Formation Damage

FORMATION DAMAGEFORMATION DAMAGE

Reservoir Rock PropertiesReservoir 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 PropertiesReservoir Rock Properties

Introduce the two reservoir terms:

POROSITYPOROSITYpercentage or fraction of void to

bulk volume of the rock

PERMEABILITYPERMEABILITYa measure of a rock’s specific flow

capacity (depends on the interconnectivity of the porosity)

TYPES OF ROCK FORMATIONSTYPES OF ROCK FORMATIONS

METAMORPHICMETAMORPHICALTERED BY INTENSE ALTERED BY INTENSE HEAT AND PRESSUREHEAT AND PRESSURE

IGNEOUSIGNEOUSSOLIDIFIED SOLIDIFIED

MOLTEN ROCKMOLTEN ROCK

SEDIMENTARYSEDIMENTARYFORMED BY EROSION, FORMED BY EROSION,

TRANSPORTATION, DEPOSITIONTRANSPORTATION, DEPOSITION

ClassificationClassification

IGNEOUS AND METAMORPHIC ROCKS RARELY CONTAIN OIL & GASIGNEOUS AND METAMORPHIC ROCKS RARELY CONTAIN OIL & GAS

Origin of Sedimentary RockOrigin of Sedimentary Rock

Sedimentary Rock Sedimentary Rock ClassificationClassification

CLASTIC Made up of grains that have been

sedimented Includes sands and shales

• NON-CLASTICNON-CLASTIC

• Made up of biogenic or chemical Made up of biogenic or chemical precipitatesprecipitates

• Includes Limestone and DolomitesIncludes Limestone and Dolomites

Sedimentary RockSedimentary Rock

CLASTIC CONGLOMERATE-

GRAVEL SANDSTONE-SANDSTONE-

SANDSAND SILTSTONE-SILT SHALE-CLAY

COMMON OIL AND GAS RESERVOIRS ARE YELLOWCOMMON OIL AND GAS RESERVOIRS ARE YELLOW

NON-CLASTIC LIMESTONELIMESTONE DOLOMITEDOLOMITE SALT GYPSUM COAL

Sand and SandstoneSand and Sandstone

Made up of sand grainsMade up of sand grains

These grains are commonlyThese grains are commonly

QuartzQuartzFeldsparFeldsparRock FragmentsRock FragmentsFossilsFossilsMicaMica

SandstoneSandstone

200 microns

SandstoneSandstone

BESIDES SAND GRAINS SANDSTONE MAY CONTAIN

MINERAL CEMENTS

THESE INCLUDE

QUARTZCALCITEDOLOMITEANHYDRITE

Sandstone withSandstone withAnhydrite CementAnhydrite Cement

200 microns

Micro-Quartz CementationMicro-Quartz Cementation

50 microns

Sand and SandstoneSand and Sandstone

Sand or Sandstone may contain:Sand or Sandstone may contain:

1. Sand Grains - Always1. Sand Grains - Always

2. Cements - Not Always (usually)2. Cements - Not Always (usually)

3. Clays - Not Always (usually)3. Clays - Not Always (usually)

4. Pore Spaces - Essential for Oil or 4. Pore Spaces - Essential for Oil or Gas Reservoir Gas Reservoir

Sandstone with ClaySandstone with Clay

50 microns

PorosityPorosity

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

percentage or fraction of void volume to bulk volume

PorosityPorosity

The Volumetric Fraction of Formation Not Occupied by Solids.

Two types of porosity:Absolute - Volume not occupied by

solids. Effective - Interconnected spaces.

Porosity - DeterminationPorosity - Determination

TOTAL VOLUME = x r2 x h

hr

r = 1.262 cm h = 3.0 cm

TOTAL VOLUME = 15.00 cm3

TO DETERMINE POROSITY:

WATER SATURATED WEIGHT = 34.2 GDRY WEIGHT = 31.2 GWEIGHT WATER = 3.0 G --> 3 CC PORE VOL.

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

Grain SortingGrain Sorting

CONTROLS POROSITY & PERMEABILITY

Large Pore Spaces Yield Good Porosity

And High Permeability.

Poor sorting yields smaller pore spaces and lower permeability.

