Lesson 7 Foam Drilling Hydraulics-3

Lesson 7 Foam Drilling Hydraulics-3 - PETE 689...

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Unformatted text preview: PETE 689 Underbalanced Drilling (UBD) Lesson 7 Foam Drilling Hydraulics Read: UDM Chapter 2.5 ­ 2.6 Pages 2.75­2.130 MudLite Manual Chapter 2 Pages 2.1­2.14 Harold Vance Department of Petroleum Engineering Foam Drilling Hydraulics Benefits of foam drilling. Rheology. Circulating pressures. Limitations of foam drilling. Homework # 2. Harold Vance Department of Petroleum Engineering Benefits of Foam Drilling High viscosity allows efficient cuttings transport. Gas injection rates can be much lower than dry gas or mist drilling. Low density of foam allows UB conditions be established in almost all circumstances. Harold Vance Department of Petroleum Engineering Benefits of Foam Drilling BHP tends to be higher than dry gas or mist operations and penetration rates maybe reduced. But, penetration rates are still much higher than conventional. Low annular velocities reduce hole erosion. Harold Vance Department of Petroleum Engineering Benefits of Foam Drilling Higher annular pressures with foam than with gasses can potentially reduce mechanical wellbore stability. Even if air is used as the gas, foam drilling can prevent downhole fires. Probably the greatest benefit of foam drilling is the ability to lift large volumes of produced liquids. Harold Vance Department of Petroleum Engineering Rheology Two factors that have the greatest impact on the flow behavior of foams are quality and flow rate. Foam viscosity is largely independent of the foaming agent’s concentration in the liquid phase. Harold Vance Department of Petroleum Engineering Rheology When viscosifying agents are added to the liquid phase, the foam viscosity increases with increasing liquid phase viscosity. Foam rheology is not very sensitive to other flow variables Harold Vance Department of Petroleum Engineering Rheology Einstein (quality from 0 to 54%) µ f = µ (1.0+2.5 Γ ) Where µ f = foam viscosity. µ = viscosity of base liquid. Γ = foam quality (fraction). Harold Vance Department of Petroleum Engineering Rheology Hatschek (quality from 0 to 74%) µ f = µ (1.0+4.5Γ ) Hatschek (quality from 75% to 100%) µ f = µ (1.0/{1 - Γ 0.333}) (1.0/{1 Harold Vance Department of Petroleum Engineering Rheology Mitchell (quality from 0 to 54%) µ f = µ (1.0+3.6Γ ) Mitchell (quality from 54% to 100%) µ f = µ (1.0/{1 - Γ 0.49}) Mitchell also assumed Bingham Plastic behavior. Harold Vance Department of Petroleum Engineering Rheology 2.5 18 16 Yield stress in normally expressed in units of lbf/100sf 2 Foam Viscosity ( c P) 14 1.5 12 10 1 8 6 0.5 4 Foam Yield Stress (psf) 20 2 0 0 0 0.2 0.4 0.6 0.8 1 Foam Quality (fractional) Plastic viscosity and yield point of foam as functions of foam quality (after Mitchell, 19716). Harold Vance Department of Petroleum Engineering Rheology Plastic Viscosity and Yield Strength of Foam(Krug,1971) Quality Plastic Yield Strength 0 1.02 0 0­25 1.25 0 25­30 1.58 0 30­35 1.60 0 35­45 2.40 0 45­55 2.88 0 55­60 3.36 0 60­65 3.70 14 65­70 4.30 23 70­75 5.00 40 75­80 5.76 48 80­86 7.21 68 86­90 9.58 100 90­96 14.38 250 Harold Vance Department of Petroleum Engineering Rheology Power­ Law Fluid Properties of Foam Foam Quality, Consistency Index, Index, Percent Gas by Volume Flow Behavior 65­69 2.766 k 0.290 69­71 2.777 0.295 72­73 2.8716 0.293 74­76 2.916 0.295 3.343 0.273 79­81 3.635 0.262 84­86 4.956 0.214 89­91 5.647 0.200 91­92 6.155 0.187 94­96 3.325 0.290 96­97.7 2.566 0.326 77­78 Harold Vance Department of Petroleum Engineering n Rheology Effective Viscosity (cP) 1000 80 Quality Foam 100 10 1 1 10 100 