PETE 689 UBD

1
PETE 689 - UBD

• Lesson 15
• Special Considerations
• Read UDM - Chapter 6

2
Special Considerations

• Safety in UBD
• Regulatory Requirements
• Environmental Issues
• Directional Drilling

3
Special Considerations

• Percussion Drilling
• High Pressure Drilling
• Cementing
• Formation Evaluation

4
Safety in UBD

• Since significantly greater volumes of oil and
  gas are produced in underbalanced drilling
  (compared to overbalanced drilling), and because
  these products are highly combustible,
  considerable attention must be paid to safety
  procedures.
• Produced fluids must be handled safely.

5
Hydrogen Sulfide

• Provide necessary notice of the proposed
  operations and hazards.
• Provide adequate training.
• Special Safety equipment, such as sensors,
  warning alarms, wind socks, concentration
  measuring devices, portable and fixed air
  breathing respirators.

6
Hydrogen Sulfide

• An H2S emergency contingency plan with the site
  specific information and detailed procedures.
• Hydrogen sulfide resistant materials and
  training.
• Pressure surface separation vessels and auxiliary
  vacuum degassing equipment to isolate all
  personnel from possible exposure to this
  poisonous gas.

7
Flaring Gas

• Adequate sized flare lines, leading to properly
  positioned flare stacks, equipped with automatic
  flame igniters, are essential.
• Take wind direction into consideration.
• Height may need adjustment.
• Flare lines must be properly anchored.

8
Separation and Storage

• Liquid hydrocarbon separation and storage
  facilities must be
• positioned remotely
• provide adequate storage volume
• proper manifolding for transfer to sales.

9
Training

• Personnel training must be provided.
• Written procedures must be provided.
• Redundancy in critical man power must be
  provided.
• Redundancy in choke manifold.
• Emergency ingress and egress must be provided.

10
Downhole Fires

• Air drilling can lead to downhole fires and
  corrosion.

11
Drilling with Natural Gas

• Surface fires can be a problem.
• Prepare for proper handling of hydrocarbon gasses
  at the surface.
• Guidelines can be found in
• API RP 500B
• National Fire Protection Association (NFPA) 70
• NFPAA 496

12
Backflow

• Drillstrings need floats to prevent flow back up
  the drillstring.
• Placement of drillstring floats is important for
  operational and safety reasons.

13
Well Control

• No standards for testing of RH and RBOP has been
  developed.

14
Equipment

• Operational and equipment testing procedures must
  be established.
• Operations should not continue if pressures
  exceed the maximum limits established.
• In flowdrilling, emphasis is placed on monitoring
  pressure while drilling, tripping, and stripping,
  in addition to early kick detection.

15
Equipment

• To develop testing procedures, prepare a detailed
  BOP and manifolding flow diagrams that show
  step-by-step testing for system parts.
• Test BOPs when installed, each time they are
  reinstalled, once each week, and following
  repairs.

16
Equipment

• Regularly inspect and monitor surface equipment.
• Stop flowdrilling when H2S is detected.
• Inspect mud/gas separators at least daily.
• Inspect diverter rubber elements several times a
  day.
• Check diverter alignment with the rotary.
• Develop contingency plans.

17
Regulatory Requirements

• In planning an UB well, always check with local,
  state, or federal agency governing the wells
  location for the latest regulations.

18
Canada

• Interim Directive ID 94-3, from the Energy
  Resources Conservation Board provides the most
  detailed regulations in North America.
• Mandates strict enforcement of
• BOP system configuration.
• Tripping procedures.
• Well control certification of key personnel.

19
United Kingdom

• The Department of Trade and Industry sets
  specific requirements and regulations pertinent
  to the drilling and completion of underbalanced
  wells.
• Authority has be delegated to the Health and
  Safety Executive to review operators plans, and
  to grant or deny permits for proposed work.

20
United States

• In the United States, a survey of the primary oil
  and gas producing states indicated that there
  were no special regulations written specifically
  for UBD. In most cases, the existing regulations
  could be broadly interpreted to cover UBD.

