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SPE-~PErtn@nEn&miw3

SPE 20708

New Techniques and Quality Control Find Success in EnhancingProductivity and Minimizing Proppant FlowbackJ.W. Ely, S,A. Holahch & Assocs. Inc., W,T. Arnold Ill, Phillips Petroleum Co,; andS.A. Holditch, Texas A&M U,SPE Members TT

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Copyright 1990, Society of Petruwm Engineers Inc.

This paper was prepared for presentation at tha 65th Annual Techckal Conference and Exhibilim of the Sociaty of Petroleum Engineers Oeld in New Orleans, lA, September 23-26, 19S0.

Thla paper waa aelacled for presentation by an SPE Program Committee following eview of information conlained in an abskacl submilled by the author(s). Co~tenls of the paper,ae preeented, have not been reviewfid by tha Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily rolleclany position of the Society of Petroleum Engineers, ita officers, or membere. Papers presented at SPE meelings ere subject to publication review by Editorial Commitleea of the Societyof Patroleum Engineers, Permiaelon 10copy ie restricted to an abs(m.l of not moro than 300 worde. Illuetralione may not be copied. The abatract ehould contain conspicuous acknowledgmentof where and by whom the paper Ie presentarl. Write Publication Manager, SPE, P.O. Box 833S36, Richardson, TX 750S3.3836, Telex, 730989 SPEDAL.

INTRODUCTION

Hydraulic fracturing has yielded successful stimulation resultsin hydrocrwbonproducing reservoirs for over 40 years, In certainreservoirs, however, hydraulic fracturing does not always achievethe desired results, In srme cases, due to excess prsxirction ofproppant orexcess water production, the fracture treatment can causeoperating problems. A paper published by Robinson et al, discussedthe merits of flowing back a well on a small choke to minimize theclosure stress on the proppant. In that paper, a recommendation wasmade to monitor the tubing pressures after the fracture Eewrnent,and if closurE times appear to be excessive, then one should initiateit low rate flowback of the fractu~ fluid to assist fractu~ closure.

Approximately 4 years ago, the initial treatment designed to usethe forced closure technique was conduaed on a Canyon SandWC1lin west Texas, The fracture treatment was successful, but themost surprising aspect of the procedure was that significantly lesiproppant was produced after t!le treatment when compared to otherwells in the area, In the last few years, the forced closure techniquehas been used on several hundred wells in many different geologichorizons,

The forced closure technique, alone, may not bc the reason forsuccess, However, the usc of forced closure combined WMIthe useof aggressive proppant scheduling and the tipplication of intensequality control rxm lead to dntma!ic improvements in stimulationsuccess, Intense quality control involves field testing of fracturingfluids at reservoir temperature prior to pumping operations.2 In thispaper, field results have been included to illustrate how the forcedclosure technique, coupled with high proppant concentrations andintense quality control, can sigfiificiuttlyincreme the productivityof low permeability oil and gas wells.

Most of the early tipplicationttof the forced closure techniqueinvolved the usc of foam frac,vrhtg fluids or polyemulsicmfluids.As more was learned about the procedure, forced closure wac usedregitrdless of the fracturing fluid being used during the treatment.Expwicncc indicates that the forced closure tcchniquc will work

~cfcrcnces and illustrations at end of pitpcr.

even when crosslinked fluids arc pumped, 13yflowing the WCIIb;dimmediately at u low controlled rate irfler the pumpi,lg stops, thtexcess pressure in and around the fracture ~iitlhelp to ~l~ill]UP IhCfluids.

The foreed closure technique has been used in fonnit[iontranging from the tight Devonian Shales in Appalachia to the higlpermeability coal seams in the San Juan Basin. Table 1 presents olist of formations that have been stimulated and then produced birckusing the forced closure technique.

ADVANTAGES OF HIGH PROPPANT CONCENTRA~IONf

The adwmtages o using high proppant conccntrwion hi\s beerwell doaumentcd in the perrolcum literature.345Recent publicotion}have shown that higher concentrations are needed to rninimizc [INeffects of damage to the pro~~iuupack caused by gel residue, fine:and excess closutv pressure. 0 Experience suggests that iigg~essivtproppant schedules will be beneficirtl because high stn(concentrations will result in a very viscous slurry,11By llS;rI~ il[aggressive pumping schcdulc, much higher sand cot~centri{tlonfhave been successfully put away than those previously pwnput itsimilar wells.

