Unlocking Hidden Reservoir Potential ThroughIntegrated Formation Damage Evaluation

(SPE 115690 and SPE 120694)

Colin McPhee and Michael Byrne

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

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

Example 1 - oil field

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Helium Porosity (fractional)

Air

Perm

eabi

lity

(mD

)

├ Two appraisal wells drilled in early 90’s├ Well 1 drilled with OBM and

cored. High water saturations near OWC

├ Well 2 drilled with WBM and cored. DST tested.

├ Rock properties (core)├ ka from 0.1 mD to 500 mD

(mean 10 mD)├ clay minerals and carbonate

cements├ kaolinite – up to 73% of clay

fraction├ pore lining chlorite (20% to

40%) and illite (10% to 18%)

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

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

Permeability model – Well 2

├ MLR - best match to core

Core permeability correction

y = 0.1389x1.2839

R2 = 0.7944

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Air Permeability at 400 psi (mD)

Fres

h-st

ate

Oil

Perm

eabi

lity

at 3

000

psi (

mD

)Fresh-state Ko data

Core permeability correction

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Ka at 400 psi (mD)

Ko

at 4

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SCAL dataEquality

SCAL Data

Pseudo-PLT

├ Core ko to cumulative oil rate

├ PLT overlay suggests thin high quality intervals are damaged

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Cumulative Layer Contribution (fraction)

Dep

th (f

t MD

RK

B)

KoMOD1KoMOD2

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8700

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Cumulative Layer Contribution (fraction)

Dep

th (f

t MD

RK

B)

KoMOD1KoMOD2

h1K1

h2K2

h3K3

h4K4

hiKi

Q1

Q

Q2

Q3

Q4

Qi

H

∆P

Darcy’s Law

µP

LAKQ ∆

= .

PConsthKQ iii ∆= ..

iQQQQ +++= ....21

ihhhH ...21 ++=

HKh

K iiarith

∑=

( )

⎥⎦

⎤⎢⎣

⎡+⎟⎟

⎠

⎞⎜⎜⎝

⎛

−=

'472.0

ln

00708.0 )(

Sr

r

PPBkh

q

w

e

wfi

oo

wto µ

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 the formation?

├ Post mortem encouraging enough to plan new appraisal drilled with non-damaging DIF

Fluid has been retained in the micropores between the chlorite platelets

RETAINED MUD FILTRATE LOSSES

BEFORE TEST AFTER TEST

Fluid has been retained in the micropores between the chlorite platelets

RETAINED MUD FILTRATE LOSSES

BEFORE TEST AFTER TEST

Example 2 – Gas Well

Breagh Structural Cross Section

SOUTH NORTH

Cleveland Basin Dogger High

Breagh Gas Accumulation

Top Triassic

Top Zechstein

Top Rotliegend

Top Carboniferous

Base ChalkLate Cretaceous-Early Tertiary Inversion

SOUTH NORTH

Cleveland Basin Dogger High

Breagh Gas Accumulation

Top Triassic

Top Zechstein

Top Rotliegend

Top Carboniferous

Base ChalkLate Cretaceous-Early Tertiary Inversion

Breagh Structural Cross Section

SOUTH NORTH

Cleveland Basin Dogger High

Breagh Gas Accumulation

Top Triassic

Top Zechstein

Top Rotliegend

Top Carboniferous

Base ChalkLate Cretaceous-Early Tertiary Inversion

SOUTH NORTH

Cleveland Basin Dogger High

Breagh Gas Accumulation

Top Triassic

Top Zechstein

Top Rotliegend

Top Carboniferous

Base ChalkLate Cretaceous-Early Tertiary Inversion

├ Appraisal well 42/13-2 (1998)├ 66 ft pay in 400 ft gas column├ average φ =13.4%├ average Sw = 32% ├ core permeability from 0.5 mD

to 478 mD (average ~ 10 mD) ├ 3%-5% pore filling clays

(kaolinite and illite)├ 36% to 45% of pore throats <

1 micron├ Poor test results – original

operator relinquished licence├ New operator commissioned

integrated study to evaluate well results and drill and complete new appraisal well utilising best practice in well construction

Pore filling illitePore filling kaolinite

Quartz overgrowths

Pore filling illitePore filling kaolinite

Quartz overgrowths

Pore filling illitePore filling kaolinite

Quartz overgrowths

Pore filling illitePore filling kaolinite

Quartz overgrowths

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 mDftand 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 mDLogs show deep invasion between 7450 ft and 7500 ft mD

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

Geomechanics – strength model

├ Log-derived strength model

├ Calibrated by tests on 42/13-2 core

TWC Strength Model Probability Distribution(based on 42/13-2 :7375 - 7885 ft MD)

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TWC (psi)

prob

abili

ty (C

umul

ativ

e Fr

eque

ncy)

NetPay

Percentile TWC(psi)

P5 12350P10 12802P20 13215P30 13592P40 13888P50 14101P60 14317P70 14714P80 15132P90 15617P95 17059

Net Interval

Percentile TWC(psi)

