SPE 30493 Effect of Long Term Shut in in Fracture Conductivity

8/8/2019 SPE 30493 Effect of Long Term Shut in in Fracture Conductivity

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ASPE 30493The Effect of Long-term Shut-in Periods on Fracture ConductivityD.M. Bilden, SPE, BJ Services Company, P. A. Fletcher, SPE, and C. T.Montgomery, SPE, Arco Exploration and ProductionTechnology, Piano, USA, R. J. Guillory, SPE, ARCO Indonesia, Jakarta, Indonesia and T. P. Allen, SPE, ARCO International Oil and GasCo., Piano, U.S.A.@Y& 19 95, S Oc id y O fP eLr Ok m E J@!8m , f n c.lh is w w n p qu ed for t he 1 995 S PE AN@ Te ch n ic alCm f- m id Ex hib it io nt o be h e ld 2 2-25CHob a 19P 5b t Ca l fu , T u r n .lh is p,p a ww +s ek cM fo rp se nh d mb ya n SP EP r og nm C om it te e GMOw in g Ofin hn moncO n t a i n e d r nu 1 8b s tWt s u iWn i t k d b y t h e 1 u t hm (s ). C cm tm bo ft h e p a p e r , a $ p r e sm t e d , hm e n o t bm lm iew ed by t he S`xk tyOf~En giWr s 8n du esu bju 3ed t0 m rm tion b y t h e U lt f@s ). I he_=mtiht i~aWmy_ofhWof~EtikObOHIK@US. Memm en t id t i SP E_um bxm+t i t im WE d i ta i d C ammt&s O fd le s oc ie t y Of P e tm k u m S n gi n em . P a m mO n t oq y is r es b ic t ed t oa nS b 8t n c t of n ot mm e t hm n owml s. a hM tm dm ls n la y nOt b e G Op i .? s.k 1 t8 1J a 1 3 sh 0 u k 2 r e t a in~~~tOf*~W*~ P P =W=P R=I I~ Wr iW b - SP E .P .O . ~X S 33S 36,R k f u r d sm , TX 750G 3636 , U .SA. , f a x 0 1 -2 14 -9 52 -9 43 5.

AbstractPolymer residue is known to be a major cause ofproppedtlacture conductivity damage. Many factors that can contributeto the si~]cance ofthis damage are polymer type, initial andfinal polymer concentrations, breaker types and concentrations,formation mineralogy, bottom hole static temperature, shut-intime and fluid cleanup rates.

Most fracturing treatments are designed with good fluidstability for a specific period of time that corresponds to the jobpump time. It is then desired to break the fluid as quickly andcompletely as possible to facilitate rapid cleanup of the well andminimize conductivity darnage. A common belief has been thatif the treatment is shut-in in the reservoir too long, fractureconductivity darnage may increase. This belief has led tooperational completion practices that are costly and unnecessary.A laboratory studywas conducted to study the effects oflong-term shut-in periods of up to seven days. The resuits

irdcated that additional conductivity damage would not occurlLnderLhcCOnd!tiQnsested. These observations resulted inchanges in completion procedures that improved rig timeefficiencyfor the completion of remotely located offshore wells.IntroductionOffshore and geographically remote well operations otlenrequire the use of the drilling rig for completion operations. Thetime consumed on the completion phase of the well can thereforebe very expensive. Significant cost savings can be realized if the

Soebty of PotrolsunlGl@leers

rig is moved quickly to the next drilling location.Hydraulic fracturing can significantly increase thecompletion time of a well. It is common to flow the treatmentfluid back afler each stage to recover the fluid. Concerns overpotential fkactureconductivity damage, due to treatment shut-infor an extended period of time, have dictated this practice.Multiple frac stages per well, compound the completion timeproblem fhrther. Little work has been done regarding the effectof gel residue on fracture conductivity for extended shut-in _periods before flowback. Conductivity studies have beenperformed to evaluate long-term effects on proppant packs, butonly after treatment flowback. Hawkins2looked at the effkctof fracturing fluidsfi~nfi~~t.~i~~I t t in ~ fi ln QI m e nn c~~~I~c~~v~~ ~fi~ ~in ir n a i ShUt_Uu llk ?w ,,u =Uwu WQ II.* .. -.. -in times. The results of this work showed a 10to 20 percentreduction in conductivity. However, much of the fluid tests weredone without breaker, and flowback began irnmcchatelyin mostcases or with only a short period of shut-in time(100 hrs) insome cases.It is desirable to move the drilling rig to the next slot asquickly as possible afler drilling is complete on eachwell. Dueto the significant amount of time that was being consumedduring flowback of the frac treatments between frac stages, itwas decided to investigate the effect of long-term shut-in timeson the fracture conductivity to determine if this flowback. .. . ..mt.na..es *#.oll.,maceQQn~~1a-,lu~ W ~ ii , WC bl !, U-W-7 -. -. ,. Rwfiv~w fif the fi~c fluid&Qrnaii.W-V-. , -. --- .. .frac stages at the same time atler the last fiat and after thedrilling rig moved, would greatly improve the rig utilization