Fig. 1 is a graph that illustriitcs the effect of sand con~eiltriltiolupon the viscosity of a sand-liquid slurry, Notice thi\t when th(proppant concentration is only 2-4 ppg, the slurry viscosity {sonlj10-20%hargerthttnthe liquid viscosity, However, at aconcetm:uiolof 10ppg, the slurry viscosity can be 10 times Iiwger thiil; h Iiqukviscosity, Realistically, a 50 cp fluid caITyhlg2.4 ppg of send is noa very cffectivc fritcturingfluid. The swnc 50 cp fluid Ciirr)it)g8-1(ppg will bc a thick, viscous, efficient fluid, The sand is MxunllyIwscosifitwwhen suspended in fluid,

Under certain couditicrns, the use of smaller mesh })roppi~t~i:(2(!-40 mesh) will provide better Stitnulii[ion thim achicvcd willlarger (12-20 mesh) propprtnts. When snmller mesh proppi{t~tsW(used, they can be transported better and pumped dccpcr into tlufracture, Also, after pumping, dw smaller mush pr~ppiiilts will st:i:suspended for a longer period of time, Expcricncc indicntcs that tolow permeability reservoirs, high quality, SIniilkr mesh ])~ol)pilt~[twill normally provide optimum stimuhttion rcsuhs. Applicittion:exist where the use of larger proppants and the conductivity ttw

889

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NEWTECHNIQUESANDQUALITYCONTROLFIND SUCCESSIN ENHANCINGPRtiDUCTIVITYANDMINIM

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tomes with the huger size is advantageous, as long as there isufficient viscosity to transport and ntfficient fracture width to allow)lacemcnt of such proppants. Table 2 illustfatcs two typicalIggressivcproppant schedulm, The first pumping schedule was alearforktreatment while the second schedule was usedin a Frontierracture treatment,

2UALITY CONTROL

Mostfracture trcitmtmts will notbe mixed andpum ed correctly!fquality control meastrres are not followed. Insuficient fluid

/iscositycarsresult inprematurescreenout and/orimproperproppant)lacement. Even more important, especially in low temperatureonnations, the formation rmdfracture can be plugged if the gel doeslot break, On treatments that have been monito~d, it has beenIocurnented that over 60% of the time, the fluid chemistry in theieldhas to be altered to achieve the desired results, Without pilotesting the frac:urin&fluids at reservoir temperature onsite prior tohe treatment, fluids that do not meet specMcations will be pumpedmost of the time, The maj.lr problems are shelf life andcontamination of the crosslinker and/or breaker systems. By pilot;esting the fracturing fluids at reservoir temperature prior to the;reatment,one can usually adjust the mixture of additives to achieve;hedesiredresults, This typeof testing,called intensequality control,has been described in detail by Ely et al?

It has been realized that by working very closely with the ser+cecompany,one can detect and solve most problems in the field, MostDf the fluids being used today are far more complex than mostengineersrealize, Testing has shown that variations in salts, buffers,and crosslinkers, by as little as 1070, can substantial~~affect thedownholeviscosity, This is particularly the case in high temperatureforrna:ions where, on one occasion, the complete degradation of afracturing fluid was monitored with only a 15% variation incrosslinker loading. Simple, conventional quality controltechniques, such as testing the pH of the fluid prior to addition ofthe crosslinker and looking at an itmbicm crosslink time, are notacceptable. The fluids must be tested at bottomhole conditions inorder to be assured that the fluids will perform as they have beendesigned,

IifJRCED CLOSURE THEORY AND GUIDELINES

Over 4 years ago, forced closure was employed by slowlyflowing back wells as soon as ~.: pumps were shut down, Theobjective was to attewpt to CIOSSthe fracture at a more rapid rate tominimize proppant settling. Figs, 2, 3 and 4 present examples ofsurface closure pressure graphs that have been recorded from threetypical wells, Normally rtchange in slope can be detected in the AP

Tvs t graph after only 5-10 bl)ls of fluid have been produced, It isobvious that the entire fracture is not being closed by producing thesesmall volumes of fluid, However, the fracture could be closing nearthe wellbore, By rcdtrcing the frrrcturewidth near the wellbore, thesand should bridge and not settle in the fmcture, Even if the fractureis not closed, but the sand bridges, the before mentioned objectivehas been accomplished, (XSChistories have shown that fmctr.trcclosure and sand bridging occurs more rapidly when high sandconcentrtttions are used during the treatment.

In the initial trewncnts, the wells were shut in after a deflectionin the squatvroot of time plot wttsdetected, Recently, the wells havebeen itllowed to flow itnd in fact, the flow rute httsbeen incrcused inan attempt to pack sand cithcrcloser to tluwellboreor cause fractureclosure ittgreuter distunces from tht. wellbore, Listed in Table 3 aresuggested guidelines for implementing the forced closure tcchniquc,

Some interesting obscrva!ions have surfaced through the use offorced closure, These observations have changed the thought~$xxcc:of many engineers, Several important observations areas

890

;ING PROPPANTFLOWBACK SPE 20708

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Case histones have shown that producin~ viscous fluid at verylow flow rates from a fractttre will not cause excess productionof proppar,t, Viscous fluids have been produced to the surfoceon numerous cecas,ons with little, if any, sand entrained in thefluid, However, one must use low flow rates.

