nitrogen foams

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1 Nitrogen Foams Applications & Calculations Lesson Objectives In this chapter the student will learn: How foamed fluids are different from commingled fluids. Benefits and calculations of acids when foamed. How foams can be used for diverting. Benefits and calculations for proppant laden fluids when foamed. Effect nitrogen has on cement when foamed Foam generators, what they are and how to use them. Lesson Introduction Background of Foam in the Oilfield Foams are being used in a number of petroleum industry applications that exploit the foams' high viscosity and low liquid content. Some of the earliest applications for foam dealt with its use as a displacing agent in porous media and as a drilling fluid. Following these early applications, foam was introduced as a wellbore circulating fluid for cleanout and workover applications. In the mid-1970s, nitrogen-based foams became popular for both hydraulic fracturing and fracture acidizing stimulation treatments. In the late 1970s and early 1980s, foamed cementing became a viable service, as did foamed gravel packing. The early widespread use of foams as fracturing fluids was to help low-pressure gas reservoirs in returning the liquid phase of the

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Nitrogen Foams

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Page 1: Nitrogen Foams

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Nitrogen Foams

Applications & Calculations

Lesson Objectives

In this chapter the student will learn:

• How foamed fluids are different from commingled fluids.

• Benefits and calculations of acids when foamed.

• How foams can be used for diverting.

• Benefits and calculations for proppant laden fluids when foamed.

• Effect nitrogen has on cement when foamed

• Foam generators, what they are and how to use them.

Lesson Introduction

Background of Foam in the Oilfield

Foams are being used in a number of petroleum industryapplications that exploit the foams' high viscosity and low liquidcontent. Some of the earliest applications for foam dealt with its useas a displacing agent in porous media and as a drilling fluid.Following these early applications, foam was introduced as awellbore circulating fluid for cleanout and workover applications.In the mid-1970s, nitrogen-based foams became popular for bothhydraulic fracturing and fracture acidizing stimulation treatments.In the late 1970s and early 1980s, foamed cementing became aviable service, as did foamed gravel packing.

The early widespread use of foams as fracturing fluids was to helplow-pressure gas reservoirs in returning the liquid phase of the

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foam. The internal phase of the foam typically consisted of 65 to80% by volume (quality) of nitrogen gas, with an external phase ofwater and a foaming agent (surfactant). These simple nitrogenfoam fluids, coupled with the pumping technology of the 1970s,were able to transport sand concentrations of 1 to 2 lb/gal intofractures. Such low proppant concentrations gave beneficial resultsin low-pressure sandstone, carbonate, and shale reservoirs. Muchof the success of the early treatments was due to the capability ofnitrogen gas to expand and remove substantial quantities of theliquid phase from the reservoir.

Foam Rheology

The viscosity of a fracturing fluid is important because of itsinfluence in creating fracture geometry and in transportingproppant. Adding linear polymers or crosslinked polymers towater increases its viscosity. Viscosity of the fluid mixture is alsoincreased by adding nitrogen gas to create an internal phase (gasbubbles), when a stabilizing surfactant (foaming agent) is present.High-viscosity foam fluids can be prepared using low amounts ofwater and gelling agents, thereby minimizing the liquid loadplaced on a formation.

Foam viscosity depends on a number of variables, includingquality, viscosity of the external phase, and texture. The mostimportant parameter is foam quality—the percent volume occupiedby the internal gas phase. Since gas volume is a function oftemperature and pressure, downhole conditions must be known.As quality increases, foam viscosity increases. In addition, the yieldpoint characteristics of foams are an exponential function ofquality.

Higher quality foams have better transport properties, particularlyat very low shear rates, because of high yield points. The viscouscharacter of the external liquid phase is also a major parameter.Flow of high-quality foam may be visualized as gas bubbles slidingpast one another on thin films of the liquid external phase. If theliquid film contains a viscosifying agent, then the bubbles willundergo greater drag forces because of the viscous thin films, andflow will be more difficult, resulting in higher bulk viscosity.Texture, or the bubble size distribution, plays an important butlesser role in determining foam viscosity. Foams exposed to shearfor a sufficient time will equilibrate to a bubble size distributionthat is characteristic of that shear rate. Texture is also influenced by

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the surfactant that must be present in sufficient concentration tostabilize the foam under dynamic conditions.7,8

Terminology

Q - Quality - This term is used mainly when foaming a fluid. This like VLR has no unitsdue to being a comparison of the total mixture to just one additive (gas) in the mixture. Itdiffers from VLR in that the mixture is in the bottom part of the equation rather than thetop. Due to this, the Quality will always be less than one. The Tables in section III of theNitrogen Data for Oil Well Servicing manual uses Q. It can also be calculated using theTables in section VI.

