Evaluating Hydraulic FractureEvaluating Hydraulic FracturePropagation in a Shallow SandstonePropagation in a Shallow SandstoneInterval, South TexasInterval, South TexasPresented byDave Cramer / March 10, 2011EPA Hydraulic Fracturing Technical WorkshopWell Construction and Operations2Background•This is a case study ofa water flooded oil reservoir in South Texas.•The productive interval is a tight, multilayer, Cretaceous-age sandstone with truevertical depth rangingfrom 1200-1700 ft.•Over 1000 production and water injection wells have beencompleted in thearea over past 50 years.•Hydraulic fracturing is normally employedto stimulate well productivity in thestudy area. A standard treatment design features the use of viscous 25 lb/1000guar borate fracturing fluid and 12/20 mesh proppantinjected ata high rate(e.g., 40 bbl/min.)•Although diagnostic fractureinjection testing (DFIT) analysis indicates that theminimum principle stress is horizontal, tiltmeter mapping, tracer surveys, anoffset-well corehole projectand treating pressure analysis indicate that most ofthe fracture propagation is horizontal (normal to the overburdenstress) and thatthe vertical fracture component (normal to the minimum horizontal stress) iscontained within the pay interval.•Because of the limited vertical hydraulic fracture propagation, limited entry ormulti-stage treatment methods are employedto establish hydraulic fractures ineach of the productive reservoir sand compartments.3The formation is composed of sandstones and shales.The sandstone units are a series of deltaic depositsreworked by marine processes.Characteristics of the productive sandstone interval:•reservoir depth ranges from 1200 –1700 feet TVD•average porosity: 20%•average permeability: 4 md•oil gravity: 39 APIGeologic Overview436-72Scale : 1 : 240DEPTH (1230.FT - 1330.FT)02/13/2008 22:57DB : Chittim (2)DepthIN:CALI (in)6.16.BS (IN)6.16.DEPTH(FT)TVD(FT)LithoVCL (Dec)0.1.PHIE (Dec)1.0.BVW (Dec)1.0.ResistivityRXOI (OHM.M)0.220.AT10 (OHM.M)0.220.AT20 (OHM.M)0.220.AT30 (OHM.M)0.220.AT60 (OHM.M)0.220.AT90 (OHM.M)0.220.IN:RT (ohm.m)0.220.PorosityRHO8 (G/CM3)1.652.65NPOR (FT3/FT3)0.60.PEF8 (0)0.10.SonicScannerFIN:DTS (uSec/ft)300.100.FIN:DTC (uSec/ft)150.50.DTCO (US/F)150.50.DTSM (US/F)300.100.Poisson RatioHR:PR_DYN ()0.10.5Bulk ModulusHR:BMK_DYN ()0.5.HR:SMG_DYN ()0.5.Young ModulusHR:YME_DYN (Mpsi)0.5.Strss GradientsFIN:TZSG (Psi/Ft)0.51.5FIN:PPGI (psi/Ft)0.51.5SH1 (psi/ft)0.51.5SH2 (psi/ft)0.51.512501300ZoneLog SuiteLog SuiteFlow barriersFlow barriersLog analysis provides estimates of reservoir properties5N.J. Chittim 37-30R DFIT calc bhp (psi)

500 1000 1500 2000 2500

rate (BPM) 1.0 2.0 3.0 4.0 5.0Time (min)0.010.020.030.040.050.060.070.080.090.0100.0rate (BPM)calc bhp (psi)ISIP=1429 psi (1.10 psi/ft)Breakdown at 2900 psiDiagnostic Fracture Injection Test (DFIT)Rate and Pressure DataInjection RateBottomhole PressureNote: overburden pressuregradient = 1.02 psi/ftLow volume fracture injection tests can be analyzed to provideestimates of in-situ stress and reservoir transmissibility (kh/u)6Vertical fracture closure is a proxy for minimum horizontal stress (S3)DFIT G-dp/dG PlotVertical fracture closure at trend-linebreak-over = 1094 psi (0.84 psi/ft.)Probable horizontal fracture closure (1.02 psi/ft)91 hours of shut in time7( )r rP P1h vv h t



