1. Oil-Field Hydraulics Chapter 7 Kick Fundamentals
PTRT 1321
Oil-Field Hydraulics
Chapter 7
Kick Fundamentals

2. Kick Fundamentals
Kick – unwanted flow of formation fluids into the wellbore
If recognized it can be handled in a controlled manner
If not recognized it can become uncontrollable – blowout
Harmful to personnel, equipment, environment
Wastes valuable reservoir energy

3. Causes of Kicks
Hydrostatic pressure is LESS than the formation pressure in a permeable formation open to the wellbore
Primary means of control is to maintain correct hydrostatic pressure
During drilling, completion or workover changes can occur that allow the formation pressure to exceed the hydrostatic pressure
Awareness of the possibility and then understanding of actions necessary to control the kick are important

4. Causes of Kicks Insufficient fluid weight
Inadequate fluid level in wellbore
Swabbing
Surging
Lost circulation
Abnormal pressure
Obstructions in the wellbore
Equipment failure
Human error

5. Insufficient Fluid Weight
During completion and workover the weight of the circulating fluid is the primary means of controlling a well
During remedial activities fluid density can become low for several reasons
Replacing one fluid for another, e.g. brine for a fracturing or acid job being replaced with a packer fluid
Excess rainwater if entering the circulating system can greatly affect the fluid density
Sometimes the density is intentionally decreased and must be done prudently

6. Failure to Maintain Fluid Levels
Tripping pipe can cause the level of fluid to drop since the metal was displacing fluid while in the hole
This displaced fluid must be replaced as the pipe is removed – monitoring volume helps determine if formation fluids have entered the well
Find pipe information in many places
Halliburton Red Book – eRedBook
Appendix B of the text

7. Pressure Lost pulling wet string

8. Example:
/ft
Each 90-ft stand of drill pipe generates about a 25 psi drop in pressure (0.27 x 90 = 24.3 psi)
Some regs require that the well be filled after five stands have been pulled, or when the well has lost 75 psi whichever comes first

9. Pulling the String Dry

10. Example:
/ft
Note that perhaps 13 or 14 stands of pipe can be removed prior to hitting the 75 psi requirement

11. Effect of Wellbore
Small wellbore should generally be refilled more often than a larger well bore
= maximum length of workstring that can be pulled, ft
= desired pressure drop, psi (75 psi in many cases)
= fluid weight, ppg
= annular capacity, bbl/ft
= work string displacement, bbl/ft

12. Example:
Appendix B has capacities and displacements for several sizes of drill pipe, casing and hole dimensions
Halliburton Red Book is another good source of information

13. In class Exercise (Use Appendix B)
Determine how many feet of drill collar may be removed without exceeding 75 psi if you are using 5” drill collar in an 7⅞” hole
Assume you are using brine with a fluid weight of 11 ppg
Note: If a kick occurs while tripping pipe most operators suggest that the pipe be run back into the hole after the well is shut in to provide initial control – strip the pipe back in under pressure

14. Swabbing
Inability of fluid to fall past the tubing fast enough as it’s being pulled
Swabbing is more likely if:
Tubing is pulled too fast
Using high viscosity or high gel fluids
Balled-up bit (like the rubber gasket on a syringe)
Plugged work string
Thick wall cake in uncased hole
Small clearances between string and wellbore
Swabbing most often occurs when you first move the string off bottom

15. Safety (Trip) Margin Additional fluid added to compensate for swabbing
Note that this equation is related to Eq. 9 on page 6-4 for hydrostatic pressure

16. Example

17. Alternate Calculation using Yield Point of Fluid

18. Example

19. Surging
Increase in wellbore pressure that occurs during downward movement of pipe (still caused by the fluid not being able to get out of the way
Minimize surging by:
Run in at slow rates
Keep fluid in good condition (minimize viscosity and gel strength)
Break circulation periodically while running pipe into the well
Make sure volume in equals volume out
Avoid small clearances

