PETE 689
Underbalanced Drilling (UBD)
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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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.
Harold Vance Department of Petroleum Engineering
Required Data For UBO
Candidate Identification
•
•
•
•
•
Formation fluid types.
Formation integrity test data.
Water/chemical sensitivity.
Lost circulation information.
Fracture pressure/gradient plot.
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Required Data For UBO
Candidate Identification
• 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.
Harold Vance Department of Petroleum Engineering
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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Poor 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
•
•
•
•
Fractured formations.
Vugular formations.
High permeability formations.
Highly variable formations.
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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-Sheet 1
Previous history of
underbalanced
Operations (UBO)?
No
Hydrocarbons
anticipated
Yes
Go to
Sheet 2
No
Drilling
problems
anticipated
No
No UBO
Yes
Lost
circulation
Yes
No
Yes
Stuck
pipe
Cost/safety
benefits
No
No UBO
No
Hard
drilling
(ROP/bit)
Yes
No
No UBO
Detailed engineering
(cost, safety, reservoir,
Mechanical main drivers)
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Yes
Candidate
Candidate Decision Tree-Sheet 2
Yes
Depleted
reservoir
Go to
Sheet 3
No
No
Drilling
Problems
anticipated
No UBO
Yes
Yes
Lost
circulation
No
No UBO
Yes
No
Yes
Stuck
pipe
No
Hard
Drilling
(ROP/bit)
Reservoir damage
Production impairment
Cost /safety
benefits
No
Yes
Yes
No
No UBO
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No UBO
Candidate
Candidate Decision Tree-Sheet 3
Yes
Drilling
problems
anticipated
Lost
circulation
No
No UBO
No
Yes
No
Reservoir damage
Production impairment
Stuck
pipe
Yes
Yes
No
Candidate
Hard
Drilling
(ROP/bit)
Cost /safety
benefits
No
Yes
No UBO
No
No UBO
This decision tree 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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Yes
Candidate
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.
• N2 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
water-sensitive 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.
►
Harold Vance Department of Petroleum Engineering
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 candidate
drilling techniques, a controlling factor is
the range of anticipated borehole
pressures which will be required for each
zone to be drilled.
• The upper limit for UB conditions is
formation pore pressure.
• Lower limit will generally be regulated by
the lowest pressure at which wellbore
stability is ensured.
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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:
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 Petroleum Engineering
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?
►
Harold Vance Department of Petroleum Engineering
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)?
►
Harold Vance Department of Petroleum Engineering
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.
►
Harold Vance Department of Petroleum Engineering
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.
• Will be discussed later.
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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.
Harold Vance Department of Petroleum Engineering
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.
• The allowable backpressure 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.
►
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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
• 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.
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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.
Harold Vance Department of Petroleum Engineering
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
4500
4000
•No wellbore stability
problems.
•Surface equipment can
handle the anticipated
AOF.
•Minimal water inflow
is expected.
3500
Borehole Pressure (psi)
•Shallow, normally
pressured reservoir.
3000
2500
2000
1500
1000
500
0
0
2000
4000
6000
8000
10000
True Vertical Depth (feet)
Stability regimes for the well described in Example 1.
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Example 2
•Lost circulation and
differential sticking is a
problem with mud.
•No instability problems
anticipated if borehole
pressure is > 2 ppg.
•Production rate is low.
4500
4000
3500
Borehole Pressure (psi)
•Depleted sandstone from
3,000 to 4,000 ft with a
pore pressure gradient of 5
ppg. Pore pressure above
the sand is 8 ppg.
3000
2500
2000
1500
1000
500
0
0
2000
4000
6000
8000
10000
True Vertical Depth (feet)
Stability regimes for the well described in Example 2.
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Example 3
•Pore pressure = 8 ppg
4500
•Shale from 6,000-8,000’
requires a minimum wellbore
pressure of 7 ppg
4000
•Reservoir itself is competent
unless borehole pressure
< 5 ppg
•Expect high flow rates.
3000
2500
2000
1500
1000
500
•maximum drawdown
= 500 psi
0
•Pore p. at 9,000’ = 3,744 psi
•min BHP = 3,244 psi or
6.93 ppg
Borehole Pressure (psi)
•Target zone is 9,000’
3500
4000
5000
6000
7000
8000
9000
10000
True Vertical Depth (feet)
Stability regimes for the wells described in Examples 3 through 5
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Example 4
4500
4000
•Maximum drawdown
= 100 psi.
