Foam Applications Manual

Halliburton Energy Services

Foam ApplicationsManual

®

Notices

All information contained in this publication is confidential andproprietary property of Halliburton Energy Services, a division of Halli-burton Company. Any reproduction or use of these instructions, draw-ings, or photographs without the express written permission of an officerof Halliburton Energy Services is forbidden.

©Copyright 1992, Halliburton Company

All Rights Reserved.

Printed in the United States of America.

Printing History:First Release 1992Second ReleaseReprinted

Table of Contents TOC-1

TOC

Foam Applications Manual

Table of Contents

Section 1: Introduction

Foamed Acid ...........................................................................................1-3Hydraulic Fracturing Stimulation.............................................................1-3Foam Cement .........................................................................................1-3Other Applications ..................................................................................1-3

Section 2: Nitrogen Properties

Introduction .............................................................................................2-3Physical Properties .................................................................................2-4Nitrogen Expansion ................................................................................2-4Nitrogen in Foam ....................................................................................2-4

Section 3: Nitrogen Safety

Physical Properties .................................................................................3-3Nitrogen in the Air ...................................................................................3-3Cryogenic Thermometer .........................................................................3-3Safety Precautions for Handling Liquid Nitrogen ....................................3-4First Aid Procedures for Cold Liquid Frostbite (Freeze Burns)...............3-4Liquid Air Hazard ....................................................................................3-5Oxygen Deficiency Hazard .....................................................................3-5Liquid Nitrogen Equipment Safety ..........................................................3-5

Section 4: Foam Applications in Acidizing

Acidizing with Foam ................................................................................4-3Advantages of Foamed Acid ...................................................................4-3Foamed Acid Penetration .......................................................................4-4Foam Stability .........................................................................................4-6

NOTE

To read information on a particular subject, click the heading in the Bookmarks (far left) or click the corresponding colored box below.

TOC-2 Table of Contents

Foam Diversion .......................................................................................4-6Fracture Acidizing .................................................................................4-10References ...........................................................................................4-15Other References .................................................................................4-15

Section 5: Foam Applications in Hydraulic Fracturing

Introduction .............................................................................................5-3Types of Foams Used in Hydraulic Fracturing .......................................5-4Foam Rheology.......................................................................................5-4Crosslinked Foams .................................................................................5-5Foam Fluid Loss .....................................................................................5-7Fracture Conductivity ............................................................................5-12Treating Pressure Response ................................................................5-14Fluid Recovery ......................................................................................5-22Treatment Designs for Hydraulic Fracturing .........................................5-22Minifractures .........................................................................................5-31Conclusions ..........................................................................................5-34References ...........................................................................................5-34Additional References ..........................................................................5-35

Section 6: Foam Cementing

Introduction .............................................................................................6-3Foam Generation ....................................................................................6-4Downhole Behavior .................................................................................6-6Cement and Additives .............................................................................6-9Job Considerations ...............................................................................6-10Design Considerations .........................................................................6-11Evaluating Foam Cementing Results....................................................6-13

Section 7: Other Nitrogen Applications

Sand Washing ........................................................................................7-3Unloading Wells .....................................................................................7-7Gas Displacement ................................................................................7-10Pressurizing Medium ............................................................................7-11Commingled Gas ..................................................................................7-12Sand Consolidation...............................................................................7-13Leak Detection Service .........................................................................7-17References ...........................................................................................7-19

Introduction 1-1

Section 1

Introduction

Contents

Foamed Acid ......................................................................................... 1-3Hydraulic Fracturing Stimulation .......................................................... 1-3Foam Cement ....................................................................................... 1-3Other Applications ................................................................................ 1-3

1-2 Introduction

Introduction 1-3

Nitrogen has been used in the wellservice industry for more than 30 years.Nitrogen is an inert gas that allows pres-sure to be applied downhole withoutcausing damage to sensitive formationsurfaces. Nitrogen can be used in welltesting and wellbore cleanout or in creatingfoam fluids to stimulate oil and gas pro-duction. This manual discusses the physi-cal properties of liquid and gaseous nitro-gen, important safety considerations forpersonnel and equipment, and some of themore popular applications for nitrogenfoaming.

Foamed Acid

Foamed acid is a finely dispersedmixture of nitrogen gas bubbles withinhydrochloric acid liquid. Foaming the acidincreases the volume of the active acid andimproves penetration. Foam also helpsdivert fluid from high permeability zonesinto lower permeability zones. Expansionof the gas after treating helps removecreated fines and lessens damage to theconductive fracture.

Hydraulic Fracturing Stimulation

Nitrogen is widely used in hydraulicfracturing stimulation. High quality foamsproduce high viscosity for proppant trans-port. The foam also has a low liquid con-tent to protect formations that are sensitiveto fluids. In addition, Foam helps to control

fluid loss, maximize fracture conductivity,and provide gas expansion to assistflowback. Foam fracturing fluids are espe-cially beneficial for under-pressured ordepleted reservoirs, but have been used inhigh-pressure and high-temperature reser-voirs as well. Foam can also be used inminifrac analysis, aiding in fracture design.

Foam Cement

Nitrogen in foam cement provides ameans of producing very lightweightcement. Foamed cementing slurries in therange of 4 to 15 lb/gal can develop rela-tively high compressive strength in aminimum period of time. Due to the inertcharacter of nitrogen, Halliburton's conven-tional additives can be used in foam ce-ment.

Other Applications

Nitrogen is frequently used in otherapplications such as sand washing, wellunloading, drillstem testing (as a pressuriz-ing medium), sand consolidation, and leakdetection. Halliburton has a variety offluids, additives, and engineering com-puter programs to properly design nitro-gen-assisted service for your well.

Introduction

1-4 Introduction

Nitrogen Properties 2-1

Section 2

Nitrogen Properties

Contents

Introduction .............................................................................................2-3Physical Properties .................................................................................2-4Nitrogen Expansion ................................................................................2-4Nitrogen in Foam ....................................................................................2-4

2-2 Nitrogen Properties

Nitrogen Properties 2-3

Nitrogen Properties

Introduction

Nitrogen (N2) was first introduced to wellservicing in 1956 when it was used as a gascushion to control well flowing pressureduring drillstem tests. Although quantitiesand pressures were limited, this service didallow operators to control well liquids andpressures by using an inert gas.

In 1959, cryogenic transports and pumpswere introduced for use with liquid N2. Thisallowed great volumes of liquid N2 to beconverted to gas and placed in the wellsystem under any combination of pressureand rate that the job might require.

Liquid N2 is readily available at severalindustrial complexes. As a manufacturedbyproduct of industrial gases, it is usually

created during the air separation processused to obtain liquid oxygen.

Because N2 is an inert gas, it cannot reactwith hydrocarbons to form a combustiblemixture. In addition, N2 is only slightlysoluble in water and other aqueous liquids,which allows it to remain in bubble formwhen commingled with these fluids.

Nitrogen is a nontoxic, colorless, andodorless gas naturally found in the atmo-sphere (78% of air is N2). Nitrogen is broughtto the work site in liquid form in cryogenicbottles at temperatures below -320°F (Fig. 2-1). The nitrogen is then pumped through atriple-stage cryogenic pump at a desired rateand forced into an expansion chamber. Theexpansion chamber allows the N2 to absorbsufficient heat from the environment tovaporize into dry gas. The N2 gas is then

212°F

70°F

32°F

-297.3°F Liquid oxygen

-109.3°F CO2 sublimes (dry ice)

-320.4°F Liquid nitrogen

100°C

20°C

0°C

-78.4°C

-183.0°C

-195.8°C

-273.16°C -459.7°F Absolute zero

Cryogenic range

Fig. 2-1: Cryogenic thermometer showing relative coldness of liquid nitrogen.

2-4 Nitrogen Properties

Fig. 2-2: Liquid N2 expands to 696 times its liquidvolume when heated to 70°F.

Liquid Nitrogen Gaseous Nitrogen

Heat

displaced by positive displacement pumpsout of the expansion chamber and down theservice piping to perform the prescribed job.

Physical Properties

Table 2-1 lists some of the physical prop-erties of N2 at atmospheric pressure (14.7 lb/in.2).

Nitrogen Expansion

Nitrogen expands greatly as it absorbsheat from the environment. Nitrogen

expands 696 times its volume in going from aliquid at -320°F to a gas at 70°F, as shown inFig. 2-2.

Nitrogen in Foam

Nitrogen is most often used as the gasphase of foams. Because foam has low fluidloss, low density, low liquid content, andhigh viscosity, it can be used when stimulat-ing, drilling, and cleaning low-pressure andwater-sensitive formations effectively.

Foam quality is the ratio of gas volume tofoam volume at a given pressure and tem-perature. Usually, the pressure and tempera-ture are the same as bottomhole treating orcirculating conditions. To determine foamquality (Qf), use the equation below:

QN volume

liquid volume N volumef =+

2

2 , ... (2-1)

In the 0 to 52-quality range, gas bubblesin the foam are spherical and do not contacteach other. Foam in this quality range hasrheology similar to the liquid phase.

In the 52 to 96-quality range, gas bubblesin the foam interfere with one another anddeform during flow. This causes foam viscos-ity and yield point to increase as qualityincreases. In this particular range, foambehaves like a Bingham plastic fluid, whereyield stress must be overcome to initiate fluidmovement.

Above 96 quality, foams may degenerateinto a mist. The thin liquid layer cannotcontain the larger volume of gas, causing thefoam bubbles to rupture.

The liquid phase of foam can be eitherwater-, methanol-, or hydrocarbon-based.Usually less than 1% foaming agent byvolume is added to generate the foam.

Table 2-1: Physical Properties of Nitrogen

Boiling point -320.36°F

Liquid weight density 6.745 lb/gal

Gas weight density 0.0724 lb/scf

Heat required to convertliquid to 70°F gas

184 btu/lb

Expansion ratio of liquidto gas

1 to 696*

Solubility in water

2.35 parts nitrogen in 100parts water at 32°F

1.55 parts nitrogen in 100parts water at 68°F

* One gallon of liquid nitrogen at -320°F expands to93.11 scf gas at 70°F

Nitrogen Safety 3-1

Section 3

Nitrogen Safety

Contents

Physical Properties .................................................................................3-3Nitrogen in the Air ...................................................................................3-3Cryogenic Thermometer .........................................................................3-3Safety Precautions for Handling Liquid Nitrogen ....................................3-4

Wear protective clothing .............................................................................. 3-4Avoid skin contact ........................................................................................ 3-4

First Aid Procedures for Cold Liquid Frostbite (Freeze Burns)...............3-4Symptoms .................................................................................................... 3-4What to Do ................................................................................................... 3-4What Not to Do ............................................................................................ 3-4

Liquid Air Hazard ....................................................................................3-5Oxygen Deficiency Hazard .....................................................................3-5Liquid Nitrogen Equipment Safety ..........................................................3-5

Cryogenic Materials and Components ........................................................ 3-5Cryogenic Materials ............................................................................... 3-5Cryogenic Components ......................................................................... 3-5

Noncryogenic Material and components ..................................................... 3-5Noncryogenic Material ...........................................................................3-6Noncryogenic Components.................................................................... 3-6

Equipment Precautions ................................................................................ 3-6Pressure Buildup.......................................................................................... 3-6

3-2 Nitrogen Safety

Nitrogen Safety 3-3

Nitrogen Safety

Physical Properties

Below are some of the important proper-ties of nitrogen (N2) at atmospheric pressure(14.7 lb/in.²). The importance of each prop-erty is explained in the following sections.

Boiling point -320°FLiquid density 6.745 lb/galHeat required toconvert liquid to 70°F gas 184 btu/lbExpansion ratio ofliquid to gas 1 to 696*

*One gallon of liquid nitrogen at -320°Fexpands to 93.11 scf gas at 70°F

Nitrogen in the Air

Air contains 78% nitrogen, confirmingthat nitrogen gas is colorless and odorlessand is not toxic or irritating. Nitrogen gasneither burns nor supports combustion, doesnot support life functions, and is a poorconductor of heat, preventing cold liquid N2

from instantly collapsing �hot� pressurebuilding gas. Oxygen is the component of airthat supports combustion and life functions.

Cryogenic Thermometer

The cryogenic thermometer below showsthe extraordinarily cold nature of liquidnitrogen.

Note: Water boils at 212°F, and liquidnitrogen boils at -320°F.

Fig. 3-2: Cryogenic thermometer showing relativecoldness of liquid oxygen and liquid nitrogen.

212°F

70°F

32°F

-297.3°F Liquid oxygen

-109.3°F CO2 sublimes (dry ice)

-320.4°F Liquid nitrogen

100°C

20°C

0°C

-78.4°C

-183.0°C

-195.8°C

-273.16°C -459.7°F Absolute zero

Cryogenic range

Fig. 3-1: Chart showing the amount of nitrogen in theair.

Components of Air

Nitrogen- 78%

Oxygen- 21%

Other- 1%

3-4 Nitrogen Safety

Safety Precautions for HandlingLiquid Nitrogen

Wear protective clothing

� Safety goggles or face shield� Insulated gloves� Long-sleeved shirts� Cuffless trousers

Avoid skin contact

� Liquid leaking from equipment� Cold equipment surfaces

Liquid nitrogen is hazardous! Contact ofhuman tissue with severe cold will destroytissue in a manner similar to high-tempera-ture burns. Freeze burns will result fromcontact with the actual liquid or contact withthe cold surfaces of piping and equipmentcontaining the liquid. An increased dimen-sion of hazard is added when the liquid N2 isunder pressure. These facts emphasize theneed for protective clothing and safety atti-tudes by the nitrogen equipment operator.Safety goggles or a face shield should beworn if liquid ejection or splashing may occuror cold gas may issue forcefully from equip-ment. Clean, insulated gloves that can beeasily removed and long sleeves are recom-mended for hand and arm protection.Cuffless trousers should be worn outsideboots or overshoes to shed spilled liquid.

Liquid N2 causes immediate eye damagethat is usually beyond repair! The severenature of eye injuries emphasizes the extremeimportance of wearing eye protection. Onedrop of liquid N2 to the eyeball could damagethe eyeball instantaneously. For one secondof unsafe practices, someone could be blindfor life.

First Aid Procedures for ColdLiquid Frostbite (Freeze Burns)

Symptoms

� Skin pink just before frostbite devel-ops

� Skin changes to white or greyish-yellow as frostbite develops

� Initial pain that quickly subsides� Victim feels cold and numb; he or she

is often not aware of frostbite

What to Do

� Cover the frostbitten part with awarm hand or woolen material. Iffingers or hand is frostbitten, havevictim hold hand in his or her armpit,next to body.

� Bring victim inside as soon as pos-sible.

� Place frostbitten part in lukewarmwater or warm by air at room tem-perature.

� Gently wrap the part in blankets iflukewarm water is not available or isimpractical to use.

� Let circulation reestablish itself natu-rally.

� When the part is warmed, encouragethe victim to exercise fingers and toes.

� Give victim a warm, nonalcoholicdrink.

What Not to Do

� Do not rub with snow or ice. Rubbingfrostbitten tissue increases the risk ofgangrene.

� Do not use hot water, hot waterbottles, or heat lamps over the frost-bitten area.

Nitrogen Safety 3-5

Liquid Air Hazard

Because oxygen condenses and liquifiesat a higher temperature than nitrogen, airthat has supercooled, from condensing oncold liquid nitrogen equipment surfaces, willrapidly become oxygen-enriched. This con-densed air can contain up to 52% oxygen,causing normally noncombustible material tobecome flammable and normally flammablematerial to burn at an increased rate.

Oxygen Deficiency Hazard

Cold N2 gas will displace warmer aircontaining vital oxygen for breathing. Asseen below, oxygen is necessary for people tofunction correctly. A slight oxygen deficiencyresults in deeper respiration, faster pulse, andpoor coordination. As the oxygen deficiencyincreases, one�s judgment becomes so poor,

he or she may not know to move to a wellventilated area. One full breath of purenitrogen will strip blood of necessary oxygen,resulting in a loss of consciousness. Maintainproper ventilation to prevent asphyxiation.

Liquid Nitrogen Equipment Safety

Cryogenic Materials and Components

Most construction materials are adverselyaffected by extreme low temperatures. It isimperative that the components engineeredfor use in cryogenic service be chosen fromsuitable approved materials.

Cryogenic Materials

� Copper and brass� Stainless steels�300 series� Aluminum (open-ended only and low

psi)

Cryogenic Components

� Inner tank of nitrogen tank� Nitrogen low-pressure piping� Nitrogen fluid ends� Nitrogen high-pressure piping

Noncryogenic Material andcomponents

Most of the components of nitrogenpumping units are constructed of materialsthat cannot withstand cryogenic tempera-tures. Do not expose these components toextreme cold.

Table 3-1: Symptoms of Oxygen Deficiency

Amount of Oxygenin the Air Symptoms

21% Normal

14%Deeper breathingFaster pulsePoor coordination

12%GiddinessPoor judgmentBlue lips

10%

NauseaVomitingAshen complexionApproaching loss ofconsciousness

8%

Death within 8 minutesAt 6 minutes, 50% will dieAt 4 minutes, all will recoverwith treatment

4%Coma in 40 secondsConvulsionsDeath

3-6 Nitrogen Safety

Noncryogenic Material

� Carbon steels� Low-alloy steels� Most rubbers� Most plastics

Noncryogenic Components

� Treating iron� Cryogenic tank casing� Trailer frame� Power train� Structural components� Hydraulic lines� Tires

Equipment Precautions

Treating iron will not withstand cryo-genic temperatures! Allowing liquid N2 inthe carbon steel treating iron is one of themost dangerous mistakes an operator canmake.

Carbon steel becomes brittle at approxi-mately -40°F. When this occurs, any shockcould cause treating iron to break like glass.

Carbon steel cannot withstand rapidcontraction. Nitrogen can shrink the inside oftreating iron so fast that it separates from theoutside, causing severe breaks.

Pressure Buildup

Nitrogen to be used as a gas is oftenstored and transported as a liquid foreconomy and convenience. It is easier topump as a liquid than as a gas. However,there is a continuous, unavoidable, andinexhaustible heat leak into liquid N2. Thisheat increases the temperature of the liquidor boils the liquid at a constant temperature.

Nitrogen expands 696 times its volume ingoing from a liquid at -320°F to a gas at 70°F,as shown in Fig. 3-3. One cubic foot of liquidnitrogen (50.46 lb) at -320°F exerts 0 psi.When this same volume warms to 70°F, itwill exert 42,500 psi while in the same space.As an example of the extremely high pres-sure, 12 ft of 3-in. treating iron full of N2 at10,000 psi has the same energy as 90 lb ofnitroglycerin!

This possible high pressure is whyHalliburton pumping systems are designedusing a primary safety relief valve and a

secondary bursting diskassembly at any placeN2 could be trapped.

Liquid Nitrogen Gaseous Nitrogen

Heat

Fig. 3-3: Liquid N2 expands to 696 times its liquid volume when heated to 70°F.

Foam Applications in Acidizing Stimulation 4-1

Section 4

Foam Applications in AcidizingStimulation

Contents

Acidizing with Foam.............................................................................. 4-3Advantages of Foamed Acid ................................................................ 4-3Foamed Acid Penetration ..................................................................... 4-4

Foam Quality ...............................................................................................4-4Fracture Temperatures ...............................................................................4-5Fracture Width .............................................................................................4-5Pump Rate ...................................................................................................4-6

Foam Stability ....................................................................................... 4-6Foam Diversion ..................................................................................... 4-6

Diverting Agents ..........................................................................................4-7Types of Diversion Systems .......................................................................4-8

Mechanical Systems .............................................................................4-8Chemical Systems ................................................................................4-8Foamed Systems ..................................................................................4-8

Using Foam Diverters—Pointers and Recommendations ........................4-9Commingled Nitrogen and Acid .................................................................4-9

Fracture Acidizing ............................................................................... 4-10Results of Fluid-Loss Tests ..................................................................... 4-10Results of Fracture Flow Capacity Tests................................................ 4-13

References .......................................................................................... 4-15Other References ............................................................................... 4-15

4-2 Foam Applications in Acidizing Stimulation


Foam Applications in AcidizingStimulationAcidizing with Foam

As oil and gas wells age, many of themshow similar characteristics. One of themost obvious is, of course, reducedbottomhole pressure that can contribute tothe formation of paraffins, asphaltenes, andscales. Many old wells have had repeatedacid treatments. Following conventionalacid treatments, large amounts of insolublefines such as quartz, gypsum, and feldsparsmay reduce fracture conductivity. All ofthese factors related to old wells can becontrolled through foamed acid stimula-tion.

Treating wells with characteristics asoutlined above with a conventionalnonfoamed acid treatment will probably bebeneficial. However, the high liquid con-tent of conventional fluids may increaseclay problems. Also, low viscosity of thespent acid may leave a large amount ofinsoluble fines in the well. In addition, lowbottomhole pressure may require swabbingto clean up the well.

Nitrogen (N2) is the most widely usedmaterial in foam treatments. Volumetricgas content (foam quality) is generallybetween 65 and 85% (comprising 65 to 85%gas and only 15 to 35% liquid), althoughqualities as high as 95% have been used.The liquid phase of the foam may contain0.5 to 1.0% surfactant and 0.4 to 1.0% in-hibitor.

Advantages of Foamed Acid

Foamed acid has widespread applica-tions in both oil and gas wells and offersthe following characteristics to virtually

eliminate the problems mentioned in theprevious section:

Low liquid content- Foamed acids usedin fracture acidizing generally range from60 to 80 quality. The low liquid content isextremely important when treating a liq-uid-sensitive formation where largeamounts of liquid may cause swelling inthe formation and reduce the permeabilityof the formation to the produced fluids.

Reduced fluid loss- The high apparentviscosity of the foamed acid results inreduced fluid loss, allowing deeper acidpenetration than a comparable nonfoamedor conventional acid system. In low perme-ability reservoirs, the bubbles of the foammay be sufficient to prevent leak-off to thematrix. This can reduce the affect ofwormholing (channeling). Also, since nofluid loss additive is necessary in lowpermeability reservoirs, there is a reducedchance of impairment of formation conduc-tivity due to the solids in some additives.

High apparent viscosity- Viscosity isdifficult to obtain in a nonfoamed acidsystem since the acid used frequently is notcompatible with the gelling agent. A vis-cous acid provides the advantage of betterpumpability, wider fracture, and improvedfluid loss when used in fracture acidizing.Increasing the viscosity of the acid before itis foamed will give these benefits plus helpto increase foam stability.

Better cleanup- The built-in gas assistderived from using a foamed acid treat-ment now makes recovery of treating fluidsfrom low-pressure reservoirs more effectivethan nonfoamed treatments. The built-ingas assist plus the high apparent viscosityof the foamed acid enable the acid in-soluble formation fines to be returned tothe surface on flow back rather than stay in


the formation where they could hamperproduction. This means a faster cleanupthat reduces liquid damage to water-sensi-tive formations. Also, it may eliminate theneed to swab the well after the treatment.

Improved solids transport- Anotheradvantage of foamed acid is its capabilityto suspend fines. Often in conventionalacid treatments, large amounts of insolublefines such as quartz, gypsum, and feldsparswill be left behind because of the lowviscosity of the spent acid. This may reducefracture conductivity, but with the addi-tional viscosity provided by foaming, moreof these fines are suspended and removedfrom the well during cleanup.

Less formation damage- Foamed acidhas a low liquid content. Normally, foamedacid is 60 to 80 quality. Less liquid contactsthe formation, thus reducing the opportu-nity for damage to occur.

Minimum well shut-in time- Foamedacid treatments should have minimum wellshut-in time after pumping. The foamedacid should be flowed back as soon aspossible following the treatment to reducethe chance of liquid and nitrogen separa-tion. The longer the foamed acid is allowedto remain in a static, nonflowing condition,the easier it is for liquid to drain from thefoam bubbles and for suspended fines tosettle out of the foamed acid.

Better control- Foamed acid also pro-vides better control. Flow can be bettercontrolled by adjusting the amount ofnitrogen, thereby changing the acid�sdensity. Because acid is normally heavierthan the formation water, acid treatmentstend to sink. Foamed acid can be made tostay higher in the fracture by being lessdense than the formation water. Foamingthe acid also helps control the reaction rateby reducing its diffusion. Foam increasesthe viscosity of an acid system, so the acidcan be prevented from entering morepermeable or low-pressure zones. This

allows for more uniform coverage withoutthe use of other diverters. Foamed acid canalso carry any of the conventional divertingsystems such as Perf Pac ball sealers orgranular diverter.

Foamed acid offers other advantages. Ithas less thermal demand, causing lessthermal contraction in the tubing. In coldtreatment conditions, this can save havingto reset the tubing due to tubing shrinkage.Nitrogen-foamed acid systems reduceasphaltene sludge by diluting the concen-tration of carbon dioxide (CO2) formedfrom acid reactions. In addition, foamedacid treatments can be displaced withstraight nitrogen, leaving the hole with nohydraulic column to impede load recovery.

