Presentation on formation damage by Colin McPhee from Senergy, given to SPWLA Abu Dhabi Chapter on 5th Nov 2009

1. Unlocking Hidden Reservoir Potential Through
Integrated Formation Damage Evaluation
(SPE 115690 and SPE 120694)
Colin McPhee and Michael Byrne

2. Formation damage
├ What is formation damage?
├ any reduction in near wellbore permeability which is the
result of “any stuff we do”
├ ……….such as drilling, completion, production, injection,
attempted stimulation or any other well intervention
├ What is the impact?
├ Shell has estimated that (at an oil price of less than
$20/bbl) the cost of damage on Shell-operated assets was
$1 billion/year.
├ Shell, at that time, was producing roughly 3.3 % of total
world production.
├ Today, $70/bbl and global perspective means current best
estimate for cost of damage due to deferred production and
dealing with damage is: $100 billion/year

3. When is formation damage
important?
├ Prospect /development planning
├ correct selection of field development options
├ consideration of formation damage should be an integral
part of production or injection optimisation process
├ Development wells
├ best to minimise damage
├ but can also remove damage
├ Exploration and appraisal wells
├ identify potential in undeveloped discoveries.
├ recognising and diagnosing formation damage can unlock
hidden reservoir potential
├ Two field examples
├ others undoubtedly exist elsewhere

4. Example 1 - oil field
├ Two appraisal wells drilled in
10000
early 90’s
├ Well 1 drilled with OBM and 1000
cored. High water saturations
near OWC
├ Well 2 drilled with WBM and 100
cored. DST tested.
├ Rock properties (core)
Air Permeability (mD)
├ ka from 0.1 mD to 500 mD 10
(mean 10 mD)
├ clay minerals and carbonate
cements 1
├ kaolinite – up to 73% of clay
fraction
├ pore lining chlorite (20% to 0.1
40%) and illite (10% to 18%)
0.01
0.00 0.05 0.10 0.15 0.20 0.25 0.30
Helium Porosity (fractional)

5. Welltest in Well 2
├ DST 1/1a
├ perforated underbalanced (700 psi)
├ well flowed naturally for four hours then
died. Under N2 (CT) rate stabilised around
350 stb/d.
├ Stimulated with mud acid
├ PLTs show post-acid flowrate is around
50% of the pre-acid rate
├ Initial operator’s WTA interpretation
├ kh ~ 2030 mDft
├ k = 6 mD
├ S = -1.3
├ Operator relinquished licence
├ New operator saw productivity potential
from core
├ welltest re-interpreted
├ pseudo-PLT constructed from core data
and compared with well PLT

6. Core data
├ Extensive core dataset from Well 1 and 2
├ RCA “fresh-state” oil permeability (ko) at stress
├ routine air permeability (ka) at 400 psi
├ SCAL ko at stress
├ Permeability model at reservoir conditions
├ ka enhanced by core drying (clay damage)
├ convert to reservoir conditions
├ absolute (ka) to effective (ko @ Swir) conversion
├ CBW correction
├ stress correction
├ core to log transform
├ predict reservoir condition permeability over entire reservoir
interval

7. Permeability model – Well 2
├ MLR - best match to core

8. Core permeability correction
Fresh-state Ko data
1000
Fresh-state Oil Permeability at 3000 psi (mD)
100
1.2839
y = 0.1389x
2
R = 0.7944
10
1
0.1
0.01
0.001 0.01 0.1 1 10 100 1000
Air Permeability at 400 psi (mD)

9. Core permeability correction
SCAL Data
1000
100
Ko at 4500 psi (mD)
10
SCAL data
Equality
1
0.1
0.01
0.1 1 10 100 1000
Ka at 400 psi (mD)

10. Pseudo-PLT
├ Core ko to cumulative oil rate Cumulative Layer Contribution (fraction)
0.0 0.2 0.4 0.6 0.8 1.0
8350
Q Darcy’s Law
h1K1 Q1 A ∆P 8400
Q = K.
h2K2 Q2 L µ
H Q3 8450
h3K3
Qi = K i .hi Const .∆ P
h4K4 Q4
Q = Q1 + Q 2 + .... + Qi
Qi
Depth (ft MDRKB)
hiKi 8500
H = h1 + h2 + ... hi KoMOD1
KoMOD2
∆P
∑hK
8550
K arith = i i
H
(P − P )
8600
0.00708kh( wt )
qo =
i wf
µ o Bo ⎡ ⎛ 0.472re ⎞ ⎤
ln⎜
⎢ ⎜ ⎟ + S '⎥ 8650
⎟
⎣ ⎝ rw ⎠ ⎦
8700
├ PLT overlay suggests thin high
quality intervals are damaged

