Unit 4 PDF

SHmax from wellbore breakouts Note: C0 = UCS Wbo = breakout width on one side of the wellbore Barton et al. (1988) Zoback (2007) 1 SHmax fro...

SHmax from wellbore breakouts Note: C0 = UCS Wbo = breakout width on one side of the wellbore Barton et al. (1988) Zoback (2007) 1 SHmax from wellbore breakouts (cont.) Sub horizontal lines: Diagonal line (from tensile fractures): SHmax = 3Shmin-2Pp-ΔP-σ ΔT C0 = 138 ± 14 MPa Zoback (2007); Fig 7.10 2 Pore pressure prediction 3 Pore pressure prediction methods High por/perm formations Wireline conveyed pressure measurement tools Drill stem conveyed tools (Packers and drill stem testing tools) Mudweights Offset wells Shales Laboratory experimental porosity vs pressure trends combined with logs - Hydrostatic compression lab test - Confined compaction lab test Ratio method (Sonic log, Resistivity log ) Eaton’s method 4 Note: Seismic data can also be used to pinpoint overpressured zones Compaction trends from lab measurements Figure 2.13. The decrease in porosity with effective stress in a SEI-330 shale sample subject to confined uniaxial compression test (Finkbeiner, Zoback et al. 2001). The effective stress refers to the difference between the applied uniaxial stress and pore pressure. 5  Pore pressure prediction from lab (cont.) Where, -Porosity, φ, is related to an empirically determined initial porosity φ0. -σv is the vertical effective stress, β is a second empirical constant -Porosity can be measured directly through geophysical logging. Thus, if there is a unique relation between porosity and the vertical effective stress, Sv−Pp, pore pressure can be estimated because it is the only unknown. Thus, the above equation can be rewritten as Where, φ0 is the initial porosity (at zero effective pressure), and the porosity φ is determined from the sonic travel time, t, based on geophysical P-wave velocity (Vp) measurements by: Where, f is the acoustic formation factor and tma is the matrix travel time derived from laboratory experiments 6 Pore pressure prediction (cont.) At depths A, B and C where pore pressure is hydrostatic (as shown in (a)), there is linearly increasing effective overburden stress with depth causing a monotonic porosity reduction (as shown in (b), after Burrus 1998). If overpressure develops below depth C, the vertical effective stress (length of horizontal arrows in (a)) is less at a given depth than it would be if the pore pressure was hydrostatic. In fact, the vertical effective stress can reach extremely low values in cases of hard overpressure. Geophysical data that indicate abnormally high porosity at a given depth (with respect to that expected from the normal compaction trend) can be used to infer the presence of overpressure 7 Ratio method (sonic and resistivity logs) RTENOTITLE RTENOTITLE Where, -The subscripts n and log refer to the normal and measured values -Pp is the actual pore pressure, and Phyd is the normal hydrostatic pore pressure. -Calibration of this method requires knowing the appropriate normal value of each parameter. -It is important to realize that, in contrast to trend-line methods, the ratio method does not use overburden or effective stress explicitly and thus is not an effective stress method. This can lead to unphysical situations, such as calculated pore pressures that are higher than the overburden. 8 Eaton's method Where, Pp is pore pressure; S is the stress (typically, Sv); Phyd is hydrostatic pore pressure; and the subscripts n and log refer to the normal and measured values of resistivity (R) and sonic delta-t (ΔT) at each depth. The exponents shown in equations are typical values that are often changed for different regions so that the predictions better match pore pressures inferred from other data. All calculated pore pressures should be calibrated/verified if possible Equation applied on shales 9 Example of Eaton’s method Armistead (2020) 10  Unit 4 PEO 406 (Reservoir Geomechanics) Dr. Sayantan Ghosh Indian Institute of Technology (Indian School of Mines) Dhanbad [Monsoon 2024] Content Measurement of stress magnitude and orientation from compressive and tensile failures in deviated wells Stress around a deviated wellbore Manshad (2013) 13 Stress around a deviated wellbore (cont.) Manshad (2013) 14  Stress around a deviated wellbore (cont.) (Eq 8.8) Use these values with to assess wellbore stability Manshad (2013) 15 Fig 8.1 c  Observations from inclined boreholes Orientation of the wellbore breakouts in deviated wells depends on the orientation of the well with respect to the stress field and in situ stress magnitudes. The orientations of breakouts (if they were to occur) and DITF are shown in a looking down the well reference frame Figure a shows the orientation of breakouts for deviated wells in a strike-slip faulting regime with SHmax acting in the NW–SE direction. The two lines indicate the position of the tensile fractures around the well and the angle with respect to the wellbore axis. Drilling-induced tensile fractures in deviated wells generally occur as en-echelon pairs of fractures which are inclined to the wellbore wall 16 Figure 8.4, Reservoir Geomech, Zoback (2007) Observations from inclined boreholes (cont.) Magnitude and orientation of SHmax can be modeled from: a) The very existence of the tensile fractures; b) the position of the fractures around the wellbore, θ; c) their deviation with respect to the wellbore axis, ω, and. 17 Wellbore breakout initiation tendencies Figure 8.2: The tendency for the initiation of wellbore breakouts. The color indicates the rock strength required to prevent failure, hence red indicates a relatively unstable well as it would take high rock strength to prevent failure whereas blue indicates the opposite. The strength scale is different for each figure as the stress magnitudes are progressively higher from normal to strike-slip to reverse faulting. Note that because these calculations represent the initiation of breakouts, they are not directly applicable to considerations of wellbore stability (see Chapter 10). 18 Figure 8.4, Reservoir Geomech, Zoback (2007) Tensile fracture initiation tendencies Breakout tendencies for comparison Figure 8.3. The tendency for the initiation of tensile fractures. The magnitudes of the stresses, pore pressure and mud weight assumed for each case is shown. Note that the color indicates the mud pressure required to initiate tensile failure. Hence red indicates that tensile fractures are likely to form as little excess mud weight is required to initiate failure whereas blue indicates 19 the opposite. Breakout widths Information obtained from Figure 6.3 (Zoback, 2007) 20 Field observation on DITFs Field observation on DITFs Example (cont.) Figure 8.10: Analysis similar to Figure 7.10 to constrain the magnitude of SHmax for the tensile fractures observed in the deviated well shown in Figure 8.9. The heavy black line indicates the magnitude of SHmax as a function of Shmin to cause drilling-induced tensile fractures in a well with the appropriate deviation, ECD (mud weight during mud circulation) and amount of cooling. Modified from Wiprut, Zoback et al. (2000). Reprinted with permission of Elsevier. En-echelon DITFs Increasing delta p increases DITF lengths Figure 8.7: Theoretical illustration of the manner of formation of en echelon drilling-induced tensile fractures in a deviated well. (a) The fracture forms when σtmin is tensile. The angle the fracture makes with the axis of the wellbore is defined by ω, which, like σtmin varies around the wellbore. (b) The en echelon fractures form over the angular span θt, where the wellbore wall is in tension. (c) Raising the mud weight causes the fractures to propagate over a wider range of angles because σtmin is reduced around the wellbore’s circumference. 23