Matrix Stimulation

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