Formation Damage

Reservoir Rock Properties

A commercial hydrocarbon reservoir must

exhibit two characteristics for commercial

development

1.) reservoir must accumulate and store

fluids

2.) fluids must be able to flow through

relatively long distance under relatively

small pressure gradients

Reservoir Rock Properties



Introduce the two reservoir terms:



POROSITY



percentage or fraction of void to

bulk volume of the rock



PERMEABILITY



a measure of a rock‟s specific flow

capacity (depends on the

TYPES OF ROCK FORMATIONS

METAMORPHIC

ALTERED BY INTENSE HEAT AND PRESSURE

IGNEOUS SOLIDIFIED MOLTEN ROCK SEDIMENTARY FORMED BY EROSION, TRANSPORTATION, DEPOSITION

Classification

Sedimentary Rock

Classification



CLASTIC



Made up of grains that have been

sedimented



Includes sands and shales

•

NON-CLASTIC

•

Made up of biogenic or chemical

precipitates

Sedimentary Rock



CLASTIC

 CONGLOMERATE-GRAVEL  SANDSTONE-SAND  SILTSTONE-SILT  SHALE-CLAY

COMMON OIL AND GAS RESERVOIRS ARE YELLOW



NON-CLASTIC

 LIMESTONE  DOLOMITE  SALT  GYPSUM  COAL

Sand and Sandstone

Made up of sand grains

These grains are commonly Quartz

Feldspar

Rock Fragments Fossils

Sandstone

Sandstone

BESIDES SAND GRAINS SANDSTONE MAY CONTAIN MINERAL CEMENTS THESE INCLUDE QUARTZ CALCITE DOLOMITE ANHYDRITE

Sandstone with

Anhydrite Cement

Micro-Quartz Cementation

Sand and Sandstone

Sand or Sandstone may contain:

1. Sand Grains - Always

2. Cements - Not Always (usually)

3. Clays - Not Always (usually)

4. Pore Spaces - Essential for Oil or Gas Reservoir

Sandstone with Clay

Porosity

PORE VOLUME = TOTAL VOLUME - SOLIDS VOLUME

= (bulk volume) - (volume occupied by solids)

POROSITY = PORE VOLUME / TOTAL VOLUME

Porosity is expressed as a fraction or percentage and often represented by Greek letter phi



Porosity



The Volumetric Fraction of Formation

Not Occupied by Solids.



Two types of porosity:



Absolute - Volume not occupied by

solids.

Porosity - Determination

TOTAL VOLUME =  x r2 _{x h} h r r = 1.262 cm h = 3.0 cm TOTAL VOLUME = 15.00 cm3 TO DETERMINE POROSITY:

WATER SATURATED WEIGHT = 34.2 G

DRY WEIGHT = 31.2 G

WEIGHT WATER = 3.0 G --> 3 CC PORE VOL. POROSITY = PORE VOLUME / TOTAL VOLUME

Grain Sorting



CONTROLS POROSITY & PERMEABILITY



Large Pore Spaces Yield Good Porosity

And High Permeability.



Poor sorting yields smaller pore spaces

Well-Sorted Sandstone

GOOD POROSITY

Poor Sorting

MUCH LOWER POROSITY AND PERMEABILITY

Pore Size

Methods to determine pore size and optimum bridging particle size

1. Estimate from Permeability

Pore Size in microns (



) ~ Permeability (mD)

example: k = 1000 md ~ 33  pore size 2. Measurement from Thin Section

Pore Space in Sandstone

200 microns

Permeability

The Ability of a Formation to Transmit Fluid

(Through the Inter-Connecting Pore

Spaces.)



Types of Permeability



Vertical Fracture Permeability -

Limestones, Chalks, and Some Shales

Permeability

1856 Henry D‟Arcy experimented with water

flowing through sand beds. Results of his studies produced equations relating flow rate and pressure gradient

DARCY‟S LAW:

defines the unit of

proportionality (k) between velocity (flow rate) and pressure gradient. This coefficient (k) is a property of the rock - it is independent of the fluid used to measure flow.

Darcy: Practical Definition



In the oil industry, permeability is

expressed in Darcy units. A rock has a

permeability of 1 Darcy if a pressure

gradient of 1 atm/cm induces a flow

rate of 1 cm

3

/cm

2

of cross-sectional

area of a liquid with a viscosity of 1 cp.