Foamed Acid Penetration

Tests have been conducted to calculatethe effect of various parameters on acidpenetration distance.1 Foamed acid reactionrate tests were performed on a laboratory-prepared fracture. These tests show that thespending of HCl in a fracture is governedprimarily by the mass transfer of the acid tothe fracture wall. This is referred to as a"mass transfer or diffusion" controlledspending. These tests also show that in adolomite formation at low temperaures,the foamed acid spending is primarilycontrolled by the surface reaction kinetics.The effects of various factors on the spend-ing of foamed acid are discussed in thefollowing sections.

Foam Quality

The calculated effect of foam quality onacid penetration distance (defined as thedistance the live acid would travel beforeits concentration is spent to 0.1%) at vari-ous temperatures is shown in Figs. 4-1 and


4-2 for limestone and dolomite, respectively.Four curves are shown representing 60-, 70-,80-, and 90-quality foamed 28% HCl in eachfigure. An increase in foam quality resultsin a decrease in acid penetration distance.The higher the quality of the foam the lowerthe acid content of the foam. The less acidpresent in the foam the lower the foam'srock dissolving power. This is true for boththe limestone and dolomite cases.

Fracture Temperatures

The effect of temperature on acid pen-etration distance in limestone is negligiblein the test calculations. The experimentalmass transfer coefficients were measured at70°F [21.1°C] and assumed to be indepen-dent of temperature. This may be approxi-mately correct as long as the foam texturedoes not change substantially with tempera-

Fig. 4-1: Penetration distance vs. fracturetemperature for limestone.

ture. However, the surface reaction ratedoes change with temperature, but thisreaction already is fast compared to themass transfer to the fracture face in theHCL-limestone reaction.

The dolomite acid penetration distancedoes decrease with an increase intemperture. This is because the surfacereaction rate is the controlling factor. Thesurface reaction rate changes as the tem-perature changes. This effect of surfacereaction rate can be determined experimen-tally by rotating disc tests at various tem-peratures.

Fracture Width

The wider the fracture, the longer it willtake for hydrogen ions to reach the carbonate rock surface. Thus, the acid will travelfarther down the fracture before spending.

Fig. 4-2: Penetration distance vs. fracture temperaturefor dolomite.


This is true for foamed acids as well as fornonfoamed acids. Fig. 4-3 shows this widtheffect.

Pump Rate

If the pump rate is increased and thefracture height remains constant, the dis-tance that the foamed acid will travel downa fracture before spending will increase.This is true in foamed acidizing of bothlimestone and dolomite formations. Theeffect of pump rate is shown in Fig. 4-4.

Foam Stability

Stability of the foam is an importantconsideration. If a foam is stable in spentacid, foam can be returned to the surfacewhen the well is opened, bringing the fineswith it. This also helps improve formationconductivity.

Fig. 4-3: Penetration distance vs. fracture width.

Halliburton's Pen-5, HC-2, and SPERSE-ALL surfactants have been found to beeffective foaming agents providing stablefoams in both active and spent acid systems(see Table 4-1).

Foam Diversion

In most cases, formations will be com-prised of zones possessing differentpermeabilities or zones that may havesustained differing degrees of damageduring drilling, completion, or workoveroperations. When acidizing treatments areperformed on such formations, the treatingfluids naturally enter the zones that presentthe least resistance to flow. This can resultin placing the acid in zones that require theleast stimulation.

Diversion can be used to alter the fluidinjection profile of a treatment. Because

Fig. 4-4: Penetration distance vs. pump rate.


fluids across the entire perforatedinterval, diverting agents such asinsoluble sand, benzoic acid flakes,solid organic acids, deformablesolids, mixtures of waxes and oil-soluble polymers, acid-swellablepolymers, and mixtures of inertsolids (silica flour, calcium carbon-ate, rock salt, oil-soluble resins, etc.)are frequently used to form tempo-

rary filter cakes on the higher permeabilityor least damaged zones. This then forcesthe treatment into the rest of the interval.One concern when using such materials isthat the filter cakes are sometimes slow todissolve in the produced fluids, thus re-quiring remedial treatments for divertingagent removal.

In the mid 1980's, foam was introducedas a diverting agent in place of particulate-type diverting agents for acidizing throughgravel packs. Such foams achieve diversiondue to their high apparent viscosity and theplugging effect of the gas bubbles in thefoam as they enter the pore network of theformation. Diversions have been accom-plished with 60 to 80 quality foam. Thebetter the quality of the foam, the better itsdiverting ability.

Foams possess several distinct advan-tages over particulate diverting agents. Onemain advantage is that since no solidparticles are used, and because foamsdegrade fairly rapidly, the concern aboutdiverting agent cleanup is eliminated. Asecond advantage becomes evident whenacid treatments are performed on gravel-packed wells. If particulate-type divertersare used on such wells, the particles haveto be sized such that they will be able topass through the gravel-pack sand and stillbe able to form a filter cake on the forma-tion. This dramatically limits the types ofmaterial that can be used. Foam, however,easily passes through the gravel-pack sandwhile still providing effective diversion on

Table 4-1: Halliburton Acid Foaming Agents

Agent ChargeTemperature

LimitConcentration

Pen-5 Nonionic 250°F 0.5 to 1%

HC-2 Amphoteric 275°F 0.5 to 1%

SPERSE-ALL Nonionic275°F 0.5 to 1%

275 to 300°F 2%

fluids will choose the path of least resis-tance, diversion is primarily a resistanceproblem; the goal is to alter injection rateper unit of area so that all zones accept theproper proportion of the treatment. Reser-voir properties that can vary the injectionrate per unit of area are permeability,differential pressure, and length; if theseproperties are not in the correct proportion,diversion should be considered. Thisdisproportion can result from the follow-ing:

� zones having differingpermeabilities

� zones having differing formationpressures

� zones containing fluids with differ-ent compressibility

� zones containing fluids with differ-ent viscosity

� zones having natural fracturesA goal of acid treatment is to cause

zones of similar permeability to produce athigher rates by increasing the permeabilityin the critical near-wellbore area. Diver-sion helps reach this goal by forcing acidinto damaged areas to allow the entire zone(assuming near equal permeability distri-bution) to be productive.

Diverting Agents

Diverting agents have been used instimulation treatments for years to helpensure treatment distribution over theentire perforated interval. In order toprovide uniform placement of the reacting


the formation without concern about sizingor cleanup considerations.

Types of Diversion Systems

Three types of diversion systems arepresented herein: mechanical, chemical,and foam. For the purposes of this discus-sion, foams are treated separately fromother chemical systems because they pos-sess several different characteristics.

Mechanical Systems

Mechanical systems may be used tocreate diversion. Examples of such systemsare (1) straddle packers, (2) bridge plugsand packers, and (3) perforation ball seal-ers. More information on mechanical sys-tems may be obtained from the SPE mono-graph, Hydraulic Fracturing (Sections 7.5and 8.8).

Chemical Systems

Some commonly used diverting tech-niques involve chemical systems; however,these are also more difficult systems to useproperly. Chemical diverters can be usedon perforations, in the perforation tunnel,in fractures, and on the formation face.

The choice of chemical diverter to usefor a particular application is determinedby type of production, bottomhole statictemperature (BHST), placement fluids, typeof well completion, and type of treatment.In addition, the chemical diverter chosenusually has these characteristics:

� soluble in production fluids� insoluble or marginally soluble in

placement fluids� relatively inert to other additives

used in the treatment� a melting point above the BHSTThe carrier fluid for a chemical diverter

can be either a brine, an acid, a gel, a hy-

drocarbon, an emulsion, or a foam.If the diverter is soluble in the carrier

fluid, it is important to saturate the carrierfluid with the diverter. Enough excess ofdiverting solid should be used to satisfycarrier fluid solubility of the diverter atbottomhole temperature conditions.

Advantages of chemical divertersinclude low cost and a wide range of appli-cation (perforated, openhole, gravel-packed, and fractured formations). Disad-vantages include uncertain diversion andsecondary formation damage potential.These are examined in the following sec-tions.

Chemical diverters can cause secondaryformation damage. This occurs when adiverter has completely shut off part of azone, and removal of the diverter is depen-dent on producing formation fluids. Disso-lution of the diverter may not occur in areasonable length of time.

Uncertain diversion is one of the majorlimitations of continuous chemical divert-ing in chemical treatments. A diversion ina fracturing treatment can be indicated by apressure surge at the surface. In matrixtreatments, however, solids introduced intothe formation can reduce permeability. Ahigh-permeability zone can act as a lostcirculation zone, diverting the fluid awayfrom the damaged or low-permeabilityzones and into the higher permeabilityzones. This is what diversion is designedto prevent.

Another diversion technique involvespumping an immiscible mixture of twofluids (emulsions or foams). Nonfoamedimmiscible mixtures, emulsions, are difficultto work with because their surface charac-teristics can be dramatically altered by (1)the shear encountered during injectiondown the tubing string and by (2) forcingthe emulsion to flow through formationcapillaries. This is further complicated bytheir high friction pressures in tubing.


Foamed Systems

Foam passes easily through a gravelpack but has difficulty flowing into aformation. Because of this, foam wasintroduced as a diverting agent and hasbeen used successfully in sandstoneacidizing for almost any type of completionor production. Foamed water-based fluiddiverters have been applied either continu-ously or as staged slugs.

Foams have several characteristics thatmake them effective diverting agents. Thephysical nature of foams (bubbles consist-ing of discrete cells) helps control leakoffand limits the reaction rate at any givensite, thus allowing deeper penetration.Foams can flow as liquids and remainmotionless like a solid. Major advantagesof using foam diverters include the follow-ing:

� suitability over a range of pressures,temperatures, and permeabilities

� enhanced treatment flowback� improved gravel transport into

perforations� transportation of released finesFoam quality increases as it flows away

from a wellbore, which is advantageouswhen treating a multizone interval withvarying pressures. In the lower pressurezone, the foam will have higher quality andpotentially more diversion effect. Therelationship among pressure, quality, andviscosity is such that as pressure is lost,quality and viscosity increase (until 90quality is reached).

Foams also exhibit different flow prop-erties as a function of permeability. Thespecific foam diversion technique used in atreatment design depends on individualwell characteristics and the stimulationobjective; therefore, it should be expectedthat foams may exhibit diverting propertiesas a result of differences in permeability orreservoir pressure.

A significant benefit of foameddiverters is their capability to transportreleased fines and insoluble particles out ofthe near-wellbore area during flowback.This property is especially important inunderpressured reservoirs.

Foam slugs (partially foamed treatments)offer the same advantages as using foamedfluids, but at considerably lower cost andless risk of system upsets during treatmentflowback.

Using Foam Diverters—Pointers andRecommendations

� Foams having 60 quality and higherprovide a greater reduction in flowthan lower quality foams. Moreimportantly, the duration of thediversion lasts much longer whenusing foams with 60 to 90 quality.

� In certain types of rock, brine foamsgive more resistance and longerdiversion than acid foams. This ismost prevalent in either high poros-ity and/or high permeability lime-stones.

� Alternating stages of foameddiverter and either nonfoamed orcommingled acid are more effectivethan a single stage of foam diverter.

� Foam effectively diverts acid from anondamaged core to a damagedcore.

� For successful diversion, the differ-ences in zone permeabilities shouldnot be greater than a factor of 10.

� Wormholes play an important rolein acidizing. When there is no fluid-loss control, the distance that anacid will penetrate is controlled bythe development of wormholes.Foamed diverters discourage worm-hole formation because the discretecells help control leakoff and limitthe reaction rate that can occur at


any given site. By not producingwormholes, the acid stays activelonger in the fracture, develops adeeper penetration, and producesmore flow capacity.

Commingled Nitrogen and Acid

When enough N2 is introduced into anacid to impart energy for load recovery andhydrostatic column reduction, but theamount of gas is not sufficient to causebubble bumping, it is not considered afoam. This condition greatly decreases theload recovery time by providing a gasassist. This type of gas addition can also aidin reducing the total weight of the treat-ment column by helping place it effectivelyin low bottomhole pressure wells.

Fracture Acidizing

Use of foam in fracturing treatments hasgained widespreadacceptance. Low liquidcontent, good fluid-losscontrol, and quickcleanup are just a fewreasons why foams arebeing used. Halliburtonhas investigated theeffects of foam quality,foam stability, andchemical compatibilityon fluid loss and fractureflow capacity.2 Theresults are summarizedin the following sections.

Results of Fluid-LossTests

Table 4-2 shows theeffect of foam qualityand two different foam-

ing agents on fluid loss control. Conven-tional 15% HCl channeled through a six-in.core in less than 1 minute and exhibitedlittle or no fluid-loss control. Fig. 4-5shows the face of this core and severallarge wormholes indicating where acidbreakthrough occurred. Fig. 4-6 shows theface of the core across which the 90-qualityfoamed acid, 15% HCl plus 1% foamer, wasflowed for 36 minutes. No fluid loss for 36minutes and the large number of smallholes on the face of the core indicates 90-quality foamed acid gave good fluid-losscontrol. These same results were noted for80-quality foamed acid.

When the quality of this foamed acidwas lowered from 80 to 70, breakthroughoccurred after 18 minutes. At break-through, foam, rather than separate gas andliquid phases, came through the core.Bubble size in this foam was much largerthan when the foam was initially gener-ated.

A 60-quality foamed acid broke through

Table 4-2: Effect of Foam Quality and Foaming Agents upon FluidLoss of Foamed Acid (pressure diff.= 100 psi)

Test SolutionFoam

QualityRock Permeability

to N2 at 110°F (md)Breakthrough

Time (min)36-min N2

Fluid Loss (L)

15% HCl 0 0.85 <1

15% HCl +1% Foamer A

90 0.83 >36

80 0.72 >36

70 0.84 18

60 0.66 7

15% HCl +1% Foamer B

90 1.21 0

90 0.26 0

80 0.63 0

80 0.61 0

70 0.88 0.07

70 1.14 0.69

60 0.69 0.22

60 1.83 0.46


the core in 7 minutes. Tests were repeatedsubstituting a different foamer, and resultsindicated no acid or foam fluidloss occurred for 36 minuteswhen any of these four qualityfoamed acids were tested.However, nitrogen loss didoccur when the 70- and 60-quality foamed acids weretested.

Results show the effect ofchemical compatibility in afoamed acid system. The firstfoamer made a stable foamedacid with 15% HCl, but whenthis foamed acid came in con-tact with a large amount ofspent acid, such as when a 60-or 70-quality foamed acid wasrun, the foam apparently col-lapsed and subsequently brokethrough the core. The secondfoamer appeared to be morecompatible with spent acid thanthe first, so no foam break-through occurred. It is impor-tant that all chemicals used in afoamed acid system be checked

Fig. 4-5: Fluid-loss test core showing effect ofconventional 15% HCl. Note the "wormhole."

Fig. 4-6: Fluid-loss test core showing effect of 90-quality foamed 15% HCl.

Table 4-3: Effect of Foam Quality and Acid Concentrationupon Fluid Loss of Foamed Acid (pressure diff.= 100 psi)

Test SolutionFoam


to N2 at 110°F (md)36 min N2 Fluid

Loss (l)

15% HCl + 1%Foamer

90 1.21 0

90 0.26 0

80 0.63 0

80 0.61 0

70 0.88 0.07

70 1.14 0.69

60 0.69 0.22

60 1.83 0.46

28% HCl + 1%Foamer

90 0.48 0

90 0.41 0

80 0.55 0

80 0.69 0

70 0.47 0.06

70 0.70 0.25

60 0.71 0.20

60 0.78 0.97


Table 4-4: Effect of Acid Type upon Fluid Loss of FoamedAcid (pressure diff.= 500 psi)

Test SolutionFoam


to N2 at 110°F (md)Breakthrough

Time (min)

28% HCl + 1%Foamer

90 0.43 3

90 0.39 3

80 0.53 2

80 0.15 25

80 0.41 2

28% HCl +HAC + 1%

Foamer

90 0.41 4

90 0.37 4

80 0.32 3

80 0.31 2

Table 4-5: Acid-Etched Fracture Flow Capacity withConventional and Foamed 28% HCl

Temperature- 110°F, Pressure- 1,500 psi, Closure Pressure- 1,000psi

Test EtchingTime (min)

Fracture FlowCapacity(md-ft)

Core Removed(in.)

No. 1- 200 ml/min28% HCl

9 9,691 0.044

18 12,960 0.056

27 26,691 0.068

36 40,255 0.088

No. 2- 20 ml/min28% HCl

9 4,833 0.058

18 6,990 0.074

27 7,535 0.091

36 28,409 0.109

No. 3- 180 ml/minN2 + 20 ml/min28% HCl + 1%

Foamer90-Quality Foam

9 17,533 0.066

18 12,329 0.084

27 70,000+ 0.130

36 70,000+ 0.153

tained fluid-loss control for 25minutes before foamed acidbreakthrough. The morepermeable 0.41 and 0.53 mdcores experienced foamed acidbreakthrough in 2 minutes.Increase in differential pres-sure from 100 psi to 500 psichanged the fluid-loss controlof the foamed acid consider-ably. Comparison of thefoamed 28% HCl results fromTable 4-3 with the resultsgiven in Table 4-4 clearlyillustrates the difference.

A similar trend was notedfor conventional acids contain-

ing solid fluid-loss material. With increas-ing pressure differential, it is more difficultto maintain fluid-loss control. One way tohelp minimize the effects of the increasedpressure differential is to stabilize thefoamed acid. This can be accomplished by

for compatibility in spent acid as well as inthe live acid.

Effects of foam quality and acid concen-tration on foamed acid fluid loss are shownin Table 4-3. No acid fluid loss occurred forany of the four qualities of foamed 15%HCl. Nitrogen loss did occurwith the 60- and 70-qualityfoamed 15% HCl. This sametrend was shown when acidconcentrations were increasedfrom 15 to 28% HCl.

Effects of acid type, forma-tion permeability, and pressuredifferential are illustrated inTable 4-4. The two types of acidstudied, 28% HCl and a mixtureof mineral and organic acid,foamed equally well and gavevirtually the same fluid-losscontrol. When foam break-through occurred, bubble sizesof the foams were about equalto the bubble sizes just aftergeneration.

Upon examination of the 80-quality foamed 28% HCl sys-tem, it was noticed that the 0.15md permeability core main-


Table 4-6: Effect of Foam Quality on Acid Etched FractureFlow Capacity



Fracture FlowCapacity (md-ft)

Core Removed(in.)


Foamer,90-Quality Foam

9 17,533 0.066

18 12,392 0.084

27 70,000+ 0.130

36 70,000+ 0.153



9 8,613 0.037

18 21,537 0.070

27 70,000+ 0.139

36 70,000+ 0.175

No.3- 47 ml/minN2 + 20 ml/min28% HCl + 1%


9 12,392 0.036

18 41,464 0.074

27 36,026 0.096

36 27,259 0.120



9 14,678 0.030

18 28,977 0.075

27 38,443 0.097

36 37,234 0.120

increasing the viscosity of the acid before itis foamed.

Both 80- and 90-quality foamed acidsshowed only N2 fluid loss but no acid fluidloss for 36 minutes where previously theybroke through the core in 2 to 3 minutes.Both 60- and 70-quality foamed acidsmaintained fluid-loss control for 10 to 11minutes. Increasing the acid viscosity tohelp stabilize a foamed acid and improvefluid-loss control without the use of wall-building additives is keeping with the ideaof a true foamed acid. Extremely largepressure differentials and large formationpermeabilities may, however, requireadding conventional fluid-loss additives tothe foamed acid system. Fluid loss in high

permeability formations can bereduced by using a pad fluidahead of the foamed acid.

Results of Fracture FlowCapacity Tests

Tests have shown thatfoamed acid can give goodfluid-loss control. However, asuccessful fracture acidizingtreatment does not depend onlyon good fluid-loss control.Adequate fracture flow capac-ity must be established by theacid system used. Quantity ofrock removed and the patternin which it is removed from thefracture faces are important.

Fracture flow capacitydepends on the nature of therock and the volume, type, andconcentration of acid used. Inorder to eliminate some of thevariables, Bedford Indianalimestone was selected as ahomogeneous rock and wastested with one concentrationof acid (28% HCl).

Table 4-5 shows the results of equalvelocities of treating solution as well asequal amounts of acid. Tests No. 1 and 3were both conducted at a total flow rate of200 ml/min. The foamed acid in Test No. 3was only one-tenth the amount of 28% HClas compared to the conventional acid inTest No. 1 and created more fracture flowcapacity. Comparison of Tests No. 2 and 3,which used equal amounts of 28% HCl,indicated that foamed acid created morefracture flow capacity. Also, the foamedacid system removed more core than eitherof the two conventional acid systemstested. It was noted in Test No. 3 that somefracture flow capacity was lost between thefirst and second time intervals. This effect,


called overetching, is quite common inhomogeneous cores where rock is oftenremoved evenly.

Effect of foamed acid quality on fractureflow capacity is shown in Table 4-6. Excel-lent fracture flow capacities were obtainedwhen any of the four qualities of foamedacid were used. Large amounts of corewere also removed in each of the fourcases. Niether 60- nor 70-quality foamedacids obtained the maximum fracture flowcapacity that the 80- and 90-quality foamedacids obtained. Overetching effects werealso more pronounced in the 60- and 70-quality foamed acids.

Foam stability affects acid-etchedfracture flow capacity the same as it affects

Table 4-6: Effect of Foam Quality and Foam Stability onAcid Etched Fracture Flow Capacity



Fracture FlowCapacity (md-ft)

Core Removed(in.)



9 12,392 0.036

18 41,464 0.074

27 36,026 0.096

36 27,259 0.120

No. 2- 47 ml/minN2 + 20 ml/min28% HCl + 1%Foamer + 4%

Foam Stabilizer,70-Quality Foam

9 11,314 0.048

18 30,126 0.067

27 70,000+ 0.076

36 70,000+ 0.087

No.3- 30 ml/minN2 + 20 ml/min28% HCl + 1%


9 14,678 0.030

18 28,977 0.075

27 38,443 0.097

36 37,234 0.120

No. 4- 30 ml/minN2 + 20 ml/min28% HCl + 1%Foamer + 4%

Foam Stabilizer,60-Quality Foam

9 30,695 0.037

18 70,000+ 0.054

27 70,000+ 0.063

36 70,000+ 0.070

fluid-loss control. Acid viscos-ity was increased, and 60- and70-quality foamed acids gener-ated. Table 4-7 compares theseresults. Both 60- and 70-qualityfoamed acids achieved maxi-mum fracture flow capacity andshowed no signs of overetching.Smaller amounts of rock wereremoved from the core faces,but pattern of removal wasmore effective.

These tests show thatfoamed acid achieves betterfracture flow capacity whencompared to conventional acidat equal velocities of treatingsolution as well as equalamounts of acid.


References

1. Ford, W., and Roberts, L.: "The Effect ofFoam on Surface Kinetics in FractureAcidizing," paper SPE 11120 presentedat the 1982 Annual Fall Technical Con-ference and Exhibition of the SPE, NewOrleans, LA (September 26-29).

2. Ford, W.: "The Use of Foamed Acid inFracture Acidizing," paper SPE 9652presented at the 1981 SPE Middle EastOil Technical Conference, Manama,Bahrain, March 9-12.

Other References

Burman, J.W. and Hall, B.E.: �Foam as aDiverting Technique for Matrix Sand-stone Stimulation,� paper SPE 15575presented at the 1986 SPE AnnualTechnical Conference and Exhibition,New Orleans, (October 5-8).

Ford, W., Burkleca, L., and Squire, K.:"Foamed Acid Stimulation: Success inthe Illinois and Michigan Basins," paperpresented at the 1980 Annual FallTechnical Conference and Exhibition ofthe SPE, Dallas, Texas (September 21-24).

Kennedy, D.K., Kitziger, F.W., and Hall,B.E.: �Case Study on the Effectivenessof Nitrogen Foams and Water ZoneDiverting Agents in Multistage MatrixAcid Treatments,� paper SPE 20621presented at the 1990 SPE AnnualTechnical Conference and Exhibition,New Orleans (September 23-26).

King, G.E.: "Foam and Nitrified FluidTreatments�Stimulation Techniquesand More," paper SPE 14477presentedas a Distinguished Lecture during the1986-86 Distinguished Lecturer Pro-gram.

Thompson, K. and Gdanski, R.D.: �Labora-tory Study Provides Guidelines forDiverting Acid with Foam,� paper SPE23436 presented at the 1991 SPE EasternRegional Meeting, Lexington, Kentucky(October 22-25).

Williams, B.B., Gidley, J.J., and Schechter,R.S.: Acidizing Fundamentals, SPE/AIME monograph, Vol. 6., Dallas, 1979.


