Index
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Published:2021
"Index", Production Logging: Theoretical and Interpretive Elements, A. Daniel Hill
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A
acoustic signal, 189, 193, 195–197, 200, 201, 210
acoustic wave form, 194, 196
acoustic wave train, 193, 195–196, 201
amplified gradiomanometer curve, 123
annular-mist flow, 102, 119
area method, tracer-loss log
approximation of tracer slugs, 54, 55
channel identification, 54, 56
flow profile, 54, 56
interpretation method, 54
lack of depth resolution, 53, 54
mass of tracer downstream, exit point, 52
tracer concentration, 52
velocity-shot analysis, 55
volumetric flow rate, 52, 53
array holdup measurements, 149–151, 155–156
array spinner flowmeter
Halliburton spinner array tool, 147–148, 150
Schlumberger FloScan Imager* tool, 147–148
Sondex spinner array tool, 148, 150
spinner log, 147, 149
velocity profile, 147, 149
array ultrasonic Doppler velocimetry, 148–150
attenuation-ratio logs, 208–209, 221
B
baseline gamma ray log, 50, 53, 72
basket flowmeter, 77, 78, 94, 95, 120, 122, 124, 135–137
bubble/droplet time of flight, 153
C
capacitance logs, 4, 123–126, 133–136, 139–141
casedhole formation-evaluation logs, 1, 2
cement-bond logging
amplitude log, 196–200
casing and formation amplitudes, 204–205
channeling, 205–206
eccentered casing/thin cement sheath, 207–208
eccentric tool, 205–206
free pipe, 203
full-wave-train displays, 200–201
good bond to formation and casing, 204
microannulus, 204–205
pad-type, 208–211
tools and operation theory, 193–196
transit time, 200–203
cemented pipe, 212–213
cement-quality logging
attenuation-ratio logs, 208–209
cement-bond logging (see cement-bond logging)
guidelines, 221–223
pad-type cement-bond log tools, 208–210
ultrasonic-flexural-wave logs, 218–224
ultrasonic-pulse-echo logs (see ultrasonic-pulse-echo logs)
cement sheath, 198–200, 207–208
channeling, 3–5, 31, 34, 36, 55, 57, 58, 72, 73, 174, 205–206
chemical-marker method, 152
chemical tracers, 141, 151, 152
coiled tubing conveyance, 146
cycle skipping, 193, 201–202
D
deflector-type flowmeters, 77
density logs, 120, 132, 134–138, 200, 205
dispersed-bubble flow, 102–106, 119
distributed acoustic sensing (DAS), 167, 189–190
distributed-temperature sensing (DTS), 15, 41, 43, 44, 146, 189–190
downhole fluid properties, 13–14
downhole video logging, 6
borehole image map, 227–228
with downward and side-view cameras, 227
fluid entries identification, 228–230
fracture diagnosis, perforation erosion, 230–232
locating fish, 230–231
with multiple side-viewing cameras, 227
pre-and post-processing images, 227–228
sand in wellbore, 229, 230
scale, 229–231
drag on depth technique, 63
Duns-Ros flow-regime map, 102, 104, 109
E
emulsion flow, 119
F
fiber optic distributed temperature sensors, 16–18
fiber optic reflectance probes, 149
flow-concentrating flowmeters, 94, 116, 117, 120, 126, 134, 141
fluid density logs, 116, 121–123
fluid-identification logs, 116
capacitance logs, 123–125
fluid-density logs, 121–123
optical gas holdup logs, 126–127
fluid-velocity measurements
flow-concentrating flowmeters, 120
radioactive-tracer logging, 121
spinner flowmeters, 117–121
the Ford method, 59
formation volume factors (FVFs), 128, 132, 135
free pipe, 194, 196, 198, 203, 212–213, 215, 219, 221
full-wave-train displays, 200–201, 204, 205, 207, 221
G
galaxy patterns, 219
gamma ray densitometer, 121–123, 131, 132, 135, 136, 140, 141
gamma ray log, 49, 50, 53, 72, 136
Geiger-Müller tubes, 49
gradient and differential temperature logs, 15, 17
gradiomanometer, 122, 123, 130, 131, 134
Griffith-Wallis flow-regime map, 102, 103
H
Halliburton Circumferential Acoustic Scanning Tool–Visualization (CAST-V)™, 210–211
helical spinner flowmeter, 77, 78
holdup phenomenon, 108–110, 116, 117, 122–124, 126, 128–130, 132–135
array measurements, 149–151, 155–156
capacitance array tool display, 160, 163
cause of, 101
effect of small inclination changes, 160
in high rate, high water cut horizontal well, 159–160
holdup parameter, 99
holdup ratio, 100
in-situ velocity, 101
slip velocity, 100
stagnant water, 160–162
superficial velocity, 100
terminal velocity, 101
time-averaged quantity, 99
in two-phase flow, 99–102
void fraction, 99
horizontal multiphase flow
array holdup measurements, 149–151
