The document discusses techniques developed at Louisiana State University to address gas flow behind casing issues. It describes early-time gas flow symptoms and mechanisms. It then discusses the Top Cement Pulsation technique developed by LSU to address early-time gas flow by liquefying cement slurry. For late-time gas flow, it provides statistics on sustained casing pressure occurrences and regulations. It outlines methods developed by LSU to diagnose gas leaks using bleed-down and buildup tests and assess failure risk. Finally, it presents the Buoyant Kill technique developed by LSU to remove sustained casing pressure using non-aqueous heavy kill fluids through displacement experiments.

1. Andrew K. Wojtanowicz, PhD PE
Louisiana State University
Annual DrillWell Seminar 2019
Sola Strand Hotel, Stavanger, Norway
September 25, 2019
Development of LSU Wellhead Intervention
Techniques for Annular Integrity Control
with Gas Flow behind Casing

2. 2
Contents:
• Early-time gas flow: - symptoms and mechanism;
• Wellhead intervention – Top Cement Pulsation, TCP (LSU)
• Late-time gas flow: - symptoms and statistics;
- regulations and needs
• Diagnostics: - gas leak sizing (LSU)
- risk assessment (LSU)
• Wellhead intervention – Buoyant Kill technique (LSU):
- kill fluid selection – table-top
- process visualization – floor-top
- process verification – pilot-scale
- demonstration – well-scale (LSU)
• Summary

3. Early-time GFBC – Gas Flow After Cementing (GFAC)
- Gas invasion after cement placement and before setting time
of cement
Gas Flow Behind Casing (GFBC)
Late-time GFBC – Sustained Casing Pressure (SCP)
- Annular migration of gas in producing wells long after
well completion

4. GFAC Symptoms – Chain of Events
• Cementing is completed w/o problems; Diverter/BOP
stack is nippled down after WOC
• In 1.0 – 10.5 hours the well starts flowing; Diverter is
nippled up and well diverted to control the flow.
• Diversion fails and the flow becomes more difficult to
control.
• In case of severe flow, the rig is evacuated.

5. Time
Lt
Lt
Lt
Lt
Lt
pf
pw
Pore pressure
Lost
overbalance
Bottom pressure unloading
Bottompressure
Decompression
gradient:
Gas formation
Permeable
formation
GFAC physics:

6. Bottom Pressure Drop After cementing
(Field Test)Pressure
Time
2950 psi pressure loss
4150 psi
1700 psi
7100 psi
2600
Casing
Gauges
Cement
Mud
8754’’
3636’
Pressure Unloading Model (LSU)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
0 100 200 300 400
Time (min)
Pressure(psi)
pressure transient model

7. Options for GFAC prevention
• Use new cements (higher cost):
- lightweight cements: ∆p control
- expandable cements: ∆V/V control
- straight angle cements: SGS control
- filtration agents: ∆V control (SPE-184564-MS, 2017)
• Modify cementing operation - increase thickening time:
- slurry liquefaction by shear
✓ Casing rotation / vibration
✓ Downhole cement vibrators
✓ Top cement pulsation (TCP) – LSU study

8. Cement Slurry Liquefaction in Viscometer (LSU)
0
10
20
30
40
50
60
70
80
0 50 100 150 200 250
Time,min
102 1/s
1.6 1/s
0.0 1/s
5.1 1/s
YieldStress,#/100ft2
0 50 100 150 200 250
80
60
20
40
0
Class H + 1% CaCl2 +
0.5% Halad 344)
Observation: Very small shear rate prolongs slurry liquidity

9. 12
∆p = 100 psi
Time, min:sec
Pressureinpsi
0
10
20
30
40
50
60
70
80
90
100
110
0:46 1:03 1:21 1:38 1:55 2:12 2:30 2:47 3:04
Surface
pulse
at 6986’
at 8546’
Time, min:sec
Pressureinpsi
0
10
20
30
40
50
60
70
80
90
100
110
0:46 1:03 1:21 1:38 1:55 2:12 2:30 2:47 3:04
Surface
pulse
at 6986’
at 8546’
Low-frequency small hydraulic pulsation at the wellhead
Top Cement Pulsation (TCP)
0’
Pulsation

