Formation Damage

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 interconnectivity of the porosity)

Classification

TYPES OF ROCK FORMATIONS

IGNEOUS

METAMORPHIC

SEDIMENTARY

SOLIDIFIED MOLTEN ROCK

ALTERED BY INTENSE HEAT AND PRESSURE

FORMED BY EROSION, TRANSPORTATION, DEPOSITION

IGNEOUS AND METAMORPHIC ROCKS RARELY CONTAIN OIL & GAS

Origin of Sedimentary Rock

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 • Includes Limestone and Dolomites

Sedimentary Rock



CLASTIC 







CONGLOMERATEGRAVEL SANDSTONESAND SILTSTONE-SILT SHALE-CLAY



NON-CLASTIC     

LIMESTONE DOLOMITE SALT GYPSUM COAL

COMMON OIL AND GAS RESERVOIRS ARE YELLOW

Sand and Sandstone Made up of sand grains These grains are commonly Quartz Feldspar Rock Fragments Fossils Mica

Sandstone

200 microns

Sandstone BESIDES SAND GRAINS SANDSTONE MAY CONTAIN MINERAL CEMENTS

THESE INCLUDE QUARTZ CALCITE DOLOMITE ANHYDRITE

Sandstone with Anhydrite Cement

200 microns

Micro-Quartz Cementation

50 microns

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 50 microns

Porosity percentage or fraction of void volume to bulk volume

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.  Effective - Interconnected spaces.

Porosity - Determination TOTAL VOLUME =  x r2 x h r = 1.262 cm

h r

h = 3.0 cm

TOTAL VOLUME = 15.00 cm3

TO DETERMINE POROSITY: WATER SATURATED WEIGHT DRY WEIGHT WEIGHT WATER

= 34.2 G = 31.2 G = 3.0 G --> 3 CC PORE VOL.

POROSITY = PORE VOLUME / TOTAL VOLUME = 3.0/15.0 = 0.2 = 20% POROSITY

Grain Sorting 





CONTROLS POROSITY & PERMEABILITY Large Pore Spaces Yield Good Porosity And High Permeability. Poor sorting yields smaller pore spaces and lower permeability.

Well-Sorted Sandstone

GOOD POROSITY AND PERMEABILITY

Poor Sorting

MUCH LOWER POROSITY AND PERMEABILITY

Pore Size Methods to determine pore size and optimum bridging particle size 1.

Estimate from Permeability

2.

Measurement from Thin Section - More Reliable

Pore Size in microns () ~ Permeability (mD) example: k = 1000 md ~ 33  pore size

Pore Space in Sandstone

330 x 900 

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  Matrix Permeability - Sand or Sandstone

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 cm3/cm2 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

P1 L r P2

k * A * (P1 - P2) Q = -----------------------*L

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) k = permeability in Darcys

Permeability of a Core P1

DARCY‟S LAW

L R P2

k * A * (P1 - P2) Q = -----------------------*L rearrange to Q**L k = -----------------A * (P1 - P2)

Permeability of a Core P1

Measure Flow rate under conditions:

L R

R = 1.262 cm A = 5 sq cm

L = 3.0 cm P1 = 2 atm

 = 1 cp P2 = 1 atm

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

Permeability of a Core P1

k = 0.06 darcy

L R P2

1 darcy = 1000 millidarcys k = 60 millidarcys = 60 md

Darcy‟s Law - Radial Flow

Pe re

re = drainage radius rw = well radius Pe = pressure at re Pw = pressure in well

Pw rw h = reservoir thickness k = permeability u = viscosity of oil

Darcy‟s Law - Radial Flow re = drainage radius ft rw = well radius ft Pe = pressure in psi at re Pw = pressure in psi in well

h = reservoir thickness ft k = permeability md  = viscosity of oil cp

Darcy‟s law for a well in a reservoir (disk with hole) 0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ln (re / rw)

Production Rate of Oil re = 600 ft Pe = 4000 psi rw = 0.5 ft Pw = 3600 psi

h = 20 ft k = 60 md

 = 2 cp

0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ln (re / rw) 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 * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ln (re / rw)

INTRODUCE SKIN FACTOR “S” 0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ( ln (re / rw) + S)

Skin 0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ( ln (re / rw) + S)

S > 0 ----> FORMATION DAMAGE S < 0 ----> WELL STIMULATION

Skin

SKIN FACTOR 0.0 1.0 3.0 10.0 20.0 50.0 -1.0

PRODUCTION RATE 239.7 210.0 168.4 99.4 62.7 29.8 279.0

Skin

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

THE SKIN FACTOR IS A MEASURE OF FORMATION DAMAGE.