array spinner flowmeters, 147–150
array ultrasonic Doppler flowmeters, 148–150
Eagle Ford well trajectory
toe-down orientation, 145, 146
toe-up orientation, 145
examples, 159–163
interpretation of array tool responses, 155–160
production logging tool conveyance, 146–148
tracer, 151–154
horizontal spinners, 95, 96
horizontal wells, temperature logging
gas well flow profile, 40–41
Joule-Thomson effects, 39
multistage hydraulic fracturing diagnosis, 41, 43, 44
oil and water flow profiles, 41, 42
hydraulic fractures detection in vertical wells
cool anomaly, 36, 38
fracturing fluid, 35
helical well trajectory, 39
pre-and post-fracture temperature profiles, 37, 39
rock thermal conductivities, 37
warm anomaly, 36–40
hydraulic fracturing, 1, 5, 15, 16, 35–41, 43, 50, 167, 189, 190, 230, 232
I
inchworm tractor, 146, 147
in-situ average velocity, 116–117, 151, 152, 160
interpretation of array tool responses, 155–160
interpreting spinner-flowmeter logs, 77
effective velocity, 80–82
global error minimization, 94
guidelines, 96
in-situ calibration, 93, 94
multipass method, 82–88
multiple passes, 92–94
single-pass interpretation, 92–94
two-pass method, 88–92
J
Joule-Thomson cooling, 22, 24, 32, 136, 138, 175
Joule-Thomson effects, 24, 39
Joule-Thomson heating, 22, 24
L
laminar flow, 9–13, 49, 60, 63, 65
radioactive-tracer logging
in viscous solutions, 70–72
of water, 68–70
M
matrix flow, 176–180
mature injection well, flowing and shut-in logs, 33–35
McKinley’s* mixing method, 28–30
microannulus, 199, 204–205, 208, 216–217, 219
microseismogram, 201
multicapacitance flowmeter, 153
multipass method, spinner-flowmeter logging, 83
flowmeter response for downward fluid velocity, 82
gas production well, 83–88
linear spinner response, 82
spinner response to cable speed, 82, 83
threshold velocity, 82, 83
multiphase flow, 3–5, 95, 115, 116. See also horizontal multiphase flow
fluid-identification logs, 121–127
fluid-velocity measurements, 117–121
guidelines, 138–141
operational procedures in production wells, 117
production log interpretation, 116–117
production wells, 3–5
qualitative production log interpretation, 134–140
quantitative analysis in three-phase flow, 133–134
quantitative interpretation of logs, 126–134
tracer
chemical tracers, 152
logging, 121
temperature wave, 153–154
well deviation effect, 115–116
multiphase flow in pipes
effect of pipe inclination on two-phase flow, 108–111
flow from perforations in a two-phase well, 110–111
holdup phenomenon, 99–102
horizontal two-phase flow regimes, 104, 105
oil/water flow regimes, 105–106
Taitel-Dukler flow-regime map, 106, 107
three-phase flow, 111
two-phase pressure-drop behavior, 106–108
vertical two-phase flow regimes, 102–104
multiphase-flow logs
quantitative analysis, 126–127
slip velocity correlation with the Curtis method, 129–134
slip velocity from laboratory data, 128
slip velocity from log responses above all perforations, 128–129
slip velocity from two-phase-flow pressure-drop correlation, 129
N
noise amplitude, 167, 170, 172–175, 183, 185, 188, 189
noise logging
axial flow rate, wellbore, 183, 185–186
distributed acoustic sensing, 189–190
during drilling, 187
flow from fractures and perforations, 179–182
flow through restrictions, 170–177
frequency characteristics, 169
guidelines, 190
liquid-level detection, 188
matrix flow, 176–180
noise from leaks, 181–186
tools and operations, 167–170
noise spectra
for air throttling, 170–171
at depths, 174
high-permeability carbonate samples, 179
for water throttling, 170–171
O
oil-or gas-soluble radioactive tracers, 49
oil/water flow regimes, 105–106
openhole wells, spinner-flowmeter logging, 95
optical gas holdup logs, 126–127, 133
oxygen activation, 152–153
P
perforation
accumulation of crystals, 229, 231
discrete water entries through, 229–230
flow from fractures and, 179–181
flow from perforations, 180–182
fracture diagnosis, 230–232
quantitative analysis, multiphase-flow logs, 128–129
theory of noise logging, 180–182
in two-phase well, 110–111
primary logging methods, 1
production logging
applications
anomalous rate changes, 3
during drilling, 2
flow profile measurement, 2–3
interval isolation determination, 3
multiphase flow applications, production wells, 3–5
during production or injection, 2
single-phase flow applications, injection wells, 2–3
with well completions and workovers, 4–5