Many companies try to increase breaker concentratiotw duringthe jub, particularly, if the well is to be or)e,ledto prcxh.w soonafter the treatment is completed. Based on past experius:c withthe fwced C1OSURprocess, rapid gel degradation cm bedetrimental to the fracture. Very high breaker loadings at the:ail end of the treatment can cause excessive proppunt settling.Witho~: the forced closure prc-sesz,::,e rapid breakdown of gelsmay allow proppant to settle below the zone of interest. Tic useof sufficient breaker is recommended in orckr to eventuallydegratie the gel; however, the gel should maintain good stabilityduring both pumping operiitions and during fracture closure.Some oi the latest results have shown that it is prefetiible NJinitially produce the tmbroken gel so long irs sufficientbottomhole pressure is pres?nt to lift the fluid, However, it isdesirable for the gel to eventually be completely broken. In lowtemperature wells, breaker must be iidded to itll gelled fluid,

Shutting in wells for a lengthy period of time (24 hrs) tms notshown any decrease in the amount of sand production, It isrecommended that tlomback should begin immediately afterthe treatment is corn Proppant settling can cause anincrease in the t..nount u, proppant produced. Fig. 5 illustrateswhat can occur if p oppantsettles prim to fracture closure.

Fig, 5a shows the proppant pack at the end of rhetrermnentwhena high viscosity fluid is used. Fig, 5b illustrates the proppedfracture if all the proppant settles before the fracture closes.Once the fracture closes and if settling has occurred, port of thefracture immediately above the proppant pack will be open ilndcan be a path available for proppcmtproduction (see Fig. 5c).To eliminate such problems, Fig, 5d illustrates what the fmctureshould look like when forced closure is 1sid, The~ could besome settlin~out in the fracture; however, .,le proppant near thewellbore should be trapped,

Pumping moreproppant VS,less proppitnthirsshown itreductionin proppant flowback problems, Some industry personnel havestated just the opposite. In theory, very high proppnntconcentrations should be pumped and the propptmt should bcpacked in the fract,ve as tightly as possible near the wellbore.Tightly packed and bridged proppant near the wellbore willminimize most proppant production problems, Cases have beenobserved where the service companies had problemsmaintaining the high propprrntconcentrations consistently at theend of the treutment, When this occurs, proppilnt flnwbackproblems are inevitable, even with forced closure, It is veryimportant to flush the well ihc instrtntthat vi~riationsin pr~ppi\n[cormmtrittion occur near the end of the trcatnwm, JI is alsohighly recommended that one under-flush [hetreatment, l~iivi[lgthe highest proppant concentration nt the entriu]ce to theperforations, Do not ovcrflush for any reason!

This is not tn suggest thittthe f:md closure tcchni~ucc1imin;ltcsthe newt for curable resin coit[cd si~ndIorcontrdl 01pr{)l)~)i~l][flowback, There are many fo~iitions where the forced closuretechnique anf,curable resin coated sand are required for controlof proppant flowback, Prime exirmples ure high. we wells orcarborke wells where excessive acidizing may negittccornplctcclosure on proppant near the wellbore. Forced C1OSUIEisrecommended and has successfully ken implemented on wellswhere the curable resin-coated surid has been used. Forcedclosutv technique is believed to be hencficial in obtitining gruinm grain contact and facilitates curing nnd compressive strengthwvclopment, One must always uttempt to mainutin minimalclowre during the forced closure procedure to climiniite

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USING MINI-FRAC DATA McKEE SANDSTONE CASE HISTORY

Severai major and independent oil companies rotrdncly use This case history compares before and after treatmentsforced closure after every fracture treatment, Several companies performed on the Andcctor - McKee formation located in Ectorhave tried to im rove the procedure by using mini-frac data to

rCounty, Texas. The McKee formation is a medium depth reservoir

optirnim pad vo umcs. For many years, the industry has used consisting of very fine grained, high quality sand, The forrnatio~ imini-fiat data tndetermine the total fluid loss coefficient, Typically, r.otorious for producirq; formation fines to the point of severelyif the fluid loss vthes are high, the pump rate, dle concenuation offluid loss additives, or the pad volume is increased. When a low

impeding production, The McKee averages 14percent porusity and3 md permeability within the 60 feet of net pay, Table 5 compares

value of total fluid loss coefficient is computed, however, most the pumping schedules of the previous designs and the new design.engineers do not com nsate by decreasing the pad volume, By

rdecreasing the pad vo ume and reducing the fluid loss additives in mlow leakoff situations, one can decrease closure times dramaticallyand gain further benefit from the forced c~osuretechnique, Previous treatments consisted of pumping vwious crosslink

fluids at 16 BPM. The designed proppant schedules were stagedCLEARFORK CASE HISTORY from 0.5 up to 3 15s/gal with an avetage proppant cwrccntmion

throughout thejob of only 1.9lbs/gal. Most of the treatments staredThis case history compares fracture treatments before and after scrxmingout afteronly 43,000 lbsof proppant wasput away, Fowed

aggressive proppant schedules and forced closure tvere closure was not practiced.implemented, The wells are located in I?ctor County a few milesnonh of Goldsmith, Texas. The case history acreage is currently Munder a wwefflood secondary recovery project in the Clearforkreservoir, 1 he Clcarfork averages 10.0 percent porosity and 0,5 md As Table 5 indicates, the new designs were much moreperrnettbility over the 125 feet of average net pay, aggressive. A 40 lb Borate crosslinkca ftuid pumped at 25 BPM

was used to insure adequate fracture width, The new trewnenl wasdesi~ned to pu[ away i22,000 lbs of curable resin comer!sand, ut ilmaximum sand concentration of 8 ppg, The idea behind propping

