Preface |
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ix | |
Prologue |
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xi | |
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1 | (2) |
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1.2 Mud weight MW (lb/ft3), mud weight MW (ppg), and specific gravity (SG) |
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3 | (1) |
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1.3 Hydrostatic pressure (P) and (p) |
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4 | (2) |
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1.4 Pressure gradient V (psi/ft), G (ppg) |
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6 | (1) |
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1.5 Mud pump output q (bbl/stk) and Q (gpm) |
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7 | (3) |
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10 | (1) |
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1.7 Estimated weight of drill collars in AIR |
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11 | (1) |
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1.8 Open hole and tubular capacity and displacement formulas |
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12 | (8) |
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1.9 Amount of cuttings drilled per foot of hole |
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20 | (1) |
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1.10 Annular velocity (AV) |
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21 | (2) |
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1.11 Pump output required in GPM for a desired annular velocity, ft/min |
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23 | (1) |
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24 | (1) |
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1.13 Pump pressure/pump stroke relationship (the Roughneck's formula) |
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24 | (1) |
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1.14 Buoyancy factor (BF) |
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25 | (1) |
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1.15 Formation temperature (Tf) |
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26 | (1) |
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1.16 Temperature conversion formulas |
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27 | (2) |
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Appendix: Supplementary material |
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28 | (1) |
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29 | (3) |
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32 | (5) |
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2.3 Bulk density of cuttings using the mud balance |
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37 | (1) |
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38 | (16) |
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2.5 Depth of a washout in a drill pipe |
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54 | (1) |
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2.6 Stuck pipe calculations |
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55 | (6) |
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2.7 Calculations required for placing spotting pills in an open hole annulus |
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61 | (6) |
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2.8 Line size for a low pressure system |
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67 | (2) |
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Appendix: Supplementary material |
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68 | (1) |
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68 | (1) |
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68 | (1) |
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69 | (3) |
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3.2 Pressure chart: Prepare a chart with pressure and strokes |
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72 | (3) |
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3.3 Kill sheet with a tapered string |
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75 | (2) |
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3.4 Kill sheet for a highly deviated well |
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77 | (3) |
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3.5 Maximum anticipated surface pressure |
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80 | (2) |
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82 | (1) |
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3.7 Sizing the diverter line |
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83 | (1) |
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3.8 Fracture gradient (FG) |
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83 | (10) |
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3.9 Formation pressure tests |
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93 | (8) |
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101 | (2) |
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103 | (4) |
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3.12 Gas cut mud weight measurement calculations |
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107 | (3) |
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3.13 Gas migration in a shut-in well |
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110 | (1) |
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3.14 Hydrostatic pressure decrease at TD caused by formation fluid influx due to a kick |
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111 | (2) |
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3.15 Maximum pressures when circulating out a kick (Moore equations) |
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113 | (7) |
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3.16 Gas flow into the wellbore |
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120 | (1) |
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121 | (3) |
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3.18 Stripping/snubbing calculations |
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124 | (6) |
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3.19 Subsea considerations |
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130 | (10) |
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140 | (5) |
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3.21 Controlling gas migration |
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145 | (2) |
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147 | (1) |
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3.23 Annular stripping procedures |
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148 | (3) |
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151 | (6) |
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Appendix: Supplementary material |
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154 | (1) |
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154 | (1) |
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Various Well Control Schools/Courses/Manuals |
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155 | (2) |
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4.1 Mud density increase and volume change |
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157 | (10) |
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4.2 Mud weight reduction with base liquid dilution |
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167 | (1) |
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4.3 Mixing fluids of different densities |
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168 | (1) |
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4.4 Oil-based mud calculations |
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169 | (5) |
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174 | (4) |
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4.6 Solids fractions (barite treated muds) |
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178 | (1) |
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4.7 Dilution of mud system |
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179 | (2) |
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4.8 Evaluation of hydrocyclones |
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181 | (3) |
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4.9 Evaluation of centrifuge |
