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Lesson 12. Selecting an Appropriate Technique Read: UDM Chapter 4 pages 4.1-4.54. Selecting an Appropriate Technique. Potential Applications and Candidate Technique Technical Feasibility Economic Analysis. Required data for UBO Candidate Identification:.

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lesson 12

Lesson 12

Selecting an Appropriate Technique

Read: UDM Chapter 4

pages 4.1-4.54

selecting an appropriate technique
Selecting an Appropriate Technique
  • Potential Applications and Candidate Technique
  • Technical Feasibility
  • Economic Analysis

Harold Vance Department of Petroleum Engineering

required data for ubo candidate identification
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 identification1
Required data for UBO Candidate Identification:
  • Formation fluid types
  • Formation integrity test data
  • Water/chemical sensitivity
  • Lost circulation information
  • Fracture pressure/gradient plot

Harold Vance Department of Petroleum Engineering

required data for ubo candidate identification2
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

Harold Vance Department of Petroleum Engineering

poor candidates for ubd
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

Harold Vance Department of Petroleum Engineering

poor candidates for ubd1
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

Harold Vance Department of Petroleum Engineering

poor candidates for ubd2
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
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

Harold Vance Department of Petroleum Engineering

good candidates for ubd1
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 ubd2
Good candidates for UBD
  • Fractured formations
  • Vugular formations
  • High permeability formations
  • Highly variable formations

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good candidates for ubd3
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
Candidate Decision Tree

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candidate decision tree1
Candidate Decision Tree

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candidate decision tree2
Candidate Decision Tree

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candidate decision tree3
Candidate Decision Tree

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slide19

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
Potential Applications and Candidate Technique

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low rop through hard rock
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.

Harold Vance Department of Petroleum Engineering

lost circulation through the overburden
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

Harold Vance Department of Petroleum Engineering

differential sticking through the overburden
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

Harold Vance Department of Petroleum Engineering

formation damage through a soft medium depleted reservoir
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 reservoir1
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

Harold Vance Department of Petroleum Engineering

formation damage through a normally pressured reservoir
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
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
Formation damage through an overpressured reservoir.
  • Snub drill (use a closed surface system is sour gas is possible)

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technical feasibility
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 feasibility1
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 feasibility2
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 feasibility3
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 feasibility4
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
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 limits1
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 limits2
Borehole pressure limits
  • Wellbore stability provides the lower limit to the allowable borehole pressures.

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borehole pressure limits3
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 limits4
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 limits5
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 limits6
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 limits7
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 limits8
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
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 selection1
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 selection2
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.

Harold Vance Department of Petroleum Engineering

example 1
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
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 > 2 ppg.

Production rate is low.

Harold Vance Department of Petroleum Engineering

example 3
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 < 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
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
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
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 formations1
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 formations2
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 formations3
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
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 production1
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 production2
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 production3
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
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
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 zones1
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 zones2
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 zones1
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
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
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 gas1
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 gas2
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
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
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 geometry1
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 geometry2
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
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
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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logistics1
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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logistics2
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
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 analysis1
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
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 analysis1
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
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
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
Formation Evaluation
  • Real time formation evaluation possible
  • UB coring possible

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environmental savings
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
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 1 nitrogen vs pipeline gas
Cost Comparisons - Case 1Nitrogen vs. Pipeline Gas

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cost comparisons case 1
Cost Comparisons - Case 1

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cost comparisons case 2
Cost Comparisons - Case 2

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economic analysis2
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 analysis3
Economic Analysis
  • Perform basic cost/ft drilling evaluations.

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assess drilling costs
Assess Drilling Costs

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accelerated production
Accelerated Production
  • Earlier production can improve the NPV

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improved production reserves
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 reserves1
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 reserves2
Improved Production/Reserves

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improved production reserves3
Improved Production/Reserves

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improved production reserves4
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

Example

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case 1
Case 1
  • All five wells drilled in the first year with a conventional mud system.

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case 2
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
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
Summary of Examples

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summary of examples1
Summary of Examples

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