Well-Sorted SandstoneWell-Sorted Sandstone

GOOD POROSITY

AND PERMEABILITY

Poor SortingPoor Sorting

MUCH LOWER

POROSITY AND

PERMEABILITY

Pore SizePore Size

Methods to determine pore size and optimum Methods to determine pore size and optimum bridging particle sizebridging particle size

1. 1. Estimate from PermeabilityEstimate from Permeability

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

2. 2. Measurement from Thin SectionMeasurement from Thin Section - More Reliable- More Reliable

Pore Space in SandstonePore Space in Sandstone

200 microns

330 x 900

PermeabilityPermeability

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

PermeabilityPermeability

1856 Henry D’Arcy experimented with water 1856 Henry D’Arcy experimented with water flowing through sand beds. Results of his studies flowing through sand beds. Results of his studies produced equations relating flow rate and pressure produced equations relating flow rate and pressure gradientgradient

DARCY’S LAWDARCY’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 DefinitionDarcy: 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 FlowDarcy’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 CorePermeability of a Core

DARCY’S LAW

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

*L

Lr

P1

P2

Q = flow rate in cc/secA = 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

DARCY’S LAW

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

* L

rearrange to

Q * * Lk = ------------------ A * (P1 - P2)

LR

P1

P2


Measure Flow rate under conditions:

R = 1.262 cm L = 3.0 cm = 1 cpA = 5 sq cm P1 = 2 atm P2 = 1 atm

Flow rate = 0.1 cc/sec = 6 cc/min

LR

P1

P2

Q * * L 0.1 * 1 * 3 0.3k = ------------------ = ----------------- = ----- = 0.06 darcy A * (P1 - P2) 5 * (2 - 1) 5


LR

P1

P2

k = 0.06 darcy

1 darcy = 1000 millidarcys

k = 60 millidarcys = 60 md


Darcy’s Law - Radial FlowDarcy’s Law - Radial Flow

re

rw

Pe

Pw

re = drainage radiusrw = well radiusPe = pressure at re

Pw = pressure in well

h = reservoir thicknessk = permeabilityu = viscosity of oil

re = drainage radius ftrw = well radius ftPe = pressure in psi at re

Pw = pressure in psi in well

h = reservoir thickness ftk = permeability md = viscosity of oil cp

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

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

Darcy’s Law - Radial FlowDarcy’s Law - Radial Flow

Production Rate of OilProduction Rate of Oil

re = 600 ft Pe = 4000 psi h = 20 ft = 2 cprw = 0.5 ft Pw = 3600 psi k = 60 md


0.00708 * 60 * 20 * (4000 - 3600)Q = -----------------------------------------------

2 * ln ( 600 / 0.5)

0.00708 * 60 *20 * 400 3398.4 3398.4Q = ---------------------------------- = ----------- = --------- = 239.7 bbl/d239.7 bbl/d

2 * ln (1200) 2 * 7.09 14.18

Formation DamageFormation Damage

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


INTRODUCE SKIN FACTOR “S”INTRODUCE SKIN FACTOR “S”

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

SkinSkin

S > 0 ----> FORMATION DAMAGE

S < 0 ----> WELL STIMULATION

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

SkinSkin

SKIN FACTOR PRODUCTION RATE0.0 239.71.0 210.03.0 168.4

10.0 99.420.0 62.750.0 29.8-1.0 279.0

SkinSkin

THE SKIN FACTOR CAN BE OBTAINED

FROM A PRESSURE BUILD UP TEST.

THE SKIN FACTOR IS A MEASURE

OF FORMATION DAMAGE.

re = drainage radiusrw = well radiusPe = pressure at re

Pw = pressure in well

h = reservoir thicknessk = permeability = viscosity of oil

SkinSkin

re

rw

Pe

Pw

Skin (S)

1. 1. POROSITYPOROSITY - - Determines the amount Determines the amount of Oil and/or Gas Availableof Oil and/or Gas Available

2. 2. PERMEABILITY PERMEABILITY -- Determines Possible Determines Possible Production RateProduction Rate

3. 3. SKIN FACTORSKIN FACTOR - - A measure of Formation A measure of Formation DamageDamage

Concepts to RememberConcepts to Remember

TIME --->

kO

UNDAMAGED k

Permeability TestingPermeability Testing

Step 1: Determine Undamaged Permeability


TIME --->

kO

UNDAMAGED k

Step 2: “Damage” the Permeability

expose core tofluid in directionopposite to productionflow.