Foam Applications in Hydraulic Fracturing Stimulation 5-1

Section 5

Foam Applications in HydraulicFracturing Stimulation

Contents

Introduction .............................................................................................5-3Types of Foams Used in Hydraulic Fracturing .......................................5-4Foam Rheology.......................................................................................5-4Crosslinked Foams .................................................................................5-5Foam Fluid Loss .....................................................................................5-7

Fluid-loss Coeffecients ................................................................................ 5-8Test Results of Factors Affecting Foam Performance ................................ 5-8Test Conclusions ....................................................................................... 5-12

Fracture Conductivity ............................................................................5-12Proppant Pack Permeability ...................................................................... 5-12

Proppant Grain Size............................................................................. 5-12Effective Closure Stress ...................................................................... 5-12Multiphase Flow Effects .......................................................................5-13Fracturing-Fluid Residue Damage .......................................................5-13

Filtercake Buildup ...................................................................................... 5-13Treating Pressure Response ................................................................5-14

Constant Internal Phase ............................................................................5-15Increased Proppant Concentration ............................................................5-17Field Treatment Results of Constant Internal Phase ................................5-17Conclusions................................................................................................5-22

Fluid Recovery ......................................................................................5-22Treatment Designs for Hydraulic Fracturing .........................................5-22

PROP Hydraulic Fracture Design Program ...............................................5-22FracPac II ................................................................................................... 5-24

Candidate Selection ............................................................................. 5-24Wireline Logging ..................................................................................5-25Formation Strength .............................................................................. 5-26Fracpressure Log .................................................................................5-26Perforating............................................................................................5-26Fracture Design.................................................................................... 5-263-D Fracture Design Simulator ............................................................5-29Prefracture Testing .............................................................................. 5-29Downhole Tools ...................................................................................5-30Example Procedure .............................................................................5-30

5-2 Foam Applications in Hydraulic Fracturing Stimulation

Minifractures .........................................................................................5-31Minifracture Analysis Technique ................................................................ 5-31

Analysis Theory.................................................................................... 5-31Minifracture Test Results ...........................................................................5-33

Well Data.............................................................................................. 5-33Minifracture Fluids ................................................................................ 5-33Treatment Fluids ..................................................................................5-33

Conclusions ..........................................................................................5-34References ...........................................................................................5-34Additional References ..........................................................................5-35

Contents (cont.)


Foam Applications in HydraulicFracturing Stimulation

Introduction

Foams are being used in a number ofpetroleum industry applications that exploitthe foams' high viscosity and low liquidcontent. Some of the earliest applications forfoam dealt with its use as a displacing agentin porous media and as a drilling fluid.Following these early applications, foam wasintroduced as a wellbore circulating fluid forcleanout and workover applications. In themid-1970�s, nitrogen- (N2) based foamsbecame popular for both hydraulic fracturingand fracture acidizing stimulation treatments.In the late 1970�s and early 1980�s, foamedcementing became a viable service, as didfoamed gravel packing. Most recently, carbondioxide (CO2) foams have shown usefulnessin hydraulic fracturing stimulation.

The early widespread use of foams asfracturing fluids was to help low-pressuregas reservoirs in returning the liquid phase ofthe foam. The internal phase of the foamtypically consisted of 65 to 80% by volume(quality) of N2 gas, with an external phase ofwater and a foaming agent (surfactant). Thesesimple N2 foam fluids, coupled with thepumping technology of the 1970�s, were ableto transport sand concentrations of 1 to 2 lb/gal [120 to 240 kg/m3] into fractures. Suchlow proppant concentrations gave beneficialresults in low-pressure sandstone, carbonate,and shale reservoirs. Much of the success ofthe early treatments was due to the capabilityof N2 gas to expand and remove substantialquantities of the liquid phase from the reser-voir. Gelling agents were not originally used,so no gel filtercakes were formed to damageproppant beds.

With the success of simple N2 foams inlow-pressure gas reservoirs and the develop-ment of high-pressure N2 pumping equip-ment, the application of foam fluids wasextended to higher pressure gas reservoirsand oil wells. These zones placed additionalrequirements on foam fracturing fluid, suchas higher viscosity, better leakoff control,higher temperature stability, and greaterproppant carrying capacity.

The need for higher viscosity was met byusing water soluble polymers, such as guarand hydroxypropyl guar (HPG) gellingagents, to increase viscosity of the liquidphase and the foam. Adding gelling agentsserved to improve fluid leakoff control bybuilding a thin gel filtercake on the face of thefracture. Higher temperature stability wasimproved by the development of surfactantsthat were capable of stabilizing foams togreater than 392°F [200°C].1

Mechanical improvements in high-pressure slurry pumping equipment allowedsignificantly higher concentrations of prop-pant in slurries to be pumped. By 1980,technology had developed to the point thatmassive hydraulic foam fracturing treatmentswere conducted that placed over 1 million lb[454,000 kg] of sand at concentrations up to 4lb/gal [480 kg/m3] in a formation with atemperature of 270°F [130°C].2

Deeper reservoirs were made accessiblewith the introduction of CO2 foams. CO2,pumped into the wellbore as a liquid, has agreater density than N2 gas, allowing surfacepumping pressures to be lower than with N2

for a corresponding depth. CO2 foams areformed when reservoir temperatures warmthe fluid to above the critical temperature ofliquid CO2. The resulting mixture of gaseous


CO2 with water is considered to be a foam,but the density of the CO2 remains high aslong as pressure is maintained. The structureof CO2 foams is similar to N2 foams, but theproppant transport capability of CO2 foams isinherently greater because of its higherbouyancy.

As the number of treatments using CO2

increased, it became apparent that the frictionpressure of CO2 foams was higher than for N2

foams, especially in the high concentrationproppant stages. In an effort to overcomehigh friction problems, a new method ofproducing sand-laden foams was developed.The technique of constant internal phase heldthe liquid phase volume constant whilebalancing the sum of gas plus sand to equalthe desired internal phase volume.3

Delayed crosslinked gelled fluids wereintroduced as fracturing fluids in the early1980�s, and these crosslinking agents weresoon applied to producing crosslinked N2

foams. The higher viscosity produced bycrosslinking the gelling agent in the foamproduced higher viscosity foam fluids thatwere able to place higher proppant concen-trations than noncrosslinked foams.Crosslinking of CO2 foams was introduced ata later date and extended the advantages ofCO2 foams to deeper, hotter reservoirs.4

Proppant concentrations as high as 12 lb/gal[1,440 kg/m3] have been successfully placedwith crosslinked CO2 foams using the con-stant-internal-phase technique.

Throughout the development of foamfracturing fluids over two decades, foamfracturing fluids have been used in liquidsensitive formations because of their capabil-ity to minimize liquid contact with the reser-voir and their capability to rapidly recoverthe majority of the treatment fluid. Eventhough the cost of foam treatments is typi-cally 10 to 20% greater than nonfoamedcrosslinked stimulation treatments, quickfluid recovery and minimal damage to thereservoir have given foamed fluids a place

among the leaders in number of treatmentsperformed. This section presents some of thetechnical benefits of foam as a minimaldamage fluid for fracturing.

Types of Foams Used in HydraulicFracturing

A wide variety of liquid phases areavailable for N2 foam fracturing. The baseliquids include water, water-alcohol mixtures,and hydrocarbons. Water is the most eco-nomical liquid phase available. When water-sensitive clays are likely to be encountered,salts, such as potassium chloride or Cla-StaTM

additives may be used to help protect suchclays. Adding up to 50% alcohol will furtherreduce potential clay swelling. Alcohol alsolowers the surface tension of the liquid andhas a higher vapor pressure to aid in produc-ing back the frac fluid.

Maximum protection against formationdamage can be realized by using a hydrocar-bon foam. Suitable oils for N2 foam fracturingwould include diesel and condensates. Leasecrude oils should be laboratory tested forfoamability prior to field usage. Foam genera-tors may be desirable when fracturing withhydrocarbon foam or any of the gelled sys-tems.

Foam Rheology

The viscosity of a fracturing fluid isimportant because of its influence in creatingfracture geometry and in transporting prop-pant. Adding linear polymers or crosslinkedpolymers to water increases its viscosity.Viscosity of the fluid mixture is also in-creased by adding N2 or CO2 gas to create aninternal phase (gas bubbles), when a stabiliz-ing surfactant (foaming agent) is present.


High viscosity foam fluids can be preparedusing low amounts of water and gellingagents, thereby minimizing the liquid loadplaced on a formation.

Foam rheology has been described by anumber of investigators using various fluidmodels. Work by Mitchell,5 using ungelledwater foamed with N2, characterized foam asa Bingham plastic fluid, having a positiveyield stress at zero shear rate. Foams contain-ing polymers have been described by severalmodels,6 including power law and yield-pseudoplastic.

Foam viscosity depends on a number ofvariables, including quality, viscosity of theexternal phase, and texture. The most impor-tant parameter is foam quality�the percentvolume occupied by the internal gas phase.Since gas volume is a function of temperatureand pressure, downhole conditions must beknown. As quality increases, foam viscosityincreases. In addition, the yield point charac-teristics of foams are an exponential functionof quality.

Higher quality foams have better trans-port properties, particu-larly at very low shearrates, because of highyield points. The viscouscharacter of the externalliquid phase is also amajor parameter. Flow ofhigh-quality foam may bevisualized as gas bubblessliding past one anotheron thin films of the liquidexternal phase. If theliquid film contains aviscosifying agent, thenthe bubbles will undergogreater drag forces be-cause of the viscous thinfilms, and flow will bemore difficult, resulting inhigher bulk viscosity.Texture, or the bubble

size distribution, plays an important butlesser role in determining foam viscosity.Foams exposed to shear for a sufficient timewill equilibrate to a bubble size distributionthat is characteristic of that shear rate. Tex-ture is also influenced by the surfactant thatmust be present in sufficient concentration tostabilize the foam under dynamic condi-tions.7,8

Crosslinked Foams

Foams containing polymers that havebeen crosslinked are more viscous than foamswithout crosslinking. An example is given inFig. 5-1 of CO2 foams containing 0.48% of aguar derivative. The foam containing poly-mer crosslinked with zirconium has approxi-mately twice the viscosity of thenoncrosslinked foam. Crosslinked N2 foamscan be generated with any of the typicallyused polymer-crosslinking agent combina-tions since N2 is considered chemically inert

Fig. 5-1: Viscosity of gelled foams—0.48% linear and crosslinked polymers.


and does not interfere with crosslinkingchemistry. Combinations would include guarand guar derivatives with aluminate, borate,titanate, and zirconate crosslinking agents.Crosslinked CO2 foams must be formed withpolymer-crosslinking agent combinationsthat are active in the pH range of about 3 to 5because of the strongly acidic pH effect ofCO2 on the aqueous external phase. Forexample, borate crosslinked foams cannot bemade with CO2 since a pH above 8 is re-quired to crosslink guar with borate.

Several differences exist between the typeof fractures created by crosslinked andnoncrosslinked foams. Crosslinked foamshave higher proppant carrying capacity thannoncrosslinked foams because of their higherviscosity. Proppant is easier to transport intothe fracture since a wider fracture is createdby the more viscous crosslinked foam. Since awider fracture is created, the fracture will beshorter for a given volume of fluid pumped.A shorter, wider fracture has less total frac-ture area created, meaning less surface areaexposed to fluid leakoff. The fluid-loss coeffi-cients for crosslinked and noncrosslinkedfoams are similar for the same leakoff area, sothe total leakoff with crosslinked foams isless. Lower overall leakoff, coupled withwider fractures, means that proppant place-ment with crosslinked foams is easier toaccomplish than with noncrosslinked foams.

Gel filtercakes generated with crosslinkedfoams are about as thin as noncrosslinkedfoams, 0.004 in. [0.10 mm]. Although suchthin filtercakes cause minimal occlusion ofproppant pack conductivity, the chemicalcharacter of the residue is still crosslinkedand is harder to remove than noncrosslinkedlinear polymers.

Compressible foams are structured, two-phase fluids that are formed when a largeinternal-phase volume (typically 55 to 95%) isdispersed as small, discrete entities through acontinuous liquid phase. Under typicalformation temperatures of 90°F [32.2°C]

encountered in stimulation work, the internalphases exist as gas and hence are properlytermed foams in their end-use application. Attypical surface conditions of 75°F [23.9°C]and 900 psi [6,205 kPa], N2 is a gas, but CO2 isa liquid. A liquid/liquid two-phase struc-tured fluid is classically called an emulsion.The end-use application of the two-phasefluid, however, normally is above the criticaltemperature of CO2. Evidence shows thesimilarity of two-phase structured fluidsindependent of the state of the internal phase.The liquid phase typically contains a surfac-tant and/or other stabilizers to minimizephase separation (bubble coalescence).

These dispersions of an internal phasewithin a liquid can be treated as homoge-neous fluids, provided bubble size is small incomparison to flow geometry dimensions.Volume percent of the internal phase within afoam is its quality. The degree of internal-phase dispersion is its texture. At a fixedquality, foams are commonly referred to aseither fine or coarse textured. Fine texturedenotes a high level of dispersion character-ized by many small bubbles with a narrowsize distribution and a high specific surfacearea, and coarse texture denotes largerbubbles with a broad size distribution and alower specific surface area.

Because foams exhibit shear-rate-depen-dent viscosities in laminar flow, they areclassified as non-Newtonian fluids. In addi-tion to shear rate, their apparent viscositiesalso appear to depend on quality, texture,and liquid-phase rheological properties.Measured laminar-flow apparent viscositiesgenerally are larger than those of eitherconstituent phase at all shear rates. When theliquid phase is thickened by adding solids,soluble high-molecular-weight polymers, orother viscosifying agents, even larger foamviscosities are produced.

While laminar flow is characterized bystrictly viscous energy dissipation, turbulentflow is characterized more by kinetic than


viscous energy dissipation. Density andvelocity are the factors that establish kineticenergy, and reduced foam density mayoutweigh an increased viscosity contributionand produce a turbulent-flow friction loss lessthan liquid-phase friction loss. Soluble high-molecular-weight polymers produce a formof turbulent drag reduction that is analogousto that which occurs in a nonfoamed liquid.In this case, a substantial drag reductioneffect is evident when one compares theturbulent flow friction loss of foams with andwithout a gelled liquid phase.

Foam Fluid Loss

Good fluid-loss control is important increating fracture geometry and transportingproppant into the fracture. Fluid loss fromnonfoamed gelled fracturing fluids may beunderstood as the loss of water into forma-tion capillaries at an initial rate determinedby the permeability of the rock matrix. Aswater is lost from thegelled fluid, polymer(filter cake) graduallyforms on the formationface. Once a gel filter cakehas been deposited, thepermeability of the filtercake is lower than thepermeability of the forma-tion, so the filter cakecontrols further loss ofwater to the formation.Linear gel and crosslinkedgelled fluids typicallydeposit filter cakes about0.03 to 0.04 in. [ 0.75 to 1.0mm] thick under dynamicconditions in the labora-tory.9

Gel filtercakes are alsodeposited from foamed

fluids that contain gelling agents, but thefilter cakes are much thinner. Filter cakesdeposited in the laboratory from linear gelfoams and crosslinked foams typicallyranged between 0.0016 to 0.006 in. [0.04 to0.15 mm].10 Even though the deposited filtercake is less thick, the overall fluid leakoff ratein matrix with foams is still less than withnonfoamed fluids. The reason for the lowerleakoff rate is that bubbles of gas from thefoam enter the formation matrix and impedethe loss of liquid. Two-phase flow in porousmedia is slower than single phase flow. Aplot of overall fluid-loss coefficient vs. matrixpermeability is shown in Fig. 5-2.

A thinner filter cake represents less gelmass to block produced fluid flow after thetreatment has been completed. Regainedpermeability tests on 0.1 to 0.3 md coresindicated 87 to 95% of the original matrixpermeability was regained after exposure tofoamed fluids. Fracture conductivity studiesof proppant packs indicated that 80 to 100%of baseline conductivity was measured aftertreatment with linear gelled foamed fluids.11

Fig. 5-2: Foam fluid-loss coefficient for gelled external phase.


Crosslinking the gelling agent in a foamreduced regained conductivity compared tolinear foam, but crosslinked foams still hadhigher conductivity than nonfoamedcrosslinked fluids. The capability of bothformation matrix and proppant pack to flowfluids at rates near their undamaged capaci-ties is a measure of the clean character offoamed fluids.

Fluid-loss Coeffecients

Foam has been established as a successfulfracturing fluid for several years. Claimsabout its efficiency in fluid leakoff controlhave ranged from excellent to virtually noleakoff at all. Yet treatment experience hasindicated that foam fractures occasionally doscreen out.2 Because excessive fluid leakoff isone potential cause of a premature job termi-nation, an adequate knowledge of fluid-losscoefficients is essential for proper design ofstimulation treatments.

Foam has been described previously as anonwall-building fluid.12 Such a fluid shouldhave leakoff properties described by Howardand Fast13 as

C k pI = 0 0469. /∆ φ µ , .......................... (5-1)

where k is permeability (darcies), ∆p ispressure drop (psi) across the matrix, φ isfractional porosity, and µ is viscosity (cp).There is a problem with calculating CI forfoam, however. Because foam is a two-phasestructured fluid and because some of thebubbles may be able to enter the pores of therock matrix, the rheology of foam in porousmedia is not well defined. The expansion ofbubbles in the foam caused by pressure dropcan be significant.

A fluid-loss coefficient can be determinedempirically without knowledge of the fluidviscosity by the equation from Howard andFast:13

CIII = 0.0164 m/Ac , ...................................... (5-2)

where m is the slope of an experimentalplot of fluid volume vs. the square root oftime and Ac is the cross-sectional area of thefilter medium in square centimeters. CIII isuseful for wall-building fluids, but CI isintended for nonwall-building fluids. Fornonwall-building fluids, the slope of theexperimental plot of filtrate volume will belinear with time, rather than with the squareroot of time.

The majority of foam fracturing treat-ments performed contain a viscosifier tostabilize the liquid phase, typicallyhydroxypropyl guar (HPG), that has wall-building character.

Test Results of Factors Affecting FoamPerformance

Foam fracturing fluid may experiencemany conditions during a fracturing treat-ment. Both foam-fluid and rock-matrixvariables may affect fluid-loss characteristics.A series of experiments were conducted toexamine how several variables may effectfoam performance. Some results of theseexperiments are presented and discussed.

Permeability of the rock matrix had asignificant effect on fluid-loss characteristics,as indicated in Fig. 5-3. The overall effectshowed CIII for foam increases one order ofmagnitude for an increase of two orders ofmagnitude in permeability. Some variations,dependent on foam texture and rock porestructure, might be expected from this trend.For example, a given bubble size may be ofproper size to plug small holes in low-perme-ability rock but may be too small to blockflow into much larger pores in high-perme-ability rock. Foam texture, which was notexamined as a variable, was controlled onlyby the generation technique used in thisexperiment.


The amount of gel present in the liquidphase also had a significant influence on CIII

(Fig. 5-4). Previous studies concluded thatfoam is not a wall-building fluid.12 This studyalso found that foam containing no gel in theliquid phase is not a wall-building fluid.However, foam containing 10 lb HPG/1,000gal [1,198 g/m3] or more in the liquid phasedoes form a wall. The gel layer could beobserved visually on the core face after test-ing. The semipermeable barrier controlled anumber of the variables investigated.

There was a slight effect of core length onfluid loss with no gelpresent. Yet when 20 lbHPG/1,000 gal [2,397 g/m3] was present in theliquid phase of the foam,varying core length from0.15 to 1.87 in. [0.38 to4.75 cm] produced noeffect on fluid loss (Table5-1). In addition, the effect

Fig. 5-3: Foam fluid-loss coefficient at 75°F with liquid phases containing 20 lbHPG/1,000 gal.

Table 5-2: Effect of Pressure on Fluid-Loss Coefficient

High/Low Pressure(psi)

HPG concentration

0 lb/1,000 gal 20 lb/1,000 gal

700/200 0.00274 0.00122

1,200/200 0.00518 0.00134

1,200/700 -- 0.00136

of differential pressurewas minimized with gelin the foam. However,with no gel present, foamfluid-loss increasedsignificantly with in-creases in differentialpressure (Table 5-2).

A moderate increasein fluid loss was observedwhen the core tempera-ture was increased from75 to 200°F [24 to 93°C].The effective increaseprobably was caused bythe thinning of the liquidphase of the foam bytemperature (Fig. 5-4).

No significant effectswere observed when

Table 5-1: Effect of Core Length onFluid-Loss Coefficient

Liquid phase contains 20 lb HPG/1,000 gal

Length (in.) CIII

0.15 0.00128

0.30 0.00122

0.45 0.00111

0.62 0.00122

1.87 0.00118


Fig. 5-4: Effect of core temperature and gel concentration on foam fluid-losscoefficient in 0.3-md sandstone.

foaming agents were exchanged in water-based foams. The differences in fluid-losscharacteristics between anionic and nonionicsurfactants were insignificant. The addition ofup to 50% methanol in the liquid phase alsodid not change fluid-loss properties. Oil-based foam with no gel was comparable to awater-based foam with no gel. Therefore,fluid loss is controlled more by the texture ofthe foam and viscosity of the liquid phasethan by whether the liquid phase is water,alcohol, or oil.

Most of the foams were tested at 75quality. In one experimental series, qualitywas varied at 65, 70, 75, and 80 in a foamcontaining 20 lb HPG/1,000 gal [2,397 g/m3](Table 5-3). No effect was observed whenquality was changed, indicating that the gellayer was controlling leakoff.

The effluent discharged from the coresdid not have the same composition as thefoam impinging on the cores. The mechanismof foam flow through porous media de-scribed by Holm is of a continuous, moving,

external liquid phase anda discontinuous, internalgas phase moving dis-cretely or by rupture ofthe gas cells.14 Thismechanism would besensitive to the viscosityof the liquid phase. Aviscous liquid phaseshould flow slowly andexhibit less liquid lossthrough porous mediarelative to a thin liquidphase.

The effect of gelling-agent concentration oneffluent quality is shownin Fig. 5-5. Effluent vol-umes for gas and liquidwere averaged and quali-ties calculated for foamswith 0, 20, and 40 lb

HPG/1,000 gal [0, 2,397, and 4,793 g/m3].The Ohio sandstone curve represents moredata and should be more reliable than theother samples. The higher-permeabilityBandera sandstone showed a similar trendeven though fewer data points were avail-able. In general, the liquid-loss relative to gasin a foam fluid was greater when low-viscos-ity liquid phase were used. In all cases, theeffluent quality was lower than the originalfoam quality. The numerical value of effluent

Table 5-3: Effect of Foam Quality onFluid-Loss Coefficient

Liquid phase contains 20 lb HPG/1,000 gal

Foam Quality CIII

65 0.00126

70 0.00119

75 0.00123

80 0.00119


Fig. 5-5: Quality of fluid passing through Ohio and Bandera cores vs. gelconcentration of liquid phase.

Table 5-4: Gas Permeability Regained in 4 Hours

Foam TypeOriginal Permeability

(md)Regain (%)

Water 0.3 91 to 93

50% Methanol 0.3 92 to 95

50 lb HPG/1,000 gal 0.13 87 to 91

quality was probably influenced by volumeexpansion of gas bubbles passing from highto lower pressure through the core. Thisexpansion ratio is probably greater in thelaboratory test core than in an actual stimula-tion.

Because foams containing polymers arewall-building fluids, the potential exists fordamage to original matrix permeability. Anumber of sandstone cores were tested forpermeability to nitrogen gas regained afterthe tests with foam. Table 5-4 lists regainedgas permeability ranging from 87 to 95% ofthe original gas permeability after 4 hours offlowback. The data show nosignificant difference betweenfoams containing 0 to 50 lbHPG/1,000 gal [5,991 g/cm3]in the liquid phase. Thisindicates minimal permeabil-ity damage caused by foamfracturing fluids. Measure-ments of filter-cake deposi-tion reported elsewhere

indicate that thinner filtercakes formed from foamsthan from linear gel orcrosslinked gel fluidstested under comparabledynamic conditions.10

Because foams contain agelling agent only in theliquid phase, there is lessgelling agent availablefor deposition than fromnonfoamed gelled fluids.

The values reportedhere have been used todesign successful foamfracturing treatmentssince 1981. Typical foamfracturing fluids havefluid-loss control compa-rable to gelled orcomplexed fluids forpermeabilities near 1 md.

Based on field experience, the screenoutpotential appears similar for foams andcrosslinked-gel fluids.

In core permeabilities higher than 1 md,foam fluids still exhibit fluid-loss control,although solid additives may be helpful toachieve adequate leakoff control. Typicalfoam fracturing fluids have improved fluid-loss control in core permeabilities lower than1 md.


Test Conclusions

1. Foam fracturing fluids that containHPG in the aqueous phase are wall-building fluids.

2. The fluid-loss coefficient, CIII , isdependent on permeability, gelconcentration in the liquid phase, andtemperature of the core.

3. For foam fluids containing gel, littleeffect on CIII was observed by thevariation of core length, foam quality,foam agent, or type of liquid phase.The effect of differential pressure wasminimal.

4. For foam fluids with no gel, fluid lossis dependent on core length anddifferential pressure across the core.

5. The composition of the fluid passingthrough the core differs from the foamimpinging on the core. Effluentcomposition is enriched in the liquidphase and is dependent on the con-centration of gel in the foam.

6. Regained-gas-permeability testsindicate minimal damage caused byfoam fracturing fluids.

Fracture Conductivity

Proppant Pack Permeability

Many factors influence the effectiveproppant-pack permeability (kf): proppantgrain size, effective closure stress acting onthe proppant pack and formation face,multiphase flow effects, and fracturing-fluidresidue damage.

