AcidizingThe Fundamentals

Damage Assessment

Workover & Completion CommonalitiesFluid is put into the wellbore and/or formation

Tubulars of some sort are run into the well

Fundamental Acid TechniquesWellbore clean-up (tubing/casing)Matrix acidizing (sandstone or carbonates)Acid fracturing (carbonates)

Types of AcidMineralHydrochloric - HClHydrochloric/Hydrofluoric - HCl/HFOrganic (slower reacting less corrosive)AceticFormicPowdered (acid sticks)SulfamicChloroacetic

Dissolving Capability15% HCL 1.84 ppg28% HCL 3.68 ppg9:1 mix 7.5% HCL : Acetic 1.64 ppg9:1 mix 15% HCL : Acetic 2.48 ppg9:1 mix 28% HCL : Acetic 3.72 ppg10% Acetic 0.71 ppg

Acid Reaction Rate

Basic Equation

2HCl + CaCO3 H2O + CO2 +CaCl2 Water Salt Gas1000 1843 1040 6620 2050Gals lbs gals ft3 lbs

Controlling FactorsPressureLess than 500 psiTemperatureAdd 20, double reaction rateSubtract 20, half the reaction rateVelocityAccelerate the mass transferFlow patterns radial, linear, cylindrical

Controlling FactorsConcentrationStronger is faster (to a point)Contact area & volume ratioMatrix = large surface area (30000:1)20% limestone with 10 mdNatural fracture (3000:1)Same limestone with a 0.001 natural fractureFracture = smaller surface area (32:1)Same limestone with a 0.1 created fracture

Controlling FactorsFormation compositionSurface wettingViscosity

Retarded AcidsGelled acidMineral/organic mixCommon ion

Basic Equation

2HCl + CaCO3 H2O + CO2 +CaCl2

Retarded AcidsGelled acidMineral/organic mixCommon ionOil-wet barriersEmulsionsHigh concentrations

Acid additivesCorrosion Inhibitors specify time and temperatureSurface Active Agents anionic, cationic, nonionic, amphotericAnionic tend to water wet sand, emulsify oil in water, break water in oil emulsions, disperse claysCationic tend to water wet carbonates, emulsify water in oil, break oil in water emulsions, flocculates clayAnionic and cationic surfactants mix like matter and anti-matterNonionic tends to be the most popular surfactants

Acid Additives (cont)Non-emulsifiers (acid and oil)Chemical retarders (carbonates only)Foamers2 gpt < 75 F3 gpt < 130 F5 gpt < 200 F7 gpt < 250 F10 gpt < 300 F13 gpt < 350 F

Acid Additives (cont)Alcohol (dry gas wells)Methanol < 200 FEthanol < 300 FMutual solvents (need?)Anti-sludge agents (asphaltic crudes 5-20 gpt)Clay stabilizers

Acid Additives (cont)Iron sequestering agentsIron in tubulars, scale and fomation mineralsMost treatments minimum control of 1000 mpl requires 10-15 ppt sodium erythorbateControl severe iron concerns 5000 mpl60 to 120 - 1% acetic + 50 ppt citric120 to 180 - 2% acetic + 100 ppt citric or 50-65 ppt sodium erythorbate180 plus 50-65 ppt sodium erythorbate

Acid Additives (cont)Friction reducersGelling agentsFluid loss additivesDiverting materialRock saltWax beadsOil soluble resinsBenzoic acid flakes (story time)

Wellbore Clean-upClean-upMill scaleCorrosion scalePipe dopePickled tubing

The Pickle JobMinimum volume of aromatic solvent 250 gallonsScale basis 0.1 lb/ft in 5 20# casing (or 0.003 of 5.0 sg magnetite mill scale)400 gal/1000 5 100 gal/1000 2 7/8

The Pickle Job15% HClMinimum CIAromatic solvent pre-flushNo iron control

Catch return samples

Matrix AcidizingBelow fracture gradientWormholesSize?Length?Number?

WormholesFluid loss rate determines length, inches to feet longFluid loss additivesViscosityNot a function of reaction rate!

28% HCl

Sandstone Matrix AcidizingHCl for mud damage removalCarbonate FLADehydrate bentonite clayHCl/HF for stimulation (sandstone only!)Always at matrix ratePermeability dominatesShallow stimulation

HCl/HF AcidizingAlways need HCl pre-flushHF reacts more quickly with clays than silicaDont use sodium, potassium or calcium salt waters for flushFeldspar means use half strength (13.5%:1.5%)Flush with ammonium chloride or HCl spacer

Acid Fracturing (Carbonates)Factors affecting penetrationFluid lossInjection rateFracture widthFactors affecting conductivityHeterogeneityClosure pressureRock strength

Acid Fracturing MethodsDensity controlledViscous fingering Foamed acidOverbalanced surge

Density Control

Density Control

Viscous Fingering Acid

Overbalanced SurgingPlacement of unconventionally small volumes of acid in a fracture mode is not possible in a conventional mode.

