Fracturing Gradients in Waterfloods of Low-Permeability, Partially Depleted Zones
- Martin Felsenthal (Continental Oil Co.) | Howard H. Ferrell (Continental Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1971
- Document Type
- Journal Paper
- 727 - 730
- 1971. Society of Petroleum Engineers
- 6.5.2 Water use, produced water discharge and disposal, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 3 Production and Well Operations, 1.2.3 Rock properties, 5.8.7 Carbonate Reservoir, 5.6.4 Drillstem/Well Testing, 5.4.1 Waterflooding
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Fracturing during waterflooding can be diagnosed from pressure fall-off and step-rate injectivity test data. In tectonically relaxed zones these well test data also yield Poisson ratio. Information given here suggests that Poisson ratios ranging from 0.23 to 0.33 are normal for low-permeability Poisson ratios ranging from 0.23 to 0.33 are normal for low-permeability rocks, and that higher ratios may indicate fracturing through shaly cap rock.
Formation fracturing, or "pressure parting" as it is sometimes called, can occur at surprisingly low pressure gradients during water injection. For conditions pressure gradients during water injection. For conditions conducive to vertical fracturing these fracturing gradients expressed as bottom-hole injection pressure vs depth may be as low as 0.50 psi/ft. This is much lower than the gradients usually observed in the same fields when wells are hydraulically fractured during initial completions. The reason for this difference is that the fracturing gradient is dependent on formation pressure. While the formation pressure is high, the fracturing gradient observed in completion work will also be high, but as the pressure declines during primary production, the fracturing gradient likewise primary production, the fracturing gradient likewise declines.
Fracturing gradients of 0.57 psi/ft were reported by Eaton for a pressure-depleted West Texas field where old producing wells had been converted to water injection wells. In the same field, gradients equalled 0.68 to 0.70 psi/ft during hydraulic fracturing of new wells. Eaton also reported fracturing gradients equal to 0.748, 0.864, and 0.993 psi/ft after successive 6-month periods in a California injection well, with the changes being attributed to gradual increases in formation pressure around the. wellbore. Heck also made reference to similar observations in the Bradford, Pa., field. These, and similar literature references, illustrate the phenomenon in a qualitative manner, but not enough data are given for quantitative correlations. To fill this lack of correlative data, we observed fracture gradients and also obtained corresponding shut-in formation pressures; the latter values we determined from pressure fall-off tests, using the method of Hazebroek et al. One such set of data was obtained in Field A, a 6,500-ft deep Mississippian limestone reef reservoir. in this reservoir the average fracturing gradient was reported as 0.78 psi/ft at a discovery pressure of about 2,675 psig. During primary production the formation pressure declined to values ranging from 780 to 1,700 psi in the wells of interest (the large range of values being the consequence of permeability barriers throughout the reservoir). permeability barriers throughout the reservoir). Approximately a month after old producers in this reservoir were converted to injection wells, fracture gradients and shut-in formation pressures were observed in five wells. This was repeated after another 5 months of water injection. It may be seen from the data in Fig. 1 that during the period of observation the shut-in formation pressure in the injection wells increased, on the average, 750 psi. This was accompanied by a definite rise in the fracturing gradients, as evidenced by the fact that fracture gradients averaged 0.55 psi/ft in the first month and 0.65 psi/ft in the sixth month of injection.
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