The Darcy unit is large for a practical

unit - millidarcy is commonly used,

where 1 D = 1000 mD

Darcy‟s Law - Linear Flow

K = Q  L A P 1 D = (1cm3_{/sec) (1cp) (1cm)} (1 cm2) (1 atm) Q = k A P  L

Permeability of a Core

DARCY‟S LAW k * A * (P₁ - P₂) Q = --- *L L r P₁ P₂

Q = flow rate in cc/sec A = area in cm2 = r2

P₁, P₂ = pressure in atm (1 atm = 1.033 kg/cm2) L = length in cm

 = viscosity in centipoise (1 cp = dyne•sec/100 cm2₎

DARCY‟S LAW k * A * (P₁ - P₂) Q = ---  * L rearrange to Q *  * L k = --- A * (P₁ - P₂) L R P₁ P₂

Permeability of a Core

Measure Flow rate under conditions:

R = 1.262 cm L = 3.0 cm  = 1 cp A = 5 sq cm P₁ = 2 atm P₂ = 1 atm

Flow rate = 0.1 cc/sec = 6 cc/min L R P₁ P₂ Q *  * L 0.1 * 1 * 3 0.3 k = --- = --- = --- = 0.06 darcy A * (P₁ - P₂) 5 * (2 - 1) 5

Permeability of a Core

L R P₁ P₂ k = 0.06 darcy 1 darcy = 1000 millidarcys k = 60 millidarcys = 60 md

Permeability of a Core

Darcy‟s Law - Radial Flow

r_e r_w P_e P_w r_e = drainage radius r_w = well radius P_e = pressure at r_e P_w = pressure in well h = reservoir thickness k = permeability u = viscosity of oil

r_e = drainage radius ft r_w = well radius ft

P_e = pressure in psi at r_e

P_w = pressure in psi in well

h = reservoir thickness ft k = permeability md  = viscosity of oil cp 0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * ln (r_e / r_w)

Darcy‟s law for a well in a reservoir (disk with hole)

Production Rate of Oil

r_e = 600 ft P_e = 4000 psi h = 20 ft  = 2 cp r_w = 0.5 ft P_w = 3600 psi k = 60 md 0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * ln (r_e / r_w) 0.00708 * 60 * 20 * (4000 - 3600) Q = --- 2 * ln ( 600 / 0.5) 0.00708 * 60 *20 * 400 3398.4 3398.4 Q = --- = --- = --- = 239.7 bbl/d 2 * ln (1200) 2 * 7.09 14.18

Formation Damage

THE WELL PRODUCES LESS THAN IT PREDICTED BY DARCY‟S LAW.

0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---

 * ln (r_e / r_w)

INTRODUCE SKIN FACTOR “S”

0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * ( ln (r_e / r_w) + S)

Skin

S > 0 ----> FORMATION DAMAGE S < 0 ----> WELL STIMULATION 0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * ( ln (r_e / r_w) + S)

Skin

SKIN FACTOR PRODUCTION RATE

0.0 239.7 1.0 210.0 3.0 168.4 10.0 99.4 20.0 62.7 50.0 29.8 -1.0 279.0

Skin

THE SKIN FACTOR CAN BE OBTAINED FROM A PRESSURE BUILD UP TEST.

THE SKIN FACTOR IS A MEASURE OF FORMATION DAMAGE.

r_e = drainage radius r_w = well radius P_e = pressure at r_e P_w = pressure in well h = reservoir thickness k = permeability  = viscosity of oil

Skin

r_e r_w P_e P_w Skin (S)

1. POROSITY - Determines the amount

of Oil and/or Gas Available 2. PERMEABILITY - Determines Possible

Production Rate

3. SKIN FACTOR - A measure of Formation Damage

TIME ---> k_O

UNDAMAGED k

Permeability Testing

Permeability Testing

TIME ---> k_O

UNDAMAGED k

Step 2: “Damage” the Permeability

expose core to fluid in direction opposite to

production flow.

TIME ---> k_O

UNDAMAGED k

DAMAGED k

Step 3: Determine Damaged Permeability

Permeability Testing

DAMAGED k % RETURN = 100 * ---

Relative Permeability

 IN AN OIL RESERVOIR, OIL DOES NOT

OCCUPY ALL OF THE PORE SPACE!

 Hydrocarbons were not the first fluids to

occupy the pore space of sedimentary rock…water was….i.e., the rocks were deposited by water.

 MOST OIL RESERVOIRS ARE “WATER

WET” MEANING THAT A FILM OF WATER

Water Saturation (S

_w

)

PORE VOL. = VOL. WATER + VOL. OIL Often expressed as saturation, where

S_W = WATER SATURATION

S_O = OIL SATURATION

AND S_O + S_W = 1

S_W

k_O kW

OIL PERM

WATER PERM SINGLE PHASE PERMEABILITY

Formation Damage Definition



Any loss in productivity caused by a

source other than natural pressure

depletion or mechanical restrictions

Causes of Formation Damage

1. Drilling

2. Completion

3. Stimulation

4. Production

Once a virgin reservoir is penetrated,

damage occurs. The question is to what extent?

