.
• Technical feasibility.Technical feasibility.• Economic analysis.Economic analysis.
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Required Data For UBO Required Data For UBO Candidate IdentificationCandidate Identification
• Pore pressure/gradient plots.Pore pressure/gradient plots.• Actual reservoir pore pressure.Actual reservoir pore pressure.• ROP records.ROP records.• Production rate or reservoir Production rate or reservoir
characteristics to characteristics to calculate/estimate production calculate/estimate production rate.rate.
• Core analysis.Core analysis.Harold Vance Department of Petroleum Engineering
• Formation fluid types.Formation fluid types.• Formation integrity test data.Formation integrity test data.• Water/chemical sensitivity.Water/chemical sensitivity.• Lost circulation information.Lost circulation information.• Fracture pressure/gradient Fracture pressure/gradient
plot.plot.
Required Data For UBO Required Data For UBO Candidate IdentificationCandidate Identification
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• Sour/Corrosive gas data.Sour/Corrosive gas data.• Location topography/actual Location topography/actual
location.location.• Well logs from area wells.Well logs from area wells.• Triaxial stress test data on Triaxial stress test data on
any formation samples.any formation samples.
Required Data For UBO Required Data For UBO Candidate IdentificationCandidate Identification
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Poor Candidates For Poor Candidates For UBDUBD
• High permeability coupled with High permeability coupled with high pore pressure.high pore pressure.
• Unknown reservoir pressure.Unknown reservoir pressure.• Discontinuous UBO likely Discontinuous UBO likely
(numerous trips, connections, (numerous trips, connections, surveys).surveys).
• High production rates possible at High production rates possible at low drawdown.low drawdown.
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• Weak rock formations prone to Weak rock formations prone to wellbore collapse at high drawdown.wellbore collapse at high drawdown.
• Steeply dipping/fractured formation in Steeply dipping/fractured formation in tectonically active areas.tectonically active areas.
• Thick, unstable coal beds.Thick, unstable coal beds.
Poor Candidates For Poor Candidates For UBDUBD
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• Young, geo-pressure shale.Young, geo-pressure shale.• HH22S bearing formations.S bearing formations.• Multiple reservoirs open with Multiple reservoirs open with
different pressures.different pressures.• Isolated locations with poor Isolated locations with poor
supplies.supplies.• Formation with a high likelihood Formation with a high likelihood
of corrosion.of corrosion.
Poor Candidates For Poor Candidates For UBDUBD
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Good Candidates For UBDGood Candidates For UBD
• Pressure depleted formations.Pressure depleted formations.• Areas prone to differential Areas prone to differential
pressure sticking.pressure sticking.• Hard rock (dense, low Hard rock (dense, low
permeability, low porosity).permeability, low porosity).• ““Crooked-hole” country and Crooked-hole” country and
steeply dipping formations.steeply dipping formations.
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• Lost-returns zones.Lost-returns zones.• Re-entries and workovers Re-entries and workovers
(especially pressure depleted (especially pressure depleted zones).zones).
• Zones prone to formation damage.Zones prone to formation damage.• Areas with limited availability of Areas with limited availability of
water.water.
Poor Candidates For Poor Candidates For UBDUBD
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Good Candidates For Good Candidates For UBDUBD
• Fractured formations.Fractured formations.• Vugular formations.Vugular formations.• High permeability formations.High permeability formations.• Highly variable formations.Highly variable formations.
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• Once the optimum candidate has Once the optimum candidate has been identified, the appropriate been identified, the appropriate technique must be selected, technique must be selected, based on much of the same data based on much of the same data required to pick the candidate.required to pick the candidate.
Good Candidates For Good Candidates For UBDUBD
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Candidate Decision Tree-Candidate Decision Tree-Sheet 1Sheet 1
Detailed engineeringDetailed engineering(cost, safety, reservoir,(cost, safety, reservoir,
Mechanical main drivers)Mechanical main drivers)
Previous history ofPrevious history ofunderbalancedunderbalanced
Operations (UBO)?Operations (UBO)?
Hydrocarbons anticipated
Go toSheet 2
No UBONo UBO
No UBONo UBO
No UBONo UBO
Lostcirculation
Stuckpipe
Harddrilling
(ROP/bit)
NoNo
YesYes
NoNo
NoNo
NoNo
NoNo
YesYes
NoNo
YesYes
YesYes
YesYes Cost/safetybenefits
CandidateCandidateYesYes
Drilling problems
anticipated
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NoNo
Candidate Decision Tree-Sheet Candidate Decision Tree-Sheet 22
Depletedreservoir
Go toSheet 3
No UBONo UBO
No UBONo UBO
DrillingProblems
anticipated
Lostcirculation
Stuckpipe
HardDrilling
(ROP/bit)
NoNo
NoNo
NoNo
NoNo
YesYes
NoNo
YesYes
YesYes
CandidateCandidate
No UBONo UBO
YesYes
Reservoir damageProduction impairment
Cost /safetybenefits
NoNo
YesYes
No UBONo UBONoNo
YesYes
YesYes
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This decision tree can be found on the IADC website This decision tree can be found on the IADC website (www.iadc.org).(www.iadc.org).
Click on Committees.Click on Committees.
Click on Underbalanced Drilling committee.Click on Underbalanced Drilling committee.
Click on decision tree.Click on decision tree.
Drillingproblems
anticipated
No UBONo UBO
NoNo
YesYes
No UBONo UBO
Candidate Decision Tree-Sheet 3
Lostcirculation
Reservoir damageProduction impairmentNo UBONo UBO
CandidateCandidate
NoNo
YesYes
YesYes
Cost /safetybenefits
YesYesStuckpipe
NoNo
HardDrilling
(ROP/bit)
NoNo
YesYes
NoNo
YesYes
NoNo
CandidateCandidate
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Potential Applications and Potential Applications and Candidate TechniqueCandidate Technique
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Low ROP Through Hard Low ROP Through Hard RockRock
• Dry air.Dry air.• Mist, if there is a slight water inflow.Mist, if there is a slight water inflow.• Foam, if there is heavy water inflow, Foam, if there is heavy water inflow,
if the borehole wall is prone to if the borehole wall is prone to erosion, or if there is a large hole erosion, or if there is a large hole diameter.diameter.
• NN22 or natural gas, if the well is or natural gas, if the well is producing wet gas and it is a high producing wet gas and it is a high angle or horizontal hole.angle or horizontal hole.
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Lost Circulation Through Lost Circulation Through The OverburdenThe Overburden
• Aerated mud, if the ROP is high Aerated mud, if the ROP is high (rock strength low or moderate) of (rock strength low or moderate) of if water-sensitive shales are if water-sensitive shales are present.present.
• Foam is possible if wellbore Foam is possible if wellbore instability is not a problem.instability is not a problem.
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Differential Sticking Differential Sticking Through The OverburdenThrough The Overburden• Nitrified mud, if gas production is Nitrified mud, if gas production is
likely, especially if a closed likely, especially if a closed system is to be used.system is to be used.
• Aerated mud, if gas production is Aerated mud, if gas production is unlikely and an open surface unlikely and an open surface system is to be used.system is to be used.
• Foam is possible if the pore Foam is possible if the pore pressure is very low and if the pressure is very low and if the formations are very hard.formations are very hard.