21
Issues to Consider

• Be certain that the BOP stack, with a
• diverter System
• permits drilling to proceed while
• controlling annular pressure.
• allows connections to be made either
• with the well flowing or shut-in.
• allows tripping of the drillstring under
• pressure to change bits or bottomhole assemblies.

22
Issues to Consider

• provides for backup annular control in case of
  failure of the diverter.
• provides for a choke manifold arrangement which
  allows annular pressure to be varied so that it
  will not exceed related working pressure of the
  equipment.
• Provides a mean to bleed-off pressure or to kill
  the well, independent of the diverter system.
• Provides a means to quickly and safely shut-in
  the well.

23
Issues to Consider

• Use string float(s) and fire float(s), if air is
  used.
• If sour gas is present, drillpipe protection and
  blind shear rams are needed.
• Kill fluid is needed.
• Casing integrity needs to be guaranteed and full
  length cementing should be implemented as
  regulated.
• Surface equipment spacing needs to adhere to
  appropriate regulations.

24
Issues to Consider

• Flaring must follow appropriate regulations.
• Appropriate separator equipment should be used,
  as required.
• Provide adequate provision for storage of
  produced fluids.
• Crews need to be appropriately certified and
  trained.
• Monitoring and alarms are essential for H2S
  environments.
• Adhere to all safety regulations.

25
Environmental Issues

• Regulations vary significantly from
  state-to-state, and country-to-country.
• Check applicable regulations carefully.

26
Land and Water Pollution

• UBD provides some environmental benefits (closed
  loop systems, less drilling mud, etc), but
  produces more formation fluids than conventional.
• Oil coated cuttings must be disposed of properly.

27
Air Pollution Considerations

• Burning hydrocarbons during drilling can become
  an environmental concern.
• Know regulations on air pollution.
• Dust during air drilling can be a problem.

28
Produced Water Disposal

• Produced water must be disposed of.
• Disposal operations can include
• Disposal into surface water drainage systems.
• Reinjection.
• Approved land disposal
• Overboard offshore disposal
• Reserve pits

29
Directional Drilling

• There is no reason why directional wells cannot
  be undertaken with UBD.
• However, compressible fluids can complicate
  directional drilling.

30
Directional Drilling (Complications)

• Conventional downhole motor life is shorter, and
  conventional motors are not as efficient.
• Conventional MWD systems do not work with
  compressible fluids.
• Hole cleaning can be a problem with angles gt50 deg

31
Directional Drilling (Complications)

• The horizontal section length is reduced due to
  increased drag.
• Not all formations and lithologies are suitable
  for drilling with dry gas, moist or foam.

32
Bottomhole Assemblies

• Main issues for directional drilling
  underbalanced are similar to those for
  conventional directional drilling
• Directional control.
• Surveying.
• Hole cleaning.
• Drillstring friction.

33
Bottomhole Assemblies

• BHA is designed to control direction and angle.
• The deviation tendency is a function of the
  stiffness of the assembly.

34
Three Types of BHAs

• Building assemblies
• Dropping assemblies
• Holding assemblies

35
Building Assemblies
36
Dropping Assemblies
37
Holding Assemblies
38
Downhole Motors

• Conventional mud motors can be run with
  compressible fluids, but there are disadvantages.

39
Conventional Mud Motors Disadvantages

• Designed to run with low volumetric flow rates
  and high pressure drops. Leads to high inlet
  pressures and low efficiency with compressible
  fluids.
• Compressible fluids can lead to motor stall.
• High inlet pressure results in high energy stored
  in the drillstring above the motor.

40
Conventional Mud Motors Disadvantages

• Volume to clean the hole with air drilling is
  three times greater than the recommended flow
  rate for the conventional mud motor.
• Mud motors are hydrostatic, they can use only the
  displacement work, and not the expansion work of
  the compressed air.

