formation damage
TRANSCRIPT
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FORMATION DAMAGEFORMATION DAMAGE
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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
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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)
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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
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Origin of Sedimentary RockOrigin of Sedimentary Rock
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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
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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
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Sand and SandstoneSand and Sandstone
Made up of sand grainsMade up of sand grains
These grains are commonlyThese grains are commonly
QuartzQuartzFeldsparFeldsparRock FragmentsRock FragmentsFossilsFossilsMicaMica
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SandstoneSandstone
200 microns
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SandstoneSandstone
BESIDES SAND GRAINS SANDSTONE MAY CONTAIN
MINERAL CEMENTS
THESE INCLUDE
QUARTZCALCITEDOLOMITEANHYDRITE
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Sandstone withSandstone withAnhydrite CementAnhydrite Cement
200 microns
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Micro-Quartz CementationMicro-Quartz Cementation
50 microns
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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
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Sandstone with ClaySandstone with Clay
50 microns
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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
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PorosityPorosity
The Volumetric Fraction of Formation Not Occupied by Solids.
Two types of porosity:Absolute - Volume not occupied by
solids. Effective - Interconnected spaces.
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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
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Grain SortingGrain Sorting
CONTROLS POROSITY & PERMEABILITY
Large Pore Spaces Yield Good Porosity
And High Permeability.
Poor sorting yields smaller pore spaces and lower permeability.
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Well-Sorted SandstoneWell-Sorted Sandstone
GOOD POROSITY
AND PERMEABILITY
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Poor SortingPoor Sorting
MUCH LOWER
POROSITY AND
PERMEABILITY
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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
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Pore Space in SandstonePore Space in Sandstone
200 microns
330 x 900
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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
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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.
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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
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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
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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
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DARCY’S LAW
k * A * (P1 - P2)Q = ------------------------
* L
rearrange to
Q * * Lk = ------------------ A * (P1 - P2)
LR
P1
P2
Permeability of a CorePermeability of a Core
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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
Permeability of a CorePermeability of a Core
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LR
P1
P2
k = 0.06 darcy
1 darcy = 1000 millidarcys
k = 60 millidarcys = 60 md
Permeability of a CorePermeability of a Core
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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
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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
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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 * 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 3398.4Q = ---------------------------------- = ----------- = --------- = 239.7 bbl/d239.7 bbl/d
2 * ln (1200) 2 * 7.09 14.18
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Formation DamageFormation 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”INTRODUCE SKIN FACTOR “S”
0.00708 * k * h * (Pe - Pw)Q (bbl/day) = ----------------------------------- * ( ln (re / rw) + SS)
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SkinSkin
S > 0 ----> FORMATION DAMAGE
S < 0 ----> WELL STIMULATION
0.00708 * k * h * (Pe - Pw)Q (bbl/day) = ----------------------------------- * ( ln (re / rw) + S)
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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
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SkinSkin
THE SKIN FACTOR CAN BE OBTAINED
FROM A PRESSURE BUILD UP TEST.
THE SKIN FACTOR IS A MEASURE
OF FORMATION DAMAGE.
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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)
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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
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TIME --->
kO
UNDAMAGED k
Permeability TestingPermeability Testing
Step 1: Determine Undamaged Permeability
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Permeability TestingPermeability Testing
TIME --->
kO
UNDAMAGED k
Step 2: “Damage” the Permeability
expose core tofluid in directionopposite to productionflow.
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TIME --->
kO
UNDAMAGED k
DAMAGED k
Step 3: Determine Damaged Permeability
Permeability TestingPermeability Testing
DAMAGED k% RETURN = 100 * ---------------------- UNDAMAGED k
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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.
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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
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SW
kOkW
OIL PERM
WATER PERM
SINGLE PHASE PERMEABILITY
Relative PermeabilityRelative Permeability
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Formation Damage DefinitionFormation Damage Definition
Any loss in productivity caused by a source other than natural pressure depletion or mechanical restrictions
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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...
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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) ?
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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
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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?
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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
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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”
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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
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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
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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
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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 * 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 16992Q = ---------------------------------- = ----------- = --------- = 1198 bbl/d
2 * ln (1200) 2 * 7.09 14.18
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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
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CompareCompare
1198 BBL/D UNDAMAGED
WITH 30% PERMEABILITY DAMAGE EXTENDING1.5 INTO THE RESERVOIR
1105 BBL/D DAMAGED
PRODUCTION RATE IS DAMAGED 7.8%
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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
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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?
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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)
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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)
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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
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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
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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.
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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.
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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
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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
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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
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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.
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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.
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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
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Completion Fluid DamageCompletion 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
Bad Displacement
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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-- )
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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 DamageCompletion Fluid Damage
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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
Completion Fluid DamageCompletion Fluid Damage
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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 DamageCompletion Fluid Damage
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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
Completion Fluid DamageCompletion Fluid Damage
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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
Completion Fluid DamageCompletion Fluid Damage
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ZnBr2 CaBr2 CaCl2 NaCl KCl NH4Cl KHCO2
Emulsions Emulsions
Emulsions with Crude Oil and Completion FluidsEmulsions with Crude Oil and Completion Fluids
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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
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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
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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
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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
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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
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Clay TypesClay Types
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KaoliniteKaolinite
A TWO-LAYER CLAY
Generally non-expandable
Contributes to migration of fines
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Kaolinite ClayKaolinite Clay
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SmectiteSmectite
A THREE-LAYER CLAY
Great hydrating capability in fresh water
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Smectite ClaySmectite Clay
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illiteillite
A THREE-LAYER CLAY
Compensated with K+ ion
Non-swelling characteristic contributes to migration of fines
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illite Clayillite Clay
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ChloriteChlorite
A FOUR-LAYER CLAY
Magnesium hydroxide between the montmorillonite-type unit layers
Damages formation by precipitation of iron if acidizing
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LimestoneLimestone
CalciteCalcite
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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
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SandstonesSandstones
QuartzQuartz
Clastic sedimentary Clastic sedimentary rock grains ranging rock grains ranging from from 11//1616 to 2 mm to 2 mm
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Silt stoneSilt stone
Quartz grainsQuartz grains
Fine-grained clastic rock at least 50% is 1/16 to 1/256 mm diam.
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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
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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
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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
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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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QuestionsQuestions