Formation Damage

Key Questions:



What is Magnitude ?



What is Cause (source) ?



How Far (depth of penetration) ?



Can We Prevent ?

How Much and How Deep is the

Damage?

0 20 40 60 80 100 P R O D U C T IO N D A M A G E 0 20 40 60 80 100 PERMEABILITY DAMAGE

PERMEABILITY VS PRODUCTION DAMAGE

Return Perm vs. Skin

Example:

Ki = 60 mD; Kf = 42mD; Damage = 30%

Formula for “S”

r_{a r} e k_e k_a r_e = drainage radius r_a = damaged radius r_w = well radius k_e = undamaged permeability k_a = damaged permeability r_w

r_e = drainage radius r_a = damaged radius r_w = well radius k_e = undamaged permeability k_a = damaged permeability k_e - k_a S = --- * ln (r_a / r_w) k_a

In addition to the amount of permeability damage we need to know the radius of damage.

Radius of Damage

0 10 20 30 40 50 60 70 IN V A S IO N D E P T H ( C M ) 0 24 48 72 96 120 144 TIME (HOURS) FILTRATE INVASION 2.5 CC FLUID LOSS 5 CC FLUID LOSS 7.5 CC FLUID LOSS 10 CC FLUID LOSS 21 CM WELL DIAMETER 20% POROSITY

0 10 20 30 40 50 60 70 IN V A S IO N D E P T H ( C M ) 0 24 48 72 96 120 144 TIME (HOURS) FILTRATE INVASION 2.5 CC FLUID LOSS 5 CC FLUID LOSS 7.5 CC FLUID LOSS 10 CC FLUID LOSS 21 CM WELL DIAMETER 20% POROSITY

TYPICAL PERF DEPTH

Calculate “S”

with 1.5 ft Invasion

r_a = damaged radius = 1.5 + 0.5 = 2.0 r_w = well radius = 0.5 k_e = undamaged permeability = 60 k_a = damaged permeability = 0.7 * 60 = 42 k_e - k_a 60 - 42 S = --- * Ln (r_a / r_w) = --- * Ln (2/0.5) = 0.60 k_a 42

Zero Damaged Well

r_e = 600 ft P_e = 4000 psi h = 100 ft  = 2cp r_w = 0.5 ft P_w = 3600 psi k = 60 md 0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * ln (r_e / r_w) 0.00708 * 60 * 20 * (4000 - 3600) Q = --- 2 * ln ( 600 / 0.5) 0.00708 * 60 *100 * 400 16992 16992 Q = --- = --- = --- = 1198 bbl/d 2 * ln (1200) 2 * 7.09 14.18

Damaged Well

r_e = 600 ft P_e = 4000 psi h = 100 ft  = 2cp r_w = 0.5 ft P_w = 3600 psi k = 60 md S = 0.6 0.00708 * k * h * (P_e - P_w) Q (bbl/day) = ---  * (ln (r_e / r_w) + S) 0.00708 * 60 * 100 * (4000 - 3600) Q = --- 2 * (ln ( 600 / 0.5) + 0.6) 0.00708 * 60 *100 * 400 16992 16992 Q = --- = --- = --- = 1105 bbl/d 2 * (ln (1200) + 0.6) 2 * 7.69 15.38

Compare

1198 BBL/D UNDAMAGED

WITH 30% PERMEABILITY DAMAGE EXTENDING 1.5 INTO THE RESERVOIR

1105 BBL/D DAMAGED

Compare

1198 BBL/D UNDAMAGED

WITH 30% PERMEABILITY DAMAGE EXTENDING 1.5 INTO THE RESERVOIR

1105 BBL/D DAMAGED

PRODUCTION RATE IS DAMAGED 7.8%

What About a Clear Brine?



Previous example was of a mud that

was tested in the lab and produced a

70% return Permeability. The depth of

damage was 1.5 ft and the effect on

production was a loss of 7.8 %.

Depth of Invasion for Clear

Brine



Example: Lose 1000 bbl of brine to an

interval of 100‟ with a porosity of 30%.