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Formation Damage Through A Formation Damage Through A Soft/Medium-Depleted Soft/Medium-Depleted
ReservoirReservoir
• Nitrified brine or crude.Nitrified brine or crude.► string injection, if the pore pressure is string injection, if the pore pressure is
very low.very low.► parasite injection, if the pore pressure parasite injection, if the pore pressure
is high enough and a is high enough and a deviated/horizontal hole needs deviated/horizontal hole needs conventional MWD and/or mud motor.conventional MWD and/or mud motor.
► Temporary casing injection, if the pore Temporary casing injection, if the pore pressure is intermediate and a high pressure is intermediate and a high gas rate in needed.gas rate in needed.
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• Nitrified brine or crude, con’t.Nitrified brine or crude, con’t.► String and temporary casing String and temporary casing
injection, if the pore pressure is injection, if the pore pressure is very low and/or if very high gas very low and/or if very high gas rates.rates.
• Foam, if the pore pressure is Foam, if the pore pressure is very low and an open surface very low and an open surface system is acceptable.system is acceptable.
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Formation Damage Through A Formation Damage Through A Soft/Medium-Depleted Soft/Medium-Depleted
ReservoirReservoir
Formation Damage Through Formation Damage Through A Normally Pressured A Normally Pressured
ReservoirReservoir
• Flowdrill (use a closed surface system if sour gas is possible).
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Lost Circulation/Formation Lost Circulation/Formation Damage Through A Normally Damage Through A Normally
Pressured, Fractured Pressured, Fractured ReservoirReservoir
• Flowdrill (use an atmospheric Flowdrill (use an atmospheric system if no sour gas is system if no sour gas is possible).possible).
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Formation Damage Formation Damage Through An Through An
Overpressured Reservoir.Overpressured Reservoir.
• Snub drill (use a closed surface Snub drill (use a closed surface system is sour gas is possible).system is sour gas is possible).
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Technical Technical FeasibilityFeasibility
• In evaluating the feasibility of candidate In evaluating the feasibility of candidate drilling techniques, a controlling factor drilling techniques, a controlling factor is the range of anticipated borehole is the range of anticipated borehole pressures which will be required for pressures which will be required for eacheach zone to be drilled.zone to be drilled.
• The upper limit for UB conditions is The upper limit for UB conditions is formation pore pressure.formation pore pressure.
• Lower limit will generally be regulated Lower limit will generally be regulated by the lowest pressure at which by the lowest pressure at which wellbore stability is ensured.wellbore stability is ensured.
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• First step is to determine the First step is to determine the anticipated pressures.anticipated pressures.
• Step two is to determine which Step two is to determine which methods are functional within methods are functional within the anticipated pressure window.the anticipated pressure window.
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Technical Technical FeasibilityFeasibility
• Other considerations are:Other considerations are:► Will there be sloughing shales?Will there be sloughing shales?► Are aqueous fluids Are aqueous fluids
inappropriate?inappropriate?► Will water producing horizons Will water producing horizons
be penetrated?be penetrated?► Will multiple, permeable zones, Will multiple, permeable zones,
with dramatically different pore with dramatically different pore pressures, be encountered?pressures, be encountered?
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Technical Technical FeasibilityFeasibility
• Other considerations con’t:Other considerations con’t:► What is the potential for chemical What is the potential for chemical
formation damage, due to formation damage, due to fluid/fluid or fluid/formation fluid/fluid or fluid/formation interaction and is this an interaction and is this an overwhelming problem, overwhelming problem, regardless of what wellbore regardless of what wellbore pressure is used?pressure is used?
► Is there a potential for sour gas Is there a potential for sour gas production?production?
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Technical Technical FeasibilityFeasibility
• Other considerations con’t:Other considerations con’t:► Are there features of the well Are there features of the well
geometry which dictate specific geometry which dictate specific underbalanced protocols?underbalanced protocols?
► What is the local availability of What is the local availability of suitable equipment and suitable equipment and consumables (including liquids consumables (including liquids and gases for the drilling fluids)?and gases for the drilling fluids)?
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Technical Technical FeasibilityFeasibility
Borehole Pressure Borehole Pressure LimitsLimits
• Pore pressurePore pressure► The wellbore pressure must be The wellbore pressure must be
maintained below the formation maintained below the formation pressure in pressure in allall open hole sections.open hole sections.
► If there is no formation fluid inflow, If there is no formation fluid inflow, borehole pressures with dry gas, mist, borehole pressures with dry gas, mist, foam or pure liquid will be lower when foam or pure liquid will be lower when not circulating.not circulating.
► With fluid influx, borehole pressure can With fluid influx, borehole pressure can increase or decrease when not increase or decrease when not circulating.circulating.
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• Pore pressurePore pressure Best practice is to use the:Best practice is to use the:
►Lower bounds for pore pressure Lower bounds for pore pressure prediction when choosing a prediction when choosing a technique.technique.
►While surface equipment While surface equipment capacity and drilling specifics capacity and drilling specifics should be based on an upper should be based on an upper bound.bound.
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Borehole Pressure Borehole Pressure LimitsLimits
• Wellbore stability provides Wellbore stability provides the lower limit to the the lower limit to the allowable borehole allowable borehole pressures.pressures.
• Will be discussed later.Will be discussed later.
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Borehole Pressure Borehole Pressure LimitsLimits
• Hydrocarbon production rates Hydrocarbon production rates can sometimes set the lower can sometimes set the lower bound, depending upon the bound, depending upon the surface equipment available.surface equipment available.
• Formation damage may effect Formation damage may effect the tolerable drawdown due to the tolerable drawdown due to fines mobilization in the fines mobilization in the producing formation.producing formation.
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Borehole Pressure Borehole Pressure LimitsLimits
• Backpressure from a choke can Backpressure from a choke can sometimes be used to protect the sometimes be used to protect the surface equipment from excess surface equipment from excess production rates or pressures.production rates or pressures.
• This also increases the BHP.This also increases the BHP.• The allowable backpressure is The allowable backpressure is
limited by the pressure rating of limited by the pressure rating of the equipment and formation the equipment and formation upstream of the choke.upstream of the choke.
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Borehole Pressure Borehole Pressure LimitsLimits
• 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 Borehole Pressure LimitsLimits
• 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 Borehole Pressure LimitsLimits
• With a gasified liquid, BHP can With a gasified liquid, BHP can usually be increased by reducing usually be increased by reducing the gas injection rate.the gas injection rate.
• When drilling with foam, back When drilling with foam, back pressure may be necessary to pressure may be necessary to maintain foam quality.maintain foam quality.
• Holding back pressure is most Holding back pressure is most beneficial when drilling with beneficial when drilling with liquids.liquids.
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Borehole Pressure Borehole Pressure LimitsLimits
• 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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Borehole Pressure Borehole Pressure LimitsLimits
Implications of Drilling Implications of Drilling Technique SelectionTechnique Selection
• Pore pressure gradients vary with Pore pressure gradients vary with depth.depth.
• Formation strength varies with Formation strength varies with depth.depth.
• In-situ stresses vary with depth.In-situ stresses vary with depth.• The tolerable stresses, are affected The tolerable stresses, are affected
by by the inclination and orientation by by the inclination and orientation of deviated, extended reach and of deviated, extended reach and horizontal wells.horizontal wells.