1000 10000 Shear Rate (s­1) Harold Vance Department of Petroleum Engineering Rheology Effective Viscosity (cP) 10000 90 Quality Foam 1000 100 10 1 1 10 100 1000 10000 Shear Rate (s­1) Harold Vance Department of Petroleum Engineering Rheology Effective Viscosity (cP) 10000 95 Quality Foam 1000 100 10 1 1 10 100 1000 10000 Shear Rate (s­1) Harold Vance Department of Petroleum Engineering Rheology ­ Stiff Foam Apparent Pipe viscosity (cP) 10000 1000 100 10 10 100 1000 10000 Shear Rate (s­1) Effective viscosity of stiffened nitrogen­based fracturing foam, 80 and 90 quality (after Reidenbach et al., 19866) Harold Vance Department of Petroleum Engineering Rheology The particular rheological model to use may depend on the application of the fluid. One argument is that the closer the fluid is to be a pure liquid system (low foam qualities) the more likely is that the fluid will act like a Bingham Plastic. Harold Vance Department of Petroleum Engineering Rheology Empirical evidence shows that: In laminar flow the fluid acts more like a Bingham Plastic. While in turbulent flow the fluid acts more like a Power Law Fluid. Harold Vance Department of Petroleum Engineering Cuttings Transport 1 Relative Lifting Force 0.9 0.8 0.7 0.6 0.5 Relative Velocity 2 0.4 0.3 0.2 Relative Velocity 1 0.1 0 0 0.2 0.4 0.6 0.8 1 Liquid Volume Fraction Lifting forces acting on a 0.1875­inch diameter sphere for different quality foams (after Beyer et al., 19724) Harold Vance Department of Petroleum Engineering Cuttings Transport (Moore) In laminar flow: Vt = 4,980 dc2 ρc­ρf µe In transitional flow: Vt = 175dc (ρc­ρf)2/3 (ρf µe)1/3 Harold Vance Department of Petroleum Engineering Cuttings Transport (Moore) In fully turbulent flow: √ Vt = 92.6 dc ρc ­ ρf ρf (2.54) Harold Vance Department of Petroleum Engineering Cuttings Transport Where: Vt terminal velocity of a cutting (ft/min.) Dc the cutting’s diameter (inches). ρc the cutting’s density (ppg). ρf the drilling fluid’s density (ppg). the fluid’s effective viscosity at the rate flowing up the annulus (cP). µe Harold Vance Department of Petroleum Engineering Cuttings Transport A cutting’s Reynolds number, NRec can be expressed as: NRec = 15.47ρfvtdc µe Theoretically, flow past the cutting will be Laminar if NRec < 1 Transitional if 1 < NRec < 2,000 Turbulent if NRec > 2,000. Harold Vance Department of Petroleum Engineering Cuttings Transport If flow is laminar, an increase in foam viscosity with increasing quality will dominate the reduction in foam density, and the terminal velocity will decrease with increasing foam quality, until the foam breaks down into mist. Vt = 4,980 dc2 ρc­ρf µe Harold Vance Department of Petroleum Engineering Laminar flow Cuttings Transport If the flow is turbulent, the terminal velocity is independent of the foams viscosity. The terminal velocity will increase with increasing foam quality due to reduction in density. In fully turbulent flow: Fully turbulent flow √ Vt = 92.6 dc ρc ­ ρf ρf Harold Vance Department of Petroleum Engineering Cuttings Transport For For typical foam drilling conditions, flow past a 1/2” diameter cutting in a 60 quality foam at nearly 10,000’ was transitional. The terminal velocity was computed The to be ~60 feet per minute. In transitional flow: transitional Transitional flow Vt = 175dc (ρc­ρf)2/3 (ρf µe)1/3 Harold Vance Department of Petroleum Engineering Cuttings Transport In transitional flow, the terminal velocity is sensitive to the density difference between the cutting and the foam, as well as the effective viscosity of the foam. This is probably why foam does not show as much increase in cuttings transport capacity (over water) as might be expected from