Foamed Acid

As oil and gas wells age, many of them show similarcharacteristics. One of the most obvious is, of course, reducedbottomhole pressure that can contribute to the formation ofparaffins, asphaltenes, and scales. Many old wells have hadrepeated acid treatments. Following conventional acid treatments,large amounts of insoluble fines such as quartz, gypsum, andfeldspars may reduce fracture conductivity. All of these factorsrelated to old wells can be controlled through foamed acidstimulation.

Treating wells with characteristics as outlined above with aconventional nonfoamed acid treatment will probably bebeneficial. However, the high liquid content of conventional fluidsmay increase clay problems. Also, low viscosity of the spent acidmay leave a large amount of insoluble fines in the well. Inaddition, low bottomhole pressure may require swabbing to cleanup the well.

Nitrogen (nitrogen) is the most widely used material in foamtreatments. Volumetric gas content (foam quality) is generallybetween 65 and 85% (comprising 65 to 85% gas and only 15 to 35%liquid), although qualities as high as 95% have been used. Theliquid phase of the foam may contain 0.5 to 1.0% surfactant and 0.4to 1.0% inhibitor.

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Advantages of Foamed Acid

Foamed acid has widespread applications in both oil and gas wellsand offers the following characteristics to virtually eliminate theproblems mentioned in the previous section:

Low liquid content- Foamed acids used in fracture acidizinggenerally range from 60 to 80 quality. The low liquid content isextremely important when treating a liquid-sensitive formationwhere large amounts of liquid may cause swelling in the formationand reduce the permeability of the formation to the producedfluids.

Reduced fluid loss- The high apparent viscosity of the foamedacid results in reduced fluid loss, allowing deeper acid penetrationthan a comparable nonfoamed or conventional acid system. In lowpermeability reservoirs, the bubbles of the foam may be sufficientto prevent leak-off to the matrix. This can reduce the affect ofwormholing (channeling). Also, since no fluid loss additive isnecessary in low permeability reservoirs, there is a reduced chanceof impairment of formation conductivity due to the solids in someadditives.

High apparent viscosity- Viscosity is difficult to obtain in anonfoamed acid system since the acid used frequently is notcompatible with the gelling agent. A viscous acid provides theadvantage of better pumpability, wider fracture, and improvedfluid loss when used in fracture acidizing. Increasing the viscosityof the acid before it is foamed will give these benefits plus help toincrease foam stability.

Better cleanup- The built-in gas assist derived from using afoamed acid treatment now makes recovery of treating fluids fromlow-pressure reservoirs more effective than nonfoamed treatments.The built-in gas assist plus the high apparent viscosity of thefoamed acid enable the acid insoluble formation fines to bereturned to the surface on flow back rather than stay in theformation where they could hamper production. This means afaster cleanup that reduces liquid damage to water-sensitiveformations. Also, it may eliminate the need to swab the well afterthe treatment.

Improved solids transport- Another advantage of foamed acid isits capability to suspend fines. Often in conventional acidtreatments, large amounts of insoluble fines such as quartz,gypsum, and feldspars will be left behind because of the low

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viscosity of the spent acid. This may reduce fracture conductivity,but with the additional viscosity provided by foaming, more ofthese fines are suspended and removed from the well duringcleanup.

Less formation damage- Foamed acid has a low liquid content.Normally, foamed acid is 60 to 80 quality. Less liquid contacts theformation, thus reducing the opportunity for damage to occur.

Minimum well shut-in time- Foamed acid treatments should haveminimum well shut-in time after pumping. The foamed acidshould be flowed back as soon as possible following the treatmentto reduce the chance of liquid and nitrogen separation. The longerthe foamed acid is allowed to remain in a static, nonflowingcondition, the easier it is for liquid to drain from the foam bubblesand for suspended fines to settle out of the foamed acid.