Proppant Grain Size

The permeability of a lightly stressedproppant pack is a function of the porosity of

the pack, φ, and the mean diameter of theproppant grains, d50:

k df ∝ 502 5φ , ................................................... (5-3)

Notice the importance of the proppant-pack porosity. In addition, a wider grain-sizedistribution of a given d50 reduces the perme-ability�hence the modern tendency tomarket narrow sieve fractions, with a biggermean grain size within a given nominal meshrange. For gas wells, non-Darcy (�turbu-lence�) flow effects in the propped fractureresult in an extra pressure drop, ∆pt:

∆pt ∝

ρνµ

β ν , ....................................... (5-4)

where v is the fluid flow velocity and βthe non-Darcy flow factor, which is depen-dent on kf.

Non-Darcy flow effects calculated fromGuppy et al.15 for typical hydraulically frac-tured gas wells can reduce the effectivefracture conductivity by more than a factor of3.

Effective Closure Stress

The fracture conductivity dependence oneffective closure stress (minimum in-situstress minus pore pressure) cannot be as-sessed theoretically; empirical relations basedon extensive proppant conductivity measure-ments over a wide range of conditions arerequired. The majority of these measure-ments have been carried out on the mostpopular proppant size (20/40 mesh) with lowliquid flow rates (negligible non-Darcy floweffects) at low temperature and short mea-surement times. Limited data are availablefor measurements with gas. The most recentmeasurements were conducted at reservoir


temperature with long measurementtimes.16,17 Significantly lower proppant con-ductivities are measured for realistic reservoirconditions than reported for the early short-term conductivity tests. Lack of reproducibil-ity of absolute-permeability measurementsbetween the various laboratories plagues thisarea of research because standard proceduresfor preparation-in particular pack porosity-have not been agreed on.

The high closure stresses encountered indeeper wells require the use of artificial(intermediate- or high-strength) proppants toimprove fracture conductivity. The recentlong-term measurements discussed show atechnical need for these stronger (and there-fore more conductive) proppants at lowerclosure stresses (shallower depth). This isalso true if coarser proppant sand grades areused in an attempt to increase fracture con-ductivity because crushing occurs at lowerclosure stress.

Multiphase Flow Effects

Proppant-pack conductivity is normallymeasured with single-phase flow. Adding asecond or third phase reduces the effectiveproppant-pack permeability to the originalphase significantly. A proppant-pack perme-ability decreases by more than a factor of 5 ifwater-saturated gas (two phases) flowsthrough the pack.

Fracturing-Fluid Residue Damage

The fracturing fluid is an essential part ofa hydraulic fracturing treatment. It createsthe fracture in the reservoir and transportsthe proppant. The fluid is very viscous andshows a controlled (restricted) formationleakoff to ensure an efficient fracturingoperation. Fracturing fluids often include abreaker to reduce their high viscosity to lowvalues to facilitate cleanup. Types of fractur-ing fluids include water-based fluids, oil-

Table 5-5: Global Ranges for Proppant-Pack-Conductivity Retention Factors

Type Range

Foams >80 Best

Polymer emulsion fluids 65 to 85

Gelled oils 45 to 70

Linear gels 45 to 55

Crosslinked HPG 10 to 50 Worst

based fluids, emulsions, and foams. Fractur-ing-fluid residue in the proppant pack andfilter-cake buildup at the rock surface reducefracture conductivity.

Crosslinked fracturing fluids result inmore residue than polymer emulsion fluids.Laboratory tests with the latter fluids yieldloose proppant grain pack that is virtuallyresidue-free.18 By contrast, use of crosslinkedfluids produces a proppant pack containing alot of fibrous material between the grains,which are then �glued� together.

Filtercake Buildup

During the fracturing operation, as high-pressure fracturing fluid leaks away into theformation, a polymer and fluid-loss additivefilter cake is formed. The filter-cake thicknessis determined by the particular fracturingfluid used, the formation characteristics, thefracture-to-reservoir pressure difference, andthe erosional effects caused by slurry beingpumped along the fracture faces. Duringfracture closure, the proppant is embeddedinto the filter cake, making it difficult toremove the cake during production. A typicalfilter-cake thickness of 0.13 in. [0.5 mm] oneach fracture wall will completely block athin fracture propped with two layers of 20/40-mesh proppant. Such filter cakes occur, forexample, when crosslinked fluids are usedwith diesel added as a fluid-loss agent.


Polymer emulsion fluids do not give signifi-cant filter-cake buildup.

Table 5-5 shows the global ranges thathave been published for proppant-pack-conductivity retention factors with gas as thecleanup fluid.16,18 The most important vari-ables that influence these ranges are thespecific fracturing fluid, the fracture width (inparticular when thick filter cakes are formed),and the cleanup (reservoir) fluid.

Proppant permeability damage bycrosslinked fluids substantially depends onthe filter-cake buildup. It is minimized by useof an effective viscosity breaker; this is par-ticularly necessary in shallow (low-tempera-ture) formations. An inadequate breakerleads to virtually complete loss of the prop-pant-pack conductivity. On the other hand,aggressive breaker schedules (short breaktimes) can provide high retention factors inexcess of 80%. Such aggressive breakerschedules, however, can result in excessiveproppant settling in the fracture beforeclosure. A proper balance is required.

Polymer emulsion fracturing fluids helpbecause conductivity recovery is less sensi-tive to breaker efficiency. However, surfac-tants used in these fluids sometimes makethe proppant pack oil-wet. Retained effectivepermeability to water (2% KCl brine is oftenused in tests) is much lower in such cases, aslow as 30% in some cases.

Proppant-pack conductivity increases thenon-Darcy flow (turbulence) factor. Thisturbulence factor needs to be accounted forwhen optimum hydraulic fracture stimula-tions for gas wells are designed.

Foam fluids contain only one-third toone-fourth the amount of water as anonfoamed fracturing fluid. Even though thislesser amount of water represents less poten-tial damage to the formation, the water stillneeds to be removed to minimize damage tothe formation. Controlled flowback proce-dures are important for any fracturing treat-

ment, and they are especially important forfoam fluids.

The common practice for flowback offoam fluids has been to wait from 30 minutesto 4 hours before opening the wellheadvalves to a small production choke. Morerecent techniques include opening the wellimmediately at a low rate. A properly stabi-lized foam fluid structure will remain intactwith high viscosity after 4 hours underdownhole conditions. Common enzyme oroxidizing breakers reduce only the viscosityof gelling agents and do not directly attackthe stabilizing surfactants. Reduction ofpressure at the wellbore will cause somemigration of fluid, carrying proppant backtowards the wellbore.

Experience of most foam flowbacks hasbeen that little proppant is produced if theflowback rate is kept low. The fact that solittle proppant is produced indicates that theformation has closed near the wellbore,trapping the proppant and forming a bridgeto prevent further production of proppantfrom the fracture. If high flowback rates areused, a proppant bridge may not be formedor else be eroded, and significant amounts ofproppant can be produced with the potentialto harm the formation, wellhead equipment,and personnel.

Treating Pressure Response

The pumping pressure experienced at thewellhead during a stimulation treatment isthe result of several factors:

pw = pbht + ppf - ph ,....................................... (5-5)

where pw is wellhead pumping pressure(psi), pbht is bottomhole treating pressure(psi), pf is fluid friction pressure in tubulargoods (psi), ph is hydrostatic pressure (psi/ft),and ppf is perforation friction (psi).


Table 5-6: Fluid Velocity Change for1-bbl/min Fluid Rate Change

Tubular ConfigurationVelocity Change

(ft/sec)

4.892-in. ID casing 0.72

4.00-in. ID casing 1.07

2.992-in. tubing 1.92

2.441-in. tubing 2.88

2.375-in OD x 4.892-in. IDtubing/casing annulus

0.94

Table 5-7: Hydrostatic Pressure of 70 Quality N2 and CO2Foam Fluids at 100°F, 5,000 psi, Containing Sand

Sand (lb/gal) N2 Foam (psi/ft) CO2 Foam (psi/ft)

0 0.226 0.411

2 0.302 0.472

4 0.367 0.523

6 0.422 0.567

8 0.470 0.606

10 0.512 0.639

12 0.548 0.667

The bottomhole treating pressure (BHTP)is a function primarily of formation stressesplus pore pressure. BHTP may increaseduring a treatment as a result of laminar-flowfriction within the fracture.

Fluid friction in turbulent flow down thetubular is a function of flow rate, tubulardiameter, fluid density, and fluid viscosity. Achange in flow rate of 1 bbl/min has a rela-tively small effect of velocity in casing, but ithas a larger effect in small tubing (Table 5-6).The use of high pumping rates, small-diam-eter tubing, high sand concentrations, high-quality foams, and high gel concentrationsfor high foam viscosity all increase pf.Reidenbach et al.19 gave a correlation forturbulent-flow frictionpressure of foams. Theyprovide a relationshipdeveloped from N2 foamdata, but the equationworks satisfactorily withCO2 or proppant if theproper density is used.

Perforation friction isimportant when thenumber of perforations islimited to restrict fluidflow to certain zones. Thefield examples cited here

did not use limited-entry design, so ppf will beconsidered negligible.

The hydrostatic weight of the fluid col-umn helps reduce the surface pumpingpressure required to fracture the formation.N2 foam fluids always have a lower densitythan water. The density of CO2 foams will besignificantly higher than that of N2 foams andsimilar to that of water. The addition ofproppant has a large effect on pH, especiallyat latter proppant stages. Table 5-7 shows theeffect of sand on hydrostatic pressure.

Constant Internal Phase

The observation of high friction pressuresfor foams pumped down small tubing re-quired re-examination of the structure offoam fracturing fluids. For nonfoamed frac-turing fluids, when proppant is added to thefluid, the proppant causes no major change inthe viscous character of the fluid. Foam,however, is a two-phase structured fluid,consisting of a gaseous �internal� phase anda liquid �external� phase. Discrete gaseousbubbles are surrounded by a continuous, thinliquid coating. The viscosity of the foam fluidis a function of the foam quality, as shown inFig. 5-6. �Quality� is the ratio of gas volumeto gas-plus liquid volume at a specific tem-perature and pressure. A similar viscosity


Fig. 5-6: Apparent viscosity of CO2/water two-phase fluid as a function of CO2

quality.

Liquid Liquid Liquid Liquid Liquid

Gas Gas GasGas Gas

Solid

Solid Solid

Conventional Constant-Internal-Phase

A B C D E

Fig. 5-7: Diagram of fluid ratios for conventional and constant-internal-phase design.

relationship exists for two-phase liquid/liquid emulsions. As the percentage of inter-nal phase increases in a two-phase fluid, thefluid viscosity increases.

When a solid proppant particle is addedto a two-phase foam, it is readily apparentthat a solid particle cannot become part of thecontinuous liquidphase. Rather, itmust exist as adiscrete entity,alongside the gasbubbles, Becausethe solid particlesoccupy volume,they produce theeffect of increasingthe quality andhence the viscosity.Although theaddition of prop-pant to anonfoamed gelledfluid may increase

viscosity slightly, addingit to a high-quality foamwill cause a larger in-crease in viscosity. Forexample, addition of 1lb/gal [120 g/m3] sand toa 40 lb/1,000 gal [4,793g/m3] linear gel willincrease the viscosity by 5cp at 100 seconds-1.Addition of 1 lb/gal [120g/m3] sand to a 70-quality, foamed, 40 lb/1,000-gal [4,793-g/m3] gelwill increase the viscosityby 14 cp at 100 seconds-1.To maintain a constantviscosity fracturing fluid,the balance between theinternal and externalphases must be keptconstant, hence the term

�constant internal phase.�Fig. 5-7 illustrates the concept of constant

internal phase. Fluid A is a conventionalfoam pad fluid (no proppant) containing afixed volume of gas and liquid. Fluid B is aproppant-laden fluid with solid added whilegas and liquid volumes are held constant.


During a fracturing treatment, these volumesare pumped in a given time, so the ratios alsorelate to pumping rates. The volume ofinternal phase (gas plus solid) in Fluid B isgreater than that of Fluid A, although theliquid is constant, and would result in higherviscosity and a higher downstream rate. Thiscondition has often led to excessive frictionlosses, higher wellhead pressures, and pre-mature job termination. An attempt to reducesolid, liquid, and gas rates proportionally tomake the downstream rate the same as thepad does not solve the overall problem.Although the ratios in Fluid C are the sameas in Fluid B, the internal phase ratio of FluidC is higher than that of Fluid A, so the viscos-ity of Fluid C is higher than that of Fluid Aand will give higher friction pressure. Inaddition, adjusting all three ratios increasesoperational difficulty.

An example of the viscosity increasecaused by proppant addition may be calcu-lated.5 Addition of 5 lb/gal [599 g/m3] sandto a 70-quality foam containing 40 lb/1,000-gal [4,793 g/m3] base gel will increase theinternal-phase fraction to 75.6%. The appar-ent viscosity of the fluid will increase from325 to 445 cp at 40 seconds-1.

A solution was proposed to keep bothdownstream flow rate and viscosity constant.When solid proppant is added, a constantliquid rate should be maintained but the gasflow rate should be decreased sufficiently toequal the absolute solid flow rate. Applica-tion of the constant-internal-phase concepthas allowed much better control of foamfracturing treatments down small tubing,especially with CO2.

Increased Proppant Concentration

The constant-internal-phase design hasallowed higher proppant concentrations to bepumped than conventional foam designs. Ina foam stimulation treatment, sand is notadded directly to the foam fluid but to the

liquid phase in the usual manner at a blenderunit. The resulting slurry goes through high-pressure pumps and any additional surfaceequipment and approaches the wellhead.High-pressure N2 or CO2 is added just beforethe wellhead and dilutes the sand concentra-tion by several-fold. Standard field blendingequipment can routinely handle proppantconcentrations of 20 lb/gal [2,397 g/m3] atlow fluid rates, and higher concentrations arepossible for short periods. Following conven-tional foam design, where proppant is notconsidered part of the foam, a 67-qualityfoam would be limited to about 7 lb/gal [839g/m3] sand downhole. However, use of theconstant internal-phase design decreases N2

or CO2 as proppant concentration is in-creased. Therefore, the dilution effect of thegas is less, and higher downhole proppantconcentrations may be reached. For example,starting with a 70-quality foam pad, proppantconcentrations of 12 lb/gal [1,438 g/m3] havebeen placed successfully during foam stimu-lation treatments.

A potential disadvantage of constant-internal-phase design is that the fluidpumped last contains less gas to assist influid return. Even in nongas-assist fluids,however, the easiest fluid to recover is thefluid pumped last. The fluid in greatest needof gas assist is the first fluid pumped. There-fore, the constant-internal-phase design losesvery little potential for fluid recovery byreducing gas during the latter proppantstages.

Field Treatment Results of ConstantInternal Phase

Field simulation treatments consideredhere were pumped down one of three tubularconfigurations: casing, annulus, or tubing.Surface pressure responses for foam fluidsmay differ for each configuration. Table 5-8lists examples of treatments according totubular configuration. The numbers were


Table 5-8: Treating Information for Conventional andConstant-Internal-Phase N2 and CO2 Foams

Fig.Fluid

(quality) Type*Volume

(1,000 gal)Proppant

(lb x 1,000)Depth

(ft)Tubular ID

(in.)Rate

(bbl/min)Pressure

(psi)

8 75/67 N2 Conv 41 71 6,200 4.892 15 3,800

9 70 N2 CIP 130 306 10,000 4.000 20 4,800

10 70 CO2 CIP 67 72 9,800 4.892 25 5,000

11 76/67 N2 Conv 33 70 5,600 2.375 x4.892**

13 4,000

12 75 N2 Conv 76 128 10,000 2.992 14 7,500

13 70 CO2 Conv 86 144 10,100 2.992 15 5,600

14 70 CO2 CIP 57 104 9,500 2.992 15 6,300

* Conv= conventional; CIP= constant internal phase** Annular space between 2.375-in. tubing and 4.892-in. casing

reproduced from actual treatment pressuresand rates collected by data-acquisition com-puters on location.

The first example in Fig. 5-8 is a conven-tional N2 foam treatment down 6,200 ft of 5.5in. casing. A 75-quality foam pad was initiallypumped, followed by 67%quality sand-laden fluid.The wellhead pressureincreased throughout thepad but declined as sandwas added, increasing thehydrostatic weight of thefoam column. Once thefoam column stabilized inthe wellbore, pumpingpressure remained stableuntil the sand additionwas stopped. Pumpingpressure then increasedfrom 3,400 psi for sand-laden fluid to 3,900 psi forneat foam owing to loss ofhydrostatic weight.

Fig. 5-9 shows anexample of a constant-internal-phase N2 foamtreatment down 10,000 ft

of 4.5-in. casing.The smaller diam-eter casing andhigher foam rateshould show morepronounced fric-tion effects thanthe previousexample. Duringtreatment, thedownhole foamrate including sandwas increased by10% from thedesigned 10 bbl/min. As sandconcentrationsincreased from 1 to

7.5 lb/gal [120 to 899 g/m3], the pumpingpressure dropped stepwise from 6,000 to4,500 psi. When sand feed was stopped andthe foam slurry was flushed from the casing,wellhead pressure increased by 2,000 psibecause of the loss of hydrostatic pressure of

Fig. 5-8: Conventional 75/67-quality, N2 foam pumped down 6,200 ft of 5 1/2-incasing.


Fig. 5-9: Constant-internal-phase, 70-quality, N2 foam pumped down 10,000 ftof 4 1/2-in casing.

sand. The small differences in fluid frictionpressure between Figs. 5-8 and 5-9 are over-shadowed by hydrostaticeffects resulting from theproppant.

Fig. 5-10 gives anexample of constantinternal-phase CO2 foamtreatment down 9,800 ft of5.5-in. casing. This ex-ample shows the controlof clean gel, liquid CO2,and proppant rates togive a constant downholefoam slurry rate. Theclean-gel rate remainedconstant and the CO2 ratedecreased as the proppantrate increased. The pump-ing pressure rose to amaximum by the end ofthe pad stage but steadilydecreased as the added

proppant increased thehydrostatic weight of thefluid column.

Fig. 5-11 shows anexample of a conventionalN2 foam fracturing treat-ment down 5,600 ft of2.375 x 4.891 in. annularspace. Wellhead-pressurerise during a 75-qualityfoam pad was followedby a pressure declineupon switching to sand-laden 67-quality foam.The slight decline wascaused by the combinedeffect of slightly lowerfoam viscosity and in-creased hydrostaticpressure with addedsand. During later sandstages, wellhead pump-

ing pressure increased in spite of increasedhydrostatic weight. Fluid friction pressure, as

Fig. 5-10: Constant-internal-phase, 70-quality, CO2 foam pumped down 9,800 ftof 5 1/2-in. casing.


Fig. 5-11: Conventional 75/67-quality, N2 foam pumped down 5,600 ft of 2 3/8x 5 1/2-in. annulus.

Fig. 5-12: Conventional 75-quality, N2 foam pumped down 10,000 ft of 3 1/2-in.tubing.

calculated from Eq. 1 increased from 666 psiin the pad to 776 psi in the 3-lb/gal proppantstage to 984 psi in the 4.5-lb/gal proppant stage.This treatment ended in asandout.

Fig. 5-12 gives anexample of conventionalN2 foam treatment down10,000 ft of 3.5-in. tubing.A pumping pressure of7,500 psi was establishedduring the pad andcontinued into the earlysand stages. During thelater sand stages, thehydrostatic weight in-crease caused by theadditional sand did notoffset the increase infoam-slurry frictionpressure, so wellheadtreating pressure (WHTP)rose to more than 9,000

psi. From the upwardtrend in treating pressure,an imminent sandoutmight have been expectedbut did not occur. If alower maximum allow-able treating pressure hadbeen set for this well (e.g.,if lighter wellhead equip-ment or lighter tubinghad been used), thestimulation treatmentwould have been stoppedprematurely and notcompleted.

Fig. 5-13 shows anexample similar to that inFig. 5-12. In this case aconventional CO2 foamtreatment was pumpeddown 10,100 ft of 3.5-in.tubing. The pumping

pressure began to rise as soon as sand wasadded to the foam. The friction pressure of


Fig. 5-13: Conventional 70-quality, CO2 foam pumped down 10,100 ft of 3 1/2-in. tubing.

Fig. 5-14: Constant-internal-phase, 70-quality, CO2 foam pumped down 9,500 ftof 3 1/2-in. tubing.

sand-laden 70-quality CO2 foam has oftenbeen reported as being higher than that of N2

foam, and the 3,500 psirise in pressure comparedwith the previous casetends to confirm thisreport. One might suspectan imminent sandout inFig. 5-13, but such wasnot the case.

Fig. 5-14 demonstratesthe corrective action that aconstant-internal-phasedesign can have overconventional foam design.A 70% constant-internal-phase CO2 foam treat-ment was pumped down9,500 ft of 3.5-in. ODtubing. Table 5-9 gives thepumping schedule for thetreatment of Fig. 5-14.Note that the clean-gelrate remained constant,

while the slurry rateincreased and the CO2

rate decreased. TheWHTP was very wellbehaved. Both wells inthis formation had anearly constant pressureresponse during injectionof the CO2 foam pad.Once sand additionbegan, the treating pres-sure of the conventionaltreatment of Fig. 5-13 roseat a substantial rate withincreasing proppantaddition, whereas thetreating pressure for theconstant internal-phasetreatment of Fig. 5-14actually declined withproppant addition.

Although theses areonly a few examples, they are consistent withfield experience that WHTP�s are more


Table 5-9: Constant-Internal-Phase Design for CO2 Foam Injected Down9,500 ft of 2.992-in. ID Tubing

StageFoam Volume

(gal)Proppant

(lb/gal)Clean-Gel

Rate (bbl/min)Slurry Rate

(bbl/min)Liquid CO2

Rate (bbl/min)

1 25,000 0 4.50 3.50 10.56

2 5,000 1 4.50 5.15 9.93

3 5,000 2 4.50 5.75 9.34

4 7,500 3 4.50 6.29 8.80

5 10,000 4 4.50 6.80 8.31

6 5,000 5 4.50 7.27 7.84

evenly controlled with a constant-internal-phase design, especially in treatments at highflow rates down small tubing.

Conclusions

The use of the constant-internal-phasedesign has proved successful for foam treat-ments. The design technique provides for adecreasing N2 or CO2 rate as proppant rate isincreased. Because all internal phases areconsidered to be the same, higher proppantconcentrations of up to 12 lb/gal [1,438 g/m3]have been placed successfully and with bettercontrol of wellhead pumping pressure thanin conventional designs.

Fluid Recovery

The relationships between the productiv-ity improvement factor, Fp, obtained byhydraulic fracture stimulation and the dimen-sionless fracture conductivity, CfD, of thepropped fracture have been published byPrats.20 CfD is proportional to proppant-packpermeability, kf, and fracture width bf:

CfD ∝ kfbf, ........................................................ (4)

The fractureconductivitymay be in-creased byenlarging thepropped fracturewidth, bf, byapplication ofhigh proppantconcentration.This has becomepopular duringthe last fewyears.

A dimen-sionless fracture conductivity (CfD) of 15 is aproper design value for (pseudo-) steady-state flow conditions. This value is often notachieved in practice. Moreover, the fractureconductivity found from production-testinterpretation on hydraulically fracturedwells is often an order of magnitude smallerthan expected.

Tight reservoirs with high initial transientproduction rates require higher dimension-less fracture conductivities than indicatedabove because these transient rates can lastfor more than one year and significantlycontribute to the economic success of thefracturing treatment. More sophisticatedtools, such as type curves or reservoir simula-tors, are required to assess optimum fractureconductivity in these cases.

Treatment Designs for HydraulicFracturing

PROP Hydraulic Fracture DesignProgram

Halliburton�s premier hydraulic fracturedesign program, PROP, has many featuresand options that allow good engineeringdesign of most stimulation processes. For


Table 5-10: PROP Foam Fracture Treatment Design Methods

OptionTotalRate

LiquidRate

CleanQuality

InternalPhase

Fraction

Proppant'sVolume is-

0 Varies Constant Constant Varies Added to

1 Constant Constant Varies Constant Added to

2 Constant Constant Varies Constant Included in

3 Constant Varies Constant Varies Added to

example, PROP offers four methods of de-signing a foam fracture treatment by directdata entry and output, as shown in Table 5-10.

Modifications, such as binary foam andvariations on the above �standard� options,are readily accommodated by PROP.

The output of PROP assists designers,customers, and operators in completing asuccessful job by including functional infor-mation such as rates for components andproppant schedules as a function of time onthe job. Options include choosing outputs topresent foam quality at bottomhole statictemperature as specified or calculated.

Other features include the following:� Options to specify foam rates and

qualities (internal-phase fractions) (1)in the fracture adjacent to the perfora-tions (at calculated perforation tem-peratures and BHTP), (2) at the frac-ture tip (at BHST and BHTP), (3) at anestimated average fracture tempera-ture, or (4) at a user-selected tempera-ture.

� Allows differing qualities or internal-phase fractions (IPF) from stage tostage.

� Allows differing injection rates fromstage to stage.