Skin

Pe re

re = drainage radius rw = well radius Pe = pressure at re Pw = pressure in well Skin (S)

Pw rw h = reservoir thickness k = permeability  = viscosity of oil

Concepts to Remember

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

Permeability Testing Step 1: Determine Undamaged Permeability UNDAMAGED k

kO

TIME --->

Permeability Testing Step 2: “Damage” the Permeability expose core to fluid in direction opposite to production flow.

UNDAMAGED k

kO

TIME --->

Permeability Testing Step 3: Determine Damaged Permeability UNDAMAGED k DAMAGED k

kO

DAMAGED k % RETURN = 100 * ---------------------UNDAMAGED k

TIME --->

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 COATS THE GRAIN SURFACES.

Water Saturation (Sw) FOR A HYDROCARBON RESERVOIR PORE VOL. = VOL. WATER + VOL. OIL

Often expressed as saturation, where SW = WATER SATURATION SO = OIL SATURATION AND

SO + SW = 1

Relative Permeability SINGLE PHASE PERMEABILITY

OIL PERM

kW

kO WATER PERM

SW

Formation Damage Definition



Any loss in productivity caused by a source other than natural pressure depletion or mechanical restrictions

Causes of Formation Damage Once a virgin reservoir is penetrated, damage occurs. The question is to what extent? One way to classify damage is according to origin...

1.

Drilling

2.

Completion

3.

Stimulation

4.

Production

Formation Damage Key Questions: 

What is Magnitude ?



What is Cause (source) ?



How Far (depth of penetration) ?



Can We Prevent ?



Can We Recover (remedial treatment) ?

P R O D U C T IO N D A M A G E

How Much and How Deep is the Damage? PERMEABILITY VS PRODUCTION DAMAGE INVASION DEPTH = 2 FT 100 80 60 40 20 0 0

20 40 60 80 PERMEABILITY DAMAGE

100

Return Perm vs. Skin Example: Ki = 60 mD; Kf = 42mD; Damage = 30%

What is the effect on Production?

Formula for “S” re = drainage radius

ra = damaged radius

ke ra

rw = well radius

re

ka rw ke = undamaged permeability ka = damaged permeability

Formula for “S” ke = undamaged permeability ka = damaged permeability

re = drainage radius

ra = damaged radius rw = well radius

ke - ka S = ---------- * ln (ra / rw) ka In addition to the amount of permeability damage we need to know the radius of damage.

Radius of Damage IN V A S IO N D E P T H ( C M )

FILTRATE INVASION

70 10 CC FLUID LOSS

60

7.5 CC FLUID LOSS

50 5 CC FLUID LOSS

40 30

2.5 CC FLUID LOSS

20 21 CM WELL DIAMETER

10

20% POROSITY

0 0

24

48

72

96

TIME (HOURS)

120

144

Radius of Damage IN V A S IO N D E P T H ( C M )

FILTRATE INVASION

70 10 CC FLUID LOSS

60

7.5 CC FLUID LOSS

50

TYPICAL PERF DEPTH 5 CC FLUID LOSS

40 30

2.5 CC FLUID LOSS

20 21 CM WELL DIAMETER

10

20% POROSITY

0 0

24

48

72

96

TIME (HOURS)

120

144

Calculate “S” with 1.5 ft Invasion rw = well radius = 0.5

ra = damaged radius = 1.5 + 0.5 = 2.0 ke = undamaged permeability = 60

ka = damaged permeability = 0.7 * 60 = 42 ke - ka 60 - 42 S = ---------- * Ln (ra / rw) = --------- * Ln (2/0.5) = 0.60 ka 42

Zero Damaged Well re = 600 ft Pe = 4000 psi rw = 0.5 ft Pw = 3600 psi

h = 100 ft k = 60 md

 = 2cp

0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * ln (re / rw) 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 re = 600 ft Pe = 4000 psi rw = 0.5 ft Pw = 3600 psi

h = 100 ft  = 2cp k = 60 md S = 0.6

0.00708 * k * h * (Pe - Pw) Q (bbl/day) = ---------------------------------- * (ln (re / rw) + 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

PRODUCTION RATE IS DAMAGED 7.8%

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% 93 BBl/D @ $30/BBl = 2790$/D = $1,018,350/yr

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 %. What about a solids-free, clear brine?

