1. Lesson 21 Prediction of Abnormal Pore Pressure
PETE 411 Well Drilling
Lesson 21 Prediction of Abnormal Pore Pressure

2. Prediction of Abnormal Pore Pressure
Resistivity of Shale
Temperature in the Return Mud
Drilling Rate Increase
dc - Exponent
Sonic Travel Time
Conductivity of Shale

3. HW #11 Slip Velocity Due 10-28-02
Read: Applied Drilling Engineering, Ch. 6
HW #11 Slip Velocity Due

4. Shale Resistivity vs. Depth
1. Establish trend
line in normally
pressured shale
2. Look for
deviations from
this trend line
(semi-log)

5. EXAMPLE Shale Resistivity vs. Depth 1. Establish normal trend line
2. Look for deviations
(semi-log)

6. to quantify pore pressure 9 ppg (normal)
(lb/gal equivalent)
Shale Resistivity
vs. Depth
1. Establish normal trend line
2. Look for deviations
3. Use OVERLAY
to quantify pore pressure
(use with caution)
9 ppg
(normal)

7. Depth, ft
Shale Density , g/cc

8. Depth, ft
Mud Temperature in flowline, deg F

9. Example
8.2 X
Why?

10. Example
8.8 X
Thermal conductivity, heat capacity, pore pressure...

11. Drilling Rate, ft/min
PHYD - PPORE , psi

12. Effect of Differential Pressure
DP = (P2 - P1)1,000
Effect of Differential Pressure

13. Typical Drilling Rate Profiles - Shale
The drilling rate in a normally pressured, solid shale section will generally generate a very steady and smooth drilling rate curve.
The penetration rate will be steady and not erratic (normally pressured, clean shale).

14. Typical Drilling Rate Profiles - Sand
The drilling rate in a sand will probably generate an erratic drilling rate curve.
Sands in the Gulf Coast area are generally very unconsolidated. This may cause sloughing, accompanied by erratic torque, and temporarily, erratic drilling rates.

15. Typical Drilling Rate Profiles - Shaley Sands
This is generally the most troublesome type drilling rate curve to interpret.
Many times this curve will look similar to a solid shale curve that is moving into a transition zone.
Shaley Sands
Note: This is a prime example why you should not base your decision on only one drilling parameter, even though the drilling rate parameter is one of the better parameters.

16. Typical Drilling Rate Profiles
Transition Zone Shale
If you are drilling close to balanced, there will probably be a very smooth, (gradual) increase in the drilling rate.
This is due to the difference between the hydrostatic head and the pore pressure becoming smaller.

17. Typical Drilling Rate Profiles
As the pressure becomes very small, the gas in the pores has a tendency to expand which causes the shale particles to pop from the wall. This is called sloughing shale.
The transition zone generally has a higher porosity, making drilling rates higher. In a clean shale the ROP will increase in a smooth manner.
Transition Zone Shale

18. Typical Drilling Rate Profiles
Note:
If you are drilling overbalanced in a transition it will be very difficult to pick up the transition zone initially.
This will allow you to move well into the transition zone before detecting the problem.

19. Typical Drilling Rate Profiles
This could cause you to move into a permeable zone which would probably result in a kick.
The conditions you create with overbalanced hydrostatic head will so disguise the pending danger that you may not notice the small effect of the drilling rate curve change. This will allow you to move well into that transition zone without realizing it.

20. Determination of Abnormal Pore Pressure Using the dc - exponent
From Ben Eaton:

21. Where

22. Example
Calculate the pore pressure at depth X using the data in this graph.
Assume:
West Texas location with normal overburden of
1.0 psi/ft.
X = 12,000 ft. X dc

23. Example
From Ben Eaton:

24. Example

25. E.S. Pennebaker
Used seismic field data for the detection of abnormal pressures.
Under normally pressured conditions the sonic velocity increases with depth. (i.e. Travel time decreases with depth)
(why?)