20. Pressure due to Gel Strength

21. Example:

22. Lost Circulation
Fluid loss can upset the balance between hydrostatic pressure and formation pressure
Formation fracture is one of the causes of lost circulation and this possibility should always be kept in mind
Formation strength related to weight of overburden and the pressure of the fluid in the pores
Fracture can result in a kick
Lost circulation can also occur even when fracture pressure is not exceeded due to formations that are:
Cavernous
Faulted
Vuggy (holes larger than a pore but too small for a person)
Jointed
fissured

23. Abnormal Pressure
Usually used to describe pressures in excess of those expected by a column of fluid of the same depth as the formation
Low pressures are referred to as subnormal
Normal is typically = 9 ppg or psi/ft
Can be caused by
Salt domes
Faulted structures
Underground blowouts that charge other formations penetrated by the wellbore
Uplift and erosion
If sand or shale deposits were formed so quickly that connate water could not escape
Well logging or Measurement While Drilling(MWD) techniques can detect and predict such abnormal pressure zones

24. Obstructions in the Wellbore
Obstructions such as a packer or a plug can trap pressure below the obstruction
Suppose a well that was plugged and abandoned is now being redrilled
7000 ft TVD and Formation Pressure of 2,694 psi (equivalent FW = 7.4 ppg)
Plug is set at 2,000 ft TVD and is drilled through using oil emulsion mud weighing 7.4 ppg
At 2,000 ft this mud exerts about 770 psi
Considerable formation pressure is now exposed to only 770 psi
Even though the formation fluid will produce its own hydrostatic head from 7000 ft up to 2,000 ft it is unlikely to completely balance the formation pressure and flow with begin

25. Human Error
Control can be lost due to human error, namely uncertainty as to the appropriate course of action to take
When necessary to shut in a well it must be done swiftly, without hesitation
No time should be taken for second opinions, if doubt exists then shut in the well
Most operators recommend and many regs require that crews be trained in the proper procedures for shutting in a well
Training runs and crew rotation is important so that everyone learns the appropriate steps to take when needed

26. Predicting Formation Pressures
Avoiding a kick is best accomplished with fluid in the wellbore that is dense enough to control formation pressure but light enough to prevent lost circulation
Helpful to know the formation pressures ahead of time
Pressures can be predicted using geologic, seismic and historical data combined with wireline logs of the well

27. Geologic Data
Faults – can trap formation fluids and allow abnormal pressures to develop. Pressures can change abruptly across the fault
Large structures – domes or anticlines can have abnormal pressures above the oil-water or gas-water contact because of the density differences. Abnormal pressures can often also be seen in the reservoir beds
Massive shale beds – pressures should be expected to rise abnormally with depth in thick shale beds. Watch for transition zones in which the pressure will begin to depart from normal

28. Geologic Data
Massive Salt Beds – plastic flow transmits overburden pressure to the rock below resulting in high pressure in and below the salt bed ppg may be required
Charged sands – pressure from an underground blowout escapes into a shallow sand bed pressurizing it. When a new well is drilled through the same bed it will experience abnormal pressures

29. Other Sources of Data
Seismic – deduce the shape and extent of subsurface formations. Predictions regarding abnormal pressures can then be made
Historical – mud records and drilling reports from other wells drilled in the same area can give a good indication regarding the likelihood of abnormal pressures
Logging
electric or induction log can indicate pressurized shale having more water than normally pressurized shale
Acoustic or sonic logs can also indicate high-pressure shale since speed of sound is slower because of the water in them
Density log (nuclear) can also indicate high pressure shale since it is less dense than normally pressurized shale

30. Kick Warning Signs Gain in pit volume Increase in fluid return rate
Well not taking proper fluid volume during trips
Drilling rate change
Decrease in circulating pressure or an increase in pump strokes
Change in trip, connection, or background gas
Gas-cut fluid, water-cut fluid or chloride change
Appearance of shale at the surface (cuttings)
Well flows when the pump is shut down
Change in rheology (viscosity, flow properties) of the returning fluids

31. Pit Gain
Pit gain is sure evidence that circulating fluid is being displaced by formation fluid
Pit are all at the same level when fluid is not being circulated
Suction pit drops most and pit nearest the return increases the most
Pit-level indicating device combines the volume contained in each pit (totalize) and displays it as a single indication