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• Production rates depend on Production rates depend on the length of the reservoir that the length of the reservoir that is open to the wellbore and on is open to the wellbore and on the underbalanced pressure.the underbalanced pressure.
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Implications of Drilling Implications of Drilling Technique SelectionTechnique Selection
• Once the borehole pressure limits, Once the borehole pressure limits, corresponding to wellbore corresponding to wellbore instability and excessive instability and excessive production rate, have been production rate, have been determined , a first pass determined , a first pass evaluation of the different drilling evaluation of the different drilling techniques can be performed.techniques can be performed.
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Implications of Drilling Implications of Drilling Technique SelectionTechnique Selection
Example 1Example 1
•Shallow, normally Shallow, normally pressured reservoir.pressured reservoir.
•No wellbore No wellbore stability problems.stability problems.
•Surface equipment Surface equipment can handle the can handle the anticipated AOF.anticipated AOF.
•Minimal water Minimal water inflow is expected.inflow is expected.
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Stability regimes for the well described in Stability regimes for the well described in Example 1.Example 1.
Bore
hole
Pre
ssu
re (
psi)
Bore
hole
Pre
ssu
re (
psi)
45004500
40004000
35003500
30003000
25002500
20002000
15001500
10001000
500500
00
True Vertical Depth True Vertical Depth (feet)(feet)
0 2000 4000 6000 8000 0 2000 4000 6000 8000 10000 10000
•Depleted sandstone Depleted sandstone from 3,000 to 4,000 ft from 3,000 to 4,000 ft with a pore pressure with a pore pressure gradient of 5 ppg. Pore gradient of 5 ppg. Pore pressure above the sand pressure above the sand is 8 ppg.is 8 ppg.
•Lost circulation and Lost circulation and differential sticking is a differential sticking is a problem with mud.problem with mud.
•No instability problems No instability problems anticipated if borehole anticipated if borehole pressure is > 2 ppg.pressure is > 2 ppg.
•Production rate is low.Production rate is low.
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Example 2Example 2
Bore
hole
Pre
ssu
re (
psi)
Bore
hole
Pre
ssu
re (
psi)
45004500
40004000
35003500
30003000
25002500
20002000
15001500
10001000
500500
00
True Vertical Depth (feet)True Vertical Depth (feet)
0 2000 4000 6000 8000 0 2000 4000 6000 8000 10000 10000
Stability regimes for the well described in Stability regimes for the well described in Example 2.Example 2.
•Pore pressure = 8 ppgPore pressure = 8 ppg
•Shale from 6,000-8,000’ Shale from 6,000-8,000’ requires a minimum requires a minimum wellbore pressure of 7 wellbore pressure of 7 ppgppg
•Target zone is 9,000’Target zone is 9,000’
•Reservoir itself is Reservoir itself is competent unless competent unless borehole pressure borehole pressure < 5 ppg< 5 ppg
•Expect high flow rates.Expect high flow rates.
•maximum drawdown maximum drawdown = 500 psi = 500 psi
•Pore p. at 9,000’ = 3,744 Pore p. at 9,000’ = 3,744 psipsi
•min BHP = 3,244 psi or min BHP = 3,244 psi or 6.93 ppg6.93 ppg
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Example 3Example 3
Bore
hole
Pre
ssu
re (
psi)
Bore
hole
Pre
ssu
re (
psi)
45004500
40004000
35003500
30003000
25002500
20002000
15001500
10001000
500500
00
True Vertical Depth True Vertical Depth (feet)(feet)
4000 5000 6000 7000 8000 9000 4000 5000 6000 7000 8000 9000 1000010000
Stability regimes for the wells described in Examples 3 Stability regimes for the wells described in Examples 3 through 5through 5
•Maximum Maximum drawdown = drawdown = 100 psi.100 psi.
•Equivalent to 7.79 Equivalent to 7.79 ppg.ppg.
•Diesel or crude Diesel or crude gives a pressure gives a pressure lower than this. lower than this. Plain water is too Plain water is too dense.dense.
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Example 4Example 4
Bore
hole
Pre
ssu
re (
psi)
Bore
hole
Pre
ssu
re (
psi)
45004500
40004000
35003500
30003000
25002500
20002000
15001500
10001000
500500
00
True Vertical Depth True Vertical Depth (feet)(feet)
4000 5000 6000 7000 8000 9000 4000 5000 6000 7000 8000 9000 1000010000
Stability regimes for the wells described in Examples 3 Stability regimes for the wells described in Examples 3 through 5through 5
•Reservoir is depleted Reservoir is depleted to 6.5 ppg. Maximum to 6.5 ppg. Maximum drawdown is 500 psi. drawdown is 500 psi. The tolerable range for The tolerable range for ECD through the ECD through the reservoir would be 5.4-reservoir would be 5.4-6.5 ppg. A gasified 6.5 ppg. A gasified liquid would be liquid would be required.required.
•This would not supply This would not supply sufficient support for sufficient support for the shale above.the shale above.
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Example 5Example 5
Bore
hole
Pre
ssu
re (
psi)
Bore
hole
Pre
ssu
re (
psi)
45004500
40004000
35003500
30003000
25002500
20002000
15001500
10001000
500500
00
True Vertical Depth True Vertical Depth (feet)(feet)
4000 5000 6000 7000 8000 9000 4000 5000 6000 7000 8000 9000 1000010000
Stability regimes for the wells described in Examples 3 Stability regimes for the wells described in Examples 3 through 5through 5
Evaluating Highly Evaluating Highly Productive FormationsProductive Formations
• Require detailed numerical Require detailed numerical analyses of circulating pressures.analyses of circulating pressures.
• Formation fluid influx interacts Formation fluid influx interacts with drilling fluids which effect with drilling fluids which effect borehole pressure - effecting borehole pressure - effecting influx rate.influx rate.
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• When circulation stops, the influx lifts mud from wellbore.
• This changes the borehole pressure and the production rate.
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Evaluating Highly Evaluating Highly Productive FormationsProductive Formations
• Choking back the well returns further Choking back the well returns further complicates the calculation of borehole complicates the calculation of borehole pressures and production rate.pressures and production rate.
• If the fluid is incompressible, If the fluid is incompressible, backpressure changes BHP by the backpressure changes BHP by the amount of pressure applied.amount of pressure applied.
• If the fluid is compressible, If the fluid is compressible, backpressure changes density, backpressure changes density, velocity, and BHP.velocity, and BHP.
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Evaluating Highly Evaluating Highly Productive FormationsProductive Formations
• Uncertainty of input parameters Uncertainty of input parameters in simulators leads to in simulators leads to uncertainty in output. uncertainty in output.
• In many cases these In many cases these uncertainties can make uncertainties can make simulations in technique simulations in technique selection unjustified.selection unjustified.
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Evaluating Highly Evaluating Highly Productive FormationsProductive Formations
Water ProductionWater 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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• When misting, higher gas rates When misting, higher gas rates are required to prevent slug are required to prevent slug flow.flow.
• Slug flow can damage the Slug flow can damage the borehole and surface equipment.borehole and surface equipment.
• Higher injection rates and the Higher injection rates and the increased density in the annulus increased density in the annulus may require boosters on the may require boosters on the compressors.compressors.
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Water ProductionWater Production
• Large water influxes may require Large water influxes may require foams.foams.