11. Wells Treated with Top Cement Pulsation
Field
GFAC
probability,% TCP Jobs
#
# Wells
w/o FAC
% Wells
with FAC
Tangleflags 10.5 24 24 0 100
Wildmere 25.0 20 18 10 60
Abbey 80.0 8 6 25 69
Other 75.0 28 28 0 100
All 44.0 80 76 5.0 93.4
Probability
reduction,%
Field Performance of Top Cement Pulsation

12. Late-time Gas Flow

13. • Casing head pressure is recorded due… heating
/ ballooning / gas leak….???)
• Open needle valve - pressure drops to zero;
• Close needle valve:
- pressure stays at zero (heating/balooning)
- pressure returns (gas leak) = SCP
Sustained Casing Pressure (SCP)
SYMPTOMS – Chain of Events:

14. Wellhead Pressure Bleed-down and Buildup (B-B)
(Well 18 - Intermediate casing)
1000
1100
1200
1300
1400
1500
0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0
Time (Hours)
Pressure(psi)
Valve closed
Valve open

15. SCP Problem
• Occurs randomly – no prediction
• Is persistent – cannot be bled off
• Venting not allowed – pollution
• Difficult/ access to outer annuli
• Expensive removal
• High pressure but small rate

16. SCP Occurrence & Abundance
Onshore Alberta (Watson, 2007):
14,175 of 315,000 onshore wells surveyed had surface casing
exhibiting gas migration
US GOM (MMS Report, 2004):
6,717of 14,927 wells had SCP: 2,215 of which
linked to leaking cement. Cost of removal: $650 MM
Poland (PIGNIG data, 2011):
20% to 60% wells with SCP - would bleed-off to zero @ 100 – 5000 scf/d
and re-pressurize
China (Personal communication, 2018)
80 % of shale gas field wells are leaking gas
US unconventional play in Denver-Julersburg basin, CO
(IADC/SPE-189587-MS) 2018:
One well with SCP for every five wells drilled – up to 58% in some areas.
US unconventional Cana Woodford Shale (SPE-174525-MS) 2015
SCP in some wells before fracking – in all wells after fracking

17. SCP Regulatory Control
• Bureau of Safety and Environmental Enforcement (Dpt. Interior)
• Published in 30 CFR 250.519-531 and API RP 90
SCP > MAWOP ?
N Y
SCP must
be removed
Does SCP
bleed to
zero?
NoYes24-hr pressure
buildup:
ΔP24 < < SCP ?
N
Large gas leak
to be remediated
Concept: Tolerate small SCP; Remove large SCP
Small
acceptable
gas leak
MAWOP is defined as:
Lesser of 50%∙MIYP of outer casing,
or 75%∙Collapse of inner casing,
or 80%∙MIYP of next outer casing

18. 1. Consider only casing head failure pressure
2. Ignore casing shoe failure pressure and risk
3. Do not quantify leak size (perm. / conduct.)
4. Do not address rates (leak rate / emission rate)
Shortcomings of Current Criteria:
SCP program @ LSU – JIP:
• Risk of failure: casing shoe or wellhead
• B-B test analysis - Leak size determination
• SCP removal - Buoyant Kill technique
• Leak & emission rates determination

19. Risk of
Surface vs. Subsurface
Failure due SCP

20. Well integrity failure - pollution
Surface failure:
• casing head failure;
• gas emission to atmosphere.
Subsurface failure:
• casing shoe breaching;
• gas migration outside well;
• pollution of USDW, or
atmospheric emission
USDW
Environmental Hazard of SCP

21. Wellhead or Casing Shoe Failure ?
Gas source
TOC
SCPd
Casing Shoe
Strength (CSS)
(Pcsg)
(PR)
Emission
rate ?
SCPd > CSSPcsg > MAWOP
If
Surface
failure
Sub-surface
failure
Risk of
failure?

