Well Engineering

1
Lesson 13
PETE 689 Underbalanced Drilling (UBD)

• Well Engineering
• Read UDM Chapter 5
• Pages 5.1-5.41

2
Well Engineering

• Circulation Programs
• Circulation Calculations (air, gas, mist).
• Circulation Calculations (gasified liquids).

3
Well Engineering

• Wellhead design.
• Casing design.
• Completion design.

4
Well Engineering

• Bit selection.
• Underbalanced perforating.
• Drillstring design.
• Separator design.

5
Circulation Programs

• Fundamentally no different than for balanced or
  underbalanced situations.
• Basis for hydraulics design
• Guarantee adequate hole cleaning.
• Ensure vertical transport of cuttings in annular
  zones where velocities are reduced because of
  change in annular area.

6
Circulation Programs

• Maintain wellbore stability.
• Mitigate formation damage and to operate within
  the pressure and rate constrains of the tubulars
  and the surface equipment.

7
Circulation Calculations (air, gas, mist)

• Angel's approximate method
• Collect the required information for the
  calculations. This includes
• Drilled hole size (inches).
• OD of the drill pipe (inches).
• Drilling rate (ft/hr).
• Depth (thousands of feet).

8
Circulation Calculations (air, gas, mist)

• In the table Appendix C, determine Qo and N.
  Interpolate values as required.
• Calculate the required circulation rate using
  
• Q Qo NH
• Qo, N...parameters from Appendix C.
• H.........depth in thousands of feet.
• Q.........circulation rate (scfm).

9
Circulation Calculations(gasified liquids)
Approximate volumes and pressures, for gasified
liquids, can be determined using the techniques
described previously. More precise predictions
require added levels of sophistication.
10
Wellhead DesignLow Pressure

• Gas, mist, and foam drilling are normally
  utilized on low pressure wells.
• Low pressure wells require simple wellhead
  designs.
• Some operators opt for a simple annular preventer
  alone.

11
Wellhead DesignLow Pressure

• However, a principal manufacturer of such
  equipment strongly cautions that such use exceeds
  the design criteria of this equipment.
• The minimum setup should consist of a rotating
  head mounted above a two ram set of
  manually-operated blowout preventers, consisting
  of a pipe ram and a blind ram.

12
Wellhead DesignLow Pressure

• Slightly higher pressure systems should also have
  an annular preventer between the rams and the
  rotating head.
• For added safety the BOP system should be
  hydraulically operated.
• Working pressure of these rotating heads is
  400-500 psi MWP.

13
Wellhead DesignHigh Pressure

• Gasified liquids, flowdrilling, mudcap drilling.
• Rotating heads on top of conventional
  hydraulically operated BOP usually suffice.
• In Canada, nitrified liquids are often used with
  an RBOP installed atop a conventional BOP stack.

14
Wellhead DesignHigh Pressure

• Blind rams should be installed in the bottom set
  of rams (when a two ram system is used).
• Sometimes a third set of rams (pipe rams) is
  utilized.
• In this case the RBOP is installed atop an
  annular preventer.
• The blind ram is placed between the two sets of
  pipe rams.

15
Wellhead DesignHigh Pressure

• The lowermost set of rams should be installed
  directly atop the wellhead (or an adapter spool
  if necessary).
• You should never place any choke or kill lines
  below the lowest set of rams.
• If one of these lines cuts out, there is no way
  to shut in the well.

16
Wellhead DesignHigh Pressure

• Care must be taken to utilize a rig with a
  substructure high enough so that the wellhead is
  not below ground level, with space enough to put
  the entire desired BOP stack below the rig floor.

17
Wellhead DesignSnub Drilling

• Snub drilling and CT drilling have BOP stacks
  that allow tripping at much higher pressures than
  other forms of UBD (routinely up to 10,000 psi).
• Snubbing and CT units can be used for UBD at
  pressure that cannot be managed by conventional
  surface equipment.

18
Casing Design

• Casing design for UBD is not significantly
  different than conventional.
• With air drilling, the casing tension should
  always be design with no buoyancy considered.
• No difference in burst design usually

19
Casing Design

• Collapse design should always be based on an
  empty casing string.
• A collapse design factor for UBD should be 1.2
  for UBD instead of 1.125 (API design factor).

20
Casing DesignCorrosion Control

• For fluid filled wells, corrosion is usually not
  considered when drilling.
• Corrosion is not a factor when drilling with dry
  air.
• Corrosion must be considered when drilling with
  mist, foam, or aerated fluids.
• Corrosion inhibitors should be added to the
  system.