11. Productivity and skin
├ Short build up (weather)
├ re < h
├ Radial flow not established
├ k is function of kh and kv
├ No definitive interpretation is
possible
├ Little justification for the
interpreted negative skin
factors in original interpretation
├ Cryogenic SEM showed filtrate
retention in core tests
├ Large pressure surge on
perforating dislodged mobile
fines (kaolinite and illite) from RETAINED MUD FILTRATE LOSSES
the formation? BEFORE TEST AFTER TEST
├ Post mortem encouraging
enough to plan new appraisal
drilled with non-damaging DIF
Fluid has been retained in the micropores between the chlorite platelets

12. Example 2 – Gas Well
SOUTH NORTH
├ Appraisal well 42/13-2 (1998) Base Chalk
├
Late Cretaceous-Early Tertiary Inversion
66 ft pay in 400 ft gas column
├ average φ =13.4%
├ average Sw = 32% Top Triassic
├ core permeability from 0.5 mD
to 478 mD (average ~ 10 mD) Top Zechstein
Top Rotliegend
Breagh Gas
Accumulation
├ 3%-5% pore filling clays
Top Carboniferous
(kaolinite and illite) Cleveland Basin Dogger High
├ 36% to 45% of pore throats <
1 micron Breagh Structural Cross Section
├ Poor test results – original
operator relinquished licence
├ New operator commissioned
Pore filling Pore filling illite
kaolinite
integrated study to evaluate
well results and drill and
complete new appraisal well Quartz
utilising best practice in well overgrowths
construction

13. 42/13-2 formation damage
├ Reservoir exposed to heavy salt
brine at around 400 psi
overbalance then displaced with
sea water
├ 5 intervals perforated at 1550 psi
underbalance using TCP-conveyed
4 ½” RDX guns
├ Produced at only 3 mmscf/d
├ Test results:
├ main pressure build up was
affected by changing well bore
storage, masking the radial flow
period
├ Best match the main pressure
drawdown indicated kh = 158 mDft
and damage skin (S) of +47
├ WBM filtrate invasion between 30
– 60 inches from the wellbore
(7450 ft to 7500 ft MD)
├ perfs may not have penetrated
beyond invaded and damaged
zone
Logs show deep invasion between 7450 ft and
7500 ft mD

14. Appraisal well 42/13-3 design
├ Vertical cased and perforated well
├ Key issues in well design:
├ could the reservoir section be drilled at minimum overbalance
without compromising drilling or completion operations?
├ could the well be tested or produced without sand failure or sand
production (common problem in SNS)?
├ could the well DIF be designed to prevent or minimise formation
damage during conventional drilling?
├ Underbalance drilling had cost issues
├ drill conventionally at minimum safe overbalance (+ 0.4 ppg)
├ Integrated geomechanics/formation damage study
├ evaluate wellbore stability with 10.1 ppg mud
├ assess risk of sand failure and sand production during testing
├ characterise formation properties and carry out return
permeability tests using water-based and oil-based DIFs

15. Geomechanics – strength model
TWC Strength Model Probability Distribution
(based on 42/13-2 :7375 - 7885 ft MD)
├ Log-derived strength 100%
90% Pay Interval
model Percentile TWC
probability (Cumulative Frequency)
80% (psi)
P5 12160
70% P10 12439 Net Interval
UCS = 1798E c − 3574
P20 12912 Percentile TWC
(psi)
60% P30 13086
P5 12350
P40 13306 P10 12802 Net
50% P50 13527 P20 13215 Pay
P60 13761 P30 13592
1.34 x1010 ρ b
40% P70 13940 P40 13888
P80 14180 P50 14101
Ec = P90 14464 P60 14317
30%
P70 14714
P95 14733
∆t 2
P80 15132
20% P90 15617
P95 17059
10%
0%
TWC 8000 10000 12000 14000 16000 18000 20000
= 12.24UCS −0.4696 TWC (psi)
UCS
├ Calibrated by tests on
Core Saturation Confining Failure Young's Poisson's Cohesive Friction
Depth Fluid Pressure Stress Modulus Ratio Strength Angle
(ft MD) (MPa) (psi) (Mpsi) (-) (psi) (deg)
42/13-2 core 7467.21
7467.21
Oil
Oil
UCS
18
5746
17319 2.82 0.249 1365 39.2
7478.21 Oil UCS 5464
7478.21 Oil 18 21544 3.94 0.196 1101 46.1