efllciency.The desire for improved operational efficiencies led to thelaboratory study described here.

Drilling and Completion ProgramARCO Indonesia operates several fields in the Offshore NorthWest Java Sea (ONWJ) area. A large re-completion and infdldrilling program was proposed for the B and E Field Areas in

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- ---. ->>-2 . - .1*wnwrruaucms UI up LU I 4 rrfi ~wnas pruppam aaaea) on autreatments to date, however, the use of a resin-coated 16/20mesh intermediate strength ceramic is being investigated.When applying fracturing treatments for aand control as wellas reservoir stimulation in high permeability formations, the keyto success is to obtain a highly conductive fracture. Thefhctures that were designed for the ONWJ project wells wereshort (approximately 100 foot half length), highly conductivefractures that would have final proppant concentrations in excessof 3 lbs. per square foot. All treatments were also designed toachieve a tip screenout. The ultimate goalwas to achievecompletions with negative skin factors and sand free production.

In the process of designing and implementing the approptest procedures to best simulate actual conditions, it wasnecessary to deviate slightly flom standard practices forconductivity testing. A proppant concentration of 2 pounds psquare foot is typically the standard for these tests. Howeverdue to the high proppant concentrations incorporated into thfracturing treatment designs, it was determined that aconductivity test in excess of 2 pounds per square fbot wouldnecessary. Limitations of the existing test cells dictated amaximum proppant concentration of 3 pounda per square f~these tests.The standard average final gel concentration for conducttests typically is approximately 180 pounds per 1000 gallonsThis is not the concentration of the polymer in the filter cakethe total average in the closed fracture porosity. Thisconcentration is achieved by starting with an 8 lbs. of proppa

added sluny concentration and enough proppant to obtain 2pounds per square foot offracture area in the cell. Because tscreenout designs were needed to maximize conductivity, hifinal gel loadings needed to be tested to adequately simulateactual field conditions. The leak-off during the fhcturestimulations was estimated to be higher than normal due to tunder-pressured reservoir, also leading to higher than normaconcentrations in the fracture. These tests incorporated finalaverage gel concentrations of 200 and 450 pounda per 1000gallons of fluid.Conductivity Testing EquipmentThe conductivity testing incorporated the use of a modtied Aconductivity cell (Fig. 1) which haa been described previousthe literature.s The cell has a flowpath area through theproppant pack of 10 square inches and allows for leakoffthrough Ohio Sandstone core slabs and subsequent filter cakdevelopment. The use of this type of cell is the generallyaccepted method of testing in the industry.Testing ProceduresThe tests were conducted using API I/P 61 recommendedprocedures for determining short-term fracture conductivity.-- L..-.-1L,-8L:.-J..--.- .-L:---- --.3Ine oouom core slau (urno mnaslone) was macmneu armplaced in the conductivity cell. The proppant was then addeand leveled. The test fluid was then placed on top of the aanpack and the machined top core was placed in the cell. Leakwas allowed to take place as the top core moved down to theproppant bed and the closure stress was applied. Thetemperature was increased to 150F prior to starting leakoffthen increased to 180F while leakoff occumed. A pore presof 500 psi was then applied prior to shutting in the cell for thprescribed period of time. After the shut-in period, heated 2KC1water(180F) was flowed through the pack by using aconstant rate pump while maintaining the 500 psi pore pressin the proppant pack.