• High disposal costs can sometimes High disposal costs can sometimes make mist drilling impractical.make mist drilling impractical.
• Higher density foams can decrease Higher density foams can decrease water influx, however the increased water influx, however the increased volume of make-up water may make volume of make-up water may make disposal still impractical.disposal still impractical.
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Water ProductionWater Production
• If high water influx makes If high water influx makes gas and foams impractical, gas and foams impractical, aerated mud or low density aerated mud or low density liquids may be required.liquids may be required.
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Water ProductionWater Production
Multiple Permeable Multiple Permeable ZonesZones
• If all zones are to be drilled If all zones are to be drilled UB, the circulating pressure UB, the circulating pressure must satisfy the borehole must satisfy the borehole pressure requirements for pressure requirements for all open permeable zones, all open permeable zones, simultaneously.simultaneously.
• Several factors can prevent Several factors can prevent this from happening.this from happening.
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Factors Preventing UBFactors Preventing UB In All Zones In All Zones
• The ECD of compressible fluids The ECD of compressible fluids increases with increasing increases with increasing depth.depth.
• In vertical wells, it is possible In vertical wells, it is possible for a permeable zone close to for a permeable zone close to the bit to be overbalanced the bit to be overbalanced when a permeable zone higher when a permeable zone higher up hole, with the same pore up hole, with the same pore pressure gradient, is UB.pressure gradient, is UB.
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• This effect is more pronounced in This effect is more pronounced in high angle and horizontal wells.high angle and horizontal wells.
• AFP increases along the borehole AFP increases along the borehole even if formation pore pressure even if formation pore pressure remains relatively constant remains relatively constant along the borehole.along the borehole.
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Factors Preventing UBFactors Preventing UB In All Zones In All Zones
• Changes in pore pressure gradient Changes in pore pressure gradient along the wellbore may be present.along the wellbore may be present.
• This can be due to abnormally This can be due to abnormally pressured formations, or partially pressured formations, or partially depleted formations.depleted formations.
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Factors Preventing UBFactors Preventing UB In All Zones In All Zones
Multiple Permeable ZonesMultiple Permeable Zones
• The major concern with The major concern with multiple permeable zones is multiple permeable zones is the potential for underground the potential for underground blowouts.blowouts.
• Extreme care must be taken Extreme care must be taken to prevent this from to prevent this from happening when pressure happening when pressure changes occur such as changes occur such as tripping, or connections.tripping, or connections.
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If Cross Flows Cannot Be If Cross Flows Cannot Be Tolerated:Tolerated:
• Use a different drilling technique Use a different drilling technique that allows all permeable zones that allows all permeable zones to remain UB, if possible.to remain UB, if possible.
• Kill the well before suspending Kill the well before suspending circulation.circulation.
• Change the casing scheme so Change the casing scheme so that the upper formations are that the upper formations are cased of before penetrating the cased of before penetrating the lower zone in the hole.lower zone in the hole.
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Sour GasSour Gas
• There must be no possibility There must be no possibility of releasing hydrogen sulfide of releasing hydrogen sulfide into the atmosphere while the into the atmosphere while the well is being drilled or well is being drilled or completed.completed.
• If any is produced during If any is produced during drilling it must be disposed of drilling it must be disposed of in a suitable flare.in a suitable flare.
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• HH22S can become entrained in S can become entrained in any liquid in the wellbore, and any liquid in the wellbore, and must be completely removed must be completely removed from the fluid and flared before from the fluid and flared before any of the liquids are returned any of the liquids are returned to any open surface pits.to any open surface pits.
• The separation process should The separation process should be completed in a closed be completed in a closed vessel.vessel.
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Sour GasSour Gas
• Sour gas can become entrained Sour gas can become entrained in foams. in foams.
• The foam must be completely The foam must be completely broken prior to separation.broken prior to separation.
• Unless effective defoaming can Unless effective defoaming can be guaranteed foams cannot be guaranteed foams cannot be used in closed systems, and be used in closed systems, and should not be used in the should not be used in the presence of Hydrogen Sulfide.presence of Hydrogen Sulfide.
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Sour GasSour Gas
Drilling/Reservoir Fluid Drilling/Reservoir Fluid IncompatibilityIncompatibility
• It can be difficult to prevent It can be difficult to prevent temporary overbalance.temporary overbalance.
• Drilling fluids should be Drilling fluids should be tested for compatibility with tested for compatibility with formation fluids.formation fluids.
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Hole GeometryHole Geometry
• A compressible fluid will have a A compressible fluid will have a greater ECD in deep wells than in greater ECD in deep wells than in shallow wells.shallow wells.
• Annular gas injection only reduces Annular gas injection only reduces the density of the fluids above the the density of the fluids above the injection point. Drillpipe gas injection point. Drillpipe gas injection may be necessary if long injection may be necessary if long vertical sections are to be drilled vertical sections are to be drilled with gasified liquid.with gasified liquid.
Harold Vance Department of Petroleum Engineering
• Increasing ECD with depth Increasing ECD with depth may make it impossible to may make it impossible to maintain the proper foam maintain the proper foam quality in deep wells. quality in deep wells. Backpressure may be Backpressure may be required, increasing the gas required, increasing the gas supply needed.supply needed.
• Increasing hole size makes Increasing hole size makes hole cleaning more difficult.hole cleaning more difficult.
Harold Vance Department of Petroleum Engineering
Hole GeometryHole Geometry
• Large hole sizes may require Large hole sizes may require larger diameter surface larger diameter surface equipment. Larger surface equipment. Larger surface diverter equipment may not have diverter equipment may not have the pressure rating of smaller the pressure rating of smaller resulting in lower back pressure resulting in lower back pressure capabilities.capabilities.
Harold Vance Department of Petroleum Engineering
Hole GeometryHole Geometry
Naturally Fractured Naturally Fractured FormationsFormations
• In fractured formations, high In fractured formations, high viscosity drilling fluids, viscosity drilling fluids, circulating at low rates may circulating at low rates may prevent hole enlargement prevent hole enlargement and still maintain UB. and still maintain UB.
• Stiff foams may be the Stiff foams may be the preferred candidate.preferred candidate.
Harold Vance Department of Petroleum Engineering
LogisticsLogistics
• Water supplies may be Water supplies may be limited in some areas, and a limited in some areas, and a technique that limits water technique that limits water use may be chosen.use may be chosen.
• Availability and access to the Availability and access to the gaseous phase can influence gaseous phase can influence the choice of gas used.the choice of gas used.
Harold Vance Department of Petroleum Engineering
• Offshore locations generally Offshore locations generally do not have the same space do not have the same space available as land locations.available as land locations.
• Equipment used on surface Equipment used on surface locations may not be suitable locations may not be suitable for offshore locations.for offshore locations.
• Modular closed systems must Modular closed systems must be used offshore.be used offshore.
Harold Vance Department of Petroleum Engineering
LogisticsLogistics
• The high production rates The high production rates necessary for offshore wells necessary for offshore wells to be economically viable to be economically viable may make them unlikely may make them unlikely candidates for UBD.candidates for UBD.
Harold Vance Department of Petroleum Engineering
LogisticsLogistics
Economic AnalysisEconomic Analysis
• Rules of thumb.Rules of thumb.► UBO increases costs 1.25 - UBO increases costs 1.25 -
2.0 times the cost per day 2.0 times the cost per day over conventional.over conventional.
