matrix stimulation
TRANSCRIPT
ObjectiveTo introduce the basic concepts of reservoir
“matrix”To explain Matrix acidizingTo explain the application of Coiled Tubing in
matrix acidizingTo outline the additives used in CT Matrix
acidizing and their functionsTo explain diversion and Zonal Coverage
techniques ROO “Design Protocol”
Why Acidizing through Coiled TubingWellhead / Completion tubulars protection
Accurate placement / Complete coverage
Live well operation
Jetting effect
Flowback - N2 kick off
Integrated service, fill cleanout and N2 kick-off
Wellbore fluids not bullheaded into formation
Design ConsiderationsWellbore and Completion Characteristics
Well preparation
Inhibition time
Acid neutralisation
Pump rate
Placement technique (Diversion)
Well StimulationStimulation is a chemical or mechanical method
of increasing flow capacity to a well.OS is mainly concerned with three methods of
stimulation:Wellbore Clean-up - “Fluids not injected in
formation” Chemical Treatment Perf Wash
Matrix Treatment - “ Injection below frac pressure” Matrix Acidizing Chemical Treatment
Fracturing - “ Injection above frac pressure” Acid Frac Propped Frac
Reduction in Flow Capacity May Occur:Wellbore:
Scale DamageSand FillPlugged PerforationsParaffin PluggingAsphalt Deposits
Mechanical/Chemical/Acidizing TreatmentCritical Matrix:
Drilling Mud DamageCement DamageCompletion FluidsProductionNative Clays/Fines
A naturally low permeability reservoir.
Matrix AcidizingSandstone:
Major Effects: Dissolves/Disperses Damage Restores Permeability
Limestone:Major Effects:
Enlarge Flow Channels/Fractures Disperse Damage by Dissolving Surrounding Rock Creation of Highly Conductive Wormholes
Formation DamageDamage Definition :
Partial or complete plugging of the near
wellbore area which reduces the original
permeability of the formation.
Damage is quantified by the skin factor ( S ).
Skin (s)The total Skin (ST) is the combination of
formation damage skin and pseudo-skins. It is the total skin value that is obtained directly from well-test analysis.
Formation Damage Skin:Mathematically defined as an infinitely thin zone
that creates a steady-state pressure drop at the sand face.
S > 0 Damaged FormationS = 0 Neither damaged nor stimulatedS < 0 Stimulated formation/slanted well
Pseudo Skin:Includes situations such as fractures, partial
penetration, turbulence, and fissures.The Formation Damage Skin is the only type
that can be removed by stimulation.
Types of Formation DamageEmulsionsWettability ChangeWater BlockScale FormationOrganic DepositsMixed DepositsSilt & ClayBacterial Slime
Sources of Formation DamageDrillingCementingPerforatingCompletion and WorkoverGravel PackingProductionStimulationInjection Operations
Successful Matrix TreatmentRequirements:
Correct Reactive Chemicals
Enough Treating Fluid Volume
Low Injection Pressure
Total Zone Coverage
Acidizing AdditivesCorrosion Inhibitors : Surfactants :Foaming Agents : Mutual Solvents : Antisludge Agents : Non-Emulsifiers : Iron Control :Friction Reducers : Clay Control :Diverters : Specialty Additives
Sources of IronTubulars:
Rust
Scale
Corrosion
Formation:Pyrite
Chlorite
Magnetite
Acid RequirementsReact with formation minerals and give
soluble products
React with damage and give
soluble/dispersible products
Possible to inhibit
Safe to handle
Low cost and available
Sandstone Vs. CarbonateCarbonate: Acid creates new flow path by
dissolving formation rock
Sandstone: Dissolution of the permeability damaging mineral
Controlling Precipitation SummaryPreflush
HCl is commonly used to: Avoid contact between HF and formation brine
Dissolve Carbonates Avoid formation of CaF2
Aromatic Solvents and Mutual Solvents may be
used in combination with HCl
Preflush3% NH4CI solution (10 gal/ft)
HCl
Xylene / Toluene
Removal of organic deposits
Mutual Solvent / Alcohols
Removal of organic deposits
OverflushDisplacement of acid flush away from wellbore
area
Oil Wells: NH4CI/Weak HCl/mutual solvent (if
necessary)
Gas Wells: NH4CI/Weak HCl
Surfactant/Mutual solvent:Leave formation water-wetFacilitate flowback
Nitrogen: Promote flowback in low pressure wells
Fluid PlacementFluid tends to take the path of least
resistance.
Proper diversion is a major factor in the
success or failure of a treatment.
Need for Diversion
A
Layer 1
Layer 2
Layer 3
k1 = 50 mds1 = 10
k2 = 300 mds2 = 5
k3 = 200 mds3 = 2
Damaged Zone
B
Layer 1
Layer 2
Layer 3
8%
33%
59%
Injected Fluid
Technique for Fluid DiversionMechanical:
Straddle PackersBall SealersCT Packer
Chemical:Bridging AgentsDiverting Agents
Foam - NitrifiedVEDA - Self Diverting Acid
Selective Acidizing through CT using Packers
Tubing End LocatorTubing End Locator
Flow
Flow
BuoyantBall Sealer
ConventionalDensity
Ball Sealer
Conventional density (nonbuoyant) ball sealer
100% efficient buoyant ball sealer
Ball Sealers