•Equivalent to 7.79 ppg.
•Diesel or crude gives a
pressure lower than
this. Plain water is too
dense.
Borehole Pressure (psi)
3500
3000
2500
2000
1500
1000
500
0
4000
5000
6000
7000
8000
9000
10000
True Vertical Depth (feet)
Stability regimes for the wells described in Examples 3 through 5
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Example 5
4500
•This would not supply
sufficient support for the
shale above.
4000
3500
Borehole Pressure (psi)
•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.
3000
2500
2000
1500
1000
500
0
4000
5000
6000
7000
8000
9000
10000
True Vertical Depth (feet)
Stability regimes for the wells described in Examples 3 through 5
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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.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
Factors Preventing UB
In All Zones
• This effect is more pronounced in
high angle and horizontal wells.
• AFP increases along the borehole
even if formation pore pressure
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.
Harold Vance Department of Petroleum Engineering
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 cased of
before penetrating the lower zone
in the hole.
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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.
Drillpipe gas
injection may be necessary if long
vertical sections are to be drilled
with gasified liquid.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
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 10-20%.
► In impermeable rock, ROP will
increase 100-200%.
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Drilling Days
0
0
20
40
60
80
100
120
1000
2000
Depth (feet)
3000
4000
5000
6000
7000
8000
9000
10000
Gas and mud effect on drilling time (after Moore, 197456).
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Rotating Time (hours)
0
0
10
20
30
40
50
60
70
80
90
100
500
Depth (feet)
1000
1500
2000
2500
3000
Air and water effect on drilling time (after Moore, 197456).
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Steps for Economic Analysis
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
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 UBD
•
•
•
•
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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Drilling Method
or Fluid System
Air
Savings
Problems and/or
Potential Expenditures
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
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Drilling Method
or Fluid System
Gas
(Nitrogen or
Natural Gas)
Savings
Problems and/or Potential
Expenditures
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.
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Drilling Method
or Fluid System
Mist
Savings
Problems and/or Potential
Expenditures
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
Modest additives cost.
Disposal of waste water/gas and
supplementary rental cost.
Air-mist not suitable if H2S is
present.
Equipment rental.
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Drilling Method
or Fluid System
Stable foam
Savings
Problems and/or
Potential Expenditures
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 nonflammable until sumped.
Separation and disposal.
Can handle large flows of water.
Water disposal
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Drilling Method
or Fluid System
Savings
High penetration rates and
reduction in rig time.
Stiff Foam
Problems and/or
Potential Expenditures
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 Method
or Fluid System
Savings
Problems and/or Potential
Expenditures
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.
Gasified Liquids
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
air is used.
Harold Vance Department of Petroleum Engineering
62)
is
Drilling Method
or Fluid System
Savings
Problems and/or
Potential Expenditures
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.
Snubbing or CT unit.
Snub Drilling or CT
Can be used at pressures
too high for conventional
units and underbalanced
drilling equipment.
Environmental savings
Equipment rental and operating
cost
Can handle H2S. Better
monitoring returns.
Cannot be used with explosive
mixtures.
Flowdrilling
Closed Systems
Harold Vance Department of Petroleum Engineering