► but may be accomplished in but may be accomplished in 1/4 to 1/10 of the time.1/4 to 1/10 of the time.
Harold Vance Department of Petroleum Engineering
• Rules of thumb.Rules of thumb.► In permeable rock ROP may In permeable rock ROP may
be increased from 30% to be increased from 30% to 300% as well goes from 300% as well goes from overbalanced to balanced.overbalanced to balanced.
►Below balance ROP will Below balance ROP will increase another 10-20%.increase another 10-20%.
► In impermeable rock, ROP In impermeable rock, ROP will increase 100-200%.will increase 100-200%.
Harold Vance Department of Petroleum Engineering
Economic AnalysisEconomic Analysis
Harold Vance Department of Petroleum Engineering
Gas and mud effect on drilling time (after Moore, Gas and mud effect on drilling time (after Moore, 197419745656).).
Dep
th (
feet)
Dep
th (
feet)
40004000
30003000
20002000
10001000
00
80008000
70007000
60006000
50005000
1000100000
90009000
0 20 40 60 80 100 0 20 40 60 80 100 120120
Drilling DaysDrilling Days
Harold Vance Department of Petroleum Engineering
Dep
th (
feet)
Dep
th (
feet)Rotating Time Rotating Time (hours)(hours)0 10 20 30 40 50 60 70 80 0 10 20 30 40 50 60 70 80
90 100 90 100
500500
00
10001000
15001500
20002000
25002500
30003000
Air and water effect on drilling time (after Moore, Air and water effect on drilling time (after Moore, 197419745656).).
Steps for Economic Steps for Economic AnalysisAnalysis
1.Determine the expected penetration rate or drilling time of each candidate hole-interval, 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.
Harold Vance Department of Petroleum Engineering
3.3.Multiply the conventional daily Multiply the conventional daily cost by an underbalanced factor cost by an underbalanced factor (1.3-2.0, depending on difficulty (1.3-2.0, depending on difficulty of the operation) to get the of the operation) to get the expected daily cost of UBO.expected daily cost of UBO.
4.4.Apply the expected Apply the expected underbalanced operating cost by underbalanced operating cost by the anticipated underbalanced the anticipated underbalanced drilling ROP to get the total cost drilling ROP to get the total cost for each interval.for each interval.
Steps for Economic Steps for Economic AnalysisAnalysis
Harold Vance Department of Petroleum Engineering
Factors that Effect the Factors that Effect the Economics of UBDEconomics of UBD
• Penetration rate.Penetration rate.• Bit selection.Bit selection.• Bit weight and rotary Bit weight and rotary
speed.speed.• Mud weight.Mud weight.
Harold Vance Department of Petroleum Engineering
Completions and Completions and StimulationStimulation
• UBO does not save completion time.UBO does not save completion time.• But, if you are going to drill UB to But, if you are going to drill UB to
prevent formation damage, you prevent formation damage, you better complete UB.better complete UB.
• Mitigation of formation damage in Mitigation of formation damage in wells that will need to be wells that will need to be hydraulically fractured (except hydraulically fractured (except naturally fractured) may be a poor naturally fractured) may be a poor and unnecessary economic decision.and unnecessary economic decision.
Harold Vance Department of Petroleum Engineering
Formation EvaluationFormation Evaluation
• Real time formation Real time formation evaluation possible.evaluation possible.
• UB coring possible.UB coring possible.
Harold Vance Department of Petroleum Engineering
Environmental SavingsEnvironmental Savings
• Closed systems make Closed systems make smaller reserve pits and smaller reserve pits and locations possible, but locations possible, but there is additional costs there is additional costs of rental of the systems.of rental of the systems.
Harold Vance Department of Petroleum Engineering
Fluid TypeFluid Type
• The bottom line controlling factor may be the specific fluid system adopted. Each fluid type has technical and economic advantages and limitations.
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavingsProblems and/or Problems and/or
Potential Potential ExpendituresExpenditures
AirAir
High penetration rates and reduction in rig time.
Possible problems if water flow is encountered
Low bit cost Hole erosion, if poorly consolidated.
Low water requirement
Possibility of downhole fire, if hydrocarbons are encountered.
No mud removal Supplementary equipment rental.
Low additives cost Is not suitable for H2S
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavings Problems and/or Potential Problems and/or Potential ExpendituresExpenditures
Gas(Nitrogen orNatural Gas)
High penetration rates and reduction in rig time.
Problems if water flow is encountered.Cost of gas and/or rentals.
Low bit cost Hole erosion, if poorly consolidated.
Low water requirement
Cost is high if a market for the gas exist.
No mud removal Rig safety.
Low additives cost Supplementary equipment rental If H2S is expected, consider a closed system.
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavings Problems and/or Potential Problems and/or Potential ExpendituresExpenditures
Mist
High penetration rates and reduction in rig time.
Problems if substantial water flow is encountered. Gas Cost if air not used.
Low bit cost Hole erosion, if poorly consolidated.
Low water requirement
Shale stability.
No mud removal
Disposal of waste water/gas and supplementary rental cost.
Air-mist not suitable if H2S is present.
Modest additives cost.
Equipment rental.
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavingsProblems and/or Problems and/or
Potential Potential ExpendituresExpenditures
Stable foam
High penetration rates and reduction in rig time.
Considerable foamer cost. Gas cost if air not used.
Low bit cost. Careful metering required.
Low water requirement. Specialized metering equipment.
High solids carrying capacity. Defoaming.
Good hole cleaning capability.
Compatible with oil, salt water, calcium carbonate and most formation contaminants.
Considerable cost.
Can safely entrain a considerable volume of gas into aqueous foam, rendering in non-flammable until sumped.
Separation and disposal.
Can handle large flows of water.
Water disposal
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavingsProblems and/or Problems and/or
Potential Potential ExpendituresExpenditures
Stiff Foam
High penetration rates and reduction in rig time.
Considerable mud and chemical cost.Gas cost if air is not used.
Low bit cost. Fluid degradation possible if oil, salt water or calcium chloride are encountered.
Low water requirement. Specialized metering equipment.
High solids carrying capacity.
Defoaming.
Good hole cleaning capability.
Harold Vance Department of Petroleum Engineering
Drilling Drilling Method Method
or Fluid or Fluid SystemSystem
SavingsSavings Problems and/or Problems and/or Potential ExpendituresPotential Expenditures
Gasified Liquids
Higher bottomhole pressures.
Expense of running a parasite string or a temporary casing string.Higher gas rates are required.Slow pressure response if a parasite string is used.Low underbalance pressure may cause transient departures from underbalanced conditions and advantages to impairment reduction may be lost.
Improved directional drilling in comparison to dry gases or mist (refer to chapter 6).
Tool problems with drilling injection.
Reduced drillstring wear. Supplementary surface equipment.
Reduced potential for downhole fires in vertical holes with aqueous fluids.
Corrosion potential (and requirement for inhibitors 62) is air is used.
Harold Vance Department of Petroleum Engineering
Drilling Method Drilling Method
or Fluid Systemor Fluid SystemSavingsSavings Problems and/or Problems and/or
Potential ExpendituresPotential Expenditures
Flowdrilling
Higher borehole pressures reduce the possibility of instability.