Depth of invasion

r = V/



h



Damage Due to Invasion of

Clear Brine

k

_r

S

Production

100% 0 1198 bpd (loss = 0 bpd) 90% 0.3 1150 bpd (loss = 48 bpd) 80% 0.7 1091 bpd (loss = 107 bpd) 70% 1.2 1025 bpd (loss = 173 bpd) 60% 1.9 945 bpd (loss = 253 bpd)

Damage Mechanisms



Solids Plugging



filtrate invasion / solids contamination



fines migration



Chemical Incompatibility



clay / shale swelling



inducing fines migration



fluid-fluid interactions



emulsions, precipitation (scaling)



wettability reversal

Solids Plugging

d

d‟

d‟ = Diameter of Bridging Particle

d = Diameter of Pore Throat

If d‟

> 1/2

d

Stable Bridges Will Form

Bridging Theory

 Particles  1/3 the Diameter of the Pore Throat

Will Plug on the Surface.

 Particles Less Than 1/3 to About 1/7 the

Diameter of the Pore Throat Will Plug in the Pore Channels.

 Particles Less Than 1/7 the Diameter of the

Pore Throat Will Migrate Freely Through the Formation.

Critical Plugging Particle Size

Permeability

(*Millidarcies)

Pore Size

(Microns)

Critical Plugging Range

1/3 to 1/7 (Microns) 5 2.2 0.75 to 0.32 10 3.2 1.05 to 0.45 50 7.1 2.36 to 1.01 100 10.0 3.33 to 1.43 250 15.8 5.27 to 2.26 500 22.4 7.45 to 3.19 750 27.4 9.13 to 3.91 1000 31.6 10.54 to 4.52 1500 38.7 12.91 to 5.53 2000 44.7 14.91 to 6.39

For comparison, the size of a human hair is 50-70 microns in diameter, a single grain of table salt is 90-110 microns in diameter. A filter of 10

Particle Sizes of Common

Materials

BARITE - 30 MICRONS

FINE CaCO₃ - 15 MICRONS

MEDIUM CaCO₃ - 35 MICRONS

COARSE CaCO₃ - 100 MICRONS

Return Permeability Tests - solids in NaCl brine SOLIDS % DAMAGE 0 PPM 3.8 100 PPM 15.2 190 PPM 25.8 420 PPM 48.4 990 PPM 78.8

Sadlerochit sandstone formation - Alaska

Solids in Clear Brine?



Solids removed from wellbore pipe

during circulation



mud residue (poor displacement?)



scale removal (physical disruption)



excessive use of pipe dope



Critical considerations when gravel

packing



Solubilization followed by Precipitation

Fines Migration

Fines migration refers

to the movement through the pore space of

naturally occurring

particles such as clays micro-crystalline quartz, feldspars, etc.

Fines migration is often observed upon onset of water production.

Inducing Fines Migration

Fines are mobile in the phase that wets them.

Since most formations are water wet, introducing

water (or brine) can induce

fines migration. Heavy losses of clear brine can induce

hydrodynamic pressures (due to viscosity) that can cause fines to detach and mobilize.

Completion Fluid Damage

 Dirty brine entering perforations and pore network (poor displacement or filtration)

 Brine incompatibility with formation crude or

water causing emulsion or precipitation of solids  increased water saturation due to intrinsic

viscosity of brine

 Inefficient clean up of fluid loss control pills

 Incompatibility with stimulation acid, oxidizers or other clean up fluids

Completion Fluid Damage

 Residual mud in wellbore may be carried into formation by “clean” (filtered) completion

brine

 The completion fluid returns may look clean (low solids / ntu) after circulating, yet the

wellbore remains dirty

 Gravel pack after displacements scrub pipe surface and carry solids into pack

Damage Mechanisms from Clear

Brine Completion Fluids



Solids plugging



contaminated brine



Increased water saturation (water block)



high viscosity / high surface tension



Emulsification with crude oil



reactivity of CBF with asphaltenes



Reaction with formation water



reactivity of divalent cations with slightly



High density brine have a high intrinsic

viscosity - up to 40 - 50 times that of

pure water. This viscosity makes it

difficult to “flow back” fluid that has

been “lost” to formation.



Surface Tension reducing surfactants

aid fluid recovery - SAFE-SURF LT

Formation Compatibility

Completion Fluid Damage

Formation Compatibility

SAFE-SURF LT - Fluid Recovery Aid

K_(md)

Pore Volume of Fluid Flowed Though Core

K_i K_f with SAFE-SURF LT

K_f without SAFE-SURF LT



High density brine may destabilize

asphaltene particles in crude oil and

emulsify crude.