Better control- Foamed acid also provides better control. Flow canbe better controlled by adjusting the amount of nitrogen, therebychanging the acid’s density. Because acid is normally heavier thanthe formation water, acid treatments tend to sink. Foamed acid canbe made to stay higher in the fracture by being less dense than theformation water. Foaming the acid also helps control the reactionrate by reducing its diffusion. Foam increases the viscosity of anacid system, so the acid can be prevented from entering morepermeable or low-pressure zones. This allows for more uniformcoverage without the use of other diverters. Foamed acid can alsocarry any of the conventional diverting systems such as Perf Pacball sealers or granular diverter.

Foamed acid offers other advantages. It has less thermal demand,causing less thermal contraction in the tubing. In cold treatmentconditions, this can save having to reset the tubing due to tubingshrinkage. Nitrogen-foamed acid systems reduce asphaltenesludge by diluting the concentration of carbon dioxide (CO2)formed from acid reactions. In addition, foamed acid treatmentscan be displaced with straight nitrogen, leaving the hole with nohydraulic column to impede load recovery.

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Foamed Acid & Foamed Water Calculations

CALCULATING TOTAL VOLUME OF FOAM(When you know volume of water or acid)

Quality of Foam = QVolume of Water/Acid = W

Total Volume of Foam = W

( 1 Q )−

Problem 1

Given: W= 95 bbl AcidQ=0.80 (80 Quality)

Find: Total Volume of Foamed Acid

Solution: Total Volume Foamed Acid = 95

1 0 80( . )−

=95

0 20.

= 475 bbl Foamed Acid

Problem 2

Given: W=200 bbl AcidQ=0.70 (70 Quality)

Find: Total Volume of Foamed Acid

CALCULATING VOLUME OF WATER NEEDED(When you know volume of foam)

Quality of Foam = QVolume of Foam = VVolume Water Needed = (V) x (1 - Q)

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Problem 3

Given: V = 600 bbl FoamQ = 0.75 (75 Quality)

Find: Volume of Water Needed

Solution: Volume Water Needed = 600 bbl x (1 - 0.75)

= 600 bbl x (0.25)

= 150 bbl Water

Problem 4

Given: V = 1000 bbl FoamQ = 0.65 (65 Quality)

Find: Volume of Water Needed

CALCULATING RATE OF CLEAN WATER OR ACID(When you know rate of foam)

Quality of Foam = QRate of Foam = Rf (in BPM)Rate of Water = (Rf) x (1 - Q)

Problem 5

Given: Rf = 24 BPMQ = 0.75 (75 Quality)

Find: Rate of Water

Solution: Rate of Water = (24 BPM) x (1 - 0.75)

= (24 BPM) x (0.25)

= (6 BPM Pumping Rate of Clean Water or Acid)

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Problem 6

Given: Rf = 40 BPMQ = 0.85 (85 Quality)

Find: Rate of Water

Calculating Nitrogen Pump Rate

Problem 7

Given: A customer has called in a foamed acid job. He would like to pump 238 bbl of 80 Quality foamed acid into a reservoir with a BHTP of 2800 psi at 6000 ft.

Find: Amount of acid and nitrogen needed for the job.

Solution: Using the previous calculation for volume of acid

Acid = (v)(1 - Q) = (238 bbl)(1 - .80) = 47.6 bbl

To find the nitrogen needed we will use Section III (pg. 11) in the NitrogenData for Oil Well Servicing manual. When pumping foam into thereservoir we will use the BHTP which is the pressure the fluids will beseeing just outside the perforations. For the temperature we will also usethe temperature the fluids are seeing in the reservoir. In this case we willuse 80°F. This temperature is determined by many variables such as fluidtemperature at surface, pump rate, tubing size, volume and bottom holestatic temperature. There are computer programs such as WTEMP andTEMP which can give you more accurate temperatures when necessary.

On page 11, Section III, use a pressure of 2800 psi and a quality of 80 for agas liquid ration of 4007 scf/bbl.

Nitrogen needed is = (4007 scf/bbl)(47.6 bbl) = 190,733 bbl

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Problem 8

Given: A customer has called in a foamed acid job. He would like to pump 900 bbl of foamed acid at 10 bpm foam rate. The BHTP is 3600 psi and the temperature at the perfs is 100°F. Note: Cannot use Pg. 11 in Nitrogen Data for Oil Well Servicing book due to temperature is not 80°F.