21
Casing DesignCasing wear

• Casing wear is accelerated with gas drilling.
• This is due to less lubrication by the drilling
  fluid.
• Most air drilled holes are drilled faster and
  less time is spent rotating.
• Doglegs add to casing wear.

22
Completion Design

• If a well is properly drilled under underbalanced
  conditions, but is completed using overbalanced
  methods, much if not all of the
  impairment-reducing benefits might be permanently
  lost.

23
UB Completion Techniques

• Running production casing, liners, slotted liners
  and other tools underbalanced.
• Controlled cementing of production casing or
  liners.
• Running production tubing and downhole completion
  assemblies.
• Perforating underbalanced.

24
Running Casing and Liners UB

• If the completion is not open hole, casing or
  liners must be run.
• Surface pressures are usually reduced by
  bullheading a heavier fluid down the annulus.
• This fluid may be more dense than that with which
  the well was drilled, but still must be light
  enough to prevent overbalance.

25
Running Casing and Liners UB

• For casing and un-slotted liners, the well is
  usually allowed to flow while running the casing.
• This helps to prevent excessive surge pressures.
• A snubbing unit might be required to get the
  casing started in the hole.

26
Running Casing and Liners UB

• Slotted liners do not allow the well to be
  shut-in when the liner is across the BOP stack.
• It may be necessary to flood the backside with
  drilling fluid to allow the running of the
  slotted liner into the wellbore.
• Fluid is continuously pumped down the wellbore to
  reduce pressures.

27
Cementing Pipe UB

• If casing is run underbalanced, cementing should
  also be accomplished underbalanced.
• The hydrostatic head of the slurry-HSP can be
  reduced by entraining gas, or by reduced density
  additives.

28
Running Tubing UB

• No matter the production casing/liner design,
  production will almost always be required.
• With cemented casing and liners, the tubing can
  be run conventionally.

29
Running Tubing UB

• Tubing can be run underbalanced in a number of
  ways
• Snubbing.
• CT.
• Diverting flow.
• Setting a packer above the open zone with a
  temporary plug.

30
Bit Selection

• The bit selection process
• Assemble offset well data.
• Develop a description of the well to be drilled.
• Review offset well bit runs.
• Develop candidate bit programs.
• Confirm that the selected bits are consistent
  with the proposed BHAs.
• Perform an economic evaluation, to identify the
  preferred bit program.

31
Assemble Offset Well Data

• Identify the nearest, most similar wells to the
  proposed location.
• Gather as much information as possible about
  drilling these wells.
• Include bit records, mud logs, wireline logs,
  daily drilling reports, mud reports, directional
  reports.

32
Develop A Description of The Well to Be Drilled

• Characterize the proposed hole geometry
• Hole size.
• Casing points.
• Trajectory.

33
Develop A Description of The Well to Be Drilled

• Outline the anticipated values of rock hardness
  and abrasivity at all depths.
• Sonic travel time logs give qualitative
  indications of formation hardness.
• Low travel times - high rock compressive strengths

34
Develop A Description of The Well to Be Drilled

• Abrasivity is more difficult to quantify
• It is possible to form a qualitative assessment
  of the rocks potential for abrasive bit wear.
• Abrasiveness is related to
• Hardness of its constituent minerals.
• Bulk compressive strength.
• Grain size distribution.
• Shape.

35
Develop A Description of The Well to Be Drilled

• Make note of any formations that may have a
  special impact on bit performance.
• Divide the well into distinct zones
• Each zone corresponds to a significant change in
  formation properties or drilling condition.

36
Review Offset Well Bit Runs

• Determine what bits were used to drill through
  each formation likely to be penetrated.
• Identify which bit gave the best or worst
  performance.
• Look at the bit grading.
• Use the bit performance to infer formation
  hardness and abrasivity.

37
Identify Candidate Bits

• Identify which bits are candidates for each zone
  to be penetrated.
• Consider fixed cutter and roller cone bits.

38
Roller Cone Bits

• Key design considerations for roller cone bits
  are
• Cutting structure.
• Bearing.
• Seal types.
• Gauge protection.
• Should be matched to a formations anticipated
  hardness and abrasivity.

39
Fixed Cutter Bits

• Key design considerations for fixed cutter bits
  are
• Cutting structure.
• Body material and profile.
• Gauge.
• Stabilizing (anti-whirl) features.
• Should be matched to formations hardness and
  abrasivity.

40
Fixed Cutter Considerations

• PCD cutters wear rapidly in hard formations.
• Impregnated and natural diamond bits tolerate
  very hard and abrasive formations.
• Gauge protection is dependent on abrasiveness.

