Air, Gas and Mist Drilling

1
PETE 689 Underbalanced Drilling (UBD)
Lesson 5 Air, Gas and Mist Drilling Read UDM
Chapter 2.1-2.4, Pages 2.1-2.74
Harold Vance Department of Petroleum Engineering
2
Air, Gas, and Mist Drilling

• Circulating Pressures.
• Equipment design.
• Operating procedures.
• Limitations of Dry Air Drilling.
• Natural Gas Drilling.
• Mist Drilling.

Harold Vance Department of Petroleum Engineering
3
Circulating Pressures

• Calculating standpipe pressure starts with
  predicting the pressure just below the bit, and
  working your way back to the surface.

4. Pi

• 1. PS

2. Pb
3. Pa
Pressure Calculation Steps for Pure Gas Fluid
Harold Vance Department of Petroleum Engineering
4
Bit Pressure Drop

• As air flows through the jets, it expands in
  response to the decrease in pressure and its
  velocity increases.
• Once the pressure drop exceeds a certain level,
  the air velocity reaches the prevailing speed of
  sound.

Harold Vance Department of Petroleum Engineering
5
Bit Pressure Drop

• At this point, the air cannot expand any faster
  and the upstream pressure becomes independent of
  the downstream pressure.
• This implies that under sonic discharge
  conditions the standpipe pressure is independent
  of the annular pressure.

Harold Vance Department of Petroleum Engineering
6
Bit Pressure Drop
The condition for the onset of sonic flow in
ideal gases is
Pa 2 Pb k1
-k K-1

Pa upstream pressure at the onset of sonic
flow, psia. Pb downstream pressure. k
ratio of specific heat at constant
pressure to that at constant volume. For air,
k 1.4 and Pa 1.89Pb
Harold Vance Department of Petroleum Engineering
7
Bit Pressure Drop

• If the upstream pressure is more than 1.89 times
  the annulus pressure beneath the bit, flow
  through the bit will be sonic.

Harold Vance Department of Petroleum Engineering
8
Upstream Bit Pressure Sonic Flow
G TaR 2 k1 0.5 An
Sgk k1
Pa
1-k
G mass flow rate of air in lbm/s An
total area of the bit nozzles, sq.in. Ta air
temperature above the bit, 0R R the
universal gas constant, 53.3 ft lbf/lbm 0R for
air. S gas gravity ( 1 for air). g
gravitational constant, 32.17 ft/s2
Harold Vance Department of Petroleum Engineering
9
Upstream Bit Pressure Sonic Flow
Noting that the density of air under standard
conditions is 0.0764 lbm/cu.ft. the above
equation reduces to
GTa0.5 An
QTa0.5 An
Pa 1.88 0.00239 Q
air flow rate (scfm).
Harold Vance Department of Petroleum Engineering
10
Upstream Bit PressureSub-sonic Flow
If the air flow velocity through the jets remains
sub-sonic, the pressure above the bit is related
to the mass flow rate and the annulus pressure
beneath the bit by
R ( k-1) G2Tb 2gSAn2Pb2
K K-1
Pa Pb 1
Harold Vance Department of Petroleum Engineering
11
Upstream Bit Pressure Sub-sonic Flow
For air this becomes Tb Temperature
below the bit, 0R ?g Gas density at STP,
lbm/cu.ft. ?air 0.0764 at STP, lbm/cu.ft.
0.236 G2Tb 3.5 An2Pb2
Pa Pb 1
Q?g 60
G
Harold Vance Department of Petroleum Engineering
12
Upstream Bit Pressure Sub-sonic Flow
The circulating air cools as it expands through
the bit. Assuming ideal behavior, the temperature
decrease can be estimated from Indicating
that the absolute air temperature below the bit
will be approximately 17 lower than that above
the bit if flow through the jets is sonic.
Pb Pa
K-1 k
Tb Ta
Harold Vance Department of Petroleum Engineering
13
Standpipe Pressure
v
Pa2 ß Tav2 (e 2ah/Tav 1) e
2ah/Tav
Ps
S 53.3
a
1.625 x 10-6Q2 Di5.333
ß
Di internal diameter of the drillstring, ft.
Harold Vance Department of Petroleum Engineering
14
Steps To Predicting Standpipe Pressure

• Assess whether flow through bit is sonic or
  sub-sonic.
• If sonic, the pressure above the bit is
  determined with equation 2.21
• This value is used in equation 2.25 to predict
  standpipe pressure.