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4 THE EFFECT OF LONG-TERM SHUT-IN PERIODS ON FRACTURE CONDUCTIVITY SPE 30

Tests #6 and #7 were identical in fluid formulation, butdiffered in that the final average polymer concentration in thefracture was increased from 200 to approximately 450 poundsper 1,000 gallons. This was done to measure the efkct ofextremely high leakoff which was expected to be encountered inthese treatments. The polymer concentration in Test #6 was 200pounda per 1,000 gallons and resulted in a permeability of 753Darcies or 89% regain. Test #7 contained the extremely highpolymer concentration and resulted in 736 Darcies or 87V0regain. It was concluded that the higher polymer concentrationwould not have an adverse effect on fracture conductivity withthis fiat fluid and enzyme breaker combination,

It should be noted that the strongest resin set or proppantpack consolidation, was seen in Test #2. Tests #4 through #7displayed varying degrees of consolidation that were all less thanthat obaervd-in Test #2. Tlis observation has led to tierinvestigations into resin/frac fluid additive compatibility.Field ResultsTen fracture treatments on seven completions have beenperformed to date that have incorporated long-term shut-inperioda prior to flowback of the tlacturing fluid. Pressure build-up testa from four of these completions have been analyzed andare presented in Table 4. All results are very positive in that thecalculated skin factors were all negative, indicating effectivestimulation. It should also be noted that all fracture stimulatedzones have had sand-free production. Sand-the production ispartially due to high effective fracture conductivity. Othercontrolling parameters contributing to sand-kc production arefracture length and controlled drawdown pressures.

Table 5 presents the measured fracture parameters for thetests conducted on 12/20 mesh white aand. The test fractureconductivity measurements range from 19,209 to 21,995 md-il.The analysis of the four completions in the field, presented inTable 4, resulted in fracture conductivity values of 4,10016,500,21,950 and 34,700 md-fl These values were determinedthrough pressure matching analysis techniques. With theexception of the 4,100 md-fl value, the values compare veryfavorable to those measured in the laboratory. This cm-relationfurther substantiates the relativity between the laboratory testsperformed and the actual field treatments. Designed totalaverage proppant concentrations of greater than 3 pounds persquare fbot are being achieved in the field and are providingsuccessful results.Operational ImpactThe results ihm this work allowed an improvement in thedrilling rig schedule such that a substantial amount of rig timeper well was reduced. For multiple zone completions, the zonesare stimulated separately and excess sIurty and proppant iswashed out between fiat stages, but there is no flowback ofzones until the final completion is placed. All other steps of the

normal completion prccedure remained the same. An average3 days per well was saved (1-Z days per zone, 2 zones per wewith a resultant cost saving of nearly $200,000 per well.ConclusionsLong-tetm (7 day) shut-in periods did not have a detrimentaleffect on fracture conductivity in laborato~ testing.

Pressure Transient Analysis testing on fracture stimulatedwells provided wellbore skin damage values fkom-2.3 to -4.7indicating stimulation in all cases, and no evidence of increasepolymer damage in the fractures.Significant well completion cost savings can be achieved bleaving frac treatments shut-in between stages.ChemicaI compatibility issues must be considered whendesigning fracturing treatments with curable resin coated

proppants.AcknowledgmentsThe authors would like to thank the management of BJ ServicARCO E&P Technology and ARCO Indonesia Inc. forpermission to publish this paper. Special thanks go to GarthGregory and Mike Francis for their efforts in the field and toHarold Hudson and AlIan Rickards for generating the lab dataReferences1

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Penny, G. S.: An Evaluation of the Effkcts of EnvironmentalConditions and Fracturing FluidsUpon the Long-TermConductivity of Proppants~ paper SPE 16900 p r es en t ed a t t h e1987 SPEAnnual Technical Conference and Exhibition, Dallas,Sept. 27-30.Hawkins, G.W.: Laboratory Study of Proppant-Pack PermeabiliReduction Caused byFracturing Fluids Concentrated DuringClosure: paper SPE 18261 presentation at the 63rd AnnualTechnical Conference and Exhibition of the Society of PetroleumEngineers held inHouston, TX, October 2-5,1988.Fletcher, P.A., Montgomery, C.T., Ramos, G.G.,Miller, M.E. anRich, D.A.: Using Fracturing as a Teohnique for ControllingFormation Failure~paper SPE 27899 presentation at theWesternRegional Meeting of the Society of Petroleum Engineers held inLong Beach, Ca,March 23-25,1994.Recommended practices forEvaluating Short-term Proppant PaConductivity,American Petroleum Institute RecommendedPractice 61 (T@61), First E&tion, (let. 1,1989.Gidley, J.L., Penney, G.S. and McDaniel, R.R.; Effect ofProppant Failure and FineaMigration on Conductivity of ProppedFractures~paper SPE 24008 presentation at the 1992 SPE PerrnBasin Gil and Gas Recovery Conference held inMidland, Tx,March 18-20,1992.Investigation of the Effects of Fracturing FluidsUpon theConductivity of Proppants: Final Report, 1991 STIM-LAB, IncProppant Consortium, February, 1992.Fletcher, P.A., Montgomery, C.T.,Ramos, G.G., Guillory,R.J. aFrancis, M.J.: Optimtiing Hydraulic Fracture Length to PreventFormation Failure in 011and Gas Reservoirs, 1995 Rock