its viscosity. Transitional flow Vt = 175dc (ρc­ρf)2/3 (ρf µe)1/3 Harold Vance Department of Petroleum Engineering Circulating Pressures Strongly influenced by viscosity and quality. Both viscosity and quality change with changing pressure. Harold Vance Department of Petroleum Engineering Circulating Pressures 500 Bottomhole Pressure (psi) 100/40 400 Foam Gas/Liquid Rates (scfm/gpm) 300 400/40 100/10 200 100 400/10 Well Productivity 0 0 5 10 15 20 25 30 35 40 45 Formation Fluid Influx (BWPH) Predicted influence of water inflow on bottomhole pressure (after Millhone et al., 1972 24) Harold Vance Department of Petroleum Engineering Circulating Pressures 150 1050 140 900 130 750 120 600 110 450 100 300 90 150 80 0 70 0 2000 4000 6000 8000 10000 12000 Depth (feet) Injection Pressure (psi) Air Volume Rate (scfm) and Water Rate (gpm) 1200 Recommended air and liquid injection rates and predicted injection pressures for foam drilling (after Krug amd Mitchel, 1972 19); no inflow continued… Harold Vance Department of Petroleum Engineering Circulating Pressures Mud Injection Rates (gpm) 18 35 30 25 20 15 10 5 0 Hole Diameter (Inches) 17 16 15 14 13 12 11 10 9 8 50 75 100 125 160 175 200 225 250 275 300 325 350 375 400 425 450 Air Injection Rates (cfm) Suggested air and liquid (mud) injection rates for stiff foam drilling (after Garavini et al., 19717) Harold Vance Department of Petroleum Engineering Circulating Pressures 5000 4500 Bottomhole Pressure (psi) 4000 3500 3000 2500 2000 1500 1000 500 0 0 2000 4000 6000 8000 10000 12000 Depth (feet) Predicted bottomhole pressures during foam drilling, no inflow (after Krug and Mitchell, 197219). Harold Vance Department of Petroleum Engineering Circulating Pressures Power­Law Fluid Model Pressures Guo et al. (1995) set out a procedure that can be used to calculate BHP generated by foam systems in a multi­step process. This procedure assumes the fluid behavior the Power­Law model. Harold Vance Department of Petroleum Engineering Circulating Pressures 1.Determine the desired foam velocity and foam quality at the bottom of the hole. Calculate the corresponding volumetric flow rate of gas and liquid (e. g., the volumetric flow of gas is simply the local flow rate multiplied by the fractional foam quality) at the hole bottom, Qgbh and Qlbh respectively, in ft3/sec. Harold Vance Department of Petroleum Engineering Circulating Pressures 2. After specifying a desired foam quality at the surface in the annulus (usually 95­96%), calculate the required ratio of bottomhole to surface using the equation: Pbh/Ps=(zbhTbhΓs{1­Γbh})/(ZsTsΓbh{1­Γs}) Harold Vance Department of Petroleum Engineering Circulating Pressures Where: P = pressure, lbf/ft2 z = dimensionless gas compressibility factor. T = absolute temperature, 0R Γ = foam quality fraction. The subscripts “bh” and “s” refer to bottomhole conditions and surface conditions, respectively. Harold Vance Department of Petroleum Engineering Circulating Pressures 3. Calculate the surface annular pressure using the equation: Ps= (ρl)(Dv)/[(Pbh/Ps)+(Γs/{1­Γs}) *… …...ln(Pbh/Ps)­{ΓsDv/(R`ZavTav[1­Γs])}­1] Harold Vance Department of Petroleum Engineering Circulating Pressures Where: ρl = density of the liquid phase, lbm/ft3. Dv = true vertical depth at the bottomhole location, ft. R` = universal gas constant, Rg/(Molecular weight)air , lbm/lbmmol, Rg is 1,545 lbfft/lbmmol0R and R`= 53.3 for air. The subscript “av” refers to average condition. Harold Vance Department of Petroleum Engineering Circulating Pressures 4. Calculate the bottomhole pressure using the equation: Pbh = Ps(Pbh/Ps) Where: All factors were defined earlier. Harold Vance Department of Petroleum