Harold Vance Department of Petroleum Engineering
15
Steps To Predicting Standpipe Pressure

• If flow through the bit is sub-sonic, the annulus
  pressure below the bit must be first predicted
  (Angels analysis, etc) using equation 2.12.
• The pressure above the bit is determined by
  equation 2.23.
• This value is used in Equation 2.25 to determine
  standpipe pressure.

Harold Vance Department of Petroleum Engineering
16
Important Point

• When air drilling, large changes in
• annulus pressure may result in smaller
• changes in standpipe pressure, or in the
• case of sonic flow through the bit, no
• change in standpipe pressure at all.
• Hole problems that lead to an increase
• in annulus pressure may be indicated by
• small or no changes in standpipe pressure.

Harold Vance Department of Petroleum Engineering
17
Important Point

• It is very important to monitor the
• standpipe pressure closely and react
• promptly to unanticipated changes.
• It is important to know if flow through
• the bit is sonic or not.
• If flow is sonic, standpipe pressure will
• not change with changes in annulus
• pressure.

Harold Vance Department of Petroleum Engineering
18
Example

• 8.1/2 hole at 6000 drilled with
• 4.1/2 drillpipe air rate is 1,400 scfm.
  Penetration rate ranges up to
• 300 ft/hr. Bit has no nozzles in one example
  and three 14/32s in the other.

Harold Vance Department of Petroleum Engineering
19
Predicted bottomhole annular and standpipe
pressure at various penetration rates in a 6,000
foot dry, air drilled hole.
Harold Vance Department of Petroleum Engineering
20
Predicted standpipe pressure as functions of
penetration rate, for a bit with and without
nozzles, in a 6,000 foot deep, air drilled hole.
Harold Vance Department of Petroleum Engineering
21
Equipment Design

• Compressor output is often expressed in standard
  cubic feet per minute, scfm.
• Common output ratings are 750 to 1,000 cfm.
• Altitude (and corresponding atmospheric pressure)
  has an effect on the actual output of compressors.

Harold Vance Department of Petroleum Engineering
22
Compressor Design(Assuming that air behaves as
an ideal gas)
14.7 ( T1 460) 520 P1
Vt Vo
The air delivery rate, Qo, expressed in scfm, can
be found from
520 P1 14.7 (T1460)
Qo Q
Appendix A includes a table showing atmospheric
pressure at differing elevations.
Harold Vance Department of Petroleum Engineering
23
Normal Atmospheric Pressure at Different Altitudes
Harold Vance Department of Petroleum Engineering
24
Effect Of Elevation On Compressor Output

• At 6,000 above sea level the ambient pressure is
  11.8 psia.
• At this elevation, a compressor rated at 1,000
  scfm free air delivery will deliver only 803 scfm
  if the ambient temperature is 600F.
• At ambient temperature 6,000 elevation, the
  delivery rate will drop to 745 scfm.

Harold Vance Department of Petroleum Engineering
25
Compressor Rating

• Single stage compressors typically have a maximum
  discharge pressure of
• 135 psi.
• Multi-stage compressors have discharge pressures
  from 250 - 350 psi.
• Boosters will be required for standpipe pressures
  up to 1,500 psi.

Harold Vance Department of Petroleum Engineering
26
Mist And Formers Pump
Harold Vance Department of Petroleum Engineering
27
Blooie Lines

• Diameter too large will not carry cuttings
  efficiently to the reserve pit.
• Too small, additional pressure imposed downhole.
• Blooie line cross-section should be at least
  equal to that in the annulus over the longest
  section of the hole to be drilled with air.

Harold Vance Department of Petroleum Engineering
28
Frictional pressure losses down two different 150
foot long blooie lines
Harold Vance Department of Petroleum Engineering
29
Blooie Line
Harold Vance Department of Petroleum Engineering
30
Measurement of Air Injection Rate
An orifice meter should be installed between the
compressor and the mist injector to measure the
air injection rate. Fb orifice flow factor,
(Appendix B) Fg (1/s) 0.5 S Gas gravity, (1
for air). Remember to add the prevailing
atmospheric pressure to the gauge pressure to
obtain the absolute pressure.
v
520 hwPf Tf
Q Fb Fg
Harold Vance Department of Petroleum Engineering
31
Meter chart from a well in the Arkoma Basin. The
drillstring became stuck at 345 a.m. while
drilling at 10,845 feet.
Harold Vance Department of Petroleum Engineering
32
Operating Procedures

• Unloading a well with air.
• Dmax Pmax/0.433 .
• Dmax maximum water interval to be
• unloaded by air compressors.
• Pmax delivery pressure of the air system.
• It is, however unusual to unload more than 2,000
  of water at any one time.