Previous fracture treatments did not employ forced closure and the entire fracture with resin coa,ed sand was to aid in formiitionused various crosslinkcd fracturing fluids pumped at 15 BPM, The firtcs control, After the resin cur:s, the sums on the Prop})iit)( willtypical trcatmwtt consisted of 52,000 pounds of proppant with a be evenly distributed across the entire bondd propped fracturemaximum concentration of 4 ppg, Typical stabilized production length,response from the treatments averaged 30 BOPD and 15 BWPD,The designed fracture half length was 300 feet, giving a resultant The treatment was sl]cccssfullypurnpcd und forced clnsurc Wiisfracture height of 280 feet, The proppant schedule averaged 2,8 implemented, realizing that if proppant flowed back, resin coatedpounds per gallon throughout the treatment, Table 4 illustrates a sand would have to be drilled out of the inside of the casing.typical pumping schedule. However, forced closxe was successful and no proppant was

produced into the wellbore, Force closing a curable win coatedpropped fracture in a formation that has fines problems. .ds in finescontrol, A more uniform propped fracture and better bond is

The new fracture treatments use a po!yemulsion fluid system.The treatments are designed to achieve 400 feet of propped fracture

achieved by closing the fracture prior to the resin setting up, This

half length and 500 feet of fractutv height. The proppant schedulescreates a more linear load distribution of the closure stress along theentire fracture length,

are much more ag~essive, with sand concentrations increasing to10 pounds per gallon (see Table 4), The treatments are designed to The new treatment designs have produced with no fornmtionpump about 250,000 lbs of 20140mesh Ottawa sand at 40 BPM. fines problems for six months beyond the time frame thut fine,s

started showing up on the before treatments, Fig. 7 illustrates theResults from im iernrmtingthe new design have been excellent.

iThe formation too the designed proppant schedl!e with noproduction performance of the before and after treatments,

problems, Forced closure was applied and the well flowed back FULLERTON - SAN ANDRES CASE HISTORYmost of the load with very little sand re-entry, After all load oil andwater was recovered, the average post-treatment stabilized This case history compares actual field results of multipleproduction was 100 BOPD and 60 BWPD, Fig, 6 compares the fracture treatments in the Fullerton . San Andres Field both beforetypical before production response to the new design :esponse. and after implementing the new fracturing techniques, The new

fracturing techniques consist of implementing very aggressiveQ@UWQll proppant schedules, intense quality control and forced closure, The

The success of the ncw !rcatment is Wributcd to the aggressivecase histories are located in Andrews County, a few miles north ofFrankel City, Texas, Average reservoir depth is 4600 feet, and the

proppant schedule, forced closure and quality control, Very highfracture conductivity was achieved by pumping the high sand

pay zone averages 10,8% porosity, 1.4 md permeability, and a netptty thickness of 35 feet, The case history area is currently under a

concentrations (averaged nearly 6 lbs/gal) and implementing forced waterflood secondary recovery program in the San Andrcs, with anclosure to pack the sand near the wellbore area, As Fig, 6 illustrates, average reservoir pressun$of 900 psi within the active project arc:l,the new design has substantially improved productivity, Eventhough the case history has only four months of production history, &2.fQEthe severe production decline observed after previous treatmentsappears to have been Icssened significantly, Typical fracture treatment designs, prior to implemcntirtg the

new techniques mentioned above, consisted of pumpingapproximately 30,000 gals of borate or titanittecrosslinkcd fluids at12 RPM carrying 39,000 lbs cf 20/40 mesh proppant, Ti,Gproppiwtschedules were siag~d or ramped to a maximum of 4,0 lbs/gal andenerous volumes of various low residue additives v~ereused for

i uid loss control, The designed pump schedules on the nmjority ofthe treatments were not pumped due to prenm.mdy flushing when

801

.NEWTECJNIQUESANDQIALITYCONTROLFIND 21CGESSIN ENHANCINGDl?nnllPrTVfTY ANTI MTNTMT7.TNC ,1.OPPANT liI.f)WRACK SPr? 9070F.. ..A-. -. . . . . . . . . . . . . . . . . . . . . . . . . . ---- . -.. ------- - .- - . --