16. Geomechanics – stress model
├ Vertical stress
├ density log integration 42/13-2
├ Horizontal stresses
├ LOT, image logs in 42/13-2
├ pore pressure
├ RFT
├ Analogue database
├ stress tensors validated against
offset data
Total Maximum Minimum Pore
Vertical Stress Horizontal Stress Horizontal Stress Pressure
(psi/ft) (psi/ft) (psi/ft) (psi/ft)
1.00 0.80 0.72 0.501

17. Geomechanics - results
├ Wellbore stability
├ well could be drilled with
minimum overbalance
without risk of collapse
├ Sand production
├ no risk of sand failure at
test conditions or if well Well could be drilled at 10.1 ppg with no problems
produced over life of field
├ completion design
42/13 Generic Cased and Perforated Completion
Vertical Well: BF = 3.1
Sv = 1.00 psi/ft; SH = 0.80 psi/ft, Sh = 0.72 psi/ft, pp = 0.501 psi/ft
TWC = 12160 psi (P5 TWC)
simplified and failure risks 6000
4000
minimised by avoiding sand 2000
0 0 deg
control -2000
0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 10 deg
20 deg
30 deg
BHFP (psi)
-4000
40 deg
-6000 50 deg
60 deg
-8000
70 deg
80 deg
-10000
90 deg
-12000 BHFP = Pres
-14000
-16000
-18000
Pres (psi)
No sand production for vertical C&P well

18. Return permeability tests on
42/13-2 core
├ WB and OB DIFs formulated on basis of: 1
├ average formation permeability ~ 10 mD 0.9
├ clay content (3% - 5%) and pore size 0.8
distribution (~40% < 0.5 micron) 0.7
├ Return permeability tests at reservoir
Mercury Saturation (PV)
0.6
conditions 0.5
├ replicate field placement/overbalance 0.4
Microporosity
(from 10.1 ppg mud) 0.3
├ 48 hours dynamic imbibition and 48 hours 0.2
static imbibition 0.1
├ Imbibition (fluid loss) 0
├ Monitor DIF fluid loss (fraction of pore
0.001 0.01 0.1 1 10 100
Pore Throat Size Radius (microns)
volume)
├ kg versus kg (reference)
├ after DIF exposure (worst case)
├ after mud cake removed (best case)
├ after remaining filtrate spun out
(permanent damage)

19. Return permeability test results
Low permeability interval High permeability interval
100% 100%
90%
Return Permeability Ratio (% Reference Permeability)
90%
Return Permeability Ratio (% Reference Permeability)
OBM: 45% damage OBM: 27% damage OBM: 6% permanent damage
OBM: 38% damage OBM: 26% damage OBM: 3% permanent damage
WBM: 62% damage WBM: 30% damage WBM: 24% permanent
WBM: 72% damage WBM: 58% damage WBM: 29% permanent
80% d
80%
70% 70%
60% 60%
#3 OBM #9 OBM
50% 50%
#4 WBM #10 WBM
40% 40%
30% 30%
20% 20%
10% 10%
0% Mudcake Removed 0% Mudcake Removed
1 Mudcake Removed
2 Filtrate Removed
3
Mudcake In Place
1 Mudcake Removed
2 Filtrate 3
Removed
Mudcake In Place
Plug Helium Air Reference Mud Total Return Return Return
Code Porosity Permeability kg at Swi Type Filtrate Permeability Permeability Permeability
No. Loss with mud w/out mud after spin
cake cake* down**
(fraction) (mD) (mD) (PV) (mD) (mD) (mD)
9 0.144 75.3 51.8 OBM 0.52 32.2 38.3 50.4
10 0.175 127 103 WBM 1.48 29.2 43.5 72.7
3 15.9 17.8 14.2 OBM 0.58 7.8 10.4 13.3
4 13.1 10.5 5.78 WBM 2.32 2.2 4.0 4.4
Notes: * Mud cake removed manually ** Core extracted in centrifuge to remove remaining filtrate