Harold Vance Department of Petroleum Engineering
33
Limitations of Dry Air Drilling

• Water inflows.
• Downhole fires.
• Wellbore instability.

Harold Vance Department of Petroleum Engineering
34
Water Inflows
Mud ring formed from formation water wetting the
cuttings. Cuttings stick together and accumulate
at the shoulder on the top of the BHA,
Drillstring and the walls of the hole.
Cuttings mixed with a small amount of water will
form a mud ring at the top of the drill collars
where hole cleaning is critical.
Harold Vance Department of Petroleum Engineering
35
Downhole Fires
Effect of pressure on combustible concentrations
of natural gas in air
Harold Vance Department of Petroleum Engineering
36
Reverse Circulation Air Drilling Advantages

• Reduced Damage to Permeable formations.
• Quality and size of drill cuttings is improved.
• Wellbore integrity is improved
• Less air volume required.

Harold Vance Department of Petroleum Engineering
37
Reverse Circulation Air Drilling Disadvantages

• Greater likelihood of cuttings plugging the bit.
• Surface equipment needs improvement.
• Large inflows above the bit may cause problems
  circulating down the annulus.

Harold Vance Department of Petroleum Engineering
38
Natural Gas Drilling
v
?c ?f 3Cd?f
Vt 4gdc
Vt Terminal Velocity (ft/s). g
Gravitational acceleration, 32.17 ft/sec2 dc
Characteristic particle diameter, ft. Cd Drag
coefficient. ?c Density of cuttings,
lbm/ft3 ?f Density of fluid, lbm/ft3
Harold Vance Department of Petroleum Engineering
39
Terminal Velocity Of Natural Gas At Atmospheric
Pressure
Vtg Vtair (1/S)0.5
Vtg terminal velocity in natural
gas. Vtair Terminal velocity in air. S
Specific gravity gas.
Harold Vance Department of Petroleum Engineering
40
Natural Gas Drilling

• Lower density of natural gas than air results in
• Lower BHP.
• Lower drag forces.
• Higher required circulation rates.
• Non-ideal behavior of natural gas is not usually
  a problem since operating pressures are low (lt
  2,200 psi) and ideal behavior can be assumed.

Harold Vance Department of Petroleum Engineering
41
Natural Gas Injection Rate

• A first order estimate of the minimum injection
  rates can be derived by taking Angels figures
  for air drilling at the appropriate depth and
  penetration rate and dividing these by the square
  root of the gass specific gravity.
• Usually acceptable in practice.

Harold Vance Department of Petroleum Engineering
42
Mist Drilling

• Liquid volumes are only
• 1 to 2 percent at the prevailing temperature
  and pressure.

Harold Vance Department of Petroleum Engineering
43
For A Lightened Drilling Fluid
VgP VgP VmP VgP
VfP VsP
FgP
g gas
VfP VfP VmP VgP
VfP VsP
FfP
Eq. 2.35
f liquid
VsP VsP VmP VgP
VfP VsP
FsP
P solids
FgP FfP FsP 1
Harold Vance Department of Petroleum Engineering
44
For A Lightened Drilling Fluid

• We can assume that the gaseous phase acts as an
  ideal gas.
• Solid and liquid phases are incompressible.

Harold Vance Department of Petroleum Engineering
45
For A Lightened Drilling Fluid
Po P
VgP Vgo VP Vo V VsP VsoVs
Eq. 2.37
Harold Vance Department of Petroleum Engineering
46
Substituting Eq. 2.37 into 2.35
Po P
Vgo Vgo Vf Vs
FgP
Po P
From this, the gas fractional at pressure is
Harold Vance Department of Petroleum Engineering
47
Substituting Eq. 2.37 into 2.35
Fgo Fgo (Fo Fso)
FgP
P Po
Fgo Fgo (1- Fgo)

P Po
Harold Vance Department of Petroleum Engineering
48
For The Liquid And Solid Volume Fractions
Fo (1-Fgo) (Fgo)
FfP
P Po
Fgo (1-Fgo) (Fgo)
FsP
P Po
Harold Vance Department of Petroleum Engineering
49
Mixture Density (mist)
Vmo VmP
?mP ?mo
Assuming that the gaseous phase obeys the ideal
gas law and the solid and liquid are
incompressible,
Harold Vance Department of Petroleum Engineering
50
Mixture Density (mist)
?mo ( Vgo V Vs) Vgo V Vs
?mP
Po P
?moVmo VmoFo VmoFso VmoFgo