41
Mud Motors

• Mud motors have been developed for use with
  compressible fluids.
• Advantages
• Boosters are not needed.
• Efficiency is improved.
• Motors do not stall as easily.
• Overspeed is less likely.
• Can be used with compressible and slightly
  compressible fluids.

42
Surveying

• Conventional MWD signals cannot be sent up
  compressible fluids.
• Electromagnetic MWD (EMWD) tools are being
  developed.
• Steering tools are still available.

43
Hole Cleaning

• Hole cleaning is more difficult in highly
  deviated wells.
• A rule-of-thumb is that for adequate hole
  cleaning in horizontal wells, a volumetric rate
  of 2.5 times greater than a vertical well is
  necessary.

44
Torque and Drag

• Friction coefficient in an air-drilled hole can
  be three to four times than expected in
  mud-filled hole.

45
Horizontal Section Length

• Additional torque and drag can lessen the
  achievable horizontal displacement of high angle
  and horizontal wells.

46
Lithology and Target Constraints

• Lithologies that can be drilled with air are
  limited. Younger less consolidated rocks are
  usually not good candidates for air.
• Directional wells sometimes must be drilled
  overbalanced to prevent wellbore collapse.

47
Percussion Drilling

• In percussion drilling, rock is broken by causing
  the bit to repeatedly strike the workfront,
  without imparting any significant shearing
  component to its action.
• A hammer tool is used in the BHA.
• Normally only used with dry gas, mist, and foam
  drilling.

48
Background
ROP for three different percussion tools with 8
to 8½-inch solid-head bits in Sierra White
Granite, For a WOB of 5,000 lbf. The flow rate
was between 600 and 1,100 scfm for each hammer
(after Finger, 1984 26)
49
Approximation of ROP

• Assume that the MSE Co
• Determine the hammer manufacturers power output
  value. The penetration rate is related to the
  rocks unconfined compressive strength, the
  hammer power output and the hole area by

50
Approximation of ROP
ROP 2.5210 6 H / (Co Dh2)
ROP rate of penetration (ft/hr) H hammer power
output (hp) Co unconfined compressive strength,
(psi) Dh hole diameter (inches)
51
Equipment
Flat-bottom bits, used in conjunction with an air
percussion hammer (anon)
52
Equipment
Internally ported hammer and a flat-bottom bit
(anon)
53
Equipment
Components of an externally ported hammer (anon)
54
FPB/HT (flat-bottomed percussion bit/hammer tool)
tandem recommended WOB Versus hole size (after
Whiteley and England, 1986 30)
Recommended Weight on Bit (lbf)
Bit Diameter (inches)
55
Hole Cleaning

• Pratt modified Angels minimum velocity by
• Using a revised air prediction module inside the
  drillstring where the friction factor was
  calibrated from actual measurements.
• Exit boundary conditions were modified as an
  input parameter and exit chip velocity was fixed
  at zero.
• The influence of the BHA and changing hole size
  were incorporated.
• Chip size change was built into the model.

56
Gauge Wear
Diamond-Enhanced Insert (after Reinsvold, et al.,
1988 31)
57
Smooth Hole?
Spiral hole drilled with an industrial hammer and
a flat-bottomed bit (after Pratt, 1989 29)
58
Smooth Hole?
Ledges drilled with an industrial hammer and a
flat-bottomed bit (after Pratt, 1989 29)
59
Summary

• Maintain proper WOB.
• Rotate as slowly.
• Provide an air bypass.
• Deep the threads clean and use recommended
  lubricants.
• Dope the pins only.
• Never run on junk.

60
Summary

• When changing out bits, make sure that the new
  bit is no more than 0.25 in larger than the old.
• Stabilize as required.
• Monitor compressors.
• Blow the hole clean.

61
High Pressure Drilling

• Special attention should be given to high surface
  pressures because of the additional force
  required to trip pipe.
• Stringent safety considerations are required.