Supplementary surface equipment and safety measures.
No gas supply system. Excessive production is possible.
Conventional mud motors and MWD units can be used.
Safety issues associated with oil and gas on drill site.
Mudcap Drilling
Can be used in situations where surface pressure is too high for flowdrilling.
Supplementary equipment and safety considerations.
Snub Drilling or CT
Can be used at pressures too high for conventional units and underbalanced drilling equipment.
Snubbing or CT unit.
Closed Systems
Environmental savings Equipment rental and operating cost
Can handle H2S. Better monitoring returns.
Cannot be used with explosive mixtures.
Harold Vance Department of Petroleum Engineering
Cost Comparisons - Cost Comparisons - Case 1Case 1
Nitrogen vs. Pipeline Nitrogen vs. Pipeline GasGas
General AssumptionsGeneral Assumptions
Flowrate…………………………………...3,000 cfmFlowrate…………………………………...3,000 cfmGas Price……………………………… $2.00/mcfGas Price……………………………… $2.00/mcfTrucking Distance……….... 50 miles (one Trucking Distance……….... 50 miles (one way) way) Drilling Hours/day……………....………… …… 20Drilling Hours/day……………....………… …… 20Average Gas Drilling Days/well…………… ….12Average Gas Drilling Days/well…………… ….12Diesel Usage/hour/unit…………….10.7 gallonsDiesel Usage/hour/unit…………….10.7 gallonsDiesel Fuel Price…………………... $ 0.80/gallonDiesel Fuel Price…………………... $ 0.80/gallonStandby Days (Equipment)/well…..……......... Standby Days (Equipment)/well…..……......... 44
Harold Vance Department of Petroleum Engineering
Cost Comparisons - Case 1Cost Comparisons - Case 1Nitrogen Drilling System CostNitrogen Drilling System Cost Pipeline Gas Drilling CostPipeline Gas Drilling Cost
Compressors (8) @ $135/unit/day
$ 12,960 Pipeline gas 43.2 mmcf @ $2.00/mcf
$ 86,400
Boosters (2) @ $200/unit/day (air use)
$ 4,800 Booster (2) $300/unit/day (gas use)
$ 7,200
Membrane Skids (2) @ $1,500/unit/day(1,800 cfm/skid)
$ 36,000 Drill Gas Unit (installed on location)
$ 1,000
Trucking/Transportation Fuel (delivered)
$ 9,200 Gas Line (2,000 feet) $ 1,800
25,680 gallons * $0.80/gallon $ 20,540 Trucking/Transportation Fuel (delivered)
$ 1,800
Mist Pump $ 1,500 5,138 gallons @ $0.80/gallon $ 4,110
Equipment Standby (4 days) $ 1,800 Mist Pump $ 1,500
Equipment Standby (4 days) $ 700
Total Nitrogen Drilling Total Nitrogen Drilling Cost/wellCost/well
$ $ 88,60088,600
Total pipeline Gas Total pipeline Gas Drilling Cost/wellDrilling Cost/well
$ $ 104,510104,510
Harold Vance Department of Petroleum Engineering
Item Liquid N2
Portable N2 Generating System
Drilling ProgramDrilling Program 90 days 90 days
NN22 1,500 scfm 1,500 scfm
Duration of NDuration of N22 requirementrequirement
240 hrs (10 days) 240 hrs (10 days)
NN22 Purity Purity Minimum 95 % (by volume)
Minimum 95 % (by volume)
NN22 Pressure Pressure 5,000 psi 5,000 psi
NN22 requirement requirement
1,500 scfm * 60 min/hr *
24 hr/day *10 days = 584,000 sm3
= 834,000 liters liquid N2
= 139 tanks
1,500 scfm * 60 min/hr * 24 hr/day *10 days =
584,000 sm3
Method of NMethod of N22 SupplySupply
Trucked in liquid N2(equipment rental)
On-site membrane(equipment purchase)
Cost Comparisons - Case Cost Comparisons - Case 22
Harold Vance Department of Petroleum Engineering
ItemItem Liquid NLiquid N22Portable NPortable N22
Generating SystemGenerating System
LogisticsLogistics
139 liquid N2 tanks, 1 evaporator and 1 diesel skid (141
containers)
4 skid maximum, 14 tonnes each, 1 power unit, 14 tonnes (5 containers)
Cost of UtilitiesCost of Utilities
(liquid N(liquid N2 2 , , electricity, diesel)electricity, diesel)
$ 1,284,000
Electrical power: 1,400 kW * 10 days * 24 hrs @
$0.05/kWh= $ 16,800
(Power unit rental included in capital cost)
MaintenanceMaintenance None10 % of interest and
depreciation$ 32,000
Capital CostCapital Cost NoneInterest and depreciation over 10 years $324,000
TOTALTOTAL Approximately $ 1,300,000
Approximately $ 375,000
Cost Comparisons - Case Cost Comparisons - Case 22
Harold Vance Department of Petroleum Engineering
Economic AnalysisEconomic Analysis
• On the basis of available On the basis of available technology, select the potential technology, select the potential drilling systems to be evaluated.drilling systems to be evaluated.
• Tabulate the tangible and Tabulate the tangible and intangible costs for each system.intangible costs for each system.
• Rely on previous history and Rely on previous history and recognize the inevitability of recognize the inevitability of statistical variation.statistical variation.
Harold Vance Department of Petroleum Engineering
• Perform basic cost/ft drilling evaluations.Perform basic cost/ft drilling evaluations.
Where:Where:CCTT……total cost/foot.……total cost/foot.B…….bit cost.B…….bit cost.CCrr……hourly rig cost. ……hourly rig cost. t……..rotating time.t……..rotating time.T…….round trip time.T…….round trip time.F…….footage per bit F…….footage per bit run.run.
CT = [B+Cr(t+T)] / F(4.12)(4.12)
Harold Vance Department of Petroleum Engineering
Economic AnalysisEconomic Analysis
Assess Drilling CostsAssess Drilling CostsItemItem Air DrillingAir Drilling Mud DrillingMud Drilling
IntervalInterval From 4,000 to 7,000 ft From 4,000 to 7,000 ft
Interval Length (F) (ft)Interval Length (F) (ft) 3,000 3,000
Penetration Rate Penetration Rate (ft/hr)(ft/hr)
30 15
Rotating Time (t) (hr)Rotating Time (t) (hr) 100 200
Bit Life (hr)Bit Life (hr) 100 100
Bits RequiredBits Required 1 2
Unit Bit CostUnit Bit Cost $ 4,800/bit $ 4,800/bit
Bit Cost (B)Bit Cost (B) $ 4,800 $ 4,800
Trip ScheduleTrip ScheduleTrip in to 4,000 ft
Trip out from 7,000 ft
Trip in to 4,000 ftTrip out from 5,500 ft
Trip in to 5,500 ftTrip out from 7,000 ft
Total Trip FootageTotal Trip Footage 11,000 ft11,000 ft 22,000 ft22,000 ft
Unit Trip TimeUnit Trip Time
(hr/1,000 ft)(hr/1,000 ft)1.51.5 1.51.5
Harold Vance Department of Petroleum Engineering
Assess Drilling CostsAssess Drilling CostsItemItem Air DrillingAir Drilling Mud DrillingMud Drilling
Trip Time (T) (hr)Trip Time (T) (hr) 16.5 33
Hourly Operating Hourly Operating CostCost
(C(Crr))$ 375/hr $ 250/hr
Cost / ft Cost / ft
[B+C[B+Crr(T+t)]/[F](T+t)]/[F][9,600+250(33+200)] / [3000]
$ 22.62 /ft
Competitive Cost for Competitive Cost for Air DrillingAir Drilling
[4,800+Cr(16.5+100)] / [3000]
= $ 22.62tCr = $ 541.29/hr
Barrels of Water That Barrels of Water That Can be Disposed of atCan be Disposed of at
$ 1.00/bbl$ 1.00/bbl
($541.29 - $375)/ $1.00 =166 * 24 = 3,984 BWPD
Barrels of Water That Barrels of Water That Can be Disposed of atCan be Disposed of at
$ 5.00/bbl$ 5.00/bbl
($541.29 - $375)/ $5.00 =33 * 24 = 798 BWPD
Barrels of Water That Barrels of Water That Can be Disposed of atCan be Disposed of at
$ 10.00/bbl$ 10.00/bbl
($541.29 - $375)/ $10.00 =16.6 * 24 = 400 BWPD
Harold Vance Department of Petroleum Engineering
Harold Vance Department of Petroleum Engineering
Cost
($/f
t)C
ost
($/f
t)
0 500 1000 1500 2000 2500 0 500 1000 1500 2000 2500 3000 3000
Economic water volume production (modified after Carden Economic water volume production (modified after Carden 1993199311).).