Engineering Circulating Pressures 5. Calculate foam density at bottomhole conditions using: (ρfbh) = (1­Γbh)ρl+ρgbhΓbh Where: ρfbh = density of foam at bottomhole, lbm/ft3. ρgbh = density of gas at bottomhole, lbm/ft3. ρ = P /R`Z T Harold Vance Department of Petroleum Engineering Circulating Pressures 6. Calculate the mass low rate of foam using: Mf , lbm/ sec = ρf Qf Where: Qf = volumetric flow rate of foam, ft3/sec. Harold Vance Department of Petroleum Engineering Circulating Pressures 7. Average foam density can thenbe calculated using: ρfav = Pbh/Dv 8. The average foam velocity will be: vfav , ft/sec = Mf/Aa ρfav Where: Aa = cross­sectional area of the annulus, ft2. Harold Vance Department of Petroleum Engineering Circulating Pressures 9. Then the average foam quality can be determined using: Γav = (ρl – ρfav) / (ρl – ρgav) Where: ρgav = Pav / (R`ZavTav) Harold Vance Department of Petroleum Engineering Circulating Pressures 10.Table 3­4­3 (UDOM­Signa), can be used to determine the consistency index, k , and the flow behavior index, n, based on the average foam quality from Step 9. Harold Vance Department of Petroleum Engineering Circulating Pressures 11. The effective foam quality can then be estimated based on average conditions, according to Moore (1974) using the following equation: µe = K ({2n+1}/3n)n(12vfav/{D­d})n­1 = K ({2n+1}/3n) Where: D = wellbore diameter, ft. d = drillpipe diameter, ft. Harold Vance Department of Petroleum Engineering Circulating Pressures 12. Calculate the Reynolds number using: Re = vfav (D­d)ρfav /µe 13. Then calculate the friction factor with: f = 24 / Re Harold Vance Department of Petroleum Engineering Circulating Pressures 14. The pressure loss due to friction can then be calculated using; Pf = 2fvfav ρfavLh/(gc{D­d}) Where: Lh = length of the hole, ft. gc = gravity, 32,174 lbmft/lbf sec2 Harold Vance Department of Petroleum Engineering Circulating Pressures 15. The total BHP can then be update (pbhu) by adding the friction pressure loss to the hydrostatic BHP determined in Step 4 above: Pbhu = Pbh+ Pf Harold Vance Department of Petroleum Engineering Circulating Pressures 16. The surface pressure can then be update (Psu) using the equation from step 4 above: Psu = Pbhu( Pbh/Ps) 17. Repeat Steps 7 through 16 until the update BHP nearly equals the beginning BHP. Harold Vance Department of Petroleum Engineering Injection Rates Power­Law Model Fluid Injection Rate Guo et al. not only developed a simple method of determining the bottomhole and surface annular pressures with a foam system, they also described how to continue using the technique to determine flow rates, or injection rates of the gas and liquid phases of the foam. Harold Vance Department of Petroleum Engineering Injection Rates Finally, they described the use of the technique to ensure the cuttings are being carried out of the hole adequately. Guo et al. carried their process through four additional steps that continue from the process described above. The remaining steps for a Power­Law model fluid are: Harold Vance Department of Petroleum Engineering Injection Rates 18. Using the BHP calculated with the Guo et al. method, Pbh, and the gas flow rate estimated in Step 1 above using the desired foam quality, Qghb, calculate the gas flow rate at the surface using the equation: Qgs = (Pbh/Pa)(Ta/Tbh)(Qgbh/Zbh) Where: Pa = ambient pressure, lbf/ft2 T = ambient temperature, 0R Harold Vance Department of Petroleum Engineering Injection Rates 19.Determine desired trouble­free cuttings concentration at the surface, Cd, (usually 4­6%), and use it to calculate the required cuttings transport velocity, Vtr, in ft/sec, similar to the method described