41
Develop Candidate Bit Programs

• At this stage, develop several alternative bit
  programs.
• Consists of type of bit, start and end depths,
  and anticipated penetration rates.

42
Confirm that the Selected Bits are Consistent
with the Proposed BHAs

• Do the operating parameters of the proposed BHAs
  inhibit bit performance?
• Is WOB limited?
• Do the selected downhole motors exceed the rpm
  capabilities of the bits?

43
Perform an Economic Evaluation, to Identify the
Preferred Bit Program.

• Use the estimated penetration rate and bit life
  to predict the probable cost for each bit run
• Chi CriTi Cbi
• Cri the hourly cost of operating the rig during
  that bit run, including the rig rate, fuel,
  all special services and rental items.
• Ti the duration of the run in hours.
• Cbi the cost of the bit.

44
Perform an Economic Evaluation, to Identify the
Preferred Bit Program.

• Predicted cost of the interval is the sum of all
  the bit costs for the particular bit program.
• Rank all the alternative bit programs.

45
Bit Selection for Dry Gas, Must and Foam Drilling

• Roller cone
• Fixed cutter

46
Roller Cone Bits

• Dry gas drilling produces a smoother hole bottom
  than with mud, and full coverage of the bottom of
  the hole with cutters is not as important.
• Larger teeth can be used for harder formations.
• Abrasive wear is normally higher for dry gas
  drilling.

47
Roller Cone Bits

• Cone offset is not as important with dry gas
  drilling.
• Good gauge protection is very important.
• Utilize sealed bearings.

48
Fixed Cutter Bits

• PDC bits are usually a poor choice for dry gas
  drilling.
• Not has heat tolerant.
• Diamond bits may be heat tolerant.

49
Bit selection for Gasified and Liquid Systems

• Not much difference from conventional drilling

50
Underbalanced Perforating

• Can be performed with wireline or with tubing
  conveyed perforating guns.

51
Drillstring Design

• Similar to conventional drilling.
• There will be less buoyancy.
• BHA should be designed so that all compression is
  in the BHA.
• An exception is in horizontal wellbores.

52
Example 6
Consider a planned well, where the maximum weight
on a 8¾-inch bit will be 50,000 lbf, the drill
collar size will be 6½-inch OD, by 2 13/16-inches
ID, the drilling medium will be air and the
excess collars should be ten percent to ensure
that the drillpipe remains in tension. Determine
the number of thirty-foot drill collars that will
be required.
53
Example 6

• The weight per foot of a drill collar can be
  determined from
• Wf 2.67(Dp2 Di2) 2.67(6.5 2 2.8125 2)
• Wf 92 lb/ft
• Di inside pipe diameter (inches)
• Dp outside pipe diameter (inches)
• Wf weight per foot in air (lb/ft)

54
Example 6

• The length of the drill collars can be calculated
  using Equation(5.32). Since this well is to be
  drilled in air, the buoyancy factor is one. It
  will not be one in other circumstances.
• Lc W(1DF) / Wf B
• B buoyancy factor (air1)
• DF design factor (decimal)
• Lc length of the bottom hole assembly (feet)
• W bit weight (lb)

55
Example 6

• For a bit weight of 50,000 lb
• Lc 50,000lb(10.10) / (92lb/ft)(1)
  598 feet

56
Example 6

• The number of thirty-foot drill collars would be
• 598 ft / (30) 19.93 or 20 drill collars
• The total weight, Wtc, of twenty drill collars
  would be
• Wtc 598 ft x 92 lb/ft 55,016
  lb

To develop 50,000 lb of drilling weight, twenty
drill collars are required. The total weight of
the drill collars will be approximately 55,016
lb, including the ten percent design factor.
57
Drillstring Design

• Drillpipe is usually designed with
• a design factor of 1.1
• and an overpull from
• 50,000 -100,000 lbf.

58
Example 7
Using the data from example 6, determine the
drillstring configuration for 12,000 foot deep
well. The drillpipe available is 5-inch, 19.50
lb/ft, Grade E and 5-inch, 19.50 lb/ft , Grade G.
The tensile capacity of the Grade E and G pipe
are 311,000 lbf and 436,000 lbf respectively.
All the drillpipe is API Premium Class and the
tensile strengths can be found in the API RP7G,
available from the American Petroleum Institute.
Use design factor of 1.10 and an overpull of
100,000 lbf.
59
Example 7

• From the example 6, the collar weight at the
  bottom of the Grade E pipe will be 55,000lb. The
  maximum pull on the Grade E, with the 1.10 design
  factor would be
• Pmax Pmax / DF
• DF design factor (decimal).
• Pmax length of the bottom hole assembly (feet).
• Tst bit weight (lb) .