Find: Volume of acid and nitrogen and the pump rates for the acid and nitrogen.

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EXAMPLE TABLE

GAS-LIQUID RATIOS FOR FOAMED FLUIDS

Temperature = 80 Quality Gas Liquid Ratio = SCF of N2BBL of Liquid

P 60 65 70 75 80 85 90

250 149 184 231 297 397 562 892300 177 219 275 354 472 668 1061350 205 254 319 410 547 774 1230400 233 289 363 466 621 880 1398450 261 323 406 522 696 987 1567

500 289 358 450 578 771 1093 1735600 345 428 537 691 921 1305 2073700 402 497 625 803 1071 1517 2410800 458 567 712 916 1221 1730 2747900 514 636 800 1028 1371 1942 3084

1000 570 706 887 1140 1521 2154 34211200 683 845 1062 1365 1820 2579 40961400 795 984 1237 1590 2120 3003 47701600 899 1113 1399 1798 2398 3397 53951800 1005 1244 1563 2010 2680 3796 6030

2000 1108 1372 1724 2217 2956 4187 66502200 1209 1497 1881 2418 3224 4567 72542400 1307 1618 2032 2613 3484 4936 78392600 1408 1744 2191 2817 3756 5321 84502800 1503 1861 2338 3006 4007 5677 9017

3000 1594 1974 2480 3189 4252 6024 95673200 1683 2084 2619 3367 4489 6359 101003400 1769 2191 2752 3539 4718 6685 106173600 1853 2294 2882 3705 4940 6999 111153800 1933 2393 3006 3865 5154 7301 11596

4000 2010 2488 3126 4020 5359 7592 120594200 2092 2590 3254 4184 5578 7902 125514400 2166 2682 3370 4333 5777 8184 129994600 2239 2772 3483 4479 5972 8460 134364800 2303 2852 3583 4606 6142 8701 13819

5000 2370 2934 3686 4740 6319 8953 142195500 2527 3129 3931 5054 6738 9546 151616000 2671 3307 4155 5343 7123 10092 160286500 2803 3471 4361 5607 7475 10590 168207000 2932 3630 4561 5864 7819 11077 17592

7500 3048 3774 4742 6097 8129 11516 182918000 3157 3908 4911 6314 8418 11926 189418500 3257 4032 5066 6514 8685 12304 195419000 3356 4155 5220 6711 8948 12677 201349500 3446 4267 5361 6892 9190 13019 20677

10000 3531 4371 5492 7061 9415 13338 2118410500 3613 4473 5621 7226 9635 13650 2167911000 3690 4569 5740 7381 9841 13941 2214211500 3763 4659 5853 7525 10034 14214 2257612000 3834 4747 5964 7668 10224 14484 23004

EXAMPLE TABLE

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GAS-LIQUID RATIOS FOR FOAMED FLUIDS

Temperature = 100 Quality Gas Liquid Ratio = SCF of N2BBL of Liquid

P 60 65 70 75 80 85 90

250 143 178 223 287 382 542 861300 171 211 265 341 455 644 1023350 198 245 307 395 527 747 1186400 225 278 350 449 599 849 1348450 252 312 392 504 672 951 1511

500 279 345 434 558 744 1054 1673600 333 412 518 666 888 1258 1999700 387 480 602 775 1033 1463 2324800 441 547 687 883 1177 1668 2649900 496 614 771 991 1322 1873 2974

1000 550 681 855 1100 1466 2077 32991200 658 815 1024 1316 1755 2487 39491400 758 939 1180 1517 2022 2865 45501600 861 1066 1340 1722 2296 3253 51671800 962 1191 1496 1924 2565 3634 5772

2000 1061 1313 1650 2121 2828 4007 63642200 1157 1432 1799 2313 3084 4370 69402400 1250 1547 1944 2500 3333 4722 74992600 1349 1670 2098 2697 3596 5094 80912800 1439 1782 2239 2878 3838 5437 8635

3000 1527 1891 2376 3055 4073 5770 91643200 1613 1997 2509 3226 4301 6094 96783400 1696 2100 2638 3392 4523 6408 101773600 1777 2200 2764 3553 4738 6712 106603800 1854 2296 2885 3709 4945 7005 11126