20. Damage mechanisms
Filtrate Loss Comparison - Low Permeability
3.00
├ Imbibition
Dynamic Filtration Static Filtration
2.50
├ OBM imbibition complete after ~ 25 2.00
Total Filtrate Loss (PV)
hours Continual filtrate loss
├ WBM filtrate imbibition continues
#3 OBM
1.50
Rapid spurt loss #4 WBM
unabated due to strong capillary 1.00
forces Negligible filtrate loss
├ Permeability damage
0.50
├ WBM-treated samples suffered a
0.00
0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0
Square Root of Time (hours)
permanent permeability damage of Filtrate loss curves for WBM and OBM DIFs
24% and 29%, compared to only
3% to 6% for the OBM-treated Retained
aqueous fluid
cores layer draping
grains and
├ Damage mechanisms
restricting pores
├ retention of WBM filtrate in pore
system reduces permeability to gas
├ filtrate invasion has dispersed,
dislodged and suspended kaolinite
and illite fines in the fluids
├ solids mud invasion at wellbore
face
├ Supports 42/13-2 well results
Cryogenic SEM shows WBM filtrate retention
with filtrate draping grains and restricting pores

21. 42/13-3 well results
├ Drilling and completion
├ drilled with 10.1 ppg oil-
based DIF with no wellbore
instability issues
├ Cased and perforated
├ Reservoir
├ two good quality sands
├ 7358 ft MD to 7387 ft MD
├ 7413 ft MD to 7435 ft MD
├ 77 ft net pay in 296 ft gas
column

22. 42/13-3 well test results
├ Productivity
├ perforated between 7340 ft 4000
13 2 Well Test IPR
13 3 Well Test IPR
and 7450 ft MD on 3 ½” OD 3500 BHFP 42/13-3
BHFP 42/13-2
B o tto m H o le F lo w in g P re s s u re (p s ia )
TCP test string 3000
├ test kh ~ 237 mDft
2500
├ damage skin 0 to +2
2000
1500
├ 17.6 mmscf/d compared to 3 1000
mmscf/d in 42/13-2 500
├ AOF 10 times 42/13-2 AOF 0
0 5 10 15 20 25 30
├ Success Gas Production rate (MMscf/d)
├ well proved connectivity of
channels
├ Encouraged JV partners to
plan field development

23. Latest………
├ Horizontal well
├ cased and perforated
completion
├ same OBM DIF as 42/13-3
├ drilled at minimum overbalance
├ Tested January 2009
├ tested dry gas at 26 mmscf/d
├ mechanical skin ~ 0
May 25 2009
├ Estimated reserves 600 Bcf
├ Largest undeveloped gas field
in SNS?
├ Anticipated sale price $1Billion

24. Formation damage in carbonates
├ Carbonates tend to have been neglected
as they are more complex than clastics
├ Strong imbibition forces in tight matrix
retain WBM filtrates and reduce
hydrocarbon productivity
├ Whole mud losses plug fractures
├ Design the well with fractures in mind –
these are often the reservoir and should
be protected if possible from any damage
or flow restriction
├ Drilling and completion fluids tend to be
self-evaluated by the fluid vendors.
Independent evaluation of potential
damage and stimulation in heterogeneous
carbonates is essential
├ Consider underbalance drilling and/or
completion to minimise losses and
fracture damage

25. Conclusions
├ There are many fields that have been
condemned to be non-viable as a result of
poor well productivity rather than poor
permeability or connectivity.
├ An integrated petrophysical, geomechanical
and formation evaluation solution can
recognise, diagnose and help mitigate
against formation damage.
├ Significant development opportunities can be
realised in “uneconomic and non-viable” oil
and gas fields

26. Observations
├ Disciplinary compartmentalisation and
unaligned KPIs can combine to overlook or
bypass viable opportunities, losing the value
initially to the operator itself, and potentially
to the rest of the industry.
├ The key to the revival of this “toxic asset” has
been the willingness of this operator to:
├ take calculated risks in a risk-averse climate
├ foster and encourage an integrated, multi-
disciplinary approach that draws on the
combined skills of geologists, petrophysicists,
drilling, reservoir and production engineers.

27. Thank you for listening
├ Any questions…?