Cost Comparisons - Case 1
Nitrogen vs. Pipeline Gas
General Assumptions
Flowrate…………………………………...3,000 cfm
Gas Price………………………………
$2.00/mcf
Trucking Distance……….... 50 miles (one way)
Drilling Hours/day……………....………… …… 20
Average Gas Drilling Days/well…………… ….12
Diesel Usage/hour/unit…………….10.7 gallons
Diesel Fuel Price…………………... $ 0.80/gallon
Standby Days (Equipment)/well…..……......... 4
Harold Vance Department of Petroleum Engineering
Cost Comparisons - Case 1
Nitrogen Drilling System Cost
Compressors (8) @
$135/unit/day
Boosters (2) @ $200/unit/day
(air use)
$ 12,960
Pipeline gas 43.2 mmcf @
$2.00/mcf
$ 86,400
Booster (2) $300/unit/day (gas
use)
$ 7,200
Drill Gas Unit (installed on
location)
$ 1,000
Gas Line (2,000 feet)
$ 1,800
$ 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
Membrane Skids (2) @
$1,500/unit/day
(1,800 cfm/skid)
Trucking/Transportation Fuel
(delivered)
25,680 gallons * $0.80/gallon
$ 4,800
Pipeline Gas Drilling Cost
$ 36,000
$ 9,200
Equipment Standby (4 days)
Total Nitrogen Drilling
Cost/well
$ 88,600
Total pipeline Gas Drilling
Cost/well
Harold Vance Department of Petroleum Engineering
$ 700
$ 104,510
Cost Comparisons - Case 2
Item
Liquid N2
Portable N2 Generating
System
Drilling Program
90 days
90 days
N2
1,500 scfm
1,500 scfm
Duration of N2
requirement
240 hrs (10 days)
240 hrs (10 days)
N2 Purity
Minimum 95 % (by
volume)
Minimum 95 % (by volume)
N2 Pressure
5,000 psi
5,000 psi
N2 requirement
1,500 scfm * 60 min/hr
*
24 hr/day *10 days =
584,000 sm3
= 834,000 liters liquid
N2
= 139 tanks
Method of N2 Supply
Trucked in liquid N2
(equipment rental)
1,500 scfm * 60 min/hr *
24 hr/day *10 days = 584,000
sm3
On-site membrane
(equipment purchase)
Harold Vance Department of Petroleum Engineering
Cost Comparisons - Case 2
Item
Liquid N2
Portable N2 Generating
System
Logistics
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)
$ 1,284,000
Electrical power: 1,400 kW * 10
days * 24 hrs @ $0.05/kWh
= $ 16,800
(Power unit rental included in
capital cost)
Maintenance
None
10 % of interest and
depreciation
$ 32,000
Capital Cost
None
Interest and depreciation
over 10 years $324,000
TOTAL
Approximately
$ 1,300,000
Approximately $ 375,000
Cost of Utilities
(liquid N2 , electricity,
diesel)
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
Economic Analysis
• Perform basic cost/ft drilling evaluations.
CT = [B+Cr(t+T)] / F
Where:
CT……total cost/foot.
B…….bit cost.
Cr……hourly rig cost.
t……..rotating time.
T…….round trip time.
F…….footage per bit run.
Harold Vance Department of Petroleum Engineering
(4.12)
Assess Drilling Costs
Item
Air Drilling
Mud Drilling
Interval
From 4,000 to 7,000 ft
From 4,000 to 7,000 ft
Interval Length (F) (ft)
3,000
3,000
Penetration Rate (ft/hr)
30
15
Rotating Time (t) (hr)
100
200
Bit Life (hr)
100
100
Bits Required
1
2
Unit Bit Cost
$ 4,800/bit
$ 4,800/bit
Bit Cost (B)
$ 4,800
$ 4,800
Trip Schedule
Trip in to 4,000 ft
Trip out from 7,000 ft
Trip in to 4,000 ft
Trip out from 5,500 ft
Trip in to 5,500 ft
Trip out from 7,000 ft
Total Trip Footage
11,000 ft
22,000 ft
Unit Trip Time
(hr/1,000 ft)
1.5
1.5
Harold Vance Department of Petroleum Engineering
Assess Drilling Costs
Item
Air Drilling
Mud Drilling
Trip Time (T) (hr)
16.5
33
Hourly Operating Cost
(Cr)
$ 375/hr
$ 250/hr
Cost / ft
[B+Cr(T+t)]/[F]
[9,600+250(33+200)] / [3000]
$ 22.62 /ft
Competitive Cost for Air
Drilling
[4,800+Cr(16.5+100)] /
[3000]
= $ 22.62t
Cr = $ 541.29/hr
Barrels of Water That
Can be Disposed of at
$ 1.00/bbl
($541.29 - $375)/ $1.00 =
166 * 24 = 3,984 BWPD
Barrels of Water That
Can be Disposed of at
$ 5.00/bbl
($541.29 - $375)/ $5.00 =
33 * 24 = 798 BWPD
Barrels of Water That
Can be Disposed of at
$ 10.00/bbl
($541.29 - $375)/ $10.00 =
16.6 * 24 = 400 BWPD
Harold Vance Department of Petroleum Engineering
25
24
23
Cost ($/ft)
22
21
20
19
18
17
16
15
0
500
1000
1500
2000
2500
3000
Barrels of Produced Water per Day
Economic water volume production (modified after Carden 19931).
Harold Vance Department of Petroleum Engineering
Accelerated Production
• Earlier production can improve the NPV
NPV = 1 / (1+DR)t = (1+DR)-t
NPV = net present value (discounted
value of asset).
DR = discount rate.
t
= discount time, years.
Harold Vance Department of Petroleum Engineering
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).