4000 1929 2389 3001 3859 5145 7289 115774200 2009 2487 3125 4018 5357 7589 120534400 2081 2577 3238 4163 5550 7863 124894600 2152 2665 3348 4305 5740 8131 129144800 2216 2743 3447 4432 5909 8371 13295

5000 2281 2824 3548 4562 6083 8618 136875500 2436 3016 3789 4872 6496 9202 146156000 2579 3193 4012 5158 6877 9743 154746500 2711 3356 4217 5422 7229 10241 162657000 2838 3513 4414 5675 7567 10720 17026

7500 2954 3657 4595 5908 7877 11159 177238000 3063 3792 4764 6125 8167 11570 183758500 3164 3917 4922 6328 8438 11953 189859000 3262 4038 5074 6523 8698 12321 195699500 3353 4151 5215 6705 8940 12665 20116

10000 3439 4257 5349 6877 9170 12990 2063210500 3519 4357 5475 7039 9385 13296 2111711000 3599 4455 5598 7197 9596 13595 2159111500 3673 4547 5713 7345 9794 13875 2203612000 3743 4634 5822 7486 9981 14140 22457

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Foam Diversion

In most cases, formations will be comprised of zones possessingdifferent permeabilities or zones that may have sustained differingdegrees of damage during drilling, completion, or workoveroperations. When acidizing treatments are performed on suchformations, the treating fluids naturally enter the zones thatpresent the least resistance to flow. This can result in placing theacid in zones that require the least stimulation.

Diversion can be used to alter the fluid injection profile of atreatment. Because fluids will choose the path of least resistance,diversion is primarily a resistance problem; the goal is to alterinjection rate per unit of area so that all zones accept the properproportion of the treatment. Reservoir properties that can vary theinjection rate per unit of area are permeability, differentialpressure, and length; if these properties are not in the correctproportion, diversion should be considered. This disproportioncan result from the following:

• zones having differing permeabilities

• zones having differing formation pressures

• zones containing fluids with different compressibility

• zones containing fluids with different viscosity

• zones having natural fractures

A goal of acid treatment is to cause zones of similar permeability toproduce at higher rates by increasing the permeability in thecritical near-wellbore area. Diversion helps reach this goal byforcing acid into damaged areas to allow the entire zone (assumingnear equal permeability distribution) to be productive.

Diverting Agents

Diverting agents have been used in stimulation treatments foryears to help ensure treatment distribution over the entireperforated interval. In order to provide uniform placement of thereacting fluids across the entire perforated interval, divertingagents such as insoluble sand, benzoic acid flakes, solid organicacids, deformable solids, mixtures of waxes and oil-solublepolymers, acid-swellable polymers, and mixtures of inert solids(silica flour, calcium carbonate, rock salt, oil-soluble resins, etc.) arefrequently used to form temporary filter cakes on the higher

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permeability or least damaged zones. This then forces thetreatment into the rest of the interval. One concern when usingsuch materials is that the filter cakes are sometimes slow todissolve in the produced fluids, thus requiring remedial treatmentsfor diverting agent removal.

In the mid 1980s, foam was introduced as a diverting agent in placeof particulate-type diverting agents for acidizing through gravelpacks. Such foams achieve diversion due to their high apparentviscosity and the plugging effect of the gas bubbles in the foam asthey enter the pore network of the formation. Diversions have beenaccomplished with 60 to 80 quality foam. The better the quality ofthe foam, the better its diverting ability.

Foams possess several distinct advantages over particulate diverting agents. One main advantage is that since no solid particles are used, and because foams degrade fairly rapidly, the concern about diverting agent cleanup is eliminated. A second advantage becomes evident when acid treatments are performed on gravel-packed wells. If particulate-type diverters are used on such wells, the particles have to be sized such that they will be able

to pass through the gravel-pack sand and still be able toform a filter cake on the formation. This dramatically limitsthe types of material that can be used. Foam, however, easilypasses through the gravel-pack sand while still providingeffective diversion on the formation without concern about sizing orcleanup considerations.