TIME --->

kO

UNDAMAGED k

DAMAGED k

Step 3: Determine Damaged Permeability


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

Relative PermeabilityRelative 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 (SWater Saturation (Sww))

PORE VOL. = VOL. WATER + VOL. OIL

Often expressed as saturation, where

SW = WATER SATURATIONSO = OIL SATURATION AND SSOO + S + SWW = 1 = 1

FOR A HYDROCARBON RESERVOIR

SW

kOkW

OIL PERM

WATER PERM

SINGLE PHASE PERMEABILITY

Relative PermeabilityRelative Permeability

Formation Damage DefinitionFormation Damage Definition

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

Causes of Formation DamageCauses of Formation Damage

1. Drilling

2. Completion

3. Stimulation

4. Production

Once a virgin reservoir is penetrated, Once a virgin reservoir is penetrated, damage occurs. The question is to what extent?damage occurs. The question is to what extent?

One way to classify damage is according to origin...

Formation DamageFormation Damage

Key Questions:Key Questions:

What is Magnitude ?

What is Cause (source) ?

How Far (depth of penetration) ?

Can We Prevent ?

Can We Recover (remedial treatment) ?

How Much and How Deep is the How Much and How Deep is the Damage?Damage?

0

20

40

60

80

100

PR

OD

UC

TIO

N D

AM

AG

E

0 20 40 60 80 100 PERMEABILITY DAMAGE

PERMEABILITY VS PRODUCTION DAMAGE INVASION DEPTH = 2 FT

Return Perm vs. SkinReturn Perm vs. Skin

Example:

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

What is the effect on Production?What is the effect on Production?

Formula for “S”Formula for “S”

ra re

ke

ka

re = drainage radius

ra = damaged radius

rw = well radius

ke = undamaged permeability

ka = damaged permeability

rw

re = drainage radius

ra = damaged radius

rw = well radius

ke = undamaged permeability

ka = damaged permeability

kkee - k - kaa

S = ---------- * ln (rS = ---------- * ln (raa / r / rww))

kkaa

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

Formula for “S”Formula for “S”

Radius of DamageRadius of Damage

0

10

20

30

40

50

60

70

INV

AS

ION

DE

PT

H (

CM

)

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

INV

AS

ION

DE

PT

H (

CM

)

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

Radius of DamageRadius of Damage

Calculate “S”Calculate “S”with 1.5 ft Invasionwith 1.5 ft Invasion

ra = damaged radius = 1.5 + 0.5 = 2.0

rw = well radius = 0.5

ke = undamaged permeability = 60

ka = damaged permeability = 0.7 * 60 = 42

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

ka 42

Zero Damaged WellZero Damaged Well

re = 600 ft Pe = 4000 psi h = 100 ft = 2cprw = 0.5 ft Pw = 3600 psi k = 60 md


0.00708 * 60 * 20 * (4000 - 3600)Q = -----------------------------------------------

2 * ln ( 600 / 0.5)

0.00708 * 60 *100 * 400 16992 16992Q = ---------------------------------- = ----------- = --------- = 1198 bbl/d

2 * ln (1200) 2 * 7.09 14.18

Damaged WellDamaged Well

re = 600 ft Pe = 4000 psi h = 100 ft = 2cprw = 0.5 ft Pw = 3600 psi 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 16992Q = ---------------------------------- = ----------- = --------- = 1105 bbl/d

2 * (ln (1200) + 0.6) 2 * 7.69 15.38

CompareCompare

1198 BBL/D UNDAMAGED

WITH 30% PERMEABILITY DAMAGE EXTENDING1.5 INTO THE RESERVOIR

1105 BBL/D DAMAGED

PRODUCTION RATE IS DAMAGED 7.8%

CompareCompare

1198 BBL/D UNDAMAGED

WITH 30% PERMEABILITY DAMAGE EXTENDING1.5 INTO THE RESERVOIR

1105 BBL/D DAMAGED

PRODUCTION RATE IS DAMAGED 7.8%

93 BBl/D @ $30/BBl = 2790$/D = $1,018,350/yr93 BBl/D @ $30/BBl = 2790$/D = $1,018,350/yr

What About a Clear Brine?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 Depth of Invasion for Clear BrineBrine

Example: Lose 1000 bbl of brine to an interval of 100’ with a porosity of 30%.