22. Annulus Casing Depth ,ft MIYP, psig Maximum Pressure
Wellhead Shoe
A 9 5/8", 53.5#, Q-125 14,830 12,390 NA NA
B 13 5/8", 88.2#, Q-125 10,470 10,030 4,168 1,489
C 18 5/8", 136#, N-80 6,202 5210 1,276 1,424
D 24", 256#, Gr.B 1,209 1595 478 558
In “B” annulus, casing shoe failure controls well integrity
Surface vs. Subsurface Failure ?
(Wellhead failure or casing shoe breaching)
Case study of a 14,830-ft well in GOM:

23. 0
0,0001
0,0002
0,0003
0,0004
0,0005
0,0006
0,0007
0,0008
0 2000 4000 6000 8000 10000 12000 14000
SCPd
Casing Shoe Pressure, psi
ProbabilityDensityFunction
Risk= 79.4%
Risk of Casing Shoe Failure due SCP
Unknown OBM thermally stable in time with non-progressive gels
High risk*
* Could be considerably
reduced with better mud info
Pcsg = 4,168 psi
ρin = 12.8 ppg
TOC @ 10,385’
CSS10,754’

24. B-B Test Analysis:
Leak Size & Rate

25. Sizing Gas Leak with B-B Test Simulator
• Describes pressure bleed-off and buildup
in a liquid-free casing head above gas - cut
liquid column on top of cement
Cement
Mud
Column
Gas
chamber
Gas
source
• In cement - 1-D gas flow with changing
flow rate at upper boundary and
constant pressure at lower boundary
• In liquid column - two-phase disperse
flow of gas bubble swarms slipping
upwards (drift model) in a non-Newtonian
(Power-Law) liquid
• At gas chamber (casing head) - gas
accumulation (buildup) or release
(bleed-down) – two-phase flow
through a choke

26. Well 19 - B-B Test Analysis
Iterative matching to find:
• pressure and depth gas source;
• gas leak size (effective permeability)
• casing head gas volume (gas chamber).
0
400
800
1200
1600
0 500 1000 1500
Time (min)
CasingPressure(psia)
Theoretical Data
Field Data
kA = 4.4 md-ft2
pf = 4470 psi
k = 34 mD Zf = 5450 ft
pf = 4,470 psi Lg = 23 ft
Gas: SG = 0.71
Mud: ρ = 11ppg
K = 285 eq.cp
n = 0.8
σ = 68 dyne/cm

27. B-B Test of 19 Wells – Cement Leak Rate
Well Leak Rate, scf/min
(BSEE Data Base) Seawater
in Annulus
Mud
in Annulus
WELL 7 0.14 0.14
WELL 8 2.82 0.93
WELL 9 5.41 2.79
WELL 10 (B ANNULUS) 0.34 0.25
WELL 10 (C ANNULUS) 0.09 0.05
WELL 12 0.01 0.01
WELL 13 6.77 5.42
WELL 14 22.08 18.68
WELL 19 0.03 0.03
WELL 22 38.86 31.66
WELL 25 0.41 0.18
WELL 33 0.08 0.03
WELL 35 0.46 0.24
WELL 36 0.10 0.03
WELL 38 0.01 0.01
WELL 23 (XU, 2002) 0.000095 0.000076
WELL 24 (XU, 2002) 0.000212 0.000061
CASE 1 (HUERTA, 2009) 27.47 16.18
CASE 2 (HUERTA, 2009) 0.03 0.03
• Large/small leak threshold set as 15 scf/min rate*
• Find cement leak size (mD) and compute leak rate
* API 14J for subsurface safety
valve integrity standard
16% wells

28. Buoyant Kill of SCP

29. Buoyant Kill Principle
Cement top
Annular
fluid
Cement leak
Kill fluid

30. LSU Slot Model – Visual Experiments
Size: 1.3”x13”x3’
Capacity: 2.6 gals
Clear annular fluid:
• Laponite clay
• Density (Potassium
Chromate)8.4-10 ppg
• Viscosity (CMC/PAC)12 - 40 cP
• YP: 0.8–11 #/100 sqf
• GS10min = 2 - 32 #/100 sqf
Hydraulic similarity