wexccss prcssurercadings indicated ascreenout wiis imminent. Thcncw trcutmwttput uwuy nearly twice t!:c~ltlo~,ltof [jr~}p\]:llllome of these treatments screened out even before there was time than the before treatments. This was achicvcd by implem(.nting) switch to flush. Actual treatments that were pumped averaged detailed quality control. Great cam was taken ta insure !inat the7,000 gals of crosslinked fluid and 32,0iX)lbs of proppant. Limited viscosity of the poly:mu!sion fluid at brmomholc tcmpr;titurc was,uality control checks were performd on location and the wells adequate to create the neccsstmyfriicturc width and transport theiere shut-in for 24 hours prior to flowing theri, brick,hence, forced proppant,losure was not implemented. A typicaltrctttmentwould be expemcfa pwducc 54 BOPD and 108 BWPD. Inevitably, all of the before The resultant low water production volumes of the ne.Vdesignsreatments oil production declined rapidly within the first few (see Fig. 8) are attributed mainly to ftm d closure. It ww felt thatnonthsand stabilized around 32 BOPD. Typical proppant pumping by force closing thefracture, the proppant was trapped before itcouldchedules are presented in Table 6. settle to the bot:om of the fractwe. This theory was strongly

supported by comparing after frac survey logs of fractures in whichm forced closure was and was not implemented, The proppwrt in two

fracture treatments, wells #2 and #3, was tagged with identicalThe Fullerton-San An&es case history acreage was chosen as a concentrations of the same radioactive isotope. The treatment

~ilotarea for testing these new techniques due to the history of schedules were iJentical, Forced closure on well #3 was notlroblems associated with fractur, treatments, Several historical err.ployed, The after frac survey of well #3 shows that the majorityesults of previous fracture treatments could be usedfor comparison, of the tagged propprmtoutside the wellbore hisdsculvd to the bntmmrheobjective was todesign an aggressive fracture treatment, resolve of the fracture (reference Fig. 9a). The after frac survey on well #2h? previously encountered problems, and implement these indicates that the proppam outside the wellbore Wils evenlycchniques to see if they would improve production:performance. distributed throughout the fracture. Forccdclosurv wasimplemented

on well #2. Actual production data on the two wells also supportsWi!h the help of a newly formed Phillips Fracturing Task Force, the theory. Well #3 is producing ut u much higher water cut [Iliin

hew ideas were taken to the field, A pilot well was chosen, well well #2, The higher water cut would be expected since most of thetl, A pressure buildup analysis diagnosed that the well was slightly proppant had settled to the bottom of the fracture near the aquifer;timulated with a -LO skin factor, The well was making 18 BOPD (see Fig. 9b). Well #3 has stabilized at 32 BOPD. Well #2 hasmd 1BWPD. Since several people were on location, intense quality stabilized at 66 BOPD.:ontrol was implemented.

NORTH GOLDSMITH FIELD CASE HISTORYApnlyemulsicmfracturing fluid was chosen for this pilot project,

3y using the simplest fluid system that will still create the desired This case history compares treatments performed nearracturedimensions and carry the proppant, there will be h Mroom Goldsmith, Texas in the North Goldsmith Field. The treated pity!orerror on location during the actual treatment, The polyemulsion interval is the San Andres, a shallow (4300) deposition of dolomitehid was also chosen because of its low leakoff characteristics. and anhydrite with a very low reservoir pressure of only 120 psi,

The reservoir averages 9% porosity and 1md permeability over theAn aggressive treatment schedule was designed to give 300 feet 44 feet of average net pay, Comparison and results of trewments

>f propped fracture half length with high iracture conductivity;hroughout. AsTable 6s hews, the new treatr,ientdesign used 17,000

pumped before and after implementing these new fracturingtechniques will be discussed,

gals of fluid to carry 84,000 lbs of 20/40 mesh Ottawa sand andpumpedat 2S BPM, Note.that nearly forty-five percent of the slurry Ee.ftXQand over one-half of the sand was pumped at a concentration of 10lbs/gal. Staging the sand concentrations was chosen over ramping Prior treatments performed in the San Andres fomlationso that pressures could be observed indicating how the.formation consisted of pumping a 40# crosslinked fluid carrying 70,500 lbs ofwas reacting when the higher sand concentrations hit the formation proppant at a pump rate of 15 13PM, Forced closure was notface, implemented and a typical wells incremental production averaged

10 BOPD,Well #1 was successfully stimulated, Intense well site quality

controlchecks were performed and the aggressiveproppant schedule A.fleIwas put v?,y. No indications of screenout were ever detected onthe deadw mgexcess pressure graph, Immediately upon completing As Table 7 shows, the iicw treatments it~c more aggressive imdflush, forcedclosure was implemented, The well wasinitially flowed consist of pumping 147,000 Ibs of proppimt using a 50 quality C02at 5 gakshninuntil closure was detected, One half hour after closure foam fluid, The energized system was chosen so that the well wouldwas detected, the flowback rate was increased to 10 gals/rein. flow back and implementation of forced closure would be possible,Approximmdy one hour later, the flowback rate was increased to The treatment was pumped using a constant C02 pump rate, This20 gals/rein and allowed to flow at that rate until the well died. A caused the downhole slurry rate to increase from 1,5to 20 BPM iischeck for fill showed no sand in the wellbore beyond the amount the proppant concentration increased. Resultant incrcmcntitlthat was underflushed. The well was placed on pump and after a~. production from the new designs averaged 20 BOPD.load was recovered, initial production rates were 72 BOPD anti 60BWPD, A post-fracture pressure buildup analysis indicated that the QiXuSs@treatment yielded a -5,50 skin factor, Thrve months later, the wellhad stabilized at 64 BOPD and 21 BWPD. After ten months of The new treatment design was used i~nd force closurvhistorical production, the dramatic decline in oil production that was successfully implemented, Only traces of sand were produced whilefen in the previous treatments was not evident, as illustrated in Fig. flowing the well back, The sand production resulted from very

erratic flowback rates experienced while trying to prevent the chokefrom freezing, The well was allowed to flow at excessive rittcs for