Depth of invasionDepth of invasion

r = V/r = V/hh

r = 92.6 in (7.7 ft)r = 92.6 in (7.7 ft)

Damage Due to Invasion of Damage Due to Invasion of Clear BrineClear Brine

kr 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 MechanismsDamage Mechanisms

Solids PluggingSolids Plugging filtrate invasion / solids contamination fines migration

Chemical IncompatibilityChemical Incompatibility clay / shale swelling inducing fines migration fluid-fluid interactions

emulsions, precipitation (scaling) wettability reversal

Solids PluggingSolids Plugging

d

d’

d’ = Diameter of Bridging Particle

d = Diameter of Pore Throat

If d’ > 1/2d Stable Bridges Will FormStable Bridges Will Form

Bridging TheoryBridging Theory

Particles Particles 1/3 the Diameter of the Pore 1/3 the Diameter of the Pore Throat Will Plug on the Surface.Throat Will Plug on the Surface.

Particles Less Than 1/3 to About 1/7 the Particles Less Than 1/3 to About 1/7 the Diameter of the Pore Throat Will Plug in the Diameter of the Pore Throat Will Plug in the Pore Channels.Pore Channels.

Particles Less Than 1/7 the Diameter of the Particles Less Than 1/7 the Diameter of the Pore Throat Will Migrate Freely Through the Pore Throat Will Migrate Freely Through the Formation.Formation.

Critical Plugging Particle Size Critical Plugging Particle Size

Permeability

(*Millidarcies)

Pore Size

(Microns)

Critical Plugging Range

1/3 to 1/7

(Microns)

5 2.2 0.75 to 0.3210 3.2 1.05 to 0.4550 7.1 2.36 to 1.01

100 10.0 3.33 to 1.43250 15.8 5.27 to 2.26500 22.4 7.45 to 3.19750 27.4 9.13 to 3.91

1000 31.6 10.54 to 4.521500 38.7 12.91 to 5.532000 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 microns is needed to remove a “haze” from a liquid.

Particle Sizes of Common Particle Sizes of Common MaterialsMaterials

BARITE - 30 MICRONS

FINE CaCO3 - 15 MICRONS

MEDIUM CaCO3 - 35 MICRONS

COARSE CaCO3 - 100 MICRONS

MIX II FINE - 60 MICRONS

Return Permeability Tests - solids in NaCl brineReturn Permeability Tests - solids in NaCl brine

SOLIDSSOLIDS % DAMAGE% DAMAGE

0 PPM0 PPM 3.8 3.8100 PPM100 PPM 15.2 15.2190 PPM190 PPM 25.8 25.8420 PPM420 PPM 48.4 48.4990 PPM990 PPM 78.8 78.8

Sadlerochit sandstone formation - AlaskaSadlerochit sandstone formation - Alaska

Damage Due to Solids Damage Due to Solids PluggingPlugging

Solids in Clear Brine?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 MigrationFines Migration

Fines migration refersto the movement throughthe pore space ofnaturally occurringparticles such as clays micro-crystalline quartz,feldspars, etc.

Fines migration is oftenobserved upon onset ofwater production.

Inducing Fines MigrationInducing Fines Migration

Fines are mobile in the phase that wets them.

Since most formations arewater wet, introducing water (or brine) can inducefines migration. Heavy losses of clear brine can induce hydrodynamic pressures (due to viscosity) that can cause fines to detach and mobilize.

Completion Fluid DamageCompletion 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

Problems with gravel pack placement


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

Bad Displacement

Damage Mechanisms from ClearDamage Mechanisms from ClearBrine Completion FluidsBrine 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-- )

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


Formation Compatibility

SAFE-SURF LT - Fluid Recovery Aid

K(md)

Pore Volume of Fluid Flowed Though Core

Ki Kf with SAFE-SURF LT

Kf 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


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)

Formation Compatibility - Precipitates


SAFE-SCAVITE scale inhibitor for calcium based completion fluids

Pre-flush with NH4Cl prior to circulating completion fluids when well is acid pre-packed with HCl-HF acid.