31. Failure of Miscible Displacement
(B&L and B&C….with weighted WBM)
12 ppg mud – Miscible 2 gpm
LSU Slot Model experiment:
Inject heavy WBM into clear WBM
• Heavy mud is instantly
mixed with the water-
base mud w/o settling
• Most of the heavy mud
would return in overflow

32. Need for Immiscible Hydrophobic Kill Fluid
LSU Slot Model experiment:
Inject heavy non-aqueous KF
into (clear) WBM
• Gravity settling w/o mixing
• Complete displacement
bottoms up
• Minimum volume of displacing
fluid.
• Maximum pressure buildup
12 ppg immiscible (2 gpm)

33. Compatibility Test:
25 ppg KF into N-N synthetic mud
Rag
zone
KF = Albemarle Brominated Organics
• Densities between 11- 25 ppg
• Withstand up to 150 degrees Celsius
• Partitioning coefficients from 2 to 7
• Interfacial Tension from 24 to 32 dynes/cm
• Viscosities from 2 to 4090 cP

34. Pilot - scale Experiments
0
2
4
6
8
10
12
14
16
18
20
0,00 1,00 2,00 3,00 4,00
BottomPressure,psi
Time, hours
AF fill-up
Gellation stage
Gas
injection
KF
injection
Drainage
Features:
• 30-ft high annulus (0.5 gal)
• 2 hours gel-up time
• KF injection @ const. rate
• TC (bottom) pressure vs. time
• Samples: overflow & drainage
Procedure:

35. Pilot-scale Model
Transducers
KF injection
port
Drains Gas breather
connections
AF injection
port
Gas flow
meter
Safety
relief
valve

36. 11
12
13
14
15
16
17
18
0 5 10 15 20 25
11 ppg low gel AF - 17 ppg KF - 2.48 gpm
11 ppg low gel AF - 17 ppg KF - 1.36 gpm
11 ppg high gel AF - 17 ppg KF - 0.93 gpm
Non-linear
Non-linear
Small
nonlinearity
Complete displacement line
Pilot Tests – TC Pressure Buildup due Displacement
Time. minutes
Pressure,psi
• Linear trend = perfect displacement; Slope = f(q, ∆ρ)
• Deviation = KF in overflow due mixing and gas flotation effect
• Reason for incomplete displacement: KF shortage
• Best 100% performance at low displacement rate

37. Constant- pressure
continuous displacement
Buoyant Kill Design
Advantage:
No gas migration (flotation) during
the treatment
TOC
ACP
Non-aqueous KF
= constant

38. Procedure:
1. Fill 15.5 bbls mud
2. Age 2 hours
3. Inject gas downhole
4. Build SCP = 350 psi
5. Pump KF with pump “P”
6. Keep constant BHP
(TOC) with choke “A”
7. Collect samples
Full-scale Test
in LSU well
57’, 0.375” ID tbg
Wellhead SCP
350 psi
2,750 ft
TOC gas
1,500 psi
KF

40. Pressure
Time, hours
Designed Pressure Control
Pressure @ TOC
1
2
3
4
5
SCP
Pressure,psi
1- AF fill up
2- AF gelation
3- Gas injection & migration
4- Wellhead SCP adjustment
5- KF injection
Inject KF

41. 76
Actual Pressure Change
• The 350 psi wellhead pressure (SCP) is removed
w/o changing TOC gas pressure
Pressure at TOC

42. SUMMARY
LSU studies show how to:
• prevent “early” gas migration (GFAC) with TCP
• analyze B-B test of SCP well to find size and rate of annular gas leak
• assess risk of surface vs. subsurface pollution due SCP
• compute potential gas emissions from failed SCP wellhead
• remove SCP - prior to P&A - by wellhead intervention using Buoyant
Kill technique

43. Questions?