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184 | (3) |
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4.10 Mud volume required to drill 1000ft of hole |
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187 | (2) |
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4.11 Determine the downhole density of the base oil or brine in the mud at depth of interest in ppg |
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189 | (4) |
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Appendix: Supplementary material |
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192 | (1) |
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192 | (1) |
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5.1 Cement additive calculations |
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193 | (4) |
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197 | (1) |
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5.3 Field cement additive calculations |
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198 | (2) |
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5.4 Weighted cement calculations |
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200 | (1) |
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5.5 Calculate the number of sacks required for cement job |
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201 | (4) |
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5.6 Calculations for the number of feet to be cemented |
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205 | (2) |
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5.7 Setting a balanced cement plug |
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207 | (4) |
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5.8 Differential hydrostatic pressure between cement in the annulus and mud inside the casing |
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211 | (1) |
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212 | (4) |
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5.10 Pump strokes to bump the plug |
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216 | (3) |
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Appendix: Supplementary material |
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218 | (1) |
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218 | (1) |
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6.1 System pressure losses |
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219 | (17) |
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6.2 Equivalent circulating "density" ECD (ppg) |
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236 | (1) |
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6.3 Surge and swab pressure loss |
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237 | (9) |
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6.4 Equivalent spherical diameter for drilled cuttings size used in slip velocity equations |
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246 | (2) |
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6.5 Slip velocity of cuttings in the annulus |
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248 | (3) |
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6.6 Carrying capacity index |
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251 | (1) |
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6.7 Pressure required to break circulation |
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252 | (2) |
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6.8 Initial gel strength guidelines for top hole drilling in high angle wells (after Zamora) |
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254 | (1) |
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6.9 Bit nozzle selection---Optimized hydraulics |
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255 | (6) |
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261 | (2) |
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6.11 Minimum flowrate for PEC bits |
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263 | (1) |
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6.12 Critical RPM: RPM to avoid due to excessive vibration (accurate to approximately 15%) |
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264 | (3) |
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Appendix: Supplementary material |
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264 | (1) |
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265 | (2) |
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7 Drilling and completion calculations |
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7.1 Control drilling---Maximum drilling rate (MDR) when drilling large diameter holes (14% in. and larger) in ft/h |
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267 | (1) |
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7.2 Mud effects on rate of penetration |
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268 | (3) |
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7.3 Cuttings concentration % by volume |
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271 | (3) |
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7.4 "d" Exponent and corrected "d" exponent |
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274 | (1) |
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275 | (1) |
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276 | (4) |
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7.7 Ton-mile (TM) calculations |
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280 | (5) |
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7.8 Hydrostatic pressure decrease when pulling pipe out of the hole |
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285 | (3) |
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7.9 Loss of overbalance due to falling mud level |
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288 | (1) |
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289 | (4) |
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7.11 Core analysis technique |
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293 | (2) |
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7.12 Temperature correction for brines |
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295 | (1) |
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296 | (2) |
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7.14 Directional drilling calculations |
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298 | (6) |
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304 | (3) |
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Appendix: Supplementary material |
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305 | (1) |
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305 | (2) |
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8 Air and gas calculations |
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307 | (1) |
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8.2 Direct circulation: Flow up the annulus (from annulus bottomhole to exit) |
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308 | (3) |
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8.3 Direct circulation: Flow down the inside of the drill pipe (from the bottom of the inside of the drill string to the injection at the top of the drill string) |
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311 | (1) |
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8.4 Reverse circulation: Flow up the inside of tubing string |
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312 | (3) |
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8.5 Reverse circulation: Flow down the annulus |
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315 | (2) |
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8.6 Reverse circulation: Adjusting for reservoir pressure |
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317 | (4) |
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Appendix: Supplementary material |
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319 | (1) |
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319 | (2) |
Appendix A |
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321 | (12) |
Appendix B Conversion factors |
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333 | (4) |
Appendix C Average annual atmospheric conditions |
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337 | (2) |
Index |
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339 | |