Foam Fracturing w/ Proppant

In the Foam-Frac service, nitrogen gas injected downstream of the pumps into awater-base fluid containing a foaming agent. In most jobs, nitrogen volumeranges between 65 and 85 percent of the total volume. Proppant transportcharacteristics of the foam are excellent. Friction pressure of the foam is muchlower than for the base fluid, so hydraulic horsepower requirements are greatlyreduced. The foam bubbles help block small pore spaces, so fluid loss is verylow without the use of fluid loss additives. That also helps reduce formationdamage that could be caused by the fluid loss additive. In many cases, the foamhelps create wider fractures than would equivalent volumes of conventionalliquids.

Because less liquid is used for an equivalent treatment volume, formationdamage caused by fluids is reduced. When pressure on the well is released,the foam bubbles expand to provide a tremendous assist in treatment fluid

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recovery. Usually, even in low pressure reservoirs, the need for swabbing iseliminated. And the well will clean up much faster. In fact, cleanup times oftenare measured in hours rather than weeks.

Foam Frac design programs are available to optimize results and establish thetreatment parameters.

Foam Fracturing w/ Constant Internal Phase

The addition of a proppant to a foam fluid has a greater effect on viscosity thanconventional frac systems. The proppant, in effect, increases the quality of thesystem, which increases both viscosity and friction pressure. In a “constantinternal” phase foam, the volume of nitrogen gas is decreased by the volume ofproppant added. As a result the slurry stays similar to the pad fluid.

Concept

Fluid A is a conventional foam pad fluid (no proppant) containing a fixed volumeof gas and liquid. Fluid B is a proppant-laden fluid with solid added while gasand liquid volumes are held constant. During a fracturing treatment, thesevolumes are pumped in a given time, so the ratios also relate to pumping rates.The volume of internal phase (gas plus solid) in Fluid B is greater than that offluid A, although the liquid is constant, and would result in higher viscosity and ahigher downstream rate. This condition has often led to excessive friction losseshigher wellhead pressures, and premature job termination. An attempt to reducesolid, liquid, and gas rates proportionally to make the downstream rate the sameas the pad does not solve the overall problem. Although the ratios in Fluid C arethe same as in Fluid B, the internal phase ratio of Fluid C is higher than that ofFluid A, so the viscosity of Fluid C is higher that that of Fluid A and will give

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higher friction pressure. In addition, adjusting all three ratios increasesoperational difficulty.

An example of the viscosity increase caused by proppant addition is shown inthe following calculation. The addition of 5 lb/gal sand to be 70-quality foamcontaining 40 lb/1,000 gal bas gel will increase the internal-phase fraction to75.6%. The apparent viscosity of the fluid will increase from 325 to 445 cp at 40sec-1.

A solution has been proposed to keep both downstream flow rate and viscosityconstant. When solid proppant is added, a constant liquid rate should bemaintained, but the gas flow rate should decrease sufficiently to equal theabsolute solid flow rate. Application of the constant-internal-phase concept hasallowed much better control of foam fracturing treatments down small tubing.

Sand Washing with Foam

In some wells, the maximum velocity that can be achieved withincompressible fluids is insufficient to carry the sand from thewellbore to the surface. This may be due to the extreme depth, theproduction tubing being large, the formation pressure being toolow, or a combination of these and other factors. In such cases, acompressible fluid such as foam is required.

Foam can be generated in hydrostatic pressure gradients rangingfrom 0.350 to 0.057 psi/ft, depending on wellbore pressures andtemperatures. Stable foam rheology most closely resemblesBingham plastic fluids, where yield stress must be overcome toinitiate fluid movement.

The greater sand-carrying capacity of foam allows sand to bewashed from deep, large diameter holes with limited pump ratesand low velocities. This makes the use of coil tubing possible inwells that might otherwise require a workover unit.

Foam is a gas-in-liquid emulsion consisting of 52 to 96% gas,ideally nitrogen. For this application, the liquid can be aqueous oroil-based. Surfactants are mixed with the liquid phase inconcentrations ranging from 1 to 5% by volume to reduce surfacetension. The “wet” liquid phase is then commingled with nitrogenin a foam-generating tee. Turbulence created by nitrogen and wetliquid mixing provides sufficient dispersion to form ahomogeneous, emulsified fluid.

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Foam is generated by pumping a mixture of 99% water and 1%surfactant through an atomizer tee where it is mixed with nitrogengas. Because foam is comprised mostly of gas, changes in pressure,temperature, and solids loading affects the foam quality. As such,compressible fluids have constantly changing rheology. It is wellunderstood that the compressible fluid has maximum carryingcapacity when the foam quality is maintained at 65 to 90.