QiWt@Qn short periods of time in order to clear ice from the choke, The sandI

reduction associated wit$ the icing problems hiis been clitninittedThe success of the fracture stimulation treatment is attributed to y using non-energized water in the last part of flush,

the low fluid loss and shear tesistmt proppant transportcharacteristics of the polym.rlsion fluid, as well as forced closure.Intense well site qualit) ,cmlrol also insured that the treatment wasmixed rindputnped corully.

892

r).. . . . . . -. . . ..-. - -..rb Luluo ELI, J. W., ARNOLD, W. T., AND HOLDITCH, S. A. 4

As Fig. 10depicts, the new designs are giving better rwlts, The 4, The forced closumtechniq~e isaviable prw'edure that makesweiisfractured using the new treatments are sustaining higher fluid use of the supercharge from the fmctunng treatment and lessensrates than wells treated using the old methods. This improvement potential damage from the fracturing fluids by flowing back[sattributed to the huger volume of proppant placed in !he reservoir much of the polymer and additives.Oythe new design, Also, higher sand concen~ations and forcedclosure both improve the fracture conductivity near the wellbore, 5. Further fieldtesting is underway and the direction being pursued

is more aggressive flowbaclw once near wellbore closure husCABIN LAKE DELAWARE FIEltiD CASE HISTORY occurred.

This case histo compares results of treatments befo~ znd after REFERENCESYimplementing new racturing techniques in the Cesawm Mountain

Group sandstone formations, The case histories are located in Eddy 1. Robinson, B, M,, Holditch, S. A., and Whitehtisd, W. S.:and Lea Counties, in southeast New Mexico, These formations Minimizing Damage to a Propped Fracture by Controlkx.taverage 18 percent porosity and 50 md permeability over 50 feet of Flowback Procedures, J, Per. Jcc/z. (June 1988)753-760.average net pay, The formations are straight !O sinuous channeldepositions of fine rained sandstone.which are overlain by dense

t2. Ely, J. W,, Welters, B, C. and Holditch, S. A.: improved Job

dolomites and pine out literally into siltstones and shales, The Execution and Stimulatirm Success Using Intense QuidityDelaware sandstones in ;heseareits hitvebeenidentified throughcore Control, paper presentedtit the 1989 !Xm(hwcstcrn Pcudcumanalysis to give up formation fines, Shott Course, Lubbock, TX,

Pefore 3, Coulter, G. R. imd We!!s,R. D.: The Adv;tntitgcs of HighProppant Concentration in Fritcture Stimul:ttions, Ll?l (June

Previewsfra$ture stimulation treatments utilized 65 qu?,lity(Xla !972) 643.50.foumsystems, Tnetypictdtreittmentput awity40,000 lbsof proppuntgoing up to 4 Ibs/gitl, These treatments were pumpcci iit 12 BPM 4. Ely, J. W, tindHolditch, $, A,: i)c~pWell Stimul:itionUfilizingand were designed to give a fracwe half length of 360 feet. Forced Iiigh Conccnmuions of Proppwu, pq)cr S1li4118 rcscnwdclosure was not implemented on the beforetreatments, &at the 1972 SPi3Annual Fall Meeting, Sitn Antonio, ct. 8-11.

Resultant stabilized production from the typical before 5. Watkins, H.: Y-iighcrSand Conccn[ro[ionin EtistTexiss,piip~rtreatment averaged 40 BOPD and 36 BWPD, Production fell off SPE 10913 presented It the 1982 SPE Cotton Viillcydramatically within the first few mon!hs after stimulation, Symposium, Tyler, TX (may 20).

6, Penny, G. S.: Evaluation of the Effects of EnvironmentalConditions and Fracturing Fluids on the Long-Term

The new treatments were designed using a polyemulsion type Conductivity of Proppants, paper SPE 16900 PIssented at thefluid, Models revealed that thepolyemulsion typefiuid was adequate 1987 Annual Technical Conference and Exhibition, Dallas,to create the desired fracture dimensions and carry the designed Sept. 27-30.proppant csnce:mations of up to 8 lbs/gal. The polyemulsion fluidwas also chosen to aid in formation fines control, The new fracture 7, Kim, C, M, and Losacano, J. A,: Fructurc Conductivitydesign transports 120,000 lbs of proppant and is being pumped at Damage Due to CyosslinkedGel Residue and Closure Stress on15 BPM. Quality control is implemented and forced closure is Propped 20/40 Mesh Sand, paper SPE 14436 presented m theemployed immediately upon completion of the flush stage, Table 8 1985 SPE Annual Technical Conference and Exhibition, Ldsillustrates the pumping schedules, Vegas, Sept. 22-25,