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

r = 92.6 in (7.7 ft)

Damage Due to Invasion of Clear Brine kr

S

Production

100% 90% 80% 70% 60%

0 0.3 0.7 1.2 1.9

1198 bpd 1150 bpd 1091 bpd 1025 bpd 945 bpd

(loss = 0 bpd) (loss = 48 bpd) (loss = 107 bpd) (loss = 173 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‟ > 1/2d 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 Critical Plugging Range Permeability

Pore Size

1/3 to 1/7

(*Millidarcies)

(Microns)

(Microns)

5 10 50 100 250 500 750 1000 1500 2000

2.2 3.2 7.1 10.0 15.8 22.4 27.4 31.6 38.7 44.7

0.75 to 0.32 1.05 to 0.45 2.36 to 1.01 3.33 to 1.43 5.27 to 2.26 7.45 to 3.19 9.13 to 3.91 10.54 to 4.52 12.91 to 5.53 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 microns is needed to remove a “haze” from a liquid.

Particle Sizes of Common Materials BARITE

- 30 MICRONS

FINE CaCO3

- 15 MICRONS

MEDIUM CaCO3

- 35 MICRONS

COARSE CaCO3

- 100 MICRONS

MIX II FINE

- 60 MICRONS

Damage Due to Solids Plugging Return Permeability Tests - solids in NaCl brine SOLIDS 0 PPM 100 PPM 190 PPM 420 PPM 990 PPM

% DAMAGE 3.8 15.2 25.8 48.4 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 of Iron

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 





 

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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 Problems with gravel pack placement

Completion Fluid Damage Bad Displacement 





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 soluble species (CO3-- / SO4-- / S-- )

Completion Fluid Damage Formation Compatibility 



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

Completion Fluid Damage Formation Compatibility SAFE-SURF LT - Fluid Recovery Aid Ki

K(md)

Kf with SAFE-SURF LT

Kf without SAFE-SURF LT

Pore Volume of Fluid Flowed Though Core

Completion Fluid Damage Formation Compatibility - Emulsion 



 

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

Completion Fluid Damage Formation Compatibility - Precipitates

Ca +2 + H2O + CO3-2 => Ca(CO3)(s) + H2O carbonate precipitate by CO2 producers

Ca +2 + H2O + SO4-2 => Ca(SO4)(s) + H2O sulfate precipitate by seawater contaminated waters Ca +2 + H2O + H+ + F- => CaF2(s) + H2O + H+ flouride precipitate by HF acid (stimulation)

Completion Fluid Damage Formation Compatibility - Precipitate Prevention 



SAFE-SCAVITE scale inhibitor for calcium based completion fluids Pre-flush with NH4Cl prior to circulating completion fluids when well is acid prepacked with HCl-HF acid.

Emulsions Emulsions with Crude Oil and Completion Fluids ZnBr2 CaBr2

CaCl2 NaCl

KCl

NH4Cl KHCO2

SAFE-BREAK CBF Emulsions with Crude Oil and Completion Fluids ZnBr2 CaBr2

CaCl2 NaCl

KCl

NH4Cl KHCO2 SB-CBF

Case History: High Island

Gravel Pack with 3% NH4Cl 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 = 39o ZnBr2+CaBr2 Identified in Emulsion No ZnBr2 or CaBr2 in Production Water

Analysis of High Island Samples Ion

Produced Water

K Na Fe Ca Zn Cl Br

11,368 ppm 179 ppm Slight Improvement Compatibility Tests w/ Acids and HD Brine

Crude Sensitivity Tests South Marsh Island

100 90 80 70

Blank

1% Fe2O3

60 50 40 30 20 10 0 Acetic

HCl #1

HCl #2

HCl-HF

13 ppg HD

Clay Types

Kaolinite

A TWO-LAYER CLAY 

Generally non-expandable



Contributes to migration of fines

Kaolinite Clay

Smectite

A THREE-LAYER CLAY 

Great hydrating capability in fresh water

Smectite Clay

illite

A THREE-LAYER CLAY  

Compensated with K+ ion Non-swelling characteristic contributes to migration of fines

illite Clay

Chlorite

A FOUR-LAYER CLAY 



Magnesium hydroxide between the montmorillonite-type unit layers Damages formation by precipitation of iron if acidizing

Limestone Calcite

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

Laminated or thin bedded sections Quartz, Mica & Clay

Sandstones Clastic sedimentary rock grains ranging from 1/16 to 2 mm

Quartz

Silt stone Fine-grained clastic rock at least 50% is 1/ to 1/ 16 256 mm diam.

Quartz grains

Drilling Fluid Damage 

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  Fracturing fluid failures and incompatibilities

PRODUCTION DAMAGE

Production damage  Asphalt/Paraffin precipitation  Sand production  Mobilization of fines with high production rates  Bacterial scale  Precipitation of mineral 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, cement, etc.

Questions