Selecting an Appropriate Technique

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Lesson 12

• Selecting an Appropriate Technique
• Read UDM Chapter 4
• pages 4.1-4.54

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Selecting an Appropriate Technique

• Potential Applications and Candidate Technique
• Technical Feasibility
• Economic Analysis

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Required data for UBO Candidate Identification

• Pore pressure/gradient plots
• Actual reservoir pore pressure
• ROP records
• Production rate or reservoir characteristics to
  calculate/estimate production rate
• Core analysis

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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

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Good candidates for UBD

• Pressure depleted formations
• Areas prone to differential pressure sticking
• Hard rock (dense, low permeability, low porosity)
• Crooked-hole country and steeply dipping
  formations

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Good candidates for UBD

• Lost-returns zones
• Re-entries and workovers (especially pressure
  depleted zones)
• Zones prone to formation damage
• Areas with limited availability of water

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Good candidates for UBD

• 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
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Candidate Decision Tree
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Candidate Decision Tree
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Candidate Decision Tree
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These decision trees can be found on the IADC
website (www.iadc.org). Click on Committees Click
on Underbalanced Drilling committee Click on
decision tree.
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Potential Applications and Candidate Technique
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Low ROP through hard rock

• Dry air
• Mist, if there is a slight water inflow
• Foam, if there is heavy water inflow, if the
  borehole wall is prone to erosion, or if there is
  a large hole diameter.
• Nitrogen or natural gas, if the well is producing
  wet gas and it is a high angle or horizontal
  hole.

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Lost circulation through the overburden

• Aerated mud, if the ROP is high (rock strength
  low or moderate) of if 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.

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Formation damage through a soft/medium-depleted
reservoir

• Nitrified brine or crude, cont
• String and temporary casing injection, if the
  pore pressure is very low and/or if very high gas
  rates
• Foam, if the pore pressure is very low and an
  open surface system is acceptable

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Formation damage through a normally pressured
reservoir

• Flowdrill (use a closed surface system if sour
  gas is possible)

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Lost circulation/formation damage through a
normally pressured, fractured reservoir

• Flowdrill (use an atmospheric system if no sour
  gas is possible)

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Formation damage through an overpressured
reservoir.

• Snub drill (use a closed surface system is sour
  gas is possible)

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Technical Feasibility

• In evaluating the feasibility of a technique, a
  controlling factor is the range of anticipated
  borehole pressures which will be required for
  each zone to be drilled.
• The upper limit is formation pore pressure
• Lower limit will be determined by wellbore
  stability.

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Technical Feasibility

• First step is to determine the anticipated
  pressures.
• Step two is to determine which methods are
  functional within the anticipated pressure window.

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Technical Feasibility

• Other considerations are
• 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?

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Technical Feasibility

• Other considerations cont
• What is the potential for chemical formation
  damage, due to fluid/fluid or fluid/formation
  interaction and is this an overwhelming problem,
  regardless of what wellbore pressure is used?
• Is there a potential for sour gas production?

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Technical Feasibility

• Other considerations cont
• Are there features of the well geometry which
  dictate specific underbalanced protocols?
• What is the local availability of suitable
  equipment and consumables (including liquids and
  gases for the drilling fluids)?

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Borehole pressure limits

• Pore pressure
• the wellbore pressure must be maintained below
  the formation pressure in all open hole sections.
• If there is no formation fluid inflow, borehole
  pressures with dry gas, mist, foam or pure liquid
  will be lower when not circulating.
• With fluid influx, borehole pressure can increase
  or decrease when not circulating.

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Borehole pressure limits

• Pore pressure
• Best practice is to use the
• lower bounds for pore pressure prediction when
  choosing a technique
• while surface equipment capacity and drilling
  specifics should be based on an upper bound.

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Borehole pressure limits

• Wellbore stability provides the lower limit to
  the allowable borehole pressures.

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Borehole pressure limits

• Hydrocarbon production rates can sometimes set
  the lower bound, depending upon the surface
  equipment available.
• Formation damage may effect the tolerable
  drawdown due to fines mobilization in the
  producing formation.

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Borehole pressure limits

• Backpressure from a choke can sometimes be used
  to protect the surface equipment from excess
  production rates or pressures.
• This also increases the BHP.
• This is limited by the pressure rating of the
  equipment and formation upstream of the choke.

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Borehole pressure limits

• When using compressible fluids, it is usually
  more cost effective to switch to a higher density
  fluid than to choke back the well.

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Borehole pressure limits

• Applying back pressure will
• increase the gas injection pressure.
• Increase the gas injection rate required for
  acceptable hole cleaning.
• These both will increase the cost of the gas
  supply.