� Design calculations may be made by avariety of different techniques (con-

stant internal-phase fraction,constant clean quality, etc.).Note: because the calculationsallow qualities or IPF�s to bespecified separately for eachtreatment stage, the programis flexible enough to allowdesign using almost anymethod of proportioning thecomponents (�gas,� liquid,and proppant); some tech-niques are simply moreautomatic.� Foam friction and hydro-

static calculations are made along thelength of the wellbore so as to (1)convert specified downhole rates andqualities into component rates atsurface or standard conditions (i.e.,pressures and temperatures), and (2)help determine fluid temperature atthe perforations.

� Up to five tubing/casing strings canbe considered.

� Proppant is considered in the frictionas well as hydrostatic calculations.

� Perforation friction is considered. Theuser is allowed to specify the perfora-tion discharge coefficient as well asthe number of (open) perforations.

� �Gas� requirements for the treatmentare calculated.

� N2 foam and CO2 treatments may bedesigned.

� For proppant settling calculations, asettling velocity correlation is used.One consequence of this calculation isthat if the gravitational forces on theproppant particles are sufficient toovercome the yield stress of the foam,settling is predicted to occur; other-wise, it is not.

� Foam rheology is modeled using thethree-parameter Herschel-Bulkleymodel. The values of n�, K�, and τ0 aredetermined from the correlations


developed byReidenbach19 etal. that takeinto consider-ation the gel-phase rheologyand the com-position of theinternal phase(N2 or CO2).The rheologicalparameters canchange notonly fromstage to stage,but with timeand tempera-ture as theproperties ofthe externalphase (i.e.,base gel) change.

Notes: A few of the mentioned featuresare not available at the moment, butwill be available in the next majorrelease of the PROP program (now inpreliminary testing).

FracPac II

A Halliburton FracPac II treatment isdesigned to create a short, wide, and highlyconductive fracture that will enhance hydro-carbon production in poorly consolidatedformations. FracPac II can help alleviatepermeability damage and sand migrationproduction barriers. FracPac II also offersadvantages over conventional gravel-packtreatments by avoiding near-wellbore dam-age and providing longer term, more success-ful, sand/fines migration control. FracPac IIstresses the use of modern technology fordesign and job execution.

Two reservoir properties commonlyassociated with poorly consolidated rocks arelow Young�s Modulus and high permeability.

FracPac takes advantage of both parameters.Low values of Young�s Modulus allow forrelatively wide fracture widths, as comparedto more stiff, or higher modulus, rocks.Combining tip screenout with a low Young�sModulus helps create maximum fracturewidth. High permeability allows significantfluid leakoff during the screenout mode,resulting in an increased concentration ofproppant in the fracture at the end of the job.The result is a maximum amount of proppantplaced per square foot of fracture area. Thiscounteracts the effect of permeability damageand improves sand control.

Candidate Selection

The FracPac II process can be applied toreservoirs where the rock is anticipated tofail, leading to sand production. Assessmentof the failure mechanisms for a given reser-voir will supply information critical for asuccessful design. Core samples and pressureanalysis, along with drilling and/or comple-tions records, should be analyzed. With

Fig. 5-15: The pressure drop near the wellbore, due to radial convergence anddamage, can initiate formation failure. FracPac II technology focuses on minimizingthis pressure drop for a given flow rate.

∆ pskin

∆ p(flow convergence)

r xs f

Radius

Pressure

pi


adequate information, the hydraulic fracturethat is necessary to prevent failure can bedesigned.

Reservoir candidates should have apermeability of sufficient magnitude (nor-mally > 5 mD) so that fracture conductivity ismore important than fracture length. Thefollowing list represents conditions thatwould make a well suitable for a FracPac IItreatment:

� Reservoir rock that fails due to highpressure drawdown developed nearthe wellbore (Fig. 5-15)

� Reservoir rock that fails due to porecollapse

� Reservoirs that have a history of sandproduction

� Reservoirs that require restrictedproduction rates to prevent sandmigration

� Reservoirs that are overpressured,resulting in the sand being poorlycompacted

� Formations that tend to have waterconing problems

� Gravel-packedwells that have lostproductivity due topore collapse (Fig. 5-16)� Poorly consoli-dated reservoirsexhibiting permeabil-ity damage fromdrilling/completionsfluids

Factors that willadversely affectselection of a candi-date well are thelocation of oil/watercontact or gas/oilcontact. These shouldbe considered whentreating a specificzone. Low stress

contrast of boundary layers may result in toomuch height growth. The manner in which awellbore is perforated may have a negativeimpact upon a treatment. Wellbore tubularsmust be of sufficient strength to withstandthe execution of the job. As with any comple-tion, the quality of the cement job, both inbonding quality and TOC, should be exam-ined for possible inter-zonal communication.

Wireline Logging

Knowing key rock properties is essentialfor a successful design. Wireline logging datashould be used to obtain this data if labora-tory analysis is not available. The optimumsituation would occur when logging informa-tion is available to correlate with laboratorytests. The recommended suite of logs follows:

Open Hole Logging� Full wave sonic log/Dipole sonic� Density log� Formation tester

Cased Hole Logging

Time

Productivity

Normal decline

FracPac II treatment

Apparent gravel-

Regravel pack

pack failure

Fig. 5-16: Productivity decline, which may appear to be due from gravel pack failure,may actually result from pore collapse. A FracPac treatment would be the only wayof reaching past this type of formation damage.


� Full wave sonic cased hole tool/Dipole sonic (the quality of the ce-ment bond will affect the efficiency ofthe tool in this case)

The post processing of this informationprovides the following logs:

Formation Strength

This log calculates the drawdown neces-sary to cause rock failure and sand produc-tion. The Mohr-Coulomb failure model isused. Information from the sonic and densitylogs are used in this analysis. For cased holelogging, values from a previously run densitylog must be used, or estimated from othersources.

Fracpressure Log

The Fracpressure log calculates the leastprincipal horizontal stress. In addition to thestress profile, a complete listing of all thecritical rock properties are presented. Theseinclude Young�s Modulus, lithology, watersaturation, average interval pressures, andfracture barrier identification. The formationtester, used to measure pore pressure, in-creases the accuracy of stress calculations. Forcased-hole logs, the value of pore pressuremust be estimated.

Stress data, from the Fracpressure log,can be input directly into the FracPac IIdesign simulator.

Perforating

The manner that a well is perforated mayaffect a FracPac treatment. The phasing of theperforations and wellbore deviation throughthe pay are two of the most critical factors. Ifthe option is open as how to perforate thereservoir for a FracPac candidate, this portionof the design should be carefully studied.

For vertical completions, multiple phaseperforating (other than 0/180° phasing) will

most likely result in a high percentage ofholes taking little or no sand during thetreatment. At the least, this will necessitate agravel pack to be incorporated following theFracPac. If the gravel pack fails to excludefines from entering the wellbore from un-treated holes, the success of the FracPac maybe obscured. The recommended approach forvertical wells is to perforate with 0/180°phasing. Preferably, the phases would be inline with the direction of fracture orientation.

For deviated and horizontal wellbores,attention must be given to the fact thatmultiple fractures can be formed (Fig. 5-17).Unless the axis of the wellbore is closelyaligned with the maximum principal horizon-tal stress, multiple fractures will likely occur.The result of this is premature screenouts.The recommended approach, for wells drilledin the direction of the minimum horizontalstress, is to cluster the perforations within a1- or 2-ft section to increase the likelihoodthat a one-fracture system will develop.

Fracture Design

To obtain a successful FracPac II design,the following parameters must be considered:

� Fracture geometry� Tip screenout� Fluid loss� Injection rate� Proppant selection� Proppant concentration� Proppant embedment� Fluid viscosityConcerning stimulation, fracture length is

not as important as the permeability contrastbetween the fracture and formation. Fracturelength should be adequate to extend beyondnear wellbore damage and the area whereradial convergent flow occurs. In many cases,a fracture length of 30 to 50 ft [10 to 16.4 m]may be quite adequate for successful results.

There may be circumstances whereincreased fracture length is required to obtain


Fig. 5-17: For deviated wellbores, especially those that are horizontal, the relationship of the principal stresses willhave a major impact upon fracture initiation.

sufficient fracture width for proppant place-ment. Also, if pore collapse is anticipated aspressure is depleted (causing permeabilityreduction), fracture length should be ex-tended. Once fracture length becomes impor-tant for stimulation purposes, and can beeconomically justified from productionimprovement, the process should be consid-ered as a fracturing job rather than a FracPac.

Fracture width needs to be maximized.The goal is to place the highest possibleamount of proppant per square foot offracture area. Fluid viscosity and pressureincrease from tip screenout are the factors

that will govern fracture width. The proppedfracture width should be close to the createdwidth.

It would be best for the fracture height tobe limited within the zone of interest. Accu-rate stress logs, used with a simulator, willserve to estimate the effect of boundarylayers on height growth. In the absence ofstress barriers, a penny-shaped fracture canbe expected. In this case, treatment volumewould control height growth. Fracture lengthand height would maintain a constant pro-portion.


Fluid loss at the fracture wall can make itdifficult to maintain fracture extension. Forpermeable formations, a fluid efficiency of 10to 20% is quite common. As the area of thefracture grows, the total leakoff may actuallyincrease to the point that it equals injectionrate. Increasing the injection rate, maximizingfluid viscosity, and using fluid-loss additiveswill help improve the fluid efficiency. Ofthese options, changing injection rate willhave the greatest impact on fluid efficiency.However, this option may also result inundesirable height growth and increase thejob cost. High fluid loss will provide thebenefit of being able to pack the fracture withsand during the screenout mode.

Proppant selection should focus uponmaximizing the permeability of the proppedfracture, especially near the wellbore. For agiven production rate, drawdown will de-crease as flow capacity in the fracture in-creases (Fig. 5-15). For permeable formations,it is very difficult to obtain sufficient flowcapacity to change the radial pattern of fluidflow to the wellbore. To do so requires sig-nificant concentrations of large proppant.

When sand/fines migration is initiated atreduced drawdown, the proppant will needto be selected based upon the sieve analysisof the formation. Normally a proppant size isdetermined by multiplying the mean diam-eter of proppant grains (d50) of the formationsieve analysis by five or six. This will result ina flow capacity that is less than optimal.However, the surface area over which theformation is screened will be much largerthan with a gravel pack.

The job should be designed to reach highproppant concentrations early in the job.Maximum concentration will need to bebased on numerous factors including rate,fluid type, and field experience. High prop-pant concentrations will minimize the vol-ume of fluid lost to the formation to obtain apacked fracture. If for some reason screenout

does not occur, the existing proppant concen-tration will offer significant benefits.

The use of PropLok coating system ishighly recommended. This curable resin,added on-the-fly at the blender tub, willalleviate flowback problems associated withhigh proppant concentrations and low clo-sure stresses. PropLok may also reduceproppant embedment and provide an addi-tional way of controlling sand migration.

Proppant embedment will reduce thepropped fracture width significantly in manyinstances. Narrow propped frac widths mayactually allow the fracture to heal. This is anadditional reason for maximizing frac widthand placing as much proppant as possibleper unit area of fracture.

The fluid used for a FracPac will needadequate viscosity to create a wide fractureand place the proppant. The 60 to 80 lb/1,000gal [7.2 to 9.6 kg/m3] linear HEC gels popularfor gravel packing will work for FracPacpurposes. Other fluid systems, such asBoraGel/Hybor Gel, PUR-GEL, and KleenGel II, will offer superior viscosity. Often, thisis accomplished at a reduced cost.

As formation permeability increases, thedeeper the fracturing fluid invades into thefracture wall. Also, stabilized fluid-losscontrol is reached earlier in time as perme-ability increases. There are indications thatcomplexed gel systems may aid fluid-losscontrol and reduce the depth of invasion atthe fracture face.

The use of N2 or CO2 foam should also beconsidered for FracPac treatments. Foamfluids may act to control excessive leakoffwithout the aid of additional fluid-lossadditivies. Less liquid is available to causepermeability damage at the fracture face.Improved flow capacity, in the proppedfracture, can be expected due to less polymerusage. The gas phase of the foam may alsoact to aid in fluid recovery.


3-D Fracture Design Simulator

The FracPac 3-D Fracture Design Simula-tor program uses planned screenout as a wayto place large amounts of proppant persquare foot of fracture area. Injecting prop-pant-laden fluid into the formation willcontinue after tip screenout has begun. Thejob will continue until a predeterminedincrease in bottomhole pressure is reached.The simulator tracks changes in fracturegeometry and proppant placement. Forma-tion characteristics and pumping scheduleare required to be input by the user. A netincrease in bottomhole pressure must also beentered.

The program provides for three stressoptions. The first option is to enter an aver-

age stress for the upper boundary and onefor the lower boundary. The second option isto enter stress vs. depth pairs for the bound-ary layers. The third option is for the simula-tor to directly read stresses from digitizedfull-wave sonic log data files.

Prefracture Testing

Prefracture testing incorporates a series ofpumping jobs, prior to the FracPac, that yieldvaluable information about the target reser-voir. For extremely short fracture lengths,these tests may not prove to be economical.However, as job volumes increase and de-signs call for extended fracture lengths, thesetests will prove beneficial to overall success.

Fig. 5-18: Example of a FracPac 3D Fracture Design Simulator output.


Of the prefracture testing techniques, theminifrac yields the most useful informationbut will cost the most. The most valuablepiece of data obtained from the minifrac isthe fluid-loss coefficient. A temperaturesurvey or radioactive tracer log may be run inconjunction with the minifrac for determiningfracture height. A dual minifrac may be usedfor determining both the Cw and spurt loss.

Downhole Tools

Ideally, FracPac II treatments are per-formed using open-ended tubing that allowsmonitoring bottomhole treating pressurefrom the annulus. Niether screens nor gravelpacking would be required as a part of thecompletion system.

Where a treating packer is required, it isuseful to incorporate a downhole pressuregauge to record bottomhole treating pressure.This data can then be analyzed after the jobfor trends in pressure that are not affected bytubular friction. This would be especiallybeneficial for the first jobs performed in afield.

Gravel packing may be required in verypoorly consolidated reservoirs, in instanceswhere perforation phasing and densitywould require a gravel pack, and in deviatedwellbores where significant footage is perfo-rated. Special tools will be required.

Otis Sand Control provides a completeline of sand control screens manufactured byHoward Smith Screen Company. Theseinclude all-welded wire wrap and Sinter-Pakscreens. The Sinter-Pak screen design excelsin resisting bending and compression stressesencountered in deviated or horizontal holes.Such screens are also more efficiently cleanedwith acid than other designs.

Multi-position gravel-pack systems aredesigned to provide a variety of operatingpositions. Multi-position tools allow theVersa-Trieve gravel-pack assembly to be runand set hydraulically. Once the packer and

assembly is set, the four gravel-pack posi-tions are obtained by reciprocating the workstring. No rotation is required throughout theentire operation.

Before performing a FracPac II treatment,the effect of pressure and temperature on thetubulars should be checked by calculatingexpected tubing contraction.

Example Procedure

The following is an example of a recom-mended procedure for executing a FracPac IIdesign on location. This includes downholeequipment for gravel packing.

1. If required, pull existing gravel packfrom well.

2. Go in hole with tubing and circulatewell clean with filtered completionfluid. Pull out of hole.

3. Pick up gravel-pack assembly (screen,packer, and multi-position tool).

4. Go in hole slowly until two stands offdepth. Make slow �pick up� and�slack off� and record weight indica-tor readings.

5. If applicable, tag sump packer andverify position.

6. Rig up Halliburton Services pumpequipment.

7. Test surface lines to necessary maxi-mum.

8. Break circulation by pumping downworkstring.

9. Hydraulically set packer at requireddepth.

10. Calculate differential pressure be-tween slurry weight of final proppantconcentration and annular fluid overdepth of workstring. Test tubing/casing annulus to 500 to 1,000 psiabove this value.

11. Reverse one tubing volume withfiltered completion fluid.

12. Hold prejob safety meeting to coversequence of job events.


13. Break circulation to establish lower,upper, and reverse positions; recordall rates, volumes, and pressures.

14. Locate multi-position tool to reverseposition, and pump a tubing cleaningtreatment (pickle treatment).

15. Place tool in reverse position, andspot minifrac fluid to end of tubing.

16. Perform first portion of dual minifracwith an initial volume equal to 20% ofthe FracPac treatment volume, or 100gal per gross foot minimum. Useidentical fluid and pump rate asplanned for the FracPac. Incorporate aradioactive isotope.

17. Monitor shut-in pressure for two tofour times pump time.

18. Execute second minifrac with approxi-mately 13 to 15% of the FracPacvolume. Monitor shut-in as with firstjob.

19. Rig up and run gamma ray andtemperature log.

20. Calculate closure pressure and fluid-loss coefficient from minifrac and logdata.

21. Adjust FracPac procedure, if neces-sary.

22. Execute FracPac:� Monitor treating pressure forBHTP trends.� If screenout mode is reached,reduce rate to stay below maximumwellhead treating pressure.� Have additional fluid and prop-pant available so that job can beextended, in case screenout does notoccur.� If screenout has not occurredwhen proppant slurry left to injectequals the gravel-pack requirement,slow rate to 2 bbl/min to forcescreenout.� Do not overflush.

23. If screenout does not occur, conductgravel-pack operation.

Minifractures

"Minifracture" treatments, orprestimulation injection tests, have been usedto estimate fluid-loss characteristics since1979. This technology has only recently beenextended to foams. Meaningful minifractureanalyses require fluids with similar or identi-cal properties to the actual stimulation fluids.Conventional aqueous fracturing fluids areinappropriate for estimating the fluid-lossbehavior of gasified fluids. Foams exhibitgreat compressibility and thermal effectsduring shut-in that can mask actual fluid-lossbehavior. The capability to account for theseeffects and properly analyze the pressureresponse would be very beneficial in optimiz-ing stimulation treatments using fluidsfoamed with N2 or CO2.

Minifracture Analysis Technique

Analysis Theory

Minifracture analysis techniques, mostlycentered on the determination of fluid effi-ciency and alternate fracture geometries,involve prediction of volume loss frompressure decline data following fractureextension. The relationship is based on thefracturing fluids being isothermal and incom-pressible.

In practice, thermal and compressibilityeffects of fluids in the wellbore and fracturemay become significant. Both of these effectsmay cause significant underestimation offluid loss if the observed pressure decline isanalyzed using conventional methods.Works by Soliman21 and Tan et al.22 show theneed to correct pressure declines from water-based fracturing fluids in high bottomholetemperature (usually above 250°F) wells.This technique generates an effective pres-


sure decline for analysis. The magnitude ofthe correction increases as fluid loss decreasesor bottomhole temperature increases.

A technique similar to that presented bySoliman is used to estimate the effectivepressure decline. The equation is presentedbelow:

( )∆Ρ ∆Ρ Ρ Τeff p avg

t

s

C PC

td

dtdt= + + ∫1

β( ) , (5-7)

The above equation was used by Solimanto obtain his effective pressure decline;however, the pressure term was changedfrom the difference between bottomholepressure and fracture-closure pressure to thedifference between the bottomhole pressureand the reservoir pressure. The change issignificant, since the magnitude of the correc-tion is based on this pressure drop. Since themodification, excellent agreement betweeneffective pressure decline analysis and treat-ment simulations has occurred.22 For aconstant observed pressure decline thischange makes the effective pressure declineextrapolate to reservoir pressure rather thanto fracture closure pressure.

Cp, compressibilitycoefficient, and Ct, thermalexpansion coefficient, havebeen calculated using thevolumetric average of thefluid components. Thesecoefficients are correctedwith a volume fractionwhich is defined as theratio of total volume(wellbore volume andfracture volume) to thefracture volume. If thewellbore is flushed withincompressible fluids, thewellbore volume is ne-glected in the correction

and volume fraction would be unity.The βs term in Eq. 5-7 is defined as the ratio

of average to net wellbore pressure. For vari-ous geometry models, βs was derived as fol-lows:23

( )β

πs

n n a

=+ + +

2 2 2 3

32

' / ( ' )

/

for Pk

0.9 for Cz

3 for Radial 2, (5-8)

where n ́is the power-law exponent forfluid and a is the viscosity constant.

The viscosity constant, a, can range from 0for uniform viscosity fluid to 2 for fluids thatstrongly degrade with temperature.

The correction technique in Eq. 5-7 requiresa thermal recovery profile during shut-in todetermine the thermal effect on the pressuredecline. The thermal recovery profile has asignificant effect on the correction of pressuredecline. Bottomhole gauges are recommendedfor monitoring the actual bottomhole tempera-ture recovery profile. Mathematical tempera-ture simulators can be used to estimate thewellbore and fracture profiles. The currentmethod assumes that the change in tempera-

Fig. 5-19: Pressure decline for pump-in/shut-in Test 2.


ture within the wellbore and fracture lengthcan be approximated by the thermal responseat the perforations.

A technique presented by Lee24 was usedto obtain the fracture geometry and fluid losscoefficient once a corrected pressure declinewas obtained. This technique makes use ofan energy balance equation instead of thepressure difference between the ISIP and Pc

to determine the fracture geometry. Thistechnique gives more applicable values thanprevious methods.

Minifracture Test Results

Minifracture tests were performed inWebb County, Texas. Following are theresults.25

Well Data

Reservoir Temperature: 215°FReservoir Pressure: 4,200 psiPermeability: 1-10 md

Minifracture Fluids

Pump-in/Shut-in Test 1 -40 lb CMHPG/Mgal in 4%KCl with 50 lb degradableparticulate fluid-lossadditive/Mgal

Pump-in/Shut-in Test 2 -70-quality CO2 foam with40 lb CMHPG/Mgaldelayed crosslinked fluidand 15 lb degradableparticulate fluid-lossadditive/Mgal foam

Treatment Fluids

Same as pump-in/shut-in Test 2.

Proposed Treatment Actual TreatmentSchedule Schedule3,000 gal pre-pad 3,000 gal pre-pad

15,000 gal pad 10,000 gal pad

13,500 gal 5,000 gal

@ 2 to 8 lb/gal 16/20 ISP @ 2 to 8 lb/gal 16/20 ISP

1,500 gal 2,000 gal

@ 8 lb/gal 16/20 ISP* @ 8 lb/gal 16/20 ISP*

1,570 gal flush 1,100 gal flush

*resin-coated

The pressure decline for pump-in/shut-inTest 1 is presented in Fig. 5-19. A fluid-losscoefficient of 0.0055 ft/sqrt (min) was calcu-lated with a closure pressure of 5,100 psi.The pressure decline for pump-in/shut-inTest 2 is presented in Fig. 5-20. A fluid-losscoefficient of 0.0032 ft/sqrt (min) was calcu-lated with the observed data and a fluid-losscoefficient of 0.0050 ft/sqrt (min) was calcu-lated with corrected data. The fluid-losscoefficient increased about 35% as a result ofthe correction. It is noteworthy that the foamyielded a lower fluid-loss coefficient than thebase gel despite having a lower concentrationof degradable particulate fluid loss additive.

Fig. 5-20: Observed and corrected pressure declines for pump-in/shut-inTest 2.


The tracer and temperature surveys indicatedthat gross fracture height was about one-halfof what was expected.

The treatment design was modified usingthe fluid-loss coefficient of 0.0050 ft/sqrt(min) and the smaller gross fracture height.The treatment screened out after about 70%of the flush was pumped. Simulation of thescreenout with a two-dimensional fracturemodel yielded a fluid-loss coefficient of0.0058 ft/sqrt (min). This is even higher thanthe value calculated with the correctedminifracture data. The treatment wouldprobably have screened out much sooner ifthe uncorrected fluid loss coefficient had beenused to modify the design.

Conclusions

Foam fluids have established their valueas low damage fracturing fluids. Foams havegood inherent fluid-loss control characteris-tics. Foams containing polymers leave amuch thinner gel filtercake residue thannonfoamed fluids. The proppant bed regainsa high percentage of conductivity aftertreatment. Foams have a low water content,so there is less aqueous fluid to recover fromthe formation after the fracturing treatment.Gas in the foams expands to assist in recov-ery of treatment fluids.

The rheology of foams has been charac-terized. Crosslinked foams provide easierplacement of proppant in a formation thannoncrosslinked-gel foams. Constant-internal-phase designs provide higher proppantconcentrations downhole.

The positive benefits of clean foam fluidsare partially offset by the slightly higher costof a foam fracturing treatment. But whereformation damage is a major factor in select-ing a fracturing fluid, foams are the fluid ofchoice.

References

1. Warnock, W.E., Harris, P.C., and King,D.S.: �Successful Field Applications ofCO2-Foam Fracturing Fluids in the Ar-kansas-Louisiana-Texas Region,� JPT (Jan1985) 80-88.

2. Bleakley, W.B.: �Mitchell Energy FoamFracs Tight Gas Zones,� Pet. Engr. Intl.(Dec 1980) 24-26.

3. Harris, P.C., Klebenow, D.E., andKundert, D.P.: �Constant-Internal-PhaseDesign Improves Stimulation Results,�SPEPE (Feb. 1991) 15-19.

4. Harris, P.C.: �A Comparison of MixedGas Foams With N2 and CO2 FoamFracturing Fluids on a Flow Loop Vis-cometer,� paper SPE 20642 presented atthe 1990 SPE Annual Technical Confer-ence and Exhibition, New Orleans, Sept.23-26.