Barrels of Produced Water per DayBarrels of Produced Water per Day
2424
2525
2323
2222
2121
2020
1919
1818
1717
1616
1515
Accelerated ProductionAccelerated Production
• Earlier production can improve the NPV
NPV = 1 / (1+DR)t = (1+DR)-t
NPVNPV = net present value = net present value (discounted (discounted value of asset). value of asset).DRDR = discount rate.= discount rate.tt = discount time, years. = discount time, years.
Harold Vance Department of Petroleum Engineering
Improved Improved Production/ReservesProduction/Reserves
• The absolute and relative The absolute and relative increase in production should increase in production should be calculated, or estimated.be calculated, or estimated.
• Productivity Index, PI should Productivity Index, PI should be calculated based on be calculated based on whether the well is vertical, whether the well is vertical, horizontal, oil, gas, radial, horizontal, oil, gas, radial, transient flow, or pseudo-transient flow, or pseudo-steady state flow (see page steady state flow (see page 4.48).4.48).
Harold Vance Department of Petroleum Engineering
• Well Inflow Quality Indicator, Well Inflow Quality Indicator, WIQI, is the ratio of the PI for an WIQI, is the ratio of the PI for an impaired to that for an impaired to that for an undamaged well.undamaged well.
Harold Vance Department of Petroleum Engineering
Improved Improved Production/ReservesProduction/Reserves
KK 50 mD50 mDHH 25 feet25 feetµµ 2 cP 2 cP BBoo 1 bbl/sbbl1 bbl/sbblrree 1,980 ft1,980 ftrrww 0.4110.411SS variablevariableOrientationOrientation verticalverticaldepthdepth 10,000 ft10,000 ftreservoir pressurereservoir pressure 4,300 psi4,300 psi
BHPPBHPP 3,000 psi (pseudo-steady 3,000 psi (pseudo-steady state)state)
Considering the following example for Considering the following example for evaluating PI:evaluating PI:
Harold Vance Department of Petroleum Engineering
Improved Improved Production/ReservesProduction/Reserves
SkinSkin Production Rate Production Rate (BOPD)(BOPD) PIPI WIQIWIQI
00 761 0.572 1
11 674 0.507 0.89
22 604 0.455 0.79
55 462 0.348 0.61
1010 331 0.249 0.44
100 55 0.041 0.07
Harold Vance Department of Petroleum Engineering
Improved Improved Production/ReservesProduction/Reserves
Harold Vance Department of Petroleum Engineering
Pro
du
cti
on
Rate
(B
OP
D)
Pro
du
cti
on
Rate
(B
OP
D)
0 1 2 5 10 0 1 2 5 10 100 100
Economic water volume production (modified after Carden Economic water volume production (modified after Carden 1993199311).).
SkinSkin
800800
700700
600600
500500
400400
300300
200200
100100
00 00
0.140.14
0.280.28
0.420.42
0.560.56
0.70.7
0.840.84
0.980.98
1.121.12
Well I
nfl
ow
Qu
ality
In
dic
ato
r W
ell I
nfl
ow
Qu
ality
In
dic
ato
r P
rod
ucti
vit
y I
nd
ex
Pro
du
cti
vit
y I
nd
ex
Improved Improved Production/ReservesProduction/Reserves
ExampleExampleOil well
Revenue Interest = R = 0.375Working Interest = WI = 0.5
Gross Income (per net bbl)Crude Price = $20.00/bbl
LessTransportation = $1.00/bblProduction taxes = $6.00/bbl
LeavesGross Income (per net bbl) = $13.00/bblEstimated Op. Expense = $5000/well monthNumber of wells = 5
Harold Vance Department of Petroleum Engineering
Case 1Case 1
All five wells drilled in the All five wells drilled in the first year with a first year with a conventional mud system.conventional mud system.
Harold Vance Department of Petroleum Engineering
YearYear 11 22 33 44 55 66 77 TotalTotal
Estimated Estimated FutureFuture OperationOperation UnitUnit
ss
(1)(1)
Gross LeaseGross Lease
ProductionProduction
- bbl201,204
170,280
122,952
96,720 77,960 55,388 18,024 742,528
(2)(2)
Net ProductionNet Production
To OperatorTo Operator
R * (1)bbl
75,452 63,855 46,107 36,270 29,325 20,771 6,759 278,448
(3)(3)
Gross IncomeGross Income
To OperatorTo Operator
(2) * $13.00
$980,870
830,115
599,391
471,510
380,055
270,017
87,8673,619,824
(4)(4)
DevelopmentDevelopment
CostCost
$750,000
0 0 0 0 0 0 750,000
(5)(5)
Number ofNumber of
Producing WellProducing Well
MonthsMonths
- - 60 60 48 48 36 36 24 312
(6)(6)
OperatingOperating
ExpenseExpense
(5) * $5,000
$300,00
0300,00
0240,00
0240,00
0180,00
0180,00
0120,00
01,560,00
0
Case 1 (Base Case)Case 1 (Base Case)
Harold Vance Department of Petroleum Engineering
YearYear 11 22 33 44 55 66 77 TotalTotal
Estimated FutureEstimated Future OperationOperation UnitsUnits
(7)(7)
CapitalCapital
ExpenditureExpenditure- $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000
(8)(8)
Share of Share of
Operating andOperating and
Capital ExpensesCapital Expenses
WI * [(4)+(6)+(7)
]$
535,000
160,000
130,000
130,000
100,000
100,000
70,0001,225,000
(9)(9)
Cash Flow toCash Flow to
OperatorOperator(3) – (8) $
445,870
670,115
469,391
341,510
280,055
170,017
17,8672,394,824
(10)(10)
5% Annual5% Annual
Deferment FactorDeferment Factor© - 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010
(11)(11)
Present WorthPresent Worth
Of Cash FlowOf Cash Flow(10) * (9) $
434,277
621,599
414,707
287,347
224,408
129,757
12,9862,157,73
6
© DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
DCRDCR annual deferment factors, applicable to equal payments at the end of each monthannual deferment factors, applicable to equal payments at the end of each monthduring a specific interval of year between (t-1) an t years from now.during a specific interval of year between (t-1) an t years from now.
ii effective annual compound safe interest rate as a decimal fraction.effective annual compound safe interest rate as a decimal fraction.tt time in yearstime in years
Harold Vance Department of Petroleum Engineering
Case 1 (Base Case)Case 1 (Base Case)
Case 2Case 2
Same as Case 1 with the Same as Case 1 with the exception that there is exception that there is higher production to higher production to reduced formation damage reduced formation damage from UBD.from UBD.