Po P
Harold Vance Department of Petroleum Engineering
51
Mixture Density (mist)
Finally
?mo 1-Fgo 1 -
?mP
Po P
Harold Vance Department of Petroleum Engineering
52
Example Mist Drilling

• Liquid is metered at 10.7 BPH (1cfm)
• Dry air injection rate 2,000 scfm
• Standpipe pressure 210 psig
• Liquid volume fraction at atmospheric pressure
  is
• 1cfm/(2,000 scfm 1cfm)5 x 10-4 .05

Harold Vance Department of Petroleum Engineering
53
Example cont

• Assume atmospheric pressure 15 Psia
• (P/Po) (21015)/15 15
• VgP 133 cfm
• Substituting into equation 2.40
• FfP 7.5 x 10-3

Harold Vance Department of Petroleum Engineering
54
Example cont

• Assume that there is a water inflow of 96.3 BWPH
  at BHP 135 psig
• Assume volume of cuttings is negligible.
• Total fluid volume is now 10 cfm.
• At the blooie line exit, the liquid volume
  fraction will be 10/2,000 x 100 0.5
• At bottom hole conditions the liquid fraction
  would be 4.78 - foam will probably form.

Harold Vance Department of Petroleum Engineering
55
Effect Of Temperature On Mist Density

• Equation 2.37 can be re-written

Po P
T To
VgP,T Vgo
Harold Vance Department of Petroleum Engineering
56
Effect Of Temperature On Mist Density

• BHT, in reality has little effect on bottom hole
  flow rates.

Harold Vance Department of Petroleum Engineering
57
Effect Of Temperature On Mist Density

• Depth Temp Flow rate Liquid
• 5000 140 0F 231 cfm 4.15
• 10,000 220 0F 262 cfm 3.68
• Pressure changes can result in up to 10 fold
  changes in volumetric flow rates.

Harold Vance Department of Petroleum Engineering
58
Hole Cleaning, Mist

• Water droplets act similarly to cuttings with
  slip velocity of near zero - mists do not clean
  the wellbore more efficiently than dry gas.
  Therefore annular velocities are high.
• Circulating fluid density is increased however
  and may add to the frictional pressure losses.

Harold Vance Department of Petroleum Engineering
59
Hole Cleaning, Mist

• The increased density will lower the terminal
  velocity of the cuttings, but will increase the
  BHP reducing the volumetric flow rate at the
  bottom of the hole.
• Higher air injection rates are usually required
  when misting than with dry air.

Harold Vance Department of Petroleum Engineering
60
Application Of Angels Method To Mist Drilling

• Determine the penetration rate that would
  generate the same mass of cuttings as the mass of
  liquid entering the well over a time period. This
  includes any base liquid, foamer, and water
  influx.

Harold Vance Department of Petroleum Engineering
61
Apparent Equivalent ROP
If the total liquid rate is L (BPH) the mass flow
of liquid entering the well will be 350.5L
assuming that the liquid is water ( 62.4
lbm/ft.cu.)
350.5L 380L 169
Db2
ROP?

p Db 2 4 12
This is added to the actual anticipated
penetration rate.
Harold Vance Department of Petroleum Engineering
62
Angels Method For Mist

• The minimum air injection rate, required for good
  hole cleaning during mist drilling, is
  determined either from Angels charts or from
  the approximation in equation 2.17.

Harold Vance Department of Petroleum Engineering
63
Example

• Hole size 7 7/8
• depth 5,000
• Drillpipe size 4 1/2
• Anticipated ROP 30 feet/hr
• Qo 671, N 65, H 5,000/1,000 5
• Minimum air rate for dry air
• Qa Qa NH 670 65x5 995 scfm

Harold Vance Department of Petroleum Engineering
64
Example

• Liquid injection rate is 6 BPH.
• Water influx is 3.8 BPH.
• Total liquid rate is 9.8 BPH.
• Penetration rate that would give this mass
  cuttings per hour is 60 ft/hr.

Harold Vance Department of Petroleum Engineering
65
Example

• The minimum air rate required for dry air
  drilling at a penetration rate of 90 ft/hr using
  the value of N for 90 ft/hr, N 98.3 would be
  1,162 scfm.

Harold Vance Department of Petroleum Engineering
66
Limitations To Mist Drilling

• Higher air injection rates than dry gas (up to
  40).
• Waste water disposal.
• Wellbore instability.
• Corrosion.

Harold Vance Department of Petroleum Engineering