5. Mitchell, B.J.: �Viscosity of Foam,� PhDdissertation, Univ. of Oklahoma (1970).

6. J.L. Gidley, et al., Ed.: Recent Advances inHydraulic Fracturing, , Monograph Series,SPE, (1989) 12 198-209.

7. Borchardt, J.K., et al.:�Surfactants for CO2

Foam Flooding,� paper SPE 14394 pre-sented at the 1985 SPE Annual TechnicalConference and Exhibition, Las Vegas,Sept. 22-25.

8. Nikolov, A.D., et al.: �The Effect of Oil onFoam Stability: Mechanisms and Implica-tions for Oil Displacement by Foam inPorous Media,� paper SPE 15443 pre-sented at the 1986 SPE Annual TechnicalConference and Exhibition, New Orleans,Oct. 5-8.

9. Norman, L.R., Hollenbeak, K.H., andHarris, P.C.: �Fracture ConductivityImpairment Removal,� paper SPE 19732presented at the 1989 SPE Annual Techni-cal Conference and Exhibition, San Anto-nio, Oct. 8-11.


10. Harris, P.C.: �Dynamic Fluid-Loss Char-acteristics of CO2-Foam Fracturing Flu-ids,� SPEPE (May 1987) 89-94.

11. Davies, D.R. and Kulper, T.O.H.: �Frac-ture Conductivity in Hydraulic FractureStimulation,� JPT (May 1988) 550-552.

12. Blauer, R.E. and Kohlhaas, C.A.: �Forma-tion Fracturing with Foam,� paper SPE5003 presented at the 1974 SPE AnnualMeeting, Houston, Oct. 6-9.

13. Howard, G.C., and Fast, C.R.: HydraulicFracturing, Monograph Series, SPE,Richardson, TX (1970) 2, 36.

14. Holm, L.W.: �The Mechansim of Gas andLiquid Flow Through Porous Media inthe Presence of Foam,: SPEJ (Dec. 1968)359-69.

15. Guppy, K.H. et al.: �Non-Darcy Flow inWells with Finite-Conductivity VerticalFractures,� SPEJ (Oct. 1982) 681-98.

16. Much, M., and Penny, G.S.: �Long-TermPerformance of Proppants Under Simu-lated Reservoir Conditions,� paper SPE16415 presented at the 1987 SPE/DOELow-Permeability Reservoirs Symposium,Denver, May 18-19.

17. McDaniel, B.W.: �Conductivity Testing ofProppants at High Temperature andStress,� paper SPE 15067 presented at the1986 SPE California Regional Meeting,Oakland, April 2-4.

18. Roodhart, L.P., Kuiper, T.O.H., andDavies, D.R.: �Proppant Pack and Forma-tion Impairment During Gas Well Hy-draulic Fracturing,� paper SPE 15629presented at the 1986 SPE Annual Techni-cal Conference and Exhibition, NewOrleans, Oct. 5-8.

19. Reidenbach, V.G., Harris, P.C., Lee, Y.N.,and Lord, D.L.: �Rheological Study ofFoam Fracturing Fluids Using Nitrogenand Carbon Dioxide,� SPEPE (Jan. 1986)31-41.

20. Prats, M.: �Effect of Vertical Fractures onReservoir Behavior; Incompressible Fluid

Case,� SPEJ (June 1961) 105-17; Trans.,AIME (1961) 222.

21. Soliman, M.Y.: "Technique for Consider-ing Fluid Compressibility and Tempera-ture Changes in Minifrac Analysis," paperSPE 15370 presented at 1986 SPE AnnualTechnical Conference and Exhibition,New Orleans, Oct. 5-8.

22. Tan, H.C., McGowen, J.M., and Soliman,M.Y.: "Field Application of MinifracAnalysis to Improve Fracturing Treat-ment Design," SPE Production Engineering(May 1990) 125-132.

23. Nolte, K.G.: "A General Analysis ofFracturing Pressure Decline with Applica-tion to Three Models," SPE FormationEvaluation, (Dec. 1986) 571-583.

24. Lee, W.S.: "Study of the Effects of FluidRheology on Minifrac Analysis," paperSPE 16916 presented at the 1987 SPEAnnual Technical Conference and Exhibi-tion, Dallas, Sept. 17-30.

25. Juranek, T.A., et al.: "Minifracture Analy-ses and Stimulation Treatment Results forCO2-Energized Fracturing Fluids in SouthTexas Gas Reservoirs," paper SPE 20706presented at the 1990 SPE Annual Techni-cal Conference and Exhibition, NewOrleans, Sept. 23-26.

Additional References

Biot, M.A., Masse, L., and Medlin, W.L.:�Temperature Analysis in HydraulicFracturing,� JPT (Nov. 1987) 1389-1397.

Craighead, M.S., Hossaini, M., and Freeman,E.R.: �Foam Fracturing Utilizing DelayedCrosslinked Gels,� paper SPE 14437presented at the 1985 SPE Annual Techni-cal Conference and Exhibition, Las Vegas,Sept. 22-25.

Ely, J.W., Arnold, W.T., and Holditch, S.A.:�New Techniques and Quality ControlFind Success in Enhancing Productivity


and Minimizing Proppant Flowback,�paper SPE 20708 presented at the 1990SPE Annual Technical Conference andExhibition, New Orleans, Sept. 23-26.

Harris, P.C.: �Dynamic Fluid-Loss Character-istics of Nitrogen Foam Fracturing Flu-ids,� JPT (Oct. 1985) 1847-1852.

Harris, P.C., Haynes, R.J., and Egger, J.P.:�The Use of CO2-Based Fracturing Fluidsin the Red Fork Formation in theAnadarko Basin, Oklahoma,� JPT (June1984) 1003-1008.

Harris, P.C.: �Effects of Texture on Rheologyof Foam Fracturing Fluids,� SPEPE (Aug.1989) 249-257.

Robinson, B.M., Holditch, S.A., andWhitehead, W.S.: �Minimizing Damageto a Propped Fracture by ControllingFlowback Procedures,� JPT (June 1988)753-759.

Stim-Lab, Inc, Consortium: �PreliminaryReport on the Investigation of the Effectsof Fracturing Fluids upon the Conductiv-ity of Proppants,� June 22, 1989.

Watkins, E.K., Wendorff, C.L., and Ainley,B.R.: �A New Crosslinked Foamed Frac-turing Fluid,� paper SPE 12027 presentedat the 1983 SPE Annual Technical Confer-ence and Exhibition, San Francisco, Oct. 5-8.

Foam Cementing 6-1

Section 6

Foam Cementing

Contents

Introduction .............................................................................................6-3Foam Generation ....................................................................................6-4

Stabilizing Additives .....................................................................................6-4Strength Development ................................................................................. 6-5Gas Injection ................................................................................................ 6-5

Downhole Behavior .................................................................................6-7Constant Gas Rate Foam Cement .............................................................. 6-7Constant Density Foam Cement.................................................................. 6-7

Cement and Additives .............................................................................6-9Job Considerations ...............................................................................6-10

Primary Cementing .................................................................................... 6-10Squeeze Cementing ..................................................................................6-11

Design Considerations .........................................................................6-12Prejob Checklist ......................................................................................... 6-12

Operator ...............................................................................................6-12Service Company .................................................................................6-12Drilling Contractor ................................................................................ 6-13

Using a Reactive Flush .............................................................................. 6-13Cement Rheology ...................................................................................... 6-13

Evaluating Foam Cementing Results....................................................6-14

6-2 Foam Cementing

Foam Cementing 6-3

Foam Cementing

Introduction

There have always been areas in whichweak zones can support only a limited heightof a normal-density (11 to 18 lb/gal) cementcolumn without breaking down. Foamcement provides a means of preparing 4 to 15lb/gal cementing slurries that develop rela-tively high compressive strengths in a mini-mum period of time, even at low formationtemperatures.

The use of foamed cement offers a low-density slurry that

� develops relatively high compressivestrengths and low permeabilities

� protects water-sensitive clay, shale,and salt formations

� can control high-volume water flow inweak formations, when mixed as aquick-set formula

� enhances protection against annulargas invasion

� is economically competitive� can be used from 28 to 600°F.Halliburton Foam Cement is a �stabilized

system� consisting of cement with carefullychosen additives, a foam stabilizer, a gas(usually nitrogen), and water. Success offoam cement comes from the ability to main-tain cement slurry density below the hydro-static breakdown of sensitive formations,

Fig. 6-1: Equipment needed in the field to mix and monitor foam cements is very similar to that used in conventionaljobs. The major exceptions are the foam generator inserted into the slurry discharge and the nitrogen unit.

6-4 Foam Cementing

which prevents lost circulation and fallbackproblems. This density control flexibilityallows a wide latitude in designing theoverall job before it is actually run in thefield. Appropriate computer-assisted pro-grams are used for prejob planning. If neces-sary, one can choose to change the density asthe pressure and circulation events varyduring job execution.

To prepare a stable foam cement, theslurry should be conveyed through an effec-tive mechanical foam generating device thatimparts sufficient energy and mixing actionwith pressurized gas to prepare uniform gasbubbles of the correct size. In nearly allrespects, regular cementing equipment is setup as for an ordinary cementing job. Thefoam generator is inserted in the cementslurry discharge line that is connected to thewell head, and the nitrogen unit is connectedto the foam generator. The cement slurry ismixed in a normal fashion, and foamingsurfactants and stabilizers are injected intothe slurry as it is picked up by the displace-ment pump unit. Fig. 6-1 on the previouspage depicts a typical field job equipmentlayout.

Foam Generation

Stabilizing Additives

Foam cement requires that a stable foambe created in which the entrained gas istrapped in discrete bubbles that are uni-formly dispersed throughout the slurry. Ifgas bubbles are not discrete and within acertain size range, the foam may be unstable,and the set cement will have high permeabil-ity and low compressive strength. Retainedstability at high foam quality is important forfoam cements with densities less than 9 lb/gal. Small, fine foam bubbles are believed topromote stronger cement walls around thebubbles and provide a set cement of in-creased integrity.

Stabilization is achieved by using anefficient foaming surfactant in addition to aneffective chemical foam stabilizer. HalliburtonFoam Stabilizer is recommended for circulat-ing temperatures of 50 to 110°F and HC-2 fortemperatures greater than 110°F. The normalsurfactant requirement is 1.5% foam additiveand 0.75% foam stabilizer, with both quanti-ties based on the volume of mixing water thatthe cement slurry is mixed with. Both addi-tives are mixed together, stirred to insureuniformity, and then injected as one solutionwith an injection pump. This results in

Table 6-1: Effect of Water Ratio on Foam Cement Strengths

Water Ratio 0.72 0.60 0.46 0.38

Surface Density of Cement Slurry (lb/gal) 13.6* 14.5** 15.6** 16.4**

Compressive Strength (psi)

Curing Time 24 hr 72 hr 24 hr 72 hr 24 hr 72 hr 24 hr 72 hr

Density of Foam (lb/gal)

8 224 230 260 518 395 665 825 1070

6 84 128 131 168 163 288 235 208

4 43 57 38 82 18 56 20 60

Samples cured at atmospheric pressure and 100°F. All samples contained 1.5% surfactant + 0.75% stabilizer by volume of water.* Class H + 2% solids stabilizer + 2% CaCl2** Class H + 3% CaCl2

Foam Cementing 6-5

approximately 0.4 gal of foam additive and0.2 gal of foam stabilizer being injected perbarrel of surface cement slurry.

Strength Development

As with ordinary slurries, thewater to cement ratio (w/c) of a foamcement slurry strongly affects thestrength of the set solid. This is illus-trated by the results in Table 6-1. Thechemical and physical properties ofthe cement also affect strength devel-opment as shown in Fig. 6-2. Perme-ability of set foam cement varies as afunction of both entrained gas volumeand curing temperature. Table 6-2 liststypical permeability data.

To those familiar with the lack ofstrength development of ordinary low-density oil well cements (10 to 11.5 lb/gal), the ability of foam cement toachieve strengths in excess of 500 psiwith air permeabilities less than 20 mdat cool temperature conditions seemsremarkable. Foam cement achieveshigher strengths than water-extendedcements primarily because of the verylow density of gas versus the density

of water. As a result, it takesfewer volumes of gas per vol-ume of cement to achieve thesame density reduction. Absenceof these additional dilutionvolumes in foam cement resultsin much stronger, competentcement. Table 6-3 on the nextpage presents some typicalcompressive strengths of foamcement.

Gas Injection

The required gas injectionrate per barrel of cement slurryshould be determined by enter-

ing the job data in a foam cement computerprogram (such as FMCEM). Fig. 6-3 on thenext page shows typical nitrogen require-ments for an 8.5 lb/gal foam cement. Foamjobs can be designed using a constant nitro-

1,400

1,200

1,000

800

600

400

200

4 6 8 10

Density (lb/gal)

Class C + 2% CaCl2

w/c = 0.56

Class A + 2% CaCl2

Class H + 2% CaCl2

w/c = 0.46

w/c = 0.38

Com

pres

sive

Str

engt

h (p

si)

Fig. 6-2: This graph of results from a 24-hour compressivestrength development test run at 100°F illustrates how physicaland chemical properties can affect foam cement strengthdevelopment.

Table 6-2: Permeability of Set Foam Cement, K (air)

Surface slurry =Class H + 2%

CaCl2, w/c = 0.38

Density (lb/gal)

4 6 8 10

Temp Permeability (md)

65°F 129 28 1.3 1.5

85°F 159 111 6.7 2.3

Surface slurry =Class C + 2%

CaCl2, w/c = 0.56

Density (lb/gal)

4 6 8 10

Temp Permeability (md)

65°F -- 15.2 1.32 1.12

85°F -- 846* 0.42 0.11

* Sample most likely had a microcrack present

6-6 Foam Cementing

gen (N2) rate or a constant downhole density.With a constant N2 rate, if the cementedinterval is long or back to the surface, dra-matic density changes can occur because ofthe decreasing hydrostaticpressure as the slurry risesin the annulus.

This problem can beavoided by initiating thejob with a low N2 rate andincreasing the rate as thejob proceeds. To inject theever-changing quantity ofN2 required to produce acolumn of constant finaldensity is not operationallyfeasible. Instead, foam jobsbased on constant densitycan be successfully per-formed with the N2 ratevaried incrementally. If theincrements are sufficiently

small, the density variations will also besmall.

Unfortunately, constant density designshave problems also. When the first stages

Table 6-3: Compressive Strengths of Foam Cement

Curing Temperature 65°F 100°F 140°F

Curing Time 12 hr 24 hr 72 hr 12 hr 24 hr 72 hr 12 hr 24 hr 72 hr

Densityof Foam(lb/gal)

Compressive Strength (psi)

Surface Slurry:15.6 lb/gal

(Class A, 2.0%CaCl2)

10 130 220 490 370 630 1,040 510 870 1,100

8 70 190 210 230 530 720 250 430 680

6 40 100 210 150 230 300 160 340 200

4 10 60 38 60 110 140 70 110 60


(Class C, 2.0%CaCl2)

10 50 410 1,130 260 1,280 1,280 650 1,250 1,390

8 70 240 320 270 350 780 260 650 530

6 50 120 200 150 180 310 120 150 140

4 10 30 110 60 80 150 50 70 80


(Class H, 2.0%CaCl2)

10 60 160 290 130 400 440 150 570 500

8 40 80 160 110 200 350 120 200 190

6 20 50 100 90 90 180 50 90 90

4 10 20 30 10 30 50 10 30 30

8.5 lb/gal

10.5 lb/gal

12.5 lb/gal

2,000 4,000 6,000 8,000 10,000

Downhole Hydrostatic Pressure (psi)

4,000

3,000

2,000

1,000

Nitr

ogen

Req

uire

men

ts (

scf/b

bl)

Fig. 6-3: Nitrogen requirements for preparing an 8.5 lb/gal foam cement.Values are in standard cubic feet of N2 per barrel of 14.8 lb/gal cement.

Foam Cementing 6-7

that have the lower N2 concentrations turnthe corner under maximum pressure, thedensity will be much greater than the designdensity and can cause breakdown.

To avoid this situation, the job can be runwith constant N2. If the interval is long, twoor three �constant� rates may be chosen, anda neat cap cement can be pumped down theannulus after the plug is bumped, if cementis brought back to surface.

The FMCEM program can be operated infour different modes. These options allow theuser a choice between a constant density anda constant N2 format with or without a set of�job calculations.� These job calculationscontain information about N2 foamer, mixwater, and cement volumes and rates to beused during the job. The program may be runwith interactive data input or with the fileinput.

Physical stabilization results when the gasis introduced into the cement slurry withsufficient energy to create microscopic,discrete gas cells. This is accomplished byusing a foam generator equipped with 3/16-in. or 1/4-in. jets. Foam cement is stable,unlike nitrified cement or drilling fluid. Theentrained gas will not coalesce from thecement slurry if the slurry remains under thedesigned temperature and pressure condi-tions.

Downhole Behavior

Foam cement applications can be dividedinto two types: constant gas rate and constantslurry density. These two designationsrepresent the two extremes and are normallygreatly modified to arrive at a practical jobdesign.

Constant Gas Rate Foam Cement

The constant gas rate technique can beused to remedy lost circulation problems,within certain limitations. Fig. 6-4 on the nextpage shows the difficulties in attempting touse a constant gas rate foam cement andcirculate it back to surface. This exampleshows a foam cement with 30 sv/vus (stan-dard volumes of N2 per unit volume ofunfoamed slurry, which is 168 scf/bbl). Withno backpressure on the annulus at the surface(curves labeled 0/0), the pressure gradient(PG) is below the fluid entry gradient toabout 7,000 ft, and cement above 2,000 ftwould not be dense enough to provide lowenough permeability for casing protection. IfN2 content is reduced, density at the shallowdepths can be corrected, but the maximumpressure gradient easily can be exceeded atthe greater depths.

This profile can be partly corrected byholding backpressure at the surface. The 500/0 curves in Fig. 6-4 show the effect of holding500 psi backpressure. However, this methodruns the risk of breaking down weak, shallowformations unless intermediate or deepsurface casing has been set to about 1,000 ft.

A better approach to using a constant ratefoam cement is to use a nonfoamed �cap� ofeither mud or regular lightweight cementahead of the foam cement. Fig. 6-5 on thenext page shows the results of using a 3,000 ftcap of 9.9 lb/gal mud (curves A) and a 12.9lb/gal regular lightweight cement (curves B).Even with a lighter 9.9 lb/gal mud cap, thefoam slurry density is never less than 9.2 lb/gal, which provides low permeability andsufficient compressive strength, and thepressure gradient profile falls well within themaximum and minimum limits.

Constant Density Foam Cement

Theoretically, constant density can bemaintained throughout a foam cement

6-8 Foam Cementing

Fig. 6-4: Graph illustrates problems involved with usinga constant gas rate foam cement to remedy lostcirculation problems. Two options are shown—oneusing no backpressure on the annulus during circulationand another in which 500 psi is held at the surface.

Fig. 6-5: To overcome problems illustrated by Fig. 6-4,a cap of mud or heavier cement can be used withconstant gas rate foam cements.

column by continuously adjusting the gasratio. In practice, incremental adjustments areused, but the increments are designed tocause only minor, acceptable density varia-tion throughout the column.

The results of changing the N2 ratio forevery 1,000 ft of slurry at shallow depths andevery 2,000 ft at the greater depths are shownin Fig 6-6. The initial ratio was 8.5 sv/vus(47.7 scf/bbl) for the slurry to be placed nearthe surface, and this increased to 123 sv/vus(690 scf/bbl) for the slurry at 12,000 ft. The8.5 sv/vus requires only 191 scf N2 if theunfoamed slurry is pumped at 4 bbl/min.This rate is too low to make accurate deliverywith most N2 pumps currently used inoilwell servicing. The properties of foamcement with only 8.5 sv/vus in the top 500 ft(3 to 8 lb/gal) are marginal for competent

cement. Unless intermediate casing has beenset or unless poor quality cement in theupper 500 to 1,000 ft can be tolerated, place-ment of a nonfoamed slurry cap is recom-mended followed by foam cement preparedby incrementally adjusting the N2 ratio.

Results of using only 200 ft of a neat ClassC slurry cap or lead slurry are shown in Fig.6-7. The minimum foam slurry density is 9.8lb/gal, and the pressure gradient still doesnot exceed the breakdown pressure at 8,000ft.

Actual applications of foam cement haveshown that a blending of fixed gas rate andconstant foam slurry density procedures willprovide the most practical method in fieldoperations. The following suggestions areoffered:

Foam Cementing 6-9

Fig. 6-6: To obtain a constant density foam cement,the N2 ratio must be adjusted with depth. In thisexample, the ratio is changed every 1,000 ft atshallower depths and at every 2,000 ft at greaterdepths to obtain an average slurry density of 10.5 lb/gal.

Fig. 6-7: In this example, the N2 ratio was adjusted withdepth, but a 200-ft 14.1 lb/gal cement cap was alsoused.

� Use constant N2 ratios only for jobs inwhich a nonfoamed cap equal to 10 to30% of the total depth can be used orwhen poor cement and low hydro-static pressure can be tolerated in thetop 25% of the column.

� Use incremental N2 ratio adjustment ifa constant N2 ratio results in unaccept-able strength and permeability in theupper part of the foam slurry.

� Limit incremental adjustments to amaximum interval of 1,000 ft fordepths less than 6,000 ft and to amaximum interval of 2,000 ft fordepths greater than 6,000 ft.

Cement and Additives

Cement slurries using many conventionalcement additives are generally batch-mixedbefore being foamed. Certain additives arenot recommended for use with foam cementsbecause they will destabilize the foam cells.Any additives that act as defoamers or dis-persants should be avoided (e.g., NF-1, D-AIR, CFR-1, CFR-2, HR-12, HALAD(R)® -9,HALAD® -14, HALAD® -22A, etc.). Mostadditives that promote gel strength usuallyare beneficial (e.g., THIX-SET A and B, THIX-SET 31A and 31B, LA-2 latex, Diacel LWL,WG-17, bentonite, ECONOLITE, etc.). Toachieve extended pumping times, it is best to

6-10 Foam Cementing

use Diacel LWL and/or WG-8 asset retarders and foam stabilizerswhenever possible.

Foam cement can also bemade salt-tolerant. Halliburton'sCFA-S foaming agent permitsgeneration of foam cement usingfresh water, NaCl concentrationsup to saturation, KCl concentra-tions up to 5%, or seawater.Studies show foamed salt cementprovides improved bonding tosalt zones and other freshwatersensitive formations.

The use of SUPER FLUSH(liquid or powder) spacer as apreflush is highly recommendedfor use with foam cement tofurther promote bonding anddisplacement.

As with conventional slurries, adding finesilica flour (SSA-1) to foamed slurries helpsprevent strength retrogression when tem-peratures in excess of 230°F will be encoun-tered. Geothermal foam cement inherentlyhas several attractive properties such as lowdensity, good strength, temperature stability,and excellent heat insulation properties.Table 6-4 shows properties of 550°F high-temperature cycling foam cement.

Job Considerations

Primary Cementing

As with most conventional cementingoperations, foam cement jobs are initiallydesigned based on static density. It is pos-sible that when frictional pressures areconsidered, a job that has a safe final hydro-static pressure might actually fracture thewell during the job. A computer cement jobsimulator program (CJOBSIM) allows theuser to simulate the actual downhole circulat-

ing pressure throughout the job at total depthand any other zone of interest. If the initialdesign fractures the well, this program can beused to determine ways to modify the designto prevent fracturing. Such modificationscould include varying the rates at differentpoints in the job, changing fluid density,running more or less spacer, or foaming afluid ahead of the cement.

A section is included in the program forN2 concentration. This can be for foamedcement and spacer. The N2 section willusually be based on the output from theFMCEM program.

To accomplish primary cementing withfoam cement, the wellhead should beequipped with annular pressure-containingdevices. If foam cement is to be circulated tothe surface, the presence of this equipment isnearly mandatory. When pressure-containingdevices are not feasible, an unfoamed cementcap should be run ahead of the foam cement.The unfoamed �cap� interval is tailored foreach specific job and has a minimum intervalof 200 ft.

Table 6-4: Properties of 550°F High Temperature CyclingFoam Cement (for steam injection conditions)

Surface Slurry: 15.4 lb/gal (Class G, 40% SSA-1, 3% Lime)

PropertiesFoam Cement Density

10 lb/gal 11.5 lb/gal 13 lb/gal

Compressive strength after20 days at 550°F

1,210 psi 1,680 psi 2,260 psi

Compressive strength after100 days at 550°F* 1,630 psi 1,550 psi 2,440 psi

Compressive strength after160 days at 550°F**

1,240 psi 2,020 psi 2,430 psi

Air permeability after 100days

2.4 md 1.0 md 0.9 md

Porosity 75 68 64

K-value (BTU/hr-ft-°F) 0.14 0.18 ---

* Cycled to 100°F twice** Cycled to 100°F three times

Foam Cementing 6-11

Table 6-5: Squeeze Job Parameters

Case 1 Case 2

Current Casing 5 1/2 in. 5 1/2 in.

Tubing Size 2 7/8 in. 2 7/8 in.

