By M. J. Economides
This workbook is a realistic spouse to the second one variation of the textbook Reservoir Stimulation. the 2 books are meant for use jointly. This new quantity might be relatively priceless for the learning of latest engineers and petroleum engineering scholars, because it comprises nearly a hundred difficulties and their options, plus a long bankruptcy giving facts worthwhile for designing a stimulation remedy. Chapters are incorporated containing functional difficulties on reservoir and good concerns, rock mechanics, fracturing fluids and proppants, fracture calibration remedies, layout and modeling of propped fractures, overview of fracture remedies, layout of matrix remedies, diversion and therapy evaluate, layout and function of acid fractures and stimulation of horizontal wells. those chapters are categorized with letters from A to J to differentiate them from their spouse chapters in Reservoir Stimulation. Equations, figures and tables from the textbook are pointed out within the workbook yet aren't reproduced.
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Extra info for A Practical Companion to Reservoir Stimulation
Tubing may result in a friction pressure drop equal to 150 psi/lOOO ft and thus add 1500 psi to the wellhead pressure requirement. The breakdown pressure calculated from Eq. 2-50 is an upper limit. For a lower limit, Eqs. 2-52 and 2-53 can be used. 25, then from Eq. 5) 77= + 500 = 5300psi. (B- 18) This value is bottomhole. 233) (3700) 2(1 A P h v d r o s r u r ic pH (60) ( 10,000) - _ 144 144 - 4167 psi, B-6 = 4743psi. 233) (B-21) ROCK MECHANICS EXAMPLE B-6 Estimation of Fracture Height Migration Calculate the fracture height for 300 psi and 500 psi net pressure for a formation with the confining stresses and data shown in Table B-2.
B-5) is approximately 5200 psi, which is also the maximum allowable injection pressure. If the well is to be hydraulically fractured, then from Eq. 2-SO (and assuming p = 0), Failure Envelope and Wellbore Stability A series of laboratory tests was performed on a typical reservoir sandstone. The tests and data are shown in Table B-4. Contemplating a completion at 10,000 ft, microhydraulic fracturing tests were conducted and revealed an in-situ stress condition described as: 0,= 1 1,000psi, o ~ , , = ~ 3800 ~ ; , ,psi, and o ~ , , ~=,7200 , psi.
45. (D-23) Then, finally, from Eq. 45) = 4645 ft’ = 827 bbl. (D-24) Invariably, the rate of fluid loss during pumping is larger than during closure. D-7 PRACTICAL COMPANION TO RESERVOIR STIMULATION EXAMPLE D-7 EXAMPLE D-8 Calculation of Fluid Efficiency from Closure Time Closure Time with Proppant If the pumping time and the closure time of a calibration treatment are 30 and 15 min, respectively, what is the fluid efficiency? 75? 000-gal total injection treatment, what should the closure time be?
A Practical Companion to Reservoir Stimulation by M. J. Economides