Harold Vance Department of Petroleum Engineering
Improved
Production/Reserves
• Well Inflow Quality Indicator,
WIQI, is the ratio of the PI for
an impaired to that for an
undamaged well.
Harold Vance Department of Petroleum Engineering
Improved
Production/Reserves
Considering the
evaluating PI:
following
example
K
50 mD
H
25 feet
µ
2 cP
Bo
1 bbl/sbbl
re
1,980 ft
rw
0.411
S
variable
Orientation
vertical
depth
10,000 ft
reservoir pressure 4,300 psi
BHPP 3,000 psi (pseudo-steady state)
Harold Vance Department of Petroleum Engineering
for
Improved
Production/Reserves
Skin
Production Rate (BOPD)
PI
WIQI
0
761
0.572
1
1
674
0.507
0.89
2
604
0.455
0.79
5
462
0.348
0.61
10
331
0.249
0.44
100
55
0.041
0.07
Harold Vance Department of Petroleum Engineering
800
1.12
700
0.98
600
0.84
500
0.7
400
0.56
300
0.42
200
0.28
100
0.14
0
Well Inflow Quality Indicator
Productivity Index
Production Rate (BOPD)
Improved
Production/Reserves
0
0
1
2
5
10
100
Skin
Economic water volume production (modified after Carden 19931).
Harold Vance Department of Petroleum Engineering
Example
Oil well
Revenue Interest
Working Interest
Gross Income (per net bbl)
Crude Price
Less
Transportation
Production taxes
Leaves
Gross Income (per net bbl)
Estimated Op. Expense
Number of wells
= R = 0.375
= WI = 0.5
= $20.00/bbl
= $1.00/bbl
= $6.00/bbl
= $13.00/bbl
= $5000/well month
=5
Harold Vance Department of Petroleum Engineering
Case 1
All five wells drilled
in the first year with
a conventional mud
system.
Harold Vance Department of Petroleum Engineering
Case 1 (Base Case)
Year
1
2
3
201,204
170,280
122,952
96,720
77,960
55,388
18,024
742,528
75,452
63,855
46,107
36,270
29,325
20,771
6,759
278,448
$
980,870
830,115
599,391
471,510
380,055
270,017
87,867
3,619,824
$
750,000
0
0
0
0
0
0
750,000
Estimated Future
Operation
Units
(1)
Gross Lease
Production
-
bbl
(2)
Net Production
To Operator
R * (1)
(3)
Gross Income
To Operator
(2) * $13.00
(4)
Development
Cost
bbl
4
5
6
7
Total
(5)
Number of
Producing Well
Months
-
-
60
60
48
48
36
36
24
312
(6)
Operating
Expense
(5) * $5,000
$
300,000
300,000
240,000
240,000
180,000
180,000
120,000
1,560,000
Harold Vance Department of Petroleum Engineering
Case 1 (Base Case)
Year
1
2
3
4
5
6
7
Total
Estimated Future
Operation
Units
(7)
Capital
Expenditure
-
$
20,000
20,000
20,000
20,000
20,000
20,000
20,000
140,000
(8)
Share of
Operating and
Capital Expenses
WI *
[(4)+(6)+(7)]
$
535,000
160,000
130,000
130,000
100,000
100,000
70,000
1,225,000
(9)
Cash Flow to
Operator
(3) – (8)
$
445,870
670,115
469,391
341,510
280,055
170,017
17,867
2,394,824
(10)
5% Annual
Deferment Factor
©
-
0.9740
0.9276
0.8835
0.8414
0.8013
0.7632
0.7268
0.9010
(11)
Present Worth
Of Cash Flow
(10) * (9)
$
434,277
621,599
414,707
287,347
224,408
129,757
12,986
2,157,736
©
DCR
i
t
DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
annual deferment factors, applicable to equal payments at the end of each month
during a specific interval of year between (t-1) an t years from now.
effective annual compound safe interest rate as a decimal fraction.
time in years
Harold Vance Department of Petroleum Engineering
Case 2
Same as Case 1 with the
exception that there is
higher
production
to
reduced formation damage
from UBD.