Tubing Depth 5,640 ft 5,496 ft

Tool 5 1/2 in. retainer 5 1/2 in. retainer

Injection depth 5,800 ft 5,800 ft

Injection Pressure 3,240 psi 3,310 psi

Well Fluid 8.9 lb/gal brine 8.9 lb/gal brine

Job Sequence

Spacer(s) 10 bbl water 10 bbl water

Lead Cement*27.3 bbl of Class C

(foamed), 10.8lb/gal

33 bbl of Class C(foamed), 10.8

lb/gal

Tail Cement 8 bbl of Class C,14.8 lb/gal

2.3 bbl of ClassC, 14.8 lb/gal

Displacement 31 bbl water 31 bbl water

* volume of unfoamed slurry

For safety and cleanup ease, the returnrelief lines should be carefully staked andchained to discharge in an acceptable wastearea, such as a sump pit. Foam cement underpressure will greatly expand if released atatmospheric pressure.

Squeeze Cementing

Since squeeze cementing is frequentlyremedial in nature, the volume of cementactually required to perform the job is oftenquite small. Excess cement blend is oftenprepared�whether or not it is actuallymixed�for an average squeeze job becauseof the uncertainty regarding the endpoint ofthe job and/or to ensure that an adequatevolume of cement is available in case forma-tion breakdown should occur. When smallcement volumes are employed, loss of ce-ment slurry to a created fracture can result ininadequate coverage of the zone of interest,thus requiring another squeeze job.

When a known potential exists for goingon vacuum on a squeeze job, foamed cementcan be used to help reduce the pressuresexerted on the weak formation, therebyproviding a means of obtaining surfacepressure indication during the squeeze. Akey element in optimizing job design vari-ables such as cement density, circulatingpressure, etc., is a computer squeeze jobsimulator (SQZSIM2) program.

A critical factor in using the squeeze jobsimulator has been its capability to assist inplanning and performing foam cementsqueeze jobs. Probably the most critical jobparameters that can be computed using thecomputerized simulation for foam cementsqueeze jobs are (1) the N2 injection volumerequired to obtain a specific foam cementdensity and (2) the base slurry volume (toyield the requested foam volume), taking intoaccount the effects of hydrostatic, circulating,and frictional pressures on the downholedensity of the compressible foam cement

system.As an example of these applica-

tions, two existing producing wellswere to be drilled to a deeper produc-ing formation (Table 6-5). The forma-tion that was being produced had alow fracture gradient that would breakdown if the well was loaded withconventional drilling fluid. Safelydrilling to this zone would require theuse of foam air drilling techniques tohelp maintain circulation while drill-ing to the new producing interval. Afoam cement squeeze job was de-signed to eliminate the need for thiscostly technology and to preventinvasion of drilling fluids and finesinto the older producing formation.Following the squeeze job, the foam-squeezed interval would be drilled outto allow the wells to be completedwith liners.

6-12 Foam Cementing

A prejob simulationwas performed to obtainthe desired foam cementdensity (10.8 lb/gal) andto predict wellheadpressures for each job.Squeeze pressure was notobtained in Case 1. InCase 2, however, addi-tional pressure wasapplied at the end of thejob, increasing the den-sity of the foam cement.Actual wellhead pres-sures from both jobsfollowed very closelythose predicted by thecomputer simulation(Figs. 6-8 and 6-9). Thegraphs show that, al-though the time at whichcertain pressures wereobtained varied slightly from the timespredicted through the simulations, the maxi-mum and minimum pressure values them-selves are consistent with those predicted bythe simulator.

Both wells were successfully drilled totarget depth without lost circulation prob-lems, and production liners were set. Result-ing production data for the original zonesshowed decreased water-to-oil ratios (WOR)without a decrease in oil production.

Design Considerations

To successfully circulate and retain foamcement at the correct density in a well thathas severe lost circulation problems, anoperator must carefully design the job andfollow the correct procedures. Prejob plan-ning and calculation from accurate dataprovided by the operator is as important ason-the-job timing and execution of the plans.

Reliable equipment should also be plannedfor. A summary of important design consid-erations is offered below.

Prejob Checklist

Operator

1. Depth of well2. Location of lost circulation zone(s)3. Breakdown gradients of fragile zones4. Circulating and static temperatures5. Ultimate formation temperatures6. Fallback history? (if yes, design

thixotropic cement blend)7. Electric, fluid, and mechanical dis-

placement hole volume8. Backpressure requirement on annulus9. Adequate spacer/flush

Fig. 6-8: Comparison of actual vs. simulated wellhead pressure (Case History 1).

Actual pressure Simulated pressure

Foam Cementing 6-13

Service Company

1. Pump truck unit- cement slurrydensity and slurry rate instrumenta-tion

2. Nitrogen service unit- gas rate, gaspressure, and control equipment

3. Check valves4. Bulk cement equipment5. Surfactant, surfactant pump, surfac-

tant rate meter6. Foam generator- metering jets, mul-

tiple connection nipples, and adapters

Drilling Contractor

1. Freshwater source2. Displacement fluid3. Location layout- sufficient equipment

space4. Reliable well head annulus pressure

control

5. Chaineddiverter return lines:sump disposal area6. Annulus chokesystem7. Casing place-ment precautions andcontrol8. Minimum pipemovement

Using a ReactiveFlush

Exceptionally badlost circulation problemscan be lessened orremedied by pumping achemically reactive flushsystem, such as SUPERFLUSH, behind thedrilling fluid and ahead

of the cement slurry. This technique wasdeveloped for use with conventional slurriesas early as 1971. The technique remainshighly recommended for use with foamcement practices.

The reactive flush is designed to coat boththe formation and pipe with chemically activematerial. Larger quantities of the materialmay tend to preferentially enter areas that areaccepting fluids under pressure. Whencontacted by the foam cement slurry, a rapidchemical reaction occurs that tends to create anearly immobile precipitate that can seal thezones that have accepted the flush. Postjobevaluations have indicated that the use of thereactive flush promotes improved bond logsand improved mud-displacement efficiencyas well as sealing lost circulation zones.Foaming the reactive flush, using the sametechnique as with the foam cement, beforepumping can improve its effectiveness.

Fig. 6-8: Comparison of actual vs. simulated wellhead pressure (Case History 1).

Actual pressure Simulated pressure

6-14 Foam Cementing

Cement Rheology

Foam cement rheologyplaces some limits on job design.The general nature of foamcement is that its viscosityincreases as the density is low-ered (i.e., the gas content in-creases). Foam cement slurriesare usually more viscous thanthe surface slurry from whichthey are prepared. Mathemati-cally, this behavior is reflected asa steady increase of K´ value asmore gas is stabilized in the foam cement.The n´ value for a typical slurry slightlydecreases, indicating the shear thinningability of the foamed fluid remains approxi-mately constant.

Table 6-6 lists typical data derived fromFann viscometer readings for Class G cementplus 40% silica flour. Steady decrease ofplastic viscosity as the cement density islowered correlates to lower solids per givenvolume, and the general increase is yieldpoint indicates greater solids carrying capac-ity for the lighter foam cement slurries. Thepractical significance of this foam cementbehavior is to make placement of foamcement in turbulent flow unlikely in wellsthat already suffer from severe lost circula-tion problems. Consideration of the frictionalbackpressure generated when placing foamcement with viscosity also suggests that lowcement displacement rates should be ob-served, especially after the foam cementclears the pipe and enters the annulus.

Evaluating Foam CementingResults

Success of foam cement jobs can bemeasured in two ways�factors noticedduring the job and post-job evaluation.

During the job, such things as interruptedcirculation, sudden or unexpected increasesor decreases in surface pressure, and infor-mation about mixing and measuring proce-dures should be carefully recorded. Experi-ence indicates that certain guidelines shouldbe followed to help assure the best possibleresults from a foam job. The following basicitems are important for a successful foamcement job:

� A means of mixing an unfoamedsurface cement slurry at a specifiedair-free density with a reasonableaccuracy (e.g., ± 0.1 lb/gal)

� Method of measuring the unfoamedslurry pump rate and total volumewith an accuracy of ± 5% or better

� Techniques for introducing foamstabilizing chemicals into theunfoamed slurry or N2 stream with anaccuracy of ± 10 %

� Facilities for measuring and control-ling gas injection rate based on massor standard volume

� Injection of the gas into the unfoamedslurry stream with sufficient energy toobtain maximum stabilization

� An inline mixing device to add stabil-ity and uniformity to the foam slurry.Up to a point, higher energy providesgreater stability. Inappropriate fieldsampling methods can easily lead to

Table 6-6: Foam Cement Viscosity Behavior

Class G + 40% Silica Flour; 15.8 lb/gal surface density

SlurryDensity(lb/gal)

n' k'Yield Point

(lb/100 sq ft)

ApparentViscosity

(cp)

PlasticViscosity

(cp)

15.8 0.67 0.02460 34 125 113

12.0 0.65 0.03149 58 141 112

10.0 0.59 0.04373 68 130 96

8.0 0.57 0.05022 74 129 92

6.0 0.48 0.06713 68 90 56

Foam Cementing 6-15

false conclusions regarding the stabil-ity of field-mixed foam cement.

Post treatment measurements using bondlogs and temperature surveys have beenused to evaluate foam cement jobs. Bond logsindicate the presence of foam cement prima-rily through attenuation of the amplitudecurve and the micro-seismogram. The ampli-tude curve responds to differing densities ofboth the conventional cements present andthe foam cements, and is helpful in locatingthe interface between the two. To get themost information possible, the amplitudeshould be set as high as possible to provide agreater range, and therefore better resolution,on the curve, which will better show changesin density.

The micro-seismogram may not show anapparent bond through the foam that is asgood as shown through normal densityslurries, but arrival of formation signals alongwith each free pipe signal indicates thatbonding has occurred. Correlation of themicro-seismogram with gamma ray or den-sity logs for verification of formation signalshas been found to be a helpful tool in evaluat-ing bond quality.

Temperature surveys, run 8 to 24 hoursafter completion of the job, have provenvaluable in locating the top of the differentintervals of cement. Cap and tail-in cementswill show a temperature gradient greaterthan normal background, while the foamedinterval will be about the same as back-ground profiles or may even show a less-than-normal temperature gradient.

Evaluation of results should not be left toone graph, one chart, or one log, but rather asmuch information as possible should begathered and correlated.

6-16 Foam Cementing

Other Nitrogen Applications 7-1

Section 7

Other Nitrogen Applications

Contents

Sand Washing ........................................................................................7-3Incompressible Wash Fluids ........................................................................ 7-3Compressible Wash Fluids .......................................................................... 7-4Sand Washing with Foam............................................................................ 7-4Operations.................................................................................................... 7-5

Wash Penetration Rate ......................................................................... 7-5Produced Fluids .....................................................................................7-6Wash Tools ............................................................................................ 7-6Conventional Circulation ........................................................................ 7-6

Job Procedure .............................................................................................. 7-6Unloading Wells .....................................................................................7-7

Unloading Design Considerations ............................................................... 7-7Unloading Concerns .................................................................................... 7-8Nitrogen-Assisted Unloading ....................................................................... 7-8

Nitrogen Behavior .................................................................................. 7-8Nitrogen Unloading Methods .................................................................7-9

Gas Displacement ................................................................................7-10Pressurizing Medium ............................................................................7-11

Drillstem Test Cushion ...............................................................................7-11Perforating Technique ............................................................................... 7-11Gas Lift Medium ......................................................................................... 7-12

Commingled Gas ..................................................................................7-12Reduce Mud Weight .................................................................................. 7-12Remove Differentially Stuck Pipe ..............................................................7-12Perform Hydrojetting ..................................................................................7-12

Sand Consolidation...............................................................................7-13Operations..................................................................................................7-13 The Resin .................................................................................................. 7-16

Leak Detection Service .........................................................................7-17Advantages ................................................................................................ 7-17Procedure...................................................................................................7-17

References ...........................................................................................7-19

NOTE

To read information on a particular subject, click the heading in the Bookmarks (far left) or click the corresponding colored box below.

7-2 Other Nitrogen Applications


Other Nitrogen Applications

Fig. 7-1: Sand washing using coiled tubing.

Casing

Tubing

Coiled Tubing

Packer

Sand Washing

One of the most common problemsassociated with producing oil and gas wells is�sand production.� This problem occurs inwells completed in unconsolidated or looselyconsolidated sandstone reservoirs or in wellsrecently subjected to fracture stimulation.

Coil tubing can be used to clean out(wash) sand from a wellbore in much thesame manner as with a conventional work-string; fluid is circulated at rates sufficient towash the sand back to the surface. Thetubing is lowered as the sand is displacedfrom the wellbore.

The obvious advantage of continuous coiltubing over jointed tubing for sand washingis the ability to maintain circulation whilegoing in or coming out of the hole, or whenwashing sand under pressure. When usingjointed tubing, the circulation must be inter-rupted whilemaking up orbreaking downjoint connections.

Water iscommonly usedfor sand wash-ing, but manywells requireusing lighter,compressiblefluids. Com-pressible washfluids used incoil tubingservice are dryN2 and foams(aqueous or oil-based). These

lighter fluid sytems offer many benefits forlow-pressure or liquid-sensitive reservoirs.

Wash-fluid density is designed to mini-mize fluid losses to the reservoir, to minimizepressures in the wash string, and to minimizethe pressure drop at the surface returns side.Incompressible fluids are commonly usedwhen velocity is the major fluid criteria, andcompressible fluids are commonly used whensolids-carrying capability is the major fluidcriteria.

Incompressible Wash Fluids

Both water and hydrocarbon liquids arecommonly used as incompressible washfluids. They can be used when sufficientformation pressure exists to allow circulationof these fluids in the well. The design ofthese wash fluids is based on formationcompatibility, well deviation, required


solids-transport capability, rheology, andsurface logistics.

For wellbores deviated above 30°, increas-ing the wash fluid viscosity reduces cleanoutefficiency, and cleanout becomes most diffi-cult around 60° deviation. For deviations lessthan 30°, increasing circulating fluid viscosityresults in more efficient sand cleanout. Maxi-mizing annular velocity and wash stringcentralization improves cleanout efficiency.A given wash fluid will carry solids out of awell if the annular velocity exceeds theterminal particle settling velocity. Due to theneed to prevent holdup of solids in theannulus and unknowns about the nature ofthe solids being removed, designs typicallyaim to have the fluid velocity twice theparticle settling velocity. When annularvelocity is less than 100 ft/min, adding aviscosifier may be necessary. It is recognizedthat most combinations of coiled tubing andcasing diameters will not allow wash fluids(slurries) to achieve turbulence in the annularspace even when water is used.

Compressible Wash Fluids

Compressible wash fluids are composedof gas and either water-based or oil-basedliquids and surfactants. The liquid phase ischosen on the same basis as noted above.Compressible fluids are more difficult todesign and use than incompressible fluids.Compressible wash fluids are composed ofvarying gas fractions and are used to com-pensate for low bottomhole pressure (BHP)formations or to lift solids when annularliquid velocities are low. Since fluid volumeschange with temperature and pressure in acompressible system, wash-fluid returns willnot travel at the same rates throughout theannulus.

Sand Washing with Foam

In some wells, the maximum velocity thatcan be achieved with incompressible fluids isinsufficient to carry the sand from the well-bore to the surface. This may be due to theextreme depth, the production tubing beinglarge, the formation pressure being too low,or a combination of these and other factors.In such cases, a compressible fluid such asfoam is required.

Foam can be generated in hydrostaticpressure gradients ranging from 0.350 to0.057 psi/ft, depending on wellbore pres-sures and temperatures. Stable foam rheol-ogy most closely resembles Bingham plasticfluids, where yield stress must be overcometo initiate fluid movement.

The greater sand-carrying capacity offoam allows sand to be washed from deep,large diameter holes with limited pump ratesand low velocities. This makes the use of coiltubing possible in wells that might otherwiserequire a workover unit.

Foam is a gas-in-liquid emulsion consist-ing of 52 to 96% gas, ideally N2. For thisapplication, the liquid can be aqueous or oil-based. Surfactants are mixed with the liquidphase in concentrations ranging from 1 to 5%by volume to reduce surface tension. The�wet� liquid phase is then commingled withN2 in a foam-generating tee. Turbulencecreated by N2 and wet liquid mixing providessufficient dispersion to form a homogeneous,emulsified fluid.

Foam is generated by pumping a mixtureof 99% water and 1% surfactant through anatomizer tee where it is mixed with N2 gas.Because foam is comprised mostly of gas,changes in pressure, temperature, and solidsloading affects the foam quality. As such,compressible fluids have constantly changingrheology. It is well understood that thecompressible fluid has maximum carryingcapacity when the foam quality is maintainedat 65 to 90.


Operations

Predicting annular velocities and solidsremoval capability requires complex calcula-tions. Sand-washing foam fluids are generallydesigned using a computer program likeFOAMUP. The sand washing rate can beestablished within the need to maintain awash fluid quality of 65 to 90.

To calculate the N2-to-fluid ratio, a bot-tomhole treating pressure must be assumed.This pressure should be less than the reser-voir pressure to sustain circulation withoutlosing fluid in the formation. After thebottomhole circulating pressure to be used isdetermined, foam calculations should beperformed using the stable foam calculatingsheet or a computer program.

Because a circulating system is beingused, a surface backpressure value equal tothe bottomhole pressure less the hydrostaticweight and friction pressure loss of thecolumn of foam must be maintained tocontrol the foam quality at depth. A surfacechoke system is needed to maintain thebackpressure on the system consistent withmaintaining the foam quality in the wellsystem. Managing this choke system andhandling the returning foam and solids needcareful consideration. Preparation must bemade for foam disposal if necessary. Thefoam liquid may be recirculated if no hydro-carbons are mixed with the foam and all sandis first removed.

The coil tubing and all surface equipmentshould be tested before going in the hole.Circulation of foam should be started at thesurface to displace any fluids in the hole asthe tubing is lowered and to be sure there iscirculation on reaching the sand fill. Thewashing operation should not be performedtoo fast; the sand carrying capabilities offoam, although excellent, could be exceeded.

Care should be taken not to wash downinto the solids too fast. Surface observationand measurement of solids washed is gener-

ally required. Often, a settling tank is used.Solids that are entrained in wash fluid mustbe continually removed from the well. Theoperator's experience should be used todetermine the best sand-washing rate alongwith the pipe size, fluid rate, and N2 ratesince the nature of the solids entrained areoften only the subject of speculation prior tothe job.

Once circulation is established in a com-pressible wash program, unit volumes ofwash fluid are pumped down the coiledtubing at pressures needed to overcomefriction pressure losses. In this condition,wash fluid is under high pressure and occu-pies minimal volume. As a unit volume ofcompressible fluid exits the coiled tubing,decreasing hydrostatic head in the annulusand reduced friction pressure allow gas in thewash fluid to expand. This expansion andsubsequent increases in wash fluid velocitycreate high frictional pressure losses.

After washing the sand to the desireddepth, circulation should be maintained untilthe returns are clean. The bottom should betagged several times to ensure that all sandhas been removed. After the well is cleanedout, it may be jetted in or filled with fluid bystopping either the water or N2.

Wash Penetration Rate

Coil tubing rate of penetration intopacked solids, coupled with annular fluidvelocity, determines the solids concentrationin fluid returns. Dispersion of solids in washmedia causes an increase in effective weightof annular fluid returns. As a result, thehydrostatic pressure differential between�clean� wash fluids in the coiled tubing and�dirty� fluids in the annulus increases.

It is not uncommon to run 1 1/4-in. ODcoiled tubing in 2 7/8-in. OD productiontubing at 60 ft/min when washing sand. Ifwash fluid is circulated at 0.50 bbl/min,annular fluid velocity is about 2 ft/sec. The


unobstructed production tubing volume is0.0325 ft3/ft and the annular volume is 0.0240ft3/ft. If there is greater than 60 ft of loosesand above a bridge, the coiled tubing canpenetrate 60 ft in one minute. At an annularvelocity of 2 ft/sec, 180 ft of annulus isdisplaced by �dirty� fluids.

Penetration of loose sand packs aregenerally not indicated at the surface andseveral sand bridges may be encounteredwhen washing deep production tubing. Ifsufficient circulation time for solids to reachthe surface is not allowed, significant hydro-static pressure increases could develop in theannulus due to entrained solids. If thisoccurs, increased hydrostatic pressure fromdirty annular fluids may force some fluid intothe formation. If, as a result, annular velocityis reduced below the rate required to keepparticles suspended, solids will fall back andcould stick the coiled tubing.

Produced Fluids

Formation fluid types can also determinehow a wash program will proceed. In aliquid-producing wellbore (oil and water),fluids are essentially incompressible and cansupport a �piston� displacement of solids upthe annulus. If produced fluid is gas, beprepared for �gas kicks� or lost returns whenbreaking through sand bridges. In addition,the difference between gas and liquid densi-ties can allow gas to override wash fluids.This results in loss of wash fluid to the forma-tion, regardless of BHP.

When washing low BHP oil wells withaqueous foam, be prepared for foam degra-dation when it commingles with oil. Oil willdestabilize foam regimes at the contactinterface, which breaks down into a gassified,oil-water emulsion. As the foam degeneratesand moves up the annulus, the sand-ladenreturns become compromised and solidsfallback can occur.

Wash Tools

Wash tool selection should be governedby wash program hydrodynamic require-ments. Wash tools should only be used ifadditional turbulent action is needed down-hole. Several tools are available for portedhydraulic jetting on packed solids or me-chanical action to break up bridges. Thesewash tools can often be constructed to serveas bypass mandrels, further extending theiruse. Depending on wash port number, sizeand wash fluid system selected, frictionalpressure losses can range from 50 to 2,500psi.

Conventional Circulation

Pumping fluid down tubing and takingreturns up the annulus is the most commoncoiled tubing technique for washing solids.In addition to wash fluid system criteria,maximum tensile loads on coiled tubingstrings should be estimated to ensure thatstress does not approach minimum tubeyield.

Both compressible and incompressiblefluids can be used with conventional circula-tion. Selection of an appropriate size ofcoiled tubing depends on minimum pumprates, total circulation system pressure losses,and minimum load rating required to safelywash and retrieve pipe from the well. Use ofdownhole safety check valves and portedwash tools does not limit conventional circu-lation wash programs.

Job Procedure

1. Rig up equipment according to stan-dard operating practices. Checkflowlines to make sure a minimum ofells are installed and that flow linesare properly secured.

2. Install a flow tee under the BOP's todirect returns out of the well so that


cutting out the Christmas tree isavoided.

3. Install an adjustable choke in theflowline (particularly applicable tofoam washing) and have a replace-ment stem on location.

4. Pressure test coil tubing unit and treeto 110% of maximum expected work-ing pressure or minimum anticipatedsurface pressure, whichever is greater,before going in the hole.

5. Start the tubing in the hole at 30 to 40ft/min if top of fill is unknown whilecirculating fluid at a slow rate. If topof fill has been located, do not exceed60 ft/min.

6. Check tubing drag every 1,000 to1,500 ft to prevent sticking the washstring. Have coiled tubing representa-tives identify tubing sections thathave been cycled extensively andavoid conducting periodic drag testsin these intervals.

7. Wash the sand slowly. When break-ing through bridges, allow sufficienttime to circulate solids from the wellbefore continuing downhole. Stringsand out in case of lost circulation toprevent sticking the wash pipe.(When washing with foam, fluid canbe lost in the formation and still showreturns on surface; therefore, thepressure recorder chart should bemonitored for pressure loss.)

8. Before entering open casing, alwayscirculate a minimum volume of fluidthat would fill the tubing string twice.(Run wash tool in open casing).

9. Maintain returns throughout the washprogram. If circulation is lost duringthe operation, immediately pull thetubing up the hole approximately2,000 ft; hold there and work untilcirculation is regained.

10. Maintain circulation until tubing ispulled completely out of wellbore.

11. Keep pipe moving at all times whilejetting.

Unloading Wells

During the life of oil and gas wells, wellcontrol practices during completion orworkover can create hydrostatic overbalance,which can reduce inflow performance andmay cause the well to stop producing. Thisoverbalance results from the pressure offluids in the wellbore exceeding the produc-ing formation pressures. Temporary andlengthy shut-in periods can also create hydro-static overbalance when the once activewellbore loads up with fluid. If no otherdamage exists, wells can often be returned toproduction by reducing the hydrostaticpressure of the fluid column. Once anunderbalance is created, the well can flowagain.

Unloading Design Considerations

Before an unloading program is designedand started, the well�s flow and productionpotential must be determined. Sas-Joworsky4

provides equations for estimating reservoirfluid production rates and well flow rates inhis article titled �Coiled Tubing...Operationand Services, Part 5�Unloading Wells withLighter Fluids.� He also explains the follow-ing mechanical considerations:

� completion type� wellbore tubular sizes� workover service tubing size� required operating system pressure

for surface flowlines and separationequipment

These mechanical parameters are used topredict �backpressure,� which is systempressure losses. Backpressure decreaseseffective formation drawdown and reducesfluid production to surface.


The tubular sizes are the most importantmechanical factor for unloading wells. Pro-duction tubing ID determines flowing liquidhead and frictional pressure loss for a givenproduction flow rate and gas-liquid-ratio(GLR) when producing fluids to the surface.As tubing ID increases, fluid velocity andfrictional pressure losses in the flowing fluidregime decrease. However, as fluid velocitydecreases, slippage and flowing pressuregradient increase. The effects of pressure lossin the tubing become critical when trying toflow fluids to the surface with coiled tubingconcentric to production tubing.