As illustrated h Fig. 11, resultant production from the new 8. McDaniel, B. W,: Conductivity Testing of IJroppimtsat Highfriscturetechniques retdized a twofold increitse, The wells usutdly Tempcratum id SWSS, piipcr SPE 15067prcscntcd iit (hc.1986flow several days after stimulation and beyond load recovery, SPE California regional Meeting, oakland, April 2-4.Average stabilized production from the new treatments is 112BOPDand 32 BWPD, The historical severe decline in production durin~ 9, Investigation of the Effects of Frii~turitlg Fiuids Upon thethe first few months has been iargcly reduced, Conductivilyof Proppams,final report, Stinl-Lab Inc., Duncim,

OK (Jan. 18, 1988),This case experienceda distinct probiem that is common to wells

that are producing with a large pressurv &op across a pertbration, 10, McDaniel, B, W,: Realistic Fracture Conductivities ofAfter forced closure is implemented and the well eventually dies, Proppants as a Function of Reservoir Temperature, puper SPEminimal sand is found in the wellbme, The well is cleaned out and !6453 presented at the 1987 SPWDOE Low Pcrtnciibiiityplaced on artificial lift, but sand starts showing up in the wellbore Reservoirs Symposium, Denvrr, May 18-19,over a period of several @dYS. This probiem has been elim nated byusing larger 12/20 mesh proppant. 11, Holditcil, S, A., Robinson, B, M,, Ely, J, W,, and Rithin~,Z.:

The Effect of Viscous Fiuid Propenies on Excess FrictionCONCLUSIONS ~PressuresMeasured During Hydraulic Fmcture Treatments,

paper SPE 18208 presented at the 1988 Annual Ikclmical1, The forced closure technique has significantlyreduced proppant Conference & Exhibition, Houston, Oct. 2-5,

production on over 90 percent of the wells tested to date,

2, The forced closure technique combined with high sandconcentrations and intense quality control wiii result inimproved productivity.

3, Guidelines for foruedclosure have beendeveloped through fieldexperience and are summarized in Table 3,

..-

.sPE 20;08

TABLE 1

EXAMPLES OF FORMATIONS WHERE FORCED CLOSUREXAS BEEN UTILIZED

Vicksburg SandstoneWilcox .%ndstoncYegua SandstoneCanyon SandsloncFrontier %mdstorwMorrow .%ndstoncSnhsckovcr %rdstoncSmirckovcr Limestonef)lrnos SandstoneClcarfork LtmcstoncNumerous CAal Scamsin the US.Couon Valley SandstoneTravis Peak %rdstoneGmyburg %ndMississippi

Dean %rndstoncDelawareEdv-ards LimesmncPr;o .%ndstoneVacuum Gloric(!itGmnitc WashSand AndrcsH--$ton Sands!oneSpraberry01isksny %ndsloneRed ForkYatesMcKee SnndstoncWaddcll WurdstoneStrPwn

TABl Y 3

FOR(?ED CLOSURE Ihll~LKh*.ENT/\TION PROCEUUIW

1.

2.

3. .

4.

3. .

().

7.

8.

Y,

I ().

11,

12

13,

TABLR 2a

TYPICAL CLEARFORK DFS[GN NEAR LIWELfAND IWXASPolycmulsion Fluid

B Smd Conccn(mliml.

Siagc Fluid Volume ppg Mesh SIZC(gais)

IWycmulsinn rsrd 5,CQfl! Polycmulshr 2,(SKI 2.5 20/ ,() h!csh3 Polycmuisinn 2,fKm S.(I 20/40$Icsh4 Pnlycmulsirm 2,fW3 7,s 20/.W hfcsh5 Polycmulsinn S,ftoo 1() 20/.$[)h!csh() Crude thh As required

TABLE 2b

FRACTURfl TRE,\1 hlENT I) LL.SIGNFOR FRONTIER FORMATION IN WYO\llNG.IO#Belayed Crosslink Ccl

i- %nd CmrccntmlionSIilgc Fluld Volume pp)j h!csh Sin(g,lls)