Formation Compatibility - Precipitate Prevention


ZnBr2 CaBr2 CaCl2 NaCl KCl NH4Cl KHCO2

Emulsions Emulsions

Emulsions with Crude Oil and Completion FluidsEmulsions with Crude Oil and Completion Fluids

ZnBr2 CaBr2 CaCl2 NaCl KCl NH4Cl KHCO2 SB-CBF

SSAFEAFE-B-BREAKREAK CBF CBF

Emulsions with Crude Oil and Completion FluidsEmulsions with Crude Oil and Completion Fluids

Case History:Case History:High IslandHigh 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 ObtainedLaboratory 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 Analysis of High Island SamplesHigh Island Samples

K 11,368 ppm 218 ppmNa 179 ppm 9,604 ppmFe <1 ppm 30 ppmCa 169 ppm 69,370 ppmZn 2 ppm 12,984 ppmCl 11,000 ppm 13,000 ppmBr <1 ppm 133,000 ppm

Ion Emulsion WaterProduced Water

Case History:Case History: South Marsh IslandSouth Marsh Island

Workover OperationRe-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

Compatibility Tests w/ Acids and HD Brine

Crude Sensitivity TestsCrude Sensitivity Tests South Marsh IslandSouth 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

Clay TypesClay Types

KaoliniteKaolinite

A TWO-LAYER CLAY

Generally non-expandable

Contributes to migration of fines

Kaolinite ClayKaolinite Clay

SmectiteSmectite

A THREE-LAYER CLAY

Great hydrating capability in fresh water

Smectite ClaySmectite Clay

illiteillite

A THREE-LAYER CLAY

Compensated with K+ ion

Non-swelling characteristic contributes to migration of fines

illite Clayillite Clay

ChloriteChlorite

A FOUR-LAYER CLAY

Magnesium hydroxide between the montmorillonite-type unit layers

Damages formation by precipitation of iron if acidizing

LimestoneLimestone

CalciteCalcite

ShaleShale

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

Laminated or thin bedded Laminated or thin bedded sections Quartz, Mica & Claysections Quartz, Mica & Clay

SandstonesSandstones

QuartzQuartz

Clastic sedimentary Clastic sedimentary rock grains ranging rock grains ranging from from 11//1616 to 2 mm to 2 mm

Silt stoneSilt stone

Quartz grainsQuartz 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

Drilling Fluid DamageDrilling Fluid Damage

STIMULATION DAMAGESTIMULATION DAMAGE

S t i m u l a t i o n F l u i d D a m a g e A c i d s l u d g e d e p o s i t s M i n e r a l i n c o m p a t i b i l i t i e s w i t h a c i d F i n e s r e l e a s e d i n a c i d t r e a t m e n t F r a c t u r i n g f l u i d f a i l u r e s a n d i n c o m p a t i b i l i t i e s

PRODUCTION DAMAGEPRODUCTION DAMAGE

P r o d u c t i o n d a m a g e A s p h a l t / P a r a f f i n p r e c i p i t a t i o n S a n d p r o d u c t i o n M o b i l i z a t i o n o f f i n e s w i t h h i g h p r o d u c t i o n r a t e s B a c t e r i a l s c a l e P r e c i p i t a t i o n o f m i n e r a l s c a l e

OTHER CAUSES OFOTHER CAUSES OFDAMAGEDAMAGE

O t h e r R e s e r v o i r c h a r a c t e r ( f r a c t u r e s , f a u l t s , i n h o m o g e n i e t i e s ) W e l l b o r e o r i e n t a t i o n ( f o r e x a m p l e , s k i n d e t e r m i n a t i o n f o r h o r i z o n t a l w e l l s h a s n o t b e e n w o r k e d o u t i n t h e s a m e d e g r e e o f d e t a i l a s f o r c o n v e n t i o n a l r e s e r v o i r s ) A n y n u m b e r o f f a i l u r e s o f e q u i p m e n t , t u b u l a r s , p a c k e r s , c e m e n t , e t c .

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Formation Damage

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