Harold Vance Department of Petroleum Engineering
Case 2
Year
1
2
3
4
5
6
7
Total
Estimated Future
Operation
Units
(1)
Gross Lease
Production
-
bbl
221,324
187,308
135,247
106,392
85,756
60,927
19,826
816,781
(2)
Net Production
To Operator
R * (1)
bbl
82,997
70,241
50,718
39,897
32,159
22,848
7,435
306,293
(3)
Gross Income
To Operator
(2) * $13.00
$
1,078,956
913,127
659,330
518,661
418,061
297,018
96,654
3,981,806
$
750,000
0
0
0
0
0
0
750,000
(4)
Development
Cost
(5)
Number of
Producing Well
Months
-
-
60
60
48
48
36
36
24
312
(6)
Operating
Expense
(5) * $5,000
$
300,000
300,000
240,000
240,000
180,000
180,000
120,000
1,560,000
Harold Vance Department of Petroleum Engineering
Case 2
Year
1
2
3
4
5
6
7
Total
Estimated Future
Operation
Units
(7)
Capital
Expenditure
-
$
20,000
20,000
20,000
20,000
20,000
20,000
20,000
140,000
(8)
Share of
Operating and
Capital Expenses
WI *
[(4)+(6)+(7)]
$
535,000
160,000
130,000
130,000
100,000
100,000
70,000
1,225,000
(9)
Cash Flow to
Operator
(3) – (8)
$
543,956
753,127
529,330
388,661
318,061
197,018
26,654
2,756,806
(10)
5% Annual
Deferment Factor
©
-
0.9740
0.9276
0.8835
0.8414
0.8013
0.7632
0.7268
0.9010
(11)
Present Worth
Of Cash Flow
(9) * (8)
$
529,814
698,600
467,663
327,019
254,862
150,364
19,372
2,483,883
©
DCR
i
t
DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
annual deferment factors, applicable to equal payments at the end of each month
during a specific interval of year between (t-1) an t years from now.
effective annual compound safe interest rate as a decimal fraction.
time in years
Harold Vance Department of Petroleum Engineering
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.
Harold Vance Department of Petroleum Engineering
Case 3
Year
1
2
3
4
5
6
7
Total
Estimated Future
Operation
Units
(1)
Gross Lease
Production
-
bbl
221,324
187,308
135,247
106,392
(2)
Net Production
To Operator
R * (1)
bbl
82,997
70,241
50,718
39,897
32,159
22,848
7,435
(3)
Gross Income
To Operator
(2) * $13.00
$
1,078,956
913,127
659,330
518,661
418,061
297,018
96,654
$
600,000
0
0
0
0
0
0
600,000
(4)
Development
Cost
85,756
60,927
19,826
816,781
306,293
3,981,806
(5)
Number of
Producing Well
Months
-
-
60
60
48
48
36
36
24
312
(6)
Operating
Expense
(5) * $5,000
$
300,000
300,000
240,000
240,000
180,000
180,000
120,000
1,560,000
Harold Vance Department of Petroleum Engineering
Case 3
Year
1
2
3
4
5
6
7
Total
Estimated Future
Operation
Units
(7)
Capital
Expenditure
-
$
20,000
20,000
20,000
20,000
20,000
20,000
20,000
140,000
(8)
Share of
Operating and
Capital Expenses
WI *
[(4)+(6)+(7)]
$
460,000
160,000
130,000
130,000
100,000
100,000
70,000
1,150,000
(9)
Cash Flow to
Operator
(3) – (8)
$
618,956
753,127
529,330
388,661
318,061
197,018
26,654
2,831,806
(10)
5% Annual
Deferment Factor
©
-
0.9740
0.9276
0.8835
0.8414
0.8013
0.7632
0.7268
0.9010
(11)
Present Worth
Of Cash Flow
(9) * (8)
$
602,864
698,600
467,663
327,019
254,862
150,364
19,372
2,551,458
©
DCR
i
t
DCR= [(1+i)1-t – (1+i)-t] / 12[(1+i)1/12 -1]
annual deferment factors, applicable to equal payments at the end of each month
during a specific interval of year between (t-1) an t years from now.
effective annual compound safe interest rate as a decimal fraction.
time in years
Harold Vance Department of Petroleum Engineering
Summary of all Cases
(Present Worth of Cash)
Case
Year
1
2
3
4
5
6
7
Total
1
434,277
621,599
414,707
287,347
224,408
129,757
12,986
2,157,736
2
529,814
698,600
467,663
327,019
254,862
150,364
19,372
2,483,883
3
602,864
698,600
467,663
327,019
254,862
150,364
19,372
2,551,458
Harold Vance Department of Petroleum Engineering
Summary of Examples
Present Worth of Cash Flow ($)
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0
1
2
3
4
5
Year
Projections Over Seven Years
Harold Vance Department of Petroleum Engineering
6
7