P5 12160P10 12439P20 12912P30 13086P40 13306P50 13527P60 13761P70 13940P80 14180P90 14464P95 14733

Pay Interval

35741798 −= cEUCS

4696.024.12 −= UCSUCSTWC

2

101034.1t

xE b

c ∆=

ρ

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)7467.21 Oil UCS 57467467.21 Oil 18 17319 2.82 0.249 1365 39.27478.21 Oil UCS 54647478.21 Oil 18 21544 3.94 0.196 1101 46.1

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 Vertical Stress

Maximum Horizontal Stress

Minimum Horizontal Stress

Pore Pressure

(psi/ft) (psi/ft) (psi/ft) (psi/ft) 1.00 0.80 0.72 0.501

Geomechanics - results

Well could be drilled at 10.1 ppg with no problemsWell could be drilled at 10.1 ppg with no problems

├ 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 produced over life of field

├ completion design simplified and failure risks minimised by avoiding sand control

42/13 Generic Cased and Perforated CompletionVertical Well: BF = 3.1

Sv = 1.00 psi/ft; SH = 0.80 psi/ft, Sh = 0.72 psi/ft, pp = 0.501 psi/ftTWC = 12160 psi (P5 TWC)

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Pres (psi)

BH

FP (p

si)

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No sand production for vertical C&P well

42/13 Generic Cased and Perforated CompletionVertical Well: BF = 3.1

Sv = 1.00 psi/ft; SH = 0.80 psi/ft, Sh = 0.72 psi/ft, pp = 0.501 psi/ftTWC = 12160 psi (P5 TWC)

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BH

FP (p

si)

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No sand production for vertical C&P well

Return permeability tests on 42/13-2 core

├ WB and OB DIFs formulated on basis of:├ average formation permeability ~ 10 mD├ clay content (3% - 5%) and pore size

distribution (~40% < 0.5 micron)├ Return permeability tests at reservoir

conditions├ replicate field placement/overbalance

(from 10.1 ppg mud)├ 48 hours dynamic imbibition and 48 hours

static imbibition├ Imbibition (fluid loss)

├ Monitor DIF fluid loss (fraction of pore volume)

├ kg versus kg (reference)├ after DIF exposure (worst case)├ after mud cake removed (best case)├ after remaining filtrate spun out

(permanent damage)

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Microporosity

Return permeability test results

Low permeability interval High permeability interval

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urn

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#3 OBM#4 WBM

Mudcake In Place Mudcake RemovedMudcake RemovedFiltrate Removed

OBM: 45% damageWBM: 62% damage

OBM: 27% damageWBM: 30% damage

OBM: 6% permanent damageWBM: 24% permanent d

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#9 OBM#10 WBM

OBM: 38% damageWBM: 72% damage

OBM: 26% damageWBM: 58% damage

OBM: 3% permanent damageWBM: 29% permanent

Mudcake In Place Mudcake RemovedMudcake RemovedFiltrate Removed

Plug Code No.

Helium Porosity

Air Permeability

Reference kg at Swi

Mud Type

Total Filtrate Loss

Return Permeability

with mud cake

Return Permeability w/out mud

cake*

Return Permeability

after spin 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

Damage mechanisms

Filtrate loss curves for WBM and OBM DIFs

Filtrate Loss Comparison - Low Permeability

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Square Root of Time (hours)

Tota

l Filt

rate

Los

s (P

V)

#3 OBM#4 WBM

Dynamic Filtration Static Filtration

Rapid spurt loss

Negligible filtrate loss

Continual filtrate loss

Filtrate loss curves for WBM and OBM DIFs

Filtrate Loss Comparison - Low Permeability

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l Filt

rate

Los

s (P

V)

#3 OBM#4 WBM

Dynamic Filtration Static Filtration

Rapid spurt loss

Negligible filtrate loss

Continual filtrate loss

├ Imbibition├ OBM imbibition complete after ~ 25

hours├ WBM filtrate imbibition continues

unabated due to strong capillary forces

├ Permeability damage├ WBM-treated samples suffered a

permanent permeability damage of 24% and 29%, compared to only 3% to 6% for the OBM-treated cores

├ Damage mechanisms├ 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

Retained aqueous fluid layer draping grains and restricting pores

Retained aqueous fluid layer draping grains and restricting pores

Cryogenic SEM shows WBM filtrate retention with filtrate draping grains and restricting pores

Retained aqueous fluid layer draping grains and restricting pores

Retained aqueous fluid layer draping grains and restricting pores

Cryogenic SEM shows WBM filtrate retention with filtrate draping grains and restricting pores

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

42/13-3 well test results

├ Productivity├ perforated between 7340 ft

and 7450 ft MD on 3 ½” OD TCP test string

├ test kh ~ 237 mDft├ damage skin 0 to +2├ 17.6 mmscf/d compared to 3

mmscf/d in 42/13-2├ AOF 10 times 42/13-2 AOF

├ Success├ well proved connectivity of

channels├ Encouraged JV partners to

plan field development

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BHFP 42/13-3

BHFP 42/13-2

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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

├ Estimated reserves 600 Bcf├ Largest undeveloped gas field

in SNS?├ Anticipated sale price $1Billion

May 25 2009

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

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

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.

Thank you for listening

├ Any questions…?