Overbalanced SurgingPlacement of acid is possible with overbalanced surging even with large variances in permeability

Carbonate Acidizing

Reasons for Carbonate Acidizing

Damaged permeabilityLow permeabilityLow perforation efficiency

Matrix Treatment DesignDetermine fracture gradientCalculate maximum BHTPCalculate maximum allowable STPEstimate injection rate - Darcy radialDetermine acid volume 50-200 gal/ftSpecify acid type, volume, rate and max pressure

Fracture AcidizingMajority of carbonate reservoir treatments are acid fracsGood conductivity is the key to successful stimulationProductivity increases of 2.5-13 fold

Factors Affecting Fracture GeometryInjection rate

Fluid viscosity

Fluid volume injected

Fluid lossRock properties

Formation fluids

Formation stresses

Reaction rates

Rule of Thumb for Acid VolumeFill the fracture with an acid volume of regular 15% HCl that is three times (3X) the fracture volume to be etched.

Treatment DesignOptimize the treatmentFracturing calculationsRock compositionClosed fracture acidizing (10-20%)Treatment review

General volumesAcid wash/soak 10-25 gals/ftMatrix acid 100-200 gals/ftAcid Fracture 400-600 gals/ft

Questions???

Pat H. Sanderson 1-13 #1Stimulation EvaluationA Look Back and Forward byPat Handren

Prior Stimulation ModelOriginal perforations16,760 16,83085/15 split dolomite/limestone10,000 gals 15% HClBHT - 277FProblemsNo cooldownReaction time ~2 min.Small radius of penetration (50-100)

PositivesReservoir has potential!

Pat H. Sanderson 1-13 #1Condensate History Match

Chart1

54022500

4562.55300

40884400

3724.19630672774000

3619.29583061743600

3520.14298143453250

3426.27797583773230

3337.28879747063230

3252.80515084223200

3172.49331088073050

3096.05171709162900

3042.10121762113000

3025.70457164633000

3009.48373092712700

2993.43588305813000

50-60' acid frac

Production Data

Year

BOPM

Pat Sanderson 1-13 #1History Match on Condensate

Sheet1

years50-60' acid frac300' acid frac300' prop fracProduction Data

0.2540210181117391482793222500600068

0.44563886610004125243274530018720145

0.6408878518715112215239440029280121

0.8372473698093102202222400038880110

13619703476569919321036004752099

1.23520672772659618419932505532089

1.43426644669119417718932306307288

1.63337618865909117018132307082488

1.83253607864568916717732007850488

23172598263408716417430508582484

2.23096589062288516117129009278479

2.43042579961208315916830009998482

2.630265712601683156165300010718482

2.830095627591582154162270011366474

329935545581782152159300012086482

Sheet2

Perforations

TopBottomnetgrossDolomiteCalcite

1660416620168812

16637166425385545

167401674666337

1676016782227525

168061683024908812

73128

Average79.767123287720.2328767123

Height700.0033874529

Length429.717341482pp -30200008-1055.25951861712320.8997819184

Width0.0166666667p - 3050008-10

Efficiency0.520%200008-10

500 bs1000

Volume15000pp15000

Reaction Time41p5000

Rate8.710801393720%15000

f6000

870005200035000

Sheet3

Acid Volume

Acid Strength

Relative Reaction Rates

Keys to Successful AcidizingCool down the reservoir Increase the fracture widthRate dependent on pressureMaximize penetration distanceClosed fracture acidizingOverflush

Two Staged Acid ProposalFirst stage20,000 gals 30# gel5,000 gals 30# borate x-linked20,000 gals 20% HCLPump at 8-10 BPM, but use pressure to dictate maximum rateDivert with 500 bioballsSecond stage15,000 gals 30# gel5,000 gals 30# borate x-linked15,000 gals 20% HCLReduce rate & over flush

Fracture ProposalRemove tubing from well.Fracture stimulate down casing @ 30 BPM using a 35# borate x-linked system and 224,000# 20/40 bauxite in 2-5ppg stages.Lubricate packer.Rerun tubing.

Stimulation ComparisonAcidizing.No mechanical changes required.No potential for pressure related failures.Conductivity is not predictable.Lower cost.FracturingRequires prep workPotential for early job termination (25%)Potential for pressure related failure (

Cost EstimatesAcidizingBook Price - $90,000 Discounted @ 40% - $54,000

FracturingBook Price - $375,000Discounted @ 40% - $225,000 (4:1 cost ratio)

Production Results

Summary of Job ResultsInitial acid treatment created 50-60 of half-lengthSecond treatment created 200-220 of half-length (~200 short of design length) and produced close to prediction for about 1.5 years.Over time the half-length has decreased due to closure or recalcification to a length of 50-60 and is back on trend with production prior to second acid job.Conclusions:Second acid job was a huge success!Well could benefit from a third acid job!!