Unloading Concerns

Numerous coiled tubing service tech-niques can be used to reduce wellbore hydro-static pressure, thereby achieving anunderbalance and unloading wellbores. Theobject of these techniques is to initiate flowfrom the formation without creating adverse�pressure shocks� downhole. In many cases,varying degrees of skin damage in thecompletion interval clean up as the wellboreunloading program progresses. However,apparent skin damage could also be due torelative permeability changes near the well-bore, perforation plugging, or damage depos-ited during completion or workover.

Once a maximum recommended pressuredrawdown has been selected, it should not beexceeded during unloading programs. Ifproduced fluid volumes remain significantlybelow projected flow rates for the applieddrawdown, it is most likely due to inaccurateparameters in flow potential calculations, butactually, something may be wrong downhole.

A common response to low surface flowrates is to increase drawdown and hope thatdownhole flow restrictions dissipate. Unfor-tunately, this reaction generally causesformation integrity failure in unconsolidatedformations, resulting in perforation tunnelcollapse and damaged flow potential. Con-

solidated formations are somewhat moreforgiving and may not be damaged as muchfrom downhole pressure shocks. Unloadingprograms should be designed to create theminimum pressure drawdown needed toinitiate flow. Once stable flow is established,formation damage can be properly assessedand corrective steps taken.

Nitrogen-Assisted Unloading

The most common method used tounload wells is nitrogen (N2) circulationthrough coiled tubing run to a predetermineddepth below the static fluid level. Althoughthis technique is commonly called �jetting� or�jet-lifting,� it starts flow by reducing well-bore hydrostatic pressure through aerationand not by �jetting� the fluids to surface. N2

is most commonly used for unloading pro-grams because it is chemically inert and onlyslightly soluble in liquids. Coiled tubingconveyed gas circulation offers greater usethan conventional single-point gas-lift opera-tions because the gas injection point can bemoved up and down the wellbore to opti-mize fluid withdrawal rates.

Nitrogen Behavior

When using N2 to unload wellbores andinitiate flow, it is important to recognize theeffects of lifting high GLR fluids within theannulus between the coiled tubing OD andthe production tubing ID. As the annulusarea decreases, annulus pressure lossesincrease exponentially. Also, the length ofconcentric coiled tubing inside the productiontubing significantly affects annular frictionpressure loss and flowing fluid head.

Nitrogen pumped down the coiled tubingis compressed to overcome the annulus fluidgradient. As the N2 injection point is loweredfurther into the well, the increased pressuregradient compresses the N2 more. When N2

exits the coiled tubing and starts to rise in the


annulus, it expands. This expansion of N2

dispersed in the annular liquid increasesapparent fluid velocity, resulting in a furtherdecrease in flowing pressure gradient. Nitro-gen expands dramatically as it continues toflow to surface.

Fluid velocity and frictional pressurelosses in the annulus increase significantlyrelative to velocity and frictional pressurelosses at the downhole N2 injection point.Turbulence from the expanding gas increasesfrictional pressure loss. At some depth in thewell, based on well parameters, frictionalpressure losses will overcome reduced pres-sures from flowing fluid gradients in thetubing annulus. Also, decreased annularcross-sectional areas greatly increase fric-tional pressure losses for equivalent N2 andliquid circulation rates. A higher N2 circula-tion rate may actually yield lower productiondue to reduced annular cross-sectional areaand the exponential increase in systemfrictional pressure loss. If this fluid produc-tion drop is not interpreted correctly, theinjection point may be run deeper into thewellbore and the N2 injection increased. Thisreaction could be disastrous by creatinggreater frictional pressure loss in the annulusand, in some cases, causing liquid flow tocease.

To increase flow from the completion, N2

circulation must be cut back very slowlywhile pulling the coiled tubing back up thewellbore. If a high circulation rate is inter-rupted while deep in the tubing, the rapiddecrease in annular friction pressure loss maycause a �pressure shock� at the formation.This pressure shock can be greater thanrecommended pressure drawdowns foroptimum well performance and inducesudden, uncontrolled flow rates that candamage the completion. For these reasons,using the smallest coiled tubing size availableand performing unloading procedures withthe lowest possible N2 circulation rates isrecommended.

Nitrogen Unloading Methods

Continuous injection- The most effectivemethod for achieving an underbalancedhydrostatic head with N2 is to run coiledtubing into the wellbore while slowly circu-lating nitrogen. This technique allows N2 inthe fluid column to disperse in the wellbore,thereby aerating annulus liquids slowly andinitiating production from the formation in acontrolled manner.

In initiating an unloading program withN2, coiled tubing is run in the well at about 40to 60 ft/min. Low N2 circulation rates, gener-ally from 150 to 250 scf/min, are initiatedwhen the end of coiled tubing is just abovethe fluid level to minimize waste. Coiledtubing is then lowered to a predetermineddepth in the well to assist fluid lifting untilthe completion can sustain production. Ascoiled tubing is run into the wellbore, thefluid column is aerated, creating anunderbalanced effect.

Intermittent injection- Another techniqueused to lighten fluid columns is intermittentN2 injection. This is accomplished by runningcoiled tubing to a predetermined depth belowthe fluid level in a wellbore before starting N2

pumping. In this case, N2 pump pressuremust be greater than the fluid column hydro-static pressure at the injection point. Once N2

injection pressure overcomes fluid columnhydrostatic pressure, N2 enters the annulusand initiates a single-point gas lift operation.As wellbore pressure above the N2 circulationpoint decreases, gas expansion in the coiledtubing accelerates, causing an effect similar toan N2 circulation rate increase. This maycause undesirable and erratic wellbore pres-sure drops, which can destabilize pressuredrawdown at the formation.


Gas Displacement

Nitrogen is most widely used to displacewell fluids from the tubing string or from thewell system to begin oil or gas production.When the well is completed with a singlestring of tubing without a packer, or with acirculating valve, the fluid is displaced downthe tubing and out of the annulus (Fig. 7-5).On a single completion with a packer, thefluid may be displaced out of the tubing intothe annulus before the packer is set. By usingN2 for gas displacement, you can save rigtime and eliminate the danger of lost swabs.Not only can N2 reduce the danger of damag-ing internal pipe coatings, but it can displacefluid in multiple-diameter tubing strings. Youcan control the return fluid rate during gasdisplacement by reducing N2 pressure.

Nitrogen is chemically compatible with allcompletion fluids and formation waters.After treating the formation with frac, acid, orother chemicals to control corrosion, scale,and paraffin, you can use nitrogen to displacethe treating fluid from the tubing into theformation (Fig. 7-6).

Nitrogen gas is chemically compatiblewith all completion fluids, does not damagethe formation, and allows faster cleanup and

flowback without swabbing, because it haslow hydrostaticity.

Another way to return reusable comple-tion fluids, remove sand from the tubing, orprovide annulus insulation is to displacefluid from the annulus into the tubing (Fig. 7-7). Fluid can be displaced around open-endedtubing, around an unseated packer, orthrough a circulating valve.

This technique is successful because N2 isnoncorrosive to tubing and casing. It reducesheat transfer because of the low specific heatand thermal conductivity. Because N2 has a

Completion fluid,gas, or gas andsand

N2

Casing

Fig. 7-6: Fluid displaced from the annulus into thetubing.

N2 gas at wellheadpressure (WHP)

Casing

Packer

Fig. 7-7: Fluid displaced from tubing into the formationwith nitrogen.

N2 gas at wellheadpressure (WHP)

Casing

Tubing

Bottomhole pressure(BHP)

Fig. 7-5: Fluid displaced down tubing and out theannulus.


low density, it also allows circulation withlow bottomhole pressure.

Pressurizing Medium

When used as a pressurizing medium, N2

can be used for the following:� drillstem test cushion� perforating technique� gas lift medium

Drillstem Test Cushion

A water or N2 cushion is sometimes usedon a drill stem test (DST) for five purposes:(1) protect the drill pipe or tubing fromcollapse, (2) protect unconsolidated sandsfrom caving in when the tester valve opens,(3) help control high pressure and highvolume wells by bringing-in the well slowly,(4) help prevent dehydration of the mud orsalt water when the tester valve opens onhigh temperature (above 375°F) wells, and (5)help relieve the sudden differential pressureacross the packer seat.

While a cushion may help in these ways,it may also hinder obtaining a good drill stemtest. When testing hard-rock formations,considerable rig time can be saved by usingminimum cushions or no cushion at all. Wellsthat flow to the surface must first get rid ofthe cushion prior to really starting to obtaininformation on the test. Gas wells clean upfaster with minimum cushion.

Minimum cushion puts maximum differ-ential on the formation and packers when thetester valve opens rather than during themiddle of the test when the cushion has beenremoved. This is important when using anitrogen cushion. If the packer or packer seatis going to fail, it will do so immediatelywhen the tester valve opens rather thanseveral hours later after bleeding of the N2

cushion.

Too much water cushion could result inan indication of a dry test when actually itwas caused by the hydrostatic head of thecushion being greater than formation pres-sure. Conversely, unconsolidated formationsmust be protected by a cushion. In thisinstance, the cushion is beneficial because itreduces the differential pressure suddenlyapplied across the face of the formation whenthe tester valve opens. Too much differentialacross the face of the formation will manytimes cause an unconsolidated formation tocave in or produce extreme quantities ofsand, plugging the tools and possibly causinga stuck string.

Maximum differential pressure across theface of the formation will result in highestproduction rate; therefore, when the drillpipe, the formation, and safety permit,miminum cushion should be used.

To use N2 as a DST cushion, perform thesteps below:

1. Before a packer is set, pressure thedrillpipe with N2 gas to check forleaks. You can do this with or withouta water cushion, depending on theneed for collapse protection.

2. After the packer is set and the toolopened, bleed the pressure at thesurface to increase the pressuredifferential into the tubular string.

Perforating Technique

Using a nitrogen cushion in perforationreduces fluid damage to the reservoir andperforation damage to the formation. Itcontrols production rate by controllingsurface pressure reduction. To perforate withN2, perform the following steps:

1. Displace well fluid from the tubingstring to the needed depth.

2. Set the packer and secure the well-head.


3. After the perforating gun is in posi-tion, adjust the pressure within thetubing string with nitrogen.

4. Perforate with positive pressuredifferential into the wellbore.

5. Retrieve perforating tools and ventthe tubing pressure to start produc-tion.

Gas Lift Medium

Using nitrogen as a gas lift allows sam-pling and gauging reservoir fluids. It also caninexpensively remove fluid from stimulationor zone communication. To use N2 as a gaslift, the following steps must be performed:

1. Displace the well fluid from thetubing out through the continuoustubing/production tubing annulus.

2. Continue to circulate N2 gas to carryformation fluids to the surface.

3. Continue injection until the well willflow naturally. Note: production datais sometimes provided for sizingpermanent gas lift equipment.

Commingled Gas

Nitrogen can be commingled with vari-ous well treating fluids to

� reduce mud weight� remove differentially stuck pipe� perform hydrojetting

Reduce Mud Weight

Nitrogen is commingled with drillingfluids to reduce mud weight and combat lostcirculation. This can be done while drilling orperforming primary cement jobs. Nitrogenquickly dissipates from the drilling mud onreturn to the surface, allowing quick return toheavier weights.

Nitrogen eliminates fluid-loss materialsusually needed for balanced orunder-pressure drilling. It is chemicallycompatible with all mud systems and in-creases cement circulation height.

Remove Differentially Stuck Pipe

Nitrogen can be commingled with mud orused to displace mud in techniques thatlower bottomhole pressure. Reducing well-bore pressure until it equals the pressuresurrounding the pipe will allow it to beremoved.

Another technique used to remove pipe isto spot a bubble of N2 gas over the differen-tially stuck zone. The low viscosity and highleakoff rate of the N2 will tend to equalizepressure around the pipe. Using N2 for thispurpose is beneficial because it does notdamage the mud system.

Perform Hydrojetting

Hydrojetting involves mixing N2 with thegel and sand to increase the penetration rate.As expanded gas passes through, the nozzleaccelerates sand speed.

When used this way, N2 increases thepenetration rate, maintains circulation pastlower pressure formations, and reduces therisk of fracturing the formation being jetted.


Sand Consolidation

In gas production operations in the Gulfof Mexico, a gravel-pack screen was salvagedby applying furan resin for near-wellboresand consolidation. This technique differsfrom traditional sand consolidation methodsin that coiled tubing is reciprocated across thegravel-pack screen interval throughout thetreatment. Additionally, nitrogen is com-mingled with all injected liquids to createshort-lived foams that expand the volume ofthe liquids, provide some diverting effect,and help ensure maintenance of permeabilityduring the treatment. The procedure wasdone at about one-fifteenth the expected costto replace the gravel pack, which was esti-mated at more than one million dollars.2

The work was needed after an upper gaszone was accessed with a jet punch. Gasproduction after the tubing was punched wasmore than 14 MMcfd, however, buildup testsindicated a flow potential of 18 MMcfd. Anacid stimulation treatment was performed,after which the well began to produce sandand had to be choked back to 2.5 MMcfd toavoid sand production. After the resin repair,flow recovered to 13 MMcfd with no sandproduction.

Originally, the completion was a selectivealternate, or �stack pack,� where two reser-voirs were gravel packed by installing twoscreens (separated by packers) on one stringof production tubing. The lower zone wa-tered out and was shut off by setting a plugin a landing nipple in the isolation string (Fig.7-2).

Operations

Once sand production began, a remedialoperation to replace the gravel-pack screenwas estimated at $1.3 million, or 15 times theestimates for repair by resin. The excessivecost for a rig workover and the fact that

Table 7-1: Well Data

Casing 7 in., 3.5 lb/ft

Tubing 3.5 in., 12.95 lb/ft

PerforationsCasing- 11,465 to 11,497 ftIsolation Tubing- 11,467 to11,494 ft

Gravel-pack assembly 4 in., 0.007 gauge x 42 ft

Gravel-pack packer 11,351 ft

Bottomhole temperature 210°F

Bottomhole pressure(est.)

2,570 psi

Plug back TD (PX plug) 11,499 ft

Deviation 22°

Well Type Gas

Fig. 7-2: An isolation string (extension of the productiontubing) with a landing nipple, was run across the uppergravel pack during initial completion. A plug was set inthe landing nipple to shut off watered-out lower zone. A“tubing punch” was performed to penetrate the isolationtubing.

additional completions existed in the samereservoir made sand consolidation the logicalchoice.

A 200-ft class liftboat with coiled tubingand nitrogen units aboard was preloaded and


moved into position. The outline of theplanned procedure was as follows:

1. Rig up N2 and 1-in. coiled tubing withnozzle.

2. Test all surface equipment to 5,000psi.

3. Pickle coiled tubing with 250 gallons15% HCl with acid inhibitor anddisplace with 2% KCl (12 bbl) contain-ing 35 lb pH neutralizer.

4. Go in hole with coiled tubing andwash well down to plug back TD at11,499 ft. Use filtered 2% KCl waterthroughout washing operations.Foam, if necessary.

5. With end of coil tubing positionedacross perforated interval, spot thefollowing treatment and squeezeaway at 1/4 to 1/2 bbl/min:� 2,750 gal 15% sodium chloride(NaCl) water containing 0.25 % surfac-tant and 600 scf/bbl N2

� 1,060 gal externally catalyzedfuran resin containing 600 scf/bbl N2

� 1,000 gal 15% NaCl water contain-ing 0.25% surfactant and 600 scf/bblN2

� 3,500 gal 10% HCl with catalystmixed in NaCl water containing 0.25%surfactant, 0.3% acid inhibitor, and600 scf/bbl N2

� Displace coiled tubing with fil-tered 2% KCl water (12 bbl)

6. Shut well in for 8 to 12 hours whileresin cures.

7. Resume production at 4 MMcf/Duntil load water is recovered.

However, the coiled tubing (furnished bya third-party vendor) parted after placing theresin. The well was killed with brine, and theparted tubing was fished from the well. Sincethe resin used was externally catalyzed, the40-hour delay resulting from the fishing jobhad no effect on the resin. When repairoperations resumed, the catalyst wasoverflushed through the gravel pack and

consolidation occurred as planned. The actualjob was as follows:

Day 1:� Preloaded jackup rig arrived on

location.� Rig jacked up in place.� Coiled tubing rigged up.� Started pressure test.Day 2:� Pressure tested to 5,000 psi.� Ran in hole to 9,810 ft; stripper on

injection head blew out.� Stripper replaced; continued in hole.� Pumped 2,750 gal 15% NaCl2 water

with 0.25% surfactant and 600 scf/bblN2.

� Pumped 1,060 gal resin containing 600scf/bbl N2.

� Followed with 1,000 gal NaCl2 with0.25% surfactant and 600 scf/bbl N2.

� Pulled up off bottom.� Discovered coiled tubing had parted.� Went in hole and found the tubing

below the stripper.Day 3:� Mixed and pumped 65 bbl NaCl water

at 1/4 bbl/min and 200 psi downcoiled tubing to kill well.

� After well was dead, went in hole andcaught fish at 28 ft.

� Removed injector head and made cut.� Well came in, everything secure.� Pulled out of hole.� Pulled coiled tubing out of head and

swapped out reels.� Rigged up new coil.� Went in hole to pump acid.Day 4:� Pressure tested new coiled tubing.� Ran coiled tubing in hole to bottom.� Pumped 3,500 gal 10% HCl with

catalyst.� Displaced with 2% KCl water.� Pulled out of hole.� Rigged down.


Figs. 7-3 through 7-5 show the stages ofthe treatment. N2 has been commingled withall the injected fluids in this treatment.Nonreactive and immiscible with the otherfluids formed, the N2 inclusion forms of ashort-lived, volume-expanding foam. The N2

in the foam acts as a diverter during themultiple-phase flow to help maintain perme-ability. In Fig. 7-3, the saltwater preflush hasentered the screen and exited casing perfora-tions to contact formation sand. In Fig. 7-4,resin has been pumped and is coating thesand. The coiled tubing has been reciprocatedacross the screen interval to direct the fluid atthe borehole wall (on longer intervals, aspecial nozzle can be attached to the end ofthe coil optimize fluid flow direction). Thesaltwater �spacer� slug and the catalyst havebeen pumped in Fig. 7-5, and the gravel packrepaired by the resin coating in-situ sand ishardening and forming a permeable but solidsand filter. A final brine flush is injected toenhance displacement of the acid catalyst.

Fig. 7-3: The brine preflush has entered the screenand exited the casing perforations. This salt water willhelp prepare the sand surfaces for adsorption of theresin.

Fig. 7-4: Resin has been pumped into the well andsprayed laterally against the walls of the borehole alongthe damaged interval. The resin is coating the sand andwill be further dispersed into the formation by the brinespacer before the catalyst is injected.

Fig. 7-5: The catalyst overflush has been injected,and the resin is hardening. After curing is complete,the gravel pack repaired by this in-situ resin coating willform a permeable but solid sand filter.


Typically, such sand packs have 85 to 90% ofthe original permeability.

The set resin is resistant to acids (exceptHF), brines, alkalies, and other common welltreating fluids. Laboratory tests on the dura-bility of sand consolidation resin systemsshow that furan resins remain stable andretain high strength when subjected to dam-aging fluids. Brine, considered to be moredamaging than oil to the stability of resin-consolidated sand, was selected as the testfluid. Field experience with furan resinoverflush treatments indicate no resin con-solidation impairment where brine has beenproduced.3

The Resin

The resin system used in the screen repairwas a water-compatible, furan resin catalyzedby overflushing with acid. Long noted forhigh temperature stability, the furan resinshave been widely used as a foundry coreresin binder.4 As described in job procedures,NaCl water is placed ahead of the resin andpumped between the resin and catalyst. Thesaltwater lead is placed to help prepare sandsurfaces for the chemical reaction needed forthe resin to adsorb on the sand.

A notable benefit of externally catalyzedresin in sand-packing treatments has been thefact that it has been possible to reverse circu-late excess coated sand from the wellbore.The well can then be repacked before inject-ing the catalyst because the resin does not setuntil contacted by acid.4 This proved espe-cially beneficial when the fishing job requireda 40-hour delay before catalyzing. The tail-inload of salt water (the spacer) separates resinfrom catalyst so that no partial reaction isstarted until resin is properly placed. The saltwater also begins removal of excess resinfrom pore spaces, flushing the resin furtherinto the formation.

Traditionally, furan resin has been usedin sand control treatments both to consolidate

formation sand �in-situ� and to precoat sandat the surface before pumping downhole.Extra resin has normally been injected afterwashing out the excess pack sand and beforepumping the catalyst to consolidate a portionof the formation sand adjacent to the packsand. This new treatment is unusual in thatlarge grained pack sand is being treated inplace. An average radius of over 3 ft may beexpected from in-situ consolidations of thiskind.3,4

Resin-coated sand has also been used torepair damaged slotted liner gravel packs insituations where productivity of the well,environmental impact, or a severely damagedliner would preclude the expense of completeliner workovers. The use of resin-coated sandin such a repair job is relatively economicaland has been marginally successful. Wherethe original liner was in place and could betreated directly, the success ratio has been90% or more, but in cases where a wire-wrapped screen has been used as an innerliner, the results have not been as satisfac-tory.5

Because the damaged screen must becompletely cleared of sand on both the insideand outside, so that resin coated sand can besqueezed through the damage area and formthe �patch,� the above alternative approachwas rejected. There was no way to ensureremoval of both the pack sand and theinvasive formation sand in the well.


Leak Detection Service

Essential to the operation of oil and gasprocessing systems is the knowledge that theplant is in a safe operating condition. Withthe ever increasing demands and complexityof our often aging processing plants, thehandling of toxic gases at high pressuresrequires the need for stringent safety stan-dards. To comply with these standards, wehave to be able to locate and repair all leaks.

Halliburton has developed an efficientand cost effective technique for purging andleak detecting a processing plant. Halliburtonhas the capability and expertise to sweep outthe dangerous gases. Halliburton�s N2 con-verter pump is a self-contained, flamelesstwin pump that provides high pressure, highrates, and/or low rates to cover the numer-ous types of jobs demanded.

Conventional methods such as hydro-statically testing, visual inspection, or, on gasplants, a soap solution for detection ofbubbles, are all unrepresentative and limited.However, for accuracy and reliability, HeliumLeak Detection gives results at a level notpreviously known in the oil and gas industry.

Advantages

Halliburton�s Helium Leak Detectionadvantages include the following:

� Simulates �live� gas conditions� Tests conducted at operating pres-

sures� Gases are safe and inert.� No need to remove instrumentation� Forms an integral part of the hook-up

program� Uses reliable and robust technology� Helium is rare in the atmosphere,

therefore, sensitivity cannot be com-promised by other gases.

� The process saves time and costs bypermitting leak testing to be carried

out before start up and by removingthe need for �live� gas detection.

� By giving a quantifiable leak rate, it ispossible to monitor leaks over aperiod of time to determine anydeterioration of the joint.

Using standards derived from the USNavy in testing their submarine nuclearreactor compartments, Halliburton has thecapability of detecting leaks of 1 scf/yr to100,000 scf/yr using the same mass spec-trometer. Using our Zone II* pump unitsand our certified N2 tanks, we will safely,under controlled conditions, bring plantsections up to working pressure. Operatorscan then proceed with leak detecting.

Procedure

A vessel or section is first isolated. Halli-burton then ties in with a high-pressure 3/4in. hose and pumps 99% N2 gas and 1%helium gas into the vessel until the operatingpressure is reached. All flanges, valves, valvestems, etc. are taped or bagged using ducttape or plastic bags. This will contain thepossible leak. Upon pressuring the vessel,the leak detector will pierce the tape or bagand draw a sample through the previouslycalibrated mass spectrometer. Should morethan 5 scf/yr gas leak be monitored andrecorded, then the flange is a �fail� andwould require a retest after further mainte-nance. Less than 1 minute per test is re-quired.


Fig. 7-4: Helium leak detection schematic.


References

1. Sas-Jaworsky II, A.: �Coiled Tubing...Operation and Services, Part 5�Unload-ing Wells with Lighter Fluids,� World Oil(April 1992) 59-66.

2. McInturff, C., et. al.: "Resin Salvages GravelPack in Offshore Well," Oil & Gas Journal(Sept. 30, 1991) 94-96.

3. Rensvold, R.F.: �Sand Consolidation Resins- Their Stability in Hot Brine,� paper SPE10653 presented at the 1982 SPE Forma-tion Damage Control Symposium,Lafayette, Mar. 24-25.

4. Murphey, J.R., Bila, V.J., and Totty, K.:�Sand Consolidation Systems Placed withWater,� paper SPE 5031 presented at the1974 SPE/AIME Annual Fall Meeting,Houston, Oct. 6-9.

5. Murphey, J.R., Roll, D.L., and Wong, L.:�Resin-Coated Sand Slurries for Repair ofDamaged Liners,� paper SPE 13649presented at the 1985 SPE CaliforniaRegional Meeting, Bakersfield, Mar. 27-29.


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