32. Pit Gain (cont)
Rate of pit gain can be an indication of the permeability of the kicking formation
High-permeability
Rapid flow of fluid
Fast pit level rise
Fluid not gas-cut until a considerable volume of fluid flows from the well
Flow can start as the formation is penetrated
Kick can be sudden and very dangerous
Can be difficult to detect if well is only slightly underbalanced
Pit gain can be very slow until the gas is near the surface
The expanding gas near the surface causes rapid unloading of the well reducing the BHP and allowing formation fluids to rapidly enter the well
During mixing and adding fluid to the pits only measured volumes should be added

33. Increased Flow of Fluid
Best way to monitor is with flow measuring devices
Flow check
Raise the kelly above the rotary
Stop the circulation pumps
Check the return for flow from the well
If still flowing then the well is kicking (wait for 2 or 3 minutes)
Oil-base fluid absorb gas requiring a longer wait time (perhaps 30 minutes) (1bbl can absorb 100 Mcf of gas)
If the well flows with the pumps off but little or no pressure appears with the well shut in then it’s likely to only need a slight increase in fluid density
If pressures appear when the well is shut in then well-killing procedures should be initiated

34. Well Not Taking the Proper Amount of Fluid
As mentioned earlier it is important to replace fluid displaced by pipe during a trip
Most accurately done with a trip tank

35. Pump Stroke Counter Number of strokes to fill the well
Number of bbls required divided by pump output in bbl/stroke
Pump stroke volume can be looked up (B.6 and B.7 or other oilfield handbooks
Or calculated using the equations provided in the text

36. Duplex Pump Triplex Pump
Note: There is some lag between the stroke counter and the flow meter. This means more fluid enters the well than is counter by the stroke counter.

37. Changes in Drilling Rate
When bit enters an overpressured formation the rate of penetration usually increases (except when it doesn’t)
Sudden increase = drilling break
Generally accepted policy is to conduct a flow check after only 2 to 4 ft penetration into the break

38. Changes in Pump Speed
Pressure imbalance between tubing and annulus changes circulating pressure
If gas is encountered during the rise through the annulus it will decrease the density of the annular fluid giving rise to a decrease in circulating pressure and pumping speed increases
Time for the preventer to be closed

39. Increase in Different Types of Gas
Gas detection analyzer – establish a baseline for the type of gas being produce
Type of gases returned can provide information on the presence of a kick
Three types of gases
Background gas
Connection gas
Trip gas

40. Background Gas
Small amounts of gases entrained in the cuttings can be used to establish a baseline (trend line).
Monitoring this trend can give early indication that you are penetrating new formation and a kick could occur

41. Connection and Trip Gas
When kelly is lifted to add a joint of pipe to the workstring swabbing can occur
When pumps are shut down the reduction of BHP can also allow formation fluids to enter the well (including gas).
Small fluid entries may not be detected by flow rate or pit volume but can be detected using a gas analyzer
Trip gas is more of the same as the workstring is pulled from the well

42. Gas-cut Circulating Fluid
Gas-cut fluid does not normally cause a significant reduction in BHP (because the pressure downhole keeps the volume of gas small
The gas will expand near the surface and make the fluid light at the flow line
Fluid weight should never be increased only because of gas-cut fluids

43. Effect of Gas-cut Fluid on BHP
Even though the fluid weight has been cut in half
The effect on BHP is only 104 psi (about 0.5%)
The effect of gas-cut is typically less than the effect cause by shutting down the pumps and stopping circulation

44. Water-cut Fluid or Chloride Change
Increased formation pressures squeeze water out of the formation leaving the remaining fluids higher in salinity
Thus salinity can be expected to increase when entering an overpressurized zone
This can be seen as increases salinity in the filtrate exiting the shale shaker
If this increased salinity is not coming from the make up water the problem must be in the well
Chloride measurements indicate the level of salinity and steadily increasing chloride levels can indicate that pore pressures are also increasing

45. Sloughing Shale Underbalanced conditions can cause shale to slough
Other factors can also play a role
Formation dip
Compaction
Cementing of sand grains
Internal stress
Often attributed to other sources and the possibility of abnormal pressures can be overlooked