in the section on gasified fluids. Harold Vance Department of Petroleum Engineering Injection Rates This transport velocity should be calculated at a critical point in the wellbore, most likely at the top of the collars. This will necessitate calculating the annular pressure at the critical point using the technique described above for BHP. Harold Vance Department of Petroleum Engineering Injection Rates The following equation can then be use to calculate transport velocity at the critical point: Vtr=(ROP/Cd)(Zcr/Zd)(Tcr/Td)*.. (Γd/Γcr)(Pd/Pcr) Where: ROP = rate of penetration, ft/sec. The subscripts “cr” and “d” refer to the critical point and the cuttings delivery point (usually the surface), respectively. Harold Vance Department of Petroleum Engineering Injection Rates Also note that the pressure, foam quality, foam density, and foam velocity must be calculated at the critical point using Steps 7 through 16 in section Power­Law Fluid Model Pressures. Harold Vance Department of Petroleum Engineering Injection Rates 20.The cuttings terminal settling velocity must then be determined, based on the particle Reynolds Number, calculated using: Rep = (ρf dcVts)/µe Where: ρf = density of foam, lbm/ft3 dc = diameter of a single cutting, ft µe = effective viscosity of foam, lbm/ft­sec Harold Vance Department of Petroleum Engineering Injection Rates The particular equation for the terminal cuttings velocity, Vts, is determined by the flow regime of the fluid. The fluid will either be in viscous flow (Rep<1), transition flow (1<Rep<2,000), or turbulent flow (Rep>2,000). The equations for Vts are described in more detail in Section Cuttings Transport. Harold Vance Department of Petroleum Engineering Injection Rates Note that in the previous section referenced here, the methods were those described by Bourgoyne et al., and the ranges for viscous, transition, and turbulent flow were slightly different. Also, in the earlier section the terminal settling velocity, Vts was referred to as the slip velocity, Vsl Harold Vance Department of Petroleum Engineering Injection Rates 21.The minimum foam velocity required to lift the given cutting size can then be calculated using: Vf , ft/sec = α (Vtr+ Vts) ft/sec = Where α is a correction factor for wellbore inclination. When the wellbore is vertical, α is 1.0; when the wellbore is horizontal, α is 2.0 Harold Vance Department of Petroleum Engineering Injection Rates 22.The final step is to compare the velocity calculated in Step 21 with the velocity assumed and specific originally in the calculation of the BHP (step 1 under Power­Law Fluid Model Pressures). If the calculated required foam velocity is less than the velocity assumed and specific above, then the hole is being cleaned. Harold Vance Department of Petroleum Engineering Injection Rates Otherwise, the hole will not be cleaned. A higher value will need to be specified in step 1 above, and the entire procedure will need to be repeated. Harold Vance Department of Petroleum Engineering Limitations of Foam Drilling Corrosion when air is used as the gas. Saline formation waters increase corrosion. H2S or CO2 in the formation increases corrosion. Wellbore instability. Mechanical Chemical Harold Vance Department of Petroleum Engineering Homework # 2 Using the graphical method determine: BHP Air injection rate Water injection rate Injection pressure For the well in Homework # 1. Harold Vance Department of Petroleum Engineering Homework # 2, con’t. Repeat using the 22 step process described in handout (and this presentation). Due October 6, 2000 Harold Vance Department of Petroleum Engineering ...
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