60
Example 7
Pmax 311,000 lb / 1.10 283,000 lb The
maximum weight, Wmax, of grade E that can be
used with 100,000 lb overpull remaining
is Wmax283,0005,000100,000128,000lb
61
Example 7
The maximum length, Lmax, that can be used
is Lmax Wmax/Wf 128,000lb/19.5
lb/ft Lmax 6,564 feet (Grade
E) The maximum pull, Pmax, on the Grade G, with
the 1.10 design factor, would be Pmax
436,000 lb/ 1.10 396,000 lb
62
Example 7
The maximum weight, Wmax, of Grade G that can be
used with 100,000 lbf overpull remaining
is Wmax 396,000-55,000-100,000-128,000 Wmax
113,000 lb The maximum length , Lmax, of Grade
G drillpipe that can be used is Lmax
113,000/19.505,795 feet
63
Example 7

• Since the length of the Grade G is greater than
  that necessary to reach the surface, Grade G is
  acceptable to the surface. The drillstring would
  consist of the following
• 598 feet of drill collars (refer to Example 6).
• 6,564 feet of 5-inch, 19.50 lb/ft, Grade E
• drillpipe.
• 4,838 feet of 5-inch, 19.50 lb/ft, Grade G
• drillpipe.

64
Example 7
In this example, the maximum force that can be
pulled on the drillstring in the event it becomes
stuck is 100,000 lbf over the string weight, once
all of the Grade E drillpipe is in the hole. The
weak point will be at the top of the Grade E
drillpipe. If the drillstring is changed, the new
maximum pull must be calculated.
65
Separator Design

• Capacity is a function of
• Size.
• Design and arrangement.
• Number of stages.
• Operating P and T.
• Characteristics of fluids.
• Varying gas/liquid ratio.
• Size and distribution of particles.

66
Separator Design

• Capacity is a function of
• Liquid level.
• Well-fluid pattern.
• Foreign material in fluids.
• Foaming tendency of fluids.
• Physical condition of separator.
• Others.

67
Maximum Gas Velocity
The maximum gas velocity in an oil and gas
separator that will allow separation of liquid
mist from the gas can be calculated with the
following form of Stokes, law Vg Fco
(?L ?g)/?g½ (1) Where Vg maximum
allowable gas velocity, ft/sec Fco configuration
and operating factor (empirical) (see Fig.
12.32 for values) ?L density of liquid at
operating conditions, lbm /cu ft ?g density of
gas at operating conditions, lbm /cu ft
68
Configuration and operation factor FCO for oil
and gas separators and gas scrubbers (see Eqs. 1
and 4 through 6)
9.0
3.0
8.0
2.67
7.0
2.33
6.0
2.0
5.0
1.67
L/D RATIO FOR VERTICAL SAPARATORS
L/D RATIO FOR HORIZONTAL SEPARATORS
VaL/D RATIO FOR VERTICAL SAPARATORS
4.0
1.33
3.0
1.0
2.0
0. 67
0.33
1.0
0
0
0 0.1 0.2 0.3 0.4
0.5 0.6 0.7 0.8
0.9 1.0
Fco ( CONFIGURATION AND OPERATION FACTOR) see
equations 1,4,5 and 6
69
Gas Separating Capacity
The maximum allowable gas velocity Vg of Eq. 1 is
the maximum velocity at which the gas can flow in
the separator and still obtain the desired
quality of gas/liquid separation. Only the open
area of the separator available for gas flow is
considered in calculating its capacity.
70
Gas Separating Capacity
The gas separation capacity of an oil and gas
separator can be stated as qg
Ag Vg
(2) Where qg volume of gas
flowing through separator, cu ft/sec Ag cross-sec
tional area of separator for gas flow, sq
ft Vg gas velocity, ft/sec, from Eq. 1 The ?g
of Eq. 1 is calculated from Eq. 3 as follows
?g (P Mg) /(Zg RT) (3)
71
SEPARATOR
GAS CAPACITY OF VERTICAL OIL AND GAS SEPARATORS
72
LIQUID CAPACITIES ARE BASED ON
LIQUID CAPACITY OF VERTICAL OIL AND GAS SEPARATORS
73
LIQUID DEPTH
GAS CAPACITY OF HORIZONTAL OIL AND GAS SEPARATORS
74
SEPARATOR OD
LIQUID CAPACITY OF HORIZONTAL OIL AND GAS
SEPARATORS