I Slick wmtr rx-psd 1(WOO~

20/40h!csbDclnycd crnsslink Id 4S,(IO0 20/40 hlcsh

3 I):laycd crosslink s,(m) 20/40hbb?.4 Duloyxl crosslink s,(m) 4 20/40Mush5

Djl ILxl &Jintif)~l~)cd ~rm> Ital. i (),(1(X) (1 2[);40 blush

(> ,: 1o,ooo 20/4(1hlcsh7 Delmjcd cross mk

DLkIVCd &s.[;r,kl[),cot) 1: 20!.!0 hlmb

N s 1S,[MM) 1~ 2[1/4[1MeshDclnjcd cros~liok 6,(KH) l-t 20/40hfcsh

l% I)elqd crnss!inli ?,fm) I () 20!40 MeshSlick wmw tlush In top pcrf

TABLE 4

BtWOfW AND A1.fkHt PUMP SCI{EI)U 1.E C.Ofi! PA RISONFOR TIlfl CL.FARFORK CASE II ISIORY

UCsure 11101Ilw WCIIIISMImd Ilnwhuck nmnif oldsys(cm MCinstnllcd mrd (CSIW!so IlwW141can Ix tlowwf bock w,ithin 3[1secnndsofcmnplcting tlush, Pigurc 12 iiluslrnlm ;Ilypicul surfnw Ilrynd( tnr fnrcmt ciosurbinrpkmlunlnlion.If:1 Ilquld fmciuring fiuid is used, inshll n !lnw nhlw Capnhlcof monilnring rutcs !mm 1(11020 gnlions pcr minm dnwns(r~iltr)ot iI varinblc choke. It n hum Iriwlurins ilu id isused, nn tlnw mwcr i.. nccdud, TIIC Fnwlmck rnlc nf WISIMn lx! LwlmIkItcd trnm IIWpresmro drop :Icrn$sIh orifiw.

Isolutc Ihe clwkc imrf ilnwmdcr with iI Mnck v:Ilvc during IIICtrcuhmw(.Insure IM W choke i> fully clowd ml isokwl prinr m st:wting Ilw fr;wturc msu!mrnt.

Wilhiu 30 !icconds ofwr c{m)plcling tlw hush, open (IIChlnck VIIIVCwith Ihc ull(lkc sl Iiclostct, If (he choke fuils, Ilw block WIIVCcon he USCSIIISII bnckup 10 rqylulu IIIIWIm(c,Open Ihc chnkv sluwly, bn not cxcwd n tlnwh:wk mlc o! 1(1-1SgIIlhNISpur minulu forliquids or :111cq.ivnlm m(c tor g:wcslh!onitor pressurevs IImc (o &IIXt frnc[urc closure,Cnnlinuc 10tlnw nl n Inw mlc tnr 30 minuhx ~tfwr near wcllb{lru Irncluw clnsurc Ilw, Iwclldvtecwd.

Tht Ilowb:lck ro(c CIIUIhcn bc incrcwswtin 20.2S gallons p:r n)inuIu for Iiqoids orOqUIVillCll(mlw for guw%(.onlinut Ilnwing fm nn Uddiliollill 30 minutt:h For nnrmnl prcssurtd or Wr ,ited wcllsi

1IIIe [Iowbnck rtuc m CVUIIIUIIIIYIw Incrc:wt M 1.2 11PM, AlwIIys monimr ( ICprnduccdtlui(ts 10nltnsure rlm(i conlcnt.CImkc buck tlw Ml :IS1WCCSMJ%WIM gns nr nil tlow III(CSIwconw IiwgcFlow Ilw VWll for scvwut cloysor wcctis using choke sim nn lurgur (Ililll I (1-12/(14inch.hfonilnr nml record 1111dim cm]ccruing Ilnwing pressuresnmt nil, gns nnd wwtw lhv rnks,

TABLE S

BEFORE AND AFTER PU!,lP SCIIEDIJLE tiOhtPAIUSONFOR TI153 hfcK~h; SANDSTONE CASE II!!WORY

Previous DesignSlagt Volume Sand Cum %nd

(g:,]) (#/g#l) (p,s)El 19,000 0.0

4,000 0.5 2,()(;1: 4,00il

$ [ y;g

6,0004 I2,000

22,0006 1,)()[) 2s 37,%)07 (l,(m) 3.0 :.s,O!1(:

New I?csignStil~l! Volume Snnd Cum S:ml

(MI1) (tmq (11)s)1 20,000 0.0 i)~ 5,000 I .0 5,()()()s S,()()() 2.0 I 5,()(K)4 (),000 3.0 .33.000$ (),0(1() 4,0 57.000() 7,000 5.0 92,0007 s,(w) 6.0 122,:)00

TABLE 7

BEFORE AN I) AFIT-:R PUMP SCIISH)ULII COMPARISONFOR TIIE NORTH GOLl)SMiT1i FIELD CASE HISTORY

Ncw DcsixnStilgL! V(>lumc sand cum Sml(l

(g~ (#/g:ll) (Ills)I 5!000 0!0

; 4,00[)

TAME 6

BEFORE AND AFTER PUMP SCIIIiDULIi COMPARISONPOR TIIE FIILLERTON . SAN ANDRF3 CASE HISTORY

I

I

1- Ntnv Irc:mnent Dcsicn !II

......, V.. =-., , ,...,,,

I I t. IUul I , I ,, I

1..,,.,,,,,j ; A

,,1,000 2,000

3 1.000 4 6,0001 2,000 (1 IN,(MW

fl :,000 s 3.!,00[). . ... .

Ll,ooo~,), >,(u) I Iu I ~

TABLE 8

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