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Borehole pressure limits

• With a gasified liquid, BHP can usually be
  increased by reducing the gas injection rate.
• When drilling with foam, back pressure may be
  necessary to maintain foam quality.
• Holding back pressure is most beneficial when
  drilling with liquids.

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Borehole pressure limits

• Once the maximum tolerable surface pressure is
  reached, production rate can only be further
  reduced by increasing downhole pressure by
  increasing the effective density of the drilling
  fluid.

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Implications of Drilling Technique Selection

• 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

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Implications of Drilling Technique Selection

• Once the borehole pressure limits, corresponding
  to wellbore instability and excessive production
  rate, have been determined , a first pass
  evaluation of the different drilling techniques
  can be performed.

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Example 1
Shallow, normally pressured well. No wellbore
stability problems Surface equipment can handle
the anticipated AOF. Minimal water inflow is
expected.
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Example 2
Depleted sandstone from 3000 to 4000 ft with a
pore pressure gradient of 5 ppg. Pore pressure
above the sand is 8 ppg. Lost circulation and
sticking is a problem with mud. No instability
problems anticipated if borehole pressure is gt 2
ppg. Production rate is low.
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Example 3
Pore pressure 8 ppg Shale from 6-8000 requires
a minimum wellbore pressure of 7 ppg Target zone
is 8-9000 Reservoir itself is competent unless
borehole pressure lt 5 ppg Expect high flow rates
w/ minimum drawdown 500 psi
Pore pressure at 9000 3744 psi, min BHP 3244
psi or 6.93 ppg
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Example 4
Maximum drawdown 100 psi. equivalent to 7.79
ppg. Diesel or crude gives a pressure lower than
this. Plain water is too dense.
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Example 5
Reservoir is depleted to 6.5 ppg. Maximum
drawdown is 500 psi. The tolerable range for ECD
through the reservoir would be 5.4-6.5 ppg. A
gasified liquid would be required. This would not
supply sufficient support for the shale above.
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Evaluating Highly Productive Formations

• Require detailed numerical analyses of
  circulating pressures.
• Formation fluid influx interacts with drilling
  fluids which effect borehole pressure - effecting
  influx rate.

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Evaluating Highly Productive Formations

• When circulation stops, the influx lifts mud from
  wellbore.
• This changes the borehole pressure and the
  production rate.

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Evaluating Highly Productive Formations

• Choking back the well returns further complicates
  the calculation of borehole pressures and
  production rate.
• If the fluid is incompressible, backpressure
  changes BHP by the amount of pressure applied.
• If the fluid is compressible, backpressure
  changes density, velocity, and BHP

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Evaluating Highly Productive Formations

• Uncertainty of input parameters in simulators
  leads to uncertainty in output.
• In many cases these uncertainties can make
  simulations in technique selection unjustified.

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Water production

• Production of small quantities of water makes dry
  gas drilling difficult.
• If offset wells have a history of water
  production, dry gas drilling below the water zone
  is probably impractical.

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Water production

• When misting, higher gas rates are required to
  prevent slug flow.
• Slug flow can damage the borehole and surface
  equipment.
• Higher injection rates and the increased density
  in the annulus may require boosters on the
  compressors.

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Water production

• Large water influxes may require foams.
• High disposal costs can sometimes make mist
  drilling impractical.
• Higher density foams can decrease water influx,
  however the increased volume of make-up water may
  make disposal still impractical.

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Water production

• If high water influx makes gas and foams
  impractical, aerated mud or low density liquids
  may be required.

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Multiple permeable zones

• If all zones are to be drilled UB, the
  circulating pressure must satisfy the borehole
  pressure requirements for all open permeable
  zones, simultaneously.
• Several factors can prevent this from happening.

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Factors preventing UB in all zones

• The ECD of compressible fluids increases with
  increasing depth.
• In vertical wells, it is possible for a permeable
  zone close to the bit to be overbalanced when a
  permeable zone higher up hole, with the same pore
  pressure gradient, is UB

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Factors preventing UB in all zones

• This effect is more pronounced in high angle and
  horizontal wells.
• AFP increases along the borehole even if HSP
  remains relatively constant along the borehole.

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Factors preventing UB in all zones

• Changes in pore pressure gradient along the
  wellbore may be present.
• This can be due to abnormally pressured
  formations, or partially depleted formations.

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Multiple permeable zones

• The major concern with multiple permeable zones
  is the potential for underground blowouts.
• Extreme care must be taken to prevent this from
  happening when pressure changes occur such as
  tripping, or connections.

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If cross flows cannot be tolerated

• Use a different drilling technique that allows
  all permeable zones to remain UB, if possible
• Kill the well before suspending circulation.
• Change the casing scheme so that the upper
  formations are isolated behind pipe before
  penetrating the producing zone.