26. E.S. Pennebaker
Any departure from this trend is an indication of possible abnormal pressures.
Pennebaker used overlays to estimate abnormal pore pressures from the difference between normal and actual travel times.

27. Depth, ft
Interval Travel Time, msec per ft

28. Ben Eaton Example: Assume: S/D = 1.0 psi/ft
also found a way to determine pore pressure from interval travel times.
Example:
In a Gulf Coast well, the speed of sound is 10,000 ft/sec at a depth of 13,500 ft. The normal speed of sound at this depth, based on extrapolated trends, would be 12,000 ft/sec. What is the pore pressure at this depth?
Assume: S/D = 1.0 psi/ft

29. Ben Eaton
From Ben Eaton,
( Dt a 1/v )

30. From Ben Eaton Note: Exponent is 3.0 this time, NOT 1.2!
r = ( / 0.052) = lb/gal
p = * 13,500 = 9,320 psig

31. Equations for Pore Pressure Determination

32. Pore Pressure Determination

33. EXAMPLE 3 - An Application...
Mud Weight = 10 lb/gal. (0.52 psi/ft)
Surface csg. Set at 2,500 ft.
Fracture gradient below surf. Csg = 0.73 psi/ft
Drilling at 10,000 ft in pressure transition zone
* Mud weight may be less than pore pressure!
DETERMINE Maximum safe underbalance between mud weight and pore pressure if well kicks from formation at 10,000 ft.

34. Depth, ft Pressure, psi 2,500 Casing Seat FractureGradient
0.73 – 0.52 = (psi/ft)
2,500
Casing Seat
FractureGradient
= 0.73 psi/ft
Depth, ft
Mud Wt. Grad
= 0.52 psi/ft
10,000
5,200
Pressure, psi

35. Example 3 - Solution
The danger here is fracturing the formation near the casing seat at 2,500 ft.
The fracture gradient at this depth is 0.73 psi/ft, and the mud weight gradient is 0.52 psi/ft.
So, the additional permissible pressure gradient is 0.73 – 0.52 = 0.21 psi/ft, at the casing seat.
This corresponds to an additional pressure of
DP = 0.21 psi/ft * 2,500 ft = 525 psi

36. Example 3 – Solution – cont’d
This additional pressure, at 10,000 ft, is also 525 psi, and would amount to an additional pressure gradient of:
525 psi / 10,000 ft = psi/ft
This represents an equivalent mud weight of
/ = 1.01 lb/gal
This is the kick tolerance for a small kick!

37. Problem #3 - Alternate Solution
When a well kicks, the well is shut in and the wellbore pressure increases until the new BHP equals the new formation pressure.
At that point influx of formation fluids into the wellbore ceases.
Since the mud gradient in the wellbore has not changed, the pressure increases uniformly everywhere.

38. Depth, ft Wellbore Pressure, psi Casing Seat at 2,500 ft
525
Casing Seat at 2,500 ft
Depth, ft
After Kick and Stabilization
Before Kick
Kick at 10,000 ft DP
525
Wellbore Pressure, psi

39. At 2,500 ft Initial mud pressure = 0. 52 psi/ft
At 2,500 ft Initial mud pressure = 0.52 psi/ft * 2,500 ft = 1,300 psi Fracture pressure = 0.73 psi/ft * 2,500 ft = 1,825 psi Maximum allowable increase in pressure = 525 psi
At 10,000 ft Maximum allowable increase in pressure = 525 psi (since the pressure increases uniformly everywhere). This corresponds to an increase in mud weight of 525 / (0.052 * 10,000) = 1.01 lb/gal = maximum increase in EMW = kick tolarance for a small kick size.

40. Depth, ft Wellbore Pressure, psi 1,825 psi Casing Seat at 2,500 ft
Kick at 10,000 ft DP
Wellbore Pressure, psi

41. Depth, ft Wellbore Pressure, psi After Large Kick and Stabilization
Casing Seat at 2,500 ft
After Small Kick and Stabilization
Depth, ft
Before Kick
Kick at 10,000 ft DP
Wellbore Pressure, psi