Foam Cement

There have always been areas in which weak zones can supportonly a limited height of a normal-density (11 to 18 lb/gal) cementcolumn without breaking down. Foam cement provides a means ofpreparing 4 to 15 lb/gal cementing slurries that develop relativelyhigh compressive strengths in a minimum period of time, even atlow formation temperatures.

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

• develops relatively high compressive strengths and lowpermeabilities

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

• can control high-volume water flow in weak formations, whenmixed as a quick-set formula

• enhances protection against annular gas invasion

• is economically competitive

• can be used from 28 to 600°F

Halliburton Foam Cement is a “stabilized system” consisting ofcement with carefully chosen additives, a foam stabilizer, a gas(usually nitrogen), and water. Success of foam cement comes fromthe ability to maintain cement slurry density below the hydrostaticbreakdown of sensitive formations, which prevents lost circulationand fallback problems. This density control flexibility allows awide latitude in designing the overall job before it is actually run inthe field. Appropriate computer-assisted programs are used forprejob planning. If necessary, one can choose to change the densityas the pressure and circulation events vary during job execution.

To prepare a stable foam cement, the slurry should be conveyedthrough an effective mechanical foam generating device thatimparts sufficient energy and mixing action with pressurized gasto prepare uniform gas bubbles of the correct size. In nearly all

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respects, regular cementing equipment is set up as for an ordinarycementing job. The foam generator is inserted in the cement slurrydischarge line that is connected to the well head, and the nitrogenunit is connected to the foam generator. The cement slurry is mixedin a normal fashion, and foaming surfactants and stabilizers areinjected into the slurry as it is picked up by the displacement pumpunit. Fig. 6-1 on the previous page depicts a typical field jobequipment layout.

Foam Generators

The success of many foam treatments is dependent on the foam having the propertiesthat it was designed for. To ensure a stable foam with good texture, a foam generatoris recommended.

When to Use a Foam Generator:

• Foam Cements.• Oil Based Stimulation Fluids.• Fluids w/ Blends of Alcohol / Methanol / Toluene / Xylene / condensate /

diesel etc.• High Linear Based Gel Systems.• Rapid Crosslinked Gel Systems.• Low Rate Pumping Jobs (Matrix Aciding) & Acid Foam Diversions.• Customer Request.• When in Doubt About Performance of Surfactant.• Pumping Down Large Casing Strings.

Foam Generator Problem

Given:

N2 Pump Rate 1,000 scf/min

Expected WHP 5,000 psi

Desired Nitrogen Back Pressure 800 psi

What Size Choke is needed in the Foam Generator?

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Solution:

Q = 1.64 (D2)(V′/V) √∆P/Gas Density

V’/V Use Nitrogen Data for Oil Well Servicing Section VI on Page 2 for 5,000 psi & 80°F the VS/V is 1580 scf/bbl.

Gas Density Nitrogen Density is found in same booklet on page 5 Section VI. Follow up from 5,000 psi to intersection of T = 80°F line. The density is 2.7.

Solve Q = 1,000 scf/minD = ?V′/V = 1580 scf/bbl∇P = 800 psiGas Density = 2.71,000 scf/min = 1.64 (D2)(1580 scf/bbl) √ 800/2.71,000 scf/min = (D2) 44,603.0224 = D2

.15 = D

9/64 Choke is .14 inches10/64 Choke is .16 inches

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The “Tee” foam generator is a simple device that creates stablefoams with good textures (Fig. 18-1).

Note: There must be at least 8 to 10 feet of straight pipe followingthe foam generator tee to serve as the mixing chamber.

Fig. 18-1: Schematic of foam generator.

The following guidelines apply when you select a nozzle size:

• For foam cement, use a 16/64-in. nozzle.

• For 0 to 40-lb water gel and acid foams with 600 psi nitrogenpressure loss, use Figure 18-2.

• For 40 to 80-lb water gel and oil foams with 1,200 psi nitrogenpressure loss, use Figure 18-3.

To choose the proper nozzle size, determine the proper nitrogenflow rate (scf/min), read up the chart until this line intersects withthe curve you selected based on your wellhead pressure. Uponfinding this point, read the nozzle size on the left-hand side of thegraph for your job.