SAFE-BREAK CBF and SAFE-BREAK ZINC

surfactants to prevent emulsion

(not demulsifiers, but emulsion preventers)



CBF for calcium chloride / bromide



ZINC for zinc bromide and formate brine

Formation Compatibility - Emulsion

Completion Fluid Damage

Ca

+2

+ H

₂

O + CO

₃-2

=> Ca(CO

₃

)

_(s)

+ H

₂

O

carbonate precipitate by CO

₂

producers

Ca

+2

_{+ H}

2

O + SO

4-2

=> Ca(SO

4

)

(s)

+ H

2

O

sulfate precipitate by seawater

contaminated waters

Ca

+2

+ H

₂

O + H

+

+ F

-

=> CaF

_2(s)

+ H

₂

O + H

+

flouride precipitate by HF acid (stimulation)

Formation Compatibility - Precipitates

Completion Fluid Damage



SAFE-SCAVITE scale inhibitor for

calcium based completion fluids



Pre-flush with NH

₄

Cl prior to circulating

completion fluids when well is acid

pre-packed with HCl-HF acid.

Formation Compatibility - Precipitate Prevention

Completion Fluid Damage

ZnBr₂ CaBr₂ CaCl₂ NaCl KCl NH₄Cl KHCO₂

Emulsions

ZnBr₂ CaBr₂ CaCl₂ NaCl KCl NH₄Cl KHCO₂ SB-CBF

S

AFE

-B

REAK

CBF

Case History:

High Island

Gravel Pack with 3% NH

₄

Cl

350 bbl 15.5 ppg Zinc Bromide HD Fluid

lost prior to Gravel Pack

Well Productivity „Less Than Expected‟

Production Samples Obtained

Laboratory Analysis of Produced Water and Oil

Viscous, Highly Paraffinic Crude

7-8% Emulsion, „Free‟ Oil Gravity = 39

o

ZnBr

₂

+CaBr

₂

Identified in Emulsion

Analysis of

High Island Samples

K

11,368 ppm

218 ppm

Na

179 ppm

9,604 ppm

Fe

<1 ppm

30 ppm

Ca

169 ppm

69,370 ppm

Zn

2 ppm

12,984 ppm

Cl

11,000 ppm

13,000 ppm

Br

<1 ppm

133,000 ppm

Case History:

South Marsh Island

Workover Operation

Re-perforate, Acid Wash, Gravel Pack

Lost 600 bbl 13.0 ppg Calcium Bromide Brine Initial: 479 BOPD, 302 MCFD, 53 BWPD

Decline: 80-100 BOPD w/ FTP of 200 psi

50 bbl HCl for HEC Pill ==> No Improvement

Laboratory Identified Asphaltenes / Sludge

Stimulation Treatments ==> Slight Improvement

Crude Sensitivity Tests

South Marsh Island

0 10 20 30 40 50 60 70 80 90 100 Acetic HCl #1 HCl #2 HCl-HF 13 ppg HD Blank 1% Fe2O3

Kaolinite

A TWO-LAYER CLAY



Generally non-expandable

Smectite

A THREE-LAYER CLAY



Great hydrating capability

illite

A THREE-LAYER CLAY



Compensated with K

+

ion



Non-swelling characteristic contributes

Chlorite

A FOUR-LAYER CLAY



Magnesium hydroxide between the

montmorillonite-type unit layers



Damages formation by precipitation of

Limestone

Shale

Fine-grained clastic rocks less than 1/256 mm in diameter

Laminated or thin bedded

Sandstones

Quartz

Clastic sedimentary rock grains ranging

Silt stone

Quartz grains Fine-grained clastic rock at least 50% is 1_/ 16 to 1/256 mm diam.

 Solids entering pore networks, cracks, or fractures  Filtrate containing damaging polymers

 Filtrate containing wetting agents or emulsifiers  Filtrate incompatibility with formation water

 Filtrate interaction with pore filling and pore lining clay materials

 High Overbalance, Surge, or Swab pressure during drilling

 Cement damage to pore network, fracture or cracks

STIMULATION DAMAGE

Stimulation Fluid Damage

 Acid sludge deposits

 Mineral incompatibilities with acid

 Fines released in acid treatment

PRODUCTION DAMAGE

Production damage

 Asphalt/Paraffin precipitation

 Sand production

 Mobilization of fines with high production rates

 Bacterial scale

OTHER CAUSES OF

DAMAGE

Other

 Reservoir character (fractures, faults, inhomogenieties)

 Wellbore orientation (for example, skin determination for

 horizontal wells has not been worked out in the same

 degree of detail as for conventional reservoirs)

 Any number of failures of equipment, tubulars, packers,