# ν

σ σα α σ

ν⎡ ⎤−+ +=⎢ ⎥−⎣ ⎦Where,σv= overburden stress, psi = 1331 psi (1.02 psi/ft; bulk density log)ν= Poisson’s ratio = 0.31 (from dipole sonic log computation)αv= vertical Biot’s parameter = 1.0αh= horizontal Biot’s parameter = 1.0Pr= reservoir pore pressure, 718 psi (0.55 psi/ft; DFIT)σt= external (tectonic) stress, psi = 0 psi (assumed)σh= minimum horizontal stress, psi = 1047 psi (predicted from above)σh= minimum horizontal stress, psi = 1094 psi (observed from DFIT)Poroelastic Equation for Estimating In-SituHorizontal StressThere is reasonable agreement with predicted and measured in-situ stress8Bottomhole Treating Pressure BehaviorVariability in initial reservoir pressure isdue to injection/ withdrawal imbalanceswithin the field.Regardless of initial pore pressure, hydraulicfracturing pressure (FG) is regulated by theoverburden stress.Initial WHP0100200300400500600700800900Apr-08 Jun-08 Jul-08 Se p-08 Oct-08 Dec-08 Fe b-09 Mar-09 May-09FG0.00.20.40.60.81.01.21.41.61.82.0Apr-08 Jun-08 Jul-08 Sep-08 Oct-08 Dec-08 Feb-09 Mar-09 May-09overburden (vertical) stress ~ 1.02 psi/ft9Post-Treatment Multi Test Hole StudyTreatment Multi Test Hole StudyFrom SPE paper 1571 (1961)An extensive horizontal fracture was “excavated”10Surface Tiltmeter Deformation Visualizationhorizontal fracture(domed or conical feature)vertical fracture(trough feature)dipping fracture(asymmetricaltrough feature)11Tilt Vector Diagram & Surface DeformationVisualization, Example from Study AreaTiltmeter mapping results show the classic signature of a horizontally-dominanthydraulic fracture system. Horizontal fracture component is 78-90%Surface displacementduring the treatmentwas equal to the thickness of 2 sheets of paperNot to scale:10,000,000:1 horizontalto vertical ratio0.0078 in



# 6 5 0 0

f t12Hydraulic Fractures Open Normal to theLeast Principal StressBut it’s a little more complicated than this in shallow reservoirsS1S3S213T-Shaped FracturesThis routinely happens when the difference between horizontal and verticalprincipal stresses is small, as is the case with shallow reservoirs14pad1-4 lb5 lbFive Zone Limited Entry Treatment: Well AFive Zone Limited Entry Treatment: Well ATop of sandTop of vertical componentBottom of vertical componentHorizontalfractureHorizontalfracturesHorizontalFracture?HorizontalfractureTop of fractured interval is capped by a horizontal fracture15pad1-4 lb5 lbThree Zone Limited Entry Treatment: Well BThree Zone Limited Entry Treatment: Well BHorizontalfractureTop of sandNo apparent vertical componentHorizontalfractureHorizontalfractureDominant horizontal fracture signature16Recompletion Tracer Log: Well CNew perfsHorizontalfractureTop of sandTop of vertical componentHorizontalfractureHorizontalfractureBottom of vertical componentHydraulically fracturing via the new perf set increased oil productionby 10 fold. This response is indicative of the lack of vertical connectivityfrom the previously fractured original perf set.Original perf set17Two Zones with Ball Sealer Diversion: Well DTwo Zones with Ball Sealer Diversion: Well DHorizontalfractureHorizontalfracturesHorizontalfractureTop of sandTop of vertical componentBottom of vertical componentTop of fractured interval is capped by a horizontal fracture18pad1-4 lb5 lbFive Zone Limited Entry Treatment: Well EFive Zone Limited Entry Treatment: Well EHorizontalfractureTop of vertical componentHorizontalfracturesTop of sandHorizontalfractureBottom of vertical componentTop of fractured interval is capped by a horizontal fracture19Treatment Pressure History Evaluation: Well EISIP = 1.07 psi/ftModeled pressureActual pressureInjection rateProppantconcentrationActual results matched computer modeled results indicating good control of the process20Limited EntryTreatment ModelingPropped width after fracture closureHydraulic Fracture Modeling Results: Well EWidth vsradial position for each horizontal fractureVertical Fracture Component:assumed to be negligibleHorizontal Radius (ft)Hydraulic Widthat end of injectionfrac #1frac #2frac #3frac #4frac #5frac #621SummaryConditions are favorable for propagating horizontal fractures in shallowreservoirs.•There is a small difference between theoverburden (vertical) andminimum horizontalprincipal stresses.•The net pressure required to extend a vertical fracture is inexcess of thehorizontal-tovertical stress difference.Fracture geometry can be estimated from the treatment pressure response.•Horizontal fractures propagateradially and require decreasing net pressure to grow.•Vertical fractures eventually propagate elliptically(length-to-height aspect ratio of greaterthan one) and requireincreasing netpressure to grow.Vertical fracture growth is contained within the pay sand.•Core hole, tiltmeter, tracersurvey and treating pressure analysis indicate that horizontalfracturing is the dominant modeof fracture propagation even though the minimum in-situstress is not vertical.Methods are employed to controlthe hydraulic fracturing process.•There is a strong financialincentive to contain fracture propagation within the targetsandstone intervals.•Treatment designs are modeled and evaluated withcomputer-based processes.•Limited entry or selective multi-stage frac treatments are necessary to achieve fracturepropagation in all the sub-intervals in the study area.