62
Flowdrilling in High Pressured Formations

• The use of CT drilling is increasing with high
  pressure flowdrilling.
• Surface well control equipment must be rated
  based on maximum anticipated conditions.
• RBOPs should replace rotating heads.

63
Coiled Tubing Drilling Design Criteria

• Select the CT size, hole size, drilling fluid,
  and BHA.
• Calculate the reel weight and size.
• Calculate the tubing forces and stresses. Do not
  let them exceed 80 of the yield strength, and
  the minimum WOB can be provided at TD.

64
Coiled Tubing Drilling Design Criteria

• 4. In vertical wells.
• Dmax (sy) / ( 4.245 - 0.06493Wdf )
• Dmax maximum depth (feet)
• Wdf drilling fluid weight (ppg)
• sy yield stress (psi)
• 5. In Deviated wells.
• Ensure that the injector can supply the necessary
  push/pull.

65
Coiled Tubing Drilling Design Criteria

• 5. In Deviated wells.
• Ensure that the injector can supply the necessary
  push/pull.
• Calculate the drilling fluid pressure drop in the
  CT, BHA and annulus at 100 motor flow capacity
  and determine the absolute pressure in the CT
  during drilling.
• Asses torsional limitations. The downhole
  motor-stall torque should not be longer than the
  maximum working torque for the CT.

66
Coiled Tubing Drilling Design Criteria

• 5. In Deviated wells.
• Calculate the fatigue life of the pipe.
• Asses any hydraulic limits . Consider hole
  cleaning in vertical, inclined , and horizontal
  wellbores.
• Be sure that directional control is possible.

67
Cementing

• Extremely light cement can be used to
• Provide primary cementing in formations with low
  fracture pressures.
• Cure lost circulation in cavernous vugs.
• Squeeze depleted zones.
• Zonal isolation.
• Heat Insulation.

68
Properties of Foamed Cement

• Will the strength be adequate and will the sheath
  be destroyed by perforating?
• Compressive strength of foamed cement is
  generally higher than a comparable non-foamed
  cement of the same density.
• Will there be gas migration through the cement
  itself?
• Will the bond be different than for conventional
  cements?

69
Systems with Low Density Particulate Matter

• Cement companies have additive in which the HSP
  of the cement can be reduced.
• Example is hollow glass micro spheres.

70
Design Considerations

• Foam quality.
• PVT behavior.
• Cement system.
• Free water.
• Backpressure.
• Permeability.
• Compressive strength.
• Fluid Loss.

71
Formation Evaluation
72
Evaluation of Formation Fluids While Drilling

• Evaluation of formation fluids during UBD is more
  accurate than conventional.
• Qualitative and Quantitative information can be
  obtained or inferred.

73
Evaluation with Logging Tools

• Gamma Ray. For formation or bed definition (e.g.
  distinguishing sands from shales).
• Spectra Gamma ray. Quantitative definition of the
  gamma ray spectrum to define clay content, clay
  and mineral type, and to aid in fracture
  detection.
• Epithermal Neutron. To identify porosity of
  liquid-filled zones.
• Induction Resistivity. To help distinguish
  hydrocarbons from saline formation water and to
  help quantify the water saturation.

74
Evaluation with Logging Tools

• High Resolution Density. To quantify porosity.
• Temperature. To indicate liquid level in the
  borehole and to delineate zones where fluids are
  actually being produced.
• Production. Production logs, such as borehole
  spinners, cam help to quantify the relative
  amount of production from each interval.
• Nuclear Magnetic Resonance. To help quantify the
  permeability of formations.

75
MWD

• If a compressible fluid is used, conventional mud
  pulse telemetry tools cannot be used.
• Electromagnetic devices can.

76
Coring Underbalanced

• Reducing coring fluid invasion allows for careful
  determinations of formation properties where
  wettability alteration has been minimized.

77
Permeability and Deliverability Assessments

• Effective monitoring of production rates permits
  real-time decisions regarding changes in drilling
  depth, wellbore orientation, and overall section
  length.

78
THE END