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Sour gas

• There must be no possibility of releasing
  hydrogen sulfide into the atmosphere while the
  well is being drilled or completed.
• If any is produced during drilling it must be
  disposed of in a suitable flare.

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Sour gas

• H2S can become entrained in any liquid in the
  wellbore, and must be completely removed from the
  fluid and flared before any of the liquids are
  returned to any open surface pits.
• The separation process should be completed in a
  closed vessel.

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Sour gas

• Sour gas can become entrained in foams.
• The foam must be completely broken prior to
  separation.
• Unless effective defoaming can be guaranteed
  foams cannot be used in closed systems, and
  should not be used in the presence of Hydrogen
  Sulfide.

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Drilling/Reservoir fluid incompatibility

• It can be difficult to prevent temporary
  overbalance.
• Drilling fluids should be tested for
  compatibility with formation fluids.

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Hole geometry

• A compressible fluid will have a greater ECD in
  deep wells than in shallow wells.
• Annular gas injection only reduces the density of
  the fluids above the injection point. In deep
  wells drillstring injection may be required.

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Hole geometry

• Increasing ECD with depth may make it impossible
  to maintain the proper foam quality in deep
  wells. Backpressure may be required, increasing
  the gas supply needed.
• Increasing hole size makes hole cleaning more
  difficult.

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Hole geometry

• Large hole sizes may require larger diameter
  surface equipment. Larger surface diverter
  equipment may not have the pressure rating of
  smaller resulting in lower back pressure
  capabilities.

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Naturally fractured formations

• In fractured formations, high viscosity drilling
  fluids, circulating at low rates may prevent hole
  enlargement and still maintain UB.
• Stiff foams may be the preferred candidate.

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Logistics

• Water supplies may be limited in some areas, and
  a technique that limits water use may be chosen.
• Availability and access to the gaseous phase can
  influence the choice of gas used.

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Logistics

• Offshore locations generally do not have the same
  space available as land locations.
• Equipment used on surface locations may not be
  suitable for offshore locations.
• Modular closed systems must be used offshore.

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Logistics

• The high production rates necessary for offshore
  wells to be economically viable may make them
  unlikely candidates for UBD.

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Economic Analysis

• Rules of thumb
• UBO increases costs 1.25 - 2.0 times the cost per
  day over conventional
• but may be accomplished in 1/4 to 1/10 of the
  time.

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Economic Analysis

• Rules of thumb
• In permeable rock ROP may be increased from 30
  to 300 as well goes from overbalanced to
  balanced
• Below balance ROP will increase another 10-20
• In impermeable rock, ROP will increase 100-200

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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.

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Steps for Economic Analysis

• 3. Multiply the conventional daily cost by an
  underbalanced factor (1.3-2.0, depending on
  difficulty of the operation) to get the expected
  daily cost of UBO
• 4. Apply the expected underbalanced operating
  cost by the anticipated underbalanced drilling
  ROP to get the total cost for each interval.

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Factors that Effect the Economics of
Underbalanced Drilling

• 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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Cost Comparisons - Case 1Nitrogen vs. Pipeline
Gas
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Cost Comparisons - Case 1
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Cost Comparisons - Case 2
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Economic Analysis

• On the basis of available technology, select the
  potential drilling systems to be evaluated.
• Tabulate the tangible and intangible costs for
  each system
• Rely on previous history and recognize the
  inevitability of statistical variation

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Economic Analysis

• Perform basic cost/ft drilling evaluations.

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Assess Drilling Costs
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Accelerated Production

• Earlier production can improve the NPV

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Improved Production/Reserves

• The absolute and relative increase in production
  should be calculated, or estimated.
• Productivity Index, PI should be calculated based
  on whether the well is vertical, horizontal, oil,
  gas, radial, transient flow, or pseudo-steady
  state flow (see page 4.48)

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Improved Production/Reserves

• Well Inflow Quality Indicator, WIQI, is the ratio
  of the PI for an impaired to that for an
  undamaged well.

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Improved Production/Reserves
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Improved Production/Reserves
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Improved Production/Reserves
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Example

• Oil well
• Revenue Interest R 0.375
• Working Interest WI 0.5
• Gross Income (per net bbl)
• Crude Price 20.00/bbl
• Less
• Transportation 1.00/bbl
• Production taxes 6.00/bbl
• Leaves
• Gross Income (per net bbl) 13.00/bbl
• Estimated Op. Expense 5000/well month
• Number of wells 5

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Case 1

• All five wells drilled in the first year with a
  conventional mud system.

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Case 2

• Same as Case 1 with the exception that there is
  higher production to reduced formation damage
  from UBD.

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Case 3

• Same as case 2 with the exception that
  development costs for the five wells are 150,000
  less, due to improved drilling while
  underbalanced.

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Summary of Examples
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Summary of Examples