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SPE 30493 D . M . BI LDEN , P .A FLETCHEK C. T . MONTGOMERY, R. J. GUILLORY, T. P. ALLEN 5

MechanicsSymposium, Lake Tahoe,Nevada, June 7-9,1995.

TABLE 1- SHORT-TERM CONDUCTIVITY TESTS WITH 12/20 MESH WHITE SANDMUTUAL FLUID CLAY AN1ON1C NONIONICTEST SOLVENT RECOVERYSTABILIZERDE-EMULSIFIERDE-EMULSIFIERERMEABILITYREGAIN

J!!!2& . . . . . . -n mr,n~PKG~~ (P.p-pn (QpT) (GPT) m m (DARClES) m1 276KCI Waler 844 1002 Base Frac Flu id 2 GPT Enzyme 718 853 Base Frsc Flu id 2 GPT Enzyme 787 93

~~ELE z - ~ONG-TERM CONDUCTNITY TESTS WITH 12/20 MESH WHITE SANDMUTUAL FLUID CLAY AN1ON1CDE- NON-1ON1C DE-m.glT SOLVENT RECOVERY Stabilizer EMULSIFIER EMULSIFIER PERMEABILI TY REGAIN

w&wm!m lwAxm&l!Q mm @m_ -----(t i t1 ) (m l /B A D~117C#

1 2% KCI Water 790 1002 Base Frac Flu id 2 GPT Enzyme 697 883 Base Frac Flu id 2 GPT Enzyme 701 894 Base Frac Flu id 2 G PT Am mo niu m 50 2 4 ~ 674 86

Peraulfate< R.... r-- rnl,i,i 7 C.PT F r o -e 4 2 ~~ < a l

TABLE 3- LONG-TERM CONDUCTIVITY TESTS WITH 16/20 MESH RESIN-COATED CERAMICMUTUAL FLUID CLAY ANIONIC DE- NON-IONIC DE-

TEST S(xv!m ,T RF~f )V i7 11 V s T.A ~[ l~~R...,., -- . u .. . EMULSIFIER EMULSIFIER PERMEABILITY REGAINX!&lkwmm lw&Q!l_@nl mz!lm!zl @!?m ffml (DARCIES) m

1 2% KCI Water 845 1002 Base Frac Flu id 2 GPT Enzyme 734 873 Base Frac Flu id 2 GPT Enzyme 50 2 4 2 595 .714 Base Frac Fluid 2 GPT Enzyme 2 4 2 5 809 965 Base Frae Flu id 2GPTEnzyrne 2 4 2 735 876 Base Frae Flu id 2 GPT Enzyme 4 2 753 897* Base Frae Flu id 2 GPT Enzyme 4 2 736 87

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6 THE EFFECT OF LONG-TERM SHUT-IN PERIODS ON FRACTURE CONDUCTIVITY SPE 304

II TABLE 4- SUMMARY OF STIMULATION DATA FROM INITIAL STKMUJLATIONS IN KNDOIWslA~~_-FRACTURE FORMATION

FRACTURE HALF LENGTH CONDUCTIVITY PERMEAEILITYfMD-Fn

1 80 34,700 10 -4.72 53 4,100 30 -3.73 91 16,500 33 -2.3

u TABLE 5- FRACTURE PARAMETER MEASUREMENTS FOR 12/20 MESH WHITE SAND TESTS-T FRACTWREIDTH FRACTURE CONDUCTNITY PROPPANT PERMEABILITY

(IN) (MD-IT) (D&jXES)1 .3310 21,7S9 7902 .3310 19,229 6973 .3315 19,350 7004 .3420 19,209 6745 .34s0 21,995 76S

q s ame t es ts a s i nTab l e#2

nnt....,.tl q Wan..q-** r*r**

bb*

Figure 1. Schematic of modified API conductivity test cell.

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SPE 30493 Effect of Long Term Shut in in Fracture Conductivity