Harold Vance Department of Petroleum Engineering
YearYear 11 22 33 44 55 66 77 TotalTotal
Estimated Estimated FutureFuture OperationOperation UnitsUnits
(1)(1)
Gross LeaseGross Lease
ProductionProduction
- bbl 221,324187,308
135,247
106,392
85,756 60,927 19,826 816,781
(2)(2)
Net ProductionNet Production
To OperatorTo Operator
R * (1) bbl 82,997 70,241 50,718 39,897 32,159 22,848 7,435 306,293
(3)(3)
Gross IncomeGross Income
To OperatorTo Operator
(2) * $13.00 $1,078,956
913,127
659,330
518,661
418,061
297,018
96,6543,981,806
(4)(4)
DevelopmentDevelopment
CostCost$ 750,000 0 0 0 0 0 0 750,000
(5)(5)
Number ofNumber of
Producing WellProducing Well
MonthsMonths
- - 60 60 48 48 36 36 24 312
(6)(6)
OperatingOperating
ExpenseExpense
(5) * $5,000 $ 300,000300,00
0240,00
0240,00
0180,00
0180,00
0120,00
01,560,00
0
Case 2 Case 2
Harold Vance Department of Petroleum Engineering
YearYear 11 22 33 44 55 66 77 TotalTotal
Estimated FutureEstimated Future OperationOperation UnitsUnits
(7)(7)
CapitalCapital
ExpenditureExpenditure- $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000
(8)(8)
Share of Share of
Operating andOperating and
Capital ExpensesCapital Expenses
WI * [(4)+(6)+(7)]
$535,000
160,000
130,000
130,000
100,000
100,000
70,0001,225,000
(9)(9)
Cash Flow toCash Flow to
OperatorOperator(3) – (8) $
543,956
753,127
529,330
388,661
318,061
197,018
26,6542,756,806
(10)(10)
5% Annual5% Annual
Deferment FactorDeferment Factor© - 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010
(11)(11)
Present WorthPresent Worth
Of Cash FlowOf Cash Flow(9) * (8) $
529,814
698,600
467,663
327,019
254,862
150,364
19,3722,483,88
3
DCRDCR annual deferment factors, applicable to equal payments at the end of each monthannual deferment factors, applicable to equal payments at the end of each monthduring a specific interval of year between (t-1) an t years from now.during a specific interval of year between (t-1) an t years from now.
ii effective annual compound safe interest rate as a decimal fraction.effective annual compound safe interest rate as a decimal fraction.tt time in yearstime in years
© DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
Harold Vance Department of Petroleum Engineering
Case 2 Case 2
Case 3Case 3
Same as case 2 with the Same as case 2 with the exception that development exception that development costs for the five wells are costs for the five wells are $150,000 less, due to $150,000 less, due to improved drilling while improved drilling while underbalanced.underbalanced.
Harold Vance Department of Petroleum Engineering
YearYear 11 22 33 44 55 66 77 TotalTotal
Estimated Estimated FutureFuture OperationOperation UnitsUnits
(1)(1)
Gross LeaseGross Lease
ProductionProduction
- bbl 221,324187,308
135,247
106,392
85,756 60,927 19,826 816,781
(2)(2)
Net ProductionNet Production
To OperatorTo Operator
R * (1) bbl 82,997 70,241 50,718 39,897 32,159 22,848 7,435 306,293
(3)(3)
Gross IncomeGross Income
To OperatorTo Operator
(2) * $13.00 $1,078,956
913,127
659,330
518,661
418,061
297,018
96,6543,981,806
(4)(4)
DevelopmentDevelopment
CostCost$ 600,000 0 0 0 0 0 0 600,000
(5)(5)
Number ofNumber of
Producing WellProducing Well
MonthsMonths
- - 60 60 48 48 36 36 24 312
(6)(6)
OperatingOperating
ExpenseExpense
(5) * $5,000 $ 300,000300,00
0240,00
0240,00
0180,00
0180,00
0120,00
01,560,00
0
Case 3 Case 3
Harold Vance Department of Petroleum Engineering
Case 3 Case 3 Year 1 2 3 4 5 6 7 Total
Estimated FutureEstimated Future OperationOperation UnitsUnits
(7)(7)
CapitalCapital
ExpenditureExpenditure- $ 20,000 20,000 20,000 20,000 20,000 20,000 20,000 140,000
(8)(8)
Share of Share of
Operating andOperating and
Capital ExpensesCapital Expenses
WI * [(4)+(6)+(7)
]$
460,000
160,000
130,000
130,000
100,000
100,000
70,0001,150,000
(9)(9)
Cash Flow toCash Flow to
OperatorOperator(3) – (8) $
618,956
753,127
529,330
388,661
318,061
197,018
26,6542,831,806
(10)(10)
5% Annual5% Annual
Deferment FactorDeferment Factor© - 0.9740 0.9276 0.8835 0.8414 0.8013 0.7632 0.7268 0.9010
(11)(11)
Present WorthPresent Worth
Of Cash FlowOf Cash Flow(9) * (8) $
602,864
698,600
467,663
327,019
254,862
150,364
19,3722,551,45
8
DCRDCR annual deferment factors, applicable to equal payments at the end of each monthannual deferment factors, applicable to equal payments at the end of each monthduring a specific interval of year between (t-1) an t years from now.during a specific interval of year between (t-1) an t years from now.
ii effective annual compound safe interest rate as a decimal fraction.effective annual compound safe interest rate as a decimal fraction.tt time in yearstime in years
© DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
Harold Vance Department of Petroleum Engineering
Summary of all CasesSummary of all Cases(Present Worth of Cash)(Present Worth of Cash)
CaseYear
11 22 33 44 55 66 77 TotalTotal
11 434,277
621,599
414,707
287,347
224,408
129,757
12,9862,157,73
6
22 529,814
698,600
467,663
327,019
254,862
150,364
19,3722,483,88
3
33 602,864
698,600
467,663
327,019
254,862
150,364
19,3722,551,45
8
Harold Vance Department of Petroleum Engineering
Summary of Summary of ExamplesExamples
Harold Vance Department of Petroleum Engineering
Pre
sen
t W
ort
h o
f C
ash
Flo
w (
$)
Pre
sen
t W
ort
h o
f C
ash
Flo
w (
$)
1 2 3 4 5 6 1 2 3 4 5 6 7 7
Projections Over Seven Projections Over Seven YearsYears
YearYear
700,000700,000
600,000600,000
400,000400,000
300,000300,000
200,000200,000
100,000100,000
00
500,000500,000