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Fig. 18-2: Nozzle sizes for 0 to 40-lb water gel and acid foams with 600 psi nitrogen pressureloss.

FlowBacks of Compressible Fluids

• Not our core business. Preference is not to be doing.• Do not use the iron we use in our daily treating operations.• Under no exception are hoses to be used.• When flowing back into tanks make sure MSDS sheets on N2 are left with

company man and that he is aware of potential asphyxiation with N2 inconfined spaces.

• Make sure all flowback iron & connections have working pressures aboveexpected pressures.

• Order of preference for connections:• Flanges• Square Threads• Round Threads• V-Thread ( break easier when subjected to lateral & cyclic strain)

• Rigid steel lines. Swivel joints have more potential in parting.• Avoid turns whenever possible. Use bull plugged tees when necessary.• Use positive chokes rather than variable chokes when possible.

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• Double valve arrangement close to the wellhead & as close to the ground aspossible. Remote valve recommended.

• Stay upwind of well when flowing back.• Use a Perfball Catcher in the line when Perfballs are used.

Is the restraint system capable of controlling the released energy?

The following formulas determine the maximum torque that can be created by asystem failure:

Force = (Pressure) (Area)Torque = (Force) (Length)

Line I.D. Area Sq. Pressure Force Length Torque2″ 3.14 5,000 15,700 5 78,5003″ 7.07 5,000 35,350 5 176,7503″ 7.07 5,000 35,350 10 353,5003″ 7.07 10,000 70,700 10 707,0004″ 12.56 10,000 125,600 10 1,256,000

Fig. 18-2: Nozzle sizes for 40 to 80-lb water gel and acid foams with 1,200 psi nitrogen pressureloss.

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Computer Programs

Stimulation

StimWin - This is a Windows based program which allows you to plug in a fewnumbers and get back results without having to interpolate off charts and graphs. Theprogram runs on a 386 DX PC with at least 8 mgs of memory. Instructions to get intothe program are: Click the StimWin GUI, click APP, then Nitrogen Calculations. Undercalculate, click Foam Quality & Density.. Fill in the Black & Pink lines & read theresults givin in the Blue lines. Foam schedules for fracturing applications can also bedetermined by clicking foam schedules after clicking App.

PROP - Used in designing a sand laden foam stimulation treatment.TPHASE - Useful in designing rates, friction pressures, WHP’s etc with foams.

Washing

FoamUP - Simulates a foam cleanout job when washing varies types of debris out of vertical & horizontal holes.

Cementing

CJOBSIM - Used for simulating a foam cementing job under dynamic conditions.FMCEM - Simulates a primary foam cementing job under static conditions.

Usually it is necessary to run both the above programs when designing a primary foam cement job.

SQZSIM2 - Simulates a squeeze foam cementing job under dynamic conditions.

Chapter Feedback Exercises

DIRECTIONS: Complete the following exercise, using your workbook and notes asreferences:

1. Name two variables which effect foam viscosity? ---------------------------------------------------------------------------------------------------.

2. What size nozzle should you use for foam cementing in a foam generator? ---------------------------------.

3. List six advantages of using a Foam Acid.

a. ---------------------------------------------------------------------------------------

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b. --------------------------------------------------------------------------------------

c. --------------------------------------------------------------------------------------

d. --------------------------------------------------------------------------------------

e. -------------------------------------------------------------------------------------

f. --------------------------------------------------------------------------------------

4. Which foam quality has a higher viscosity? 60 Q, 70 Q, 80 Q. ------

5. In a 70 Q foam, what is the percentage of the mixture which is liquid? ------

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Lesson Summary

We initially discussed what foam is and what are the advantages of usingfoamed fluids. We found by adding a larger percentage of nitrogen and asurfactant to the base liquid we could get a fluid which has a low density and ahigh viscosity. In doing so we need to make sure enough energy is impartedinto the system by shearing through high velocities or a foam generator. A fluid once foamed has many added benefits. In stimulating a reservoir itallows us could fluid loss properties, improved cleanups, and excellent proppantcarrying characteristics. In wells were there is concern about loosing fluids in azone downhole, nitrogen foams can be utilized to circulate out debris or in doingprimary or secondary cementing jobs.