data requirements, 6–7
flow profile presentation, 7
history of, 1
job planning, 6
quality control, 7
record keeping, 6
role of, 1
production log interpretation, 116–117
pulsed neutron logging tool, 1, 50, 121, 152–153
Q
qualitative production log interpretation, 134–140
qualitative temperature log interpretation
bottom of injection interval identification, 33, 35
cement top location, 33, 34
channel identification with shut-in temperature log, 34, 36
flowing and shut-in logs, mature injection well, 33–35
flowing and shut-in temperature logs, young well, 34, 36
gas-entry locations, 34, 37
Joule-Thomson cooling, 32
location of underground blowout, 32, 33
shut-in logs, 34, 37
shut-in temperature logs, 31
quantitative analysis, multiphase-flow logs, 126–127
slip velocity correlation with the Curtis method, 129–134
slip velocity from laboratory data, 128
slip velocity from log responses above all perforations, 128–129
slip velocity from two-phase-flow pressure-drop correlation, 129
quantitative analysis of temperature logs
computer simulation, 29–33
McKinley’s* mixing method, 28–30
Romero-Juarez method, 25, 28
R
radioactive-tracer logging, 4–7, 34, 121
centralizing, 49
decentralizing, 49
gamma ray log, 49
Geiger-Müller tubes, 49
general recommendations, 73
injection profiles, 49
iodine 131 (131I), 49
in laminar flow
in viscous solutions, 70–72
of water, 68–70
oil-or gas-soluble radioactive tracers, 49
proppant distribution map, 50, 51
radioactive isotopes, 50
schematic diagram, 49
tagging with radioactive isotopes, 50, 51
tracer-loss log
area method, 52–56
baseline gamma ray log, 50
channel identification, 55–58
full-scale tests, 52
gamma ray intensity measurement, 50, 51
guidelines, 72–73
injection profile determination, 51
limitations, 57, 59
resultant log, 51
self method, 55
tracer placement, 65–68
two-pulse tracer logging, 71–72
velocity-shot log, 50
correction factor, 59
detector spacings, 59
effect of fluid exit between detectors, 61–65
flow profile, 61
fluid velocity, 59
the Ford method, 59
guidelines, 73
peak-to-peak transit time, 59
transit-time, 57, 60, 62
typical velocity-shot response, 59
variable wellbore cross-sectional area, 61
velocity profile correction factor, 60
volumetric flow rate, 62
xenon (131Xe), 49
Ramey equation, 20–22, 24, 25, 29, 45
reservoir sweep efficiency, 1
resistivity array tool log
Eagle Ford horizontal well, 155, 157
gas flow profile, 159–160
resistivity array data, 155, 158
wellbore areas sampled by, 155
Romero-Juarez method, 25, 28, 29
running spinner flowmeters
constant flow rate, 79
guidelines, 96
physical condition of well, 79
sand production, 79
sufficient flow rate, 79
surface electronics, 79
tool operation, 78
S
Schlumberger–s fullbore spinner, 77, 78
Schlumberger Ultrasonic Imager (USI), 210–211
Segmented Bond Tool, 208–210
self method, tracer-loss log, 55
shut-in temperature logs, 23, 30–37, 44, 45, 140
single-pass interpretation, 92–94, 155
single-pass method, 82, 132
single-phase flow, 4, 7, 49, 77, 95, 99, 100, 107, 115, 117–120, 170, 172, 187
downhole fluid properties, 13–14
flow in annulus, 11–13
injection wells, 2–3
laminar and turbulent flow, 9–10
spinner flowmeter, 119
velocity profiles, 10–11
slip velocity, 100, 102, 115–117, 127
correlation with the Curtis method, 129–134
laboratory data, 128
log responses above all perforations, 128–129
two-phase-flow pressure-drop correlation, 129
Sondex array instruments, 149–150
sonic travel time, 194
spectral noise logging tools, 167, 169–170
spinner array tool log
Eagle Ford horizontal well, 155–156
gas flow profile, 159–160
phase distributions, 155, 158
spinner data, 155, 157
wellbore areas sampled by, 155
spinner-flowmeter logging
basket flowmeter, 77, 78
description, 77
effective velocity, 80–82
fluid trap, 77
helical spinner flowmeter, 77, 78
high-flow-rate wells, 94–95
horizontal spinners, 95, 96
interpretation procedure
effective velocity, 80–82
global error minimization, 94
guidelines, 96
in-situ calibration, 93, 94
multipass method, 82–88
multiple passes, 92–94
single-pass interpretation, 92–94
two-pass method, 88–92
low-flow-rate wells, 94, 95
in openhole wells, 95
rotational velocity, 77
running spinner flowmeters
constant flow rate, 79
guidelines, 96
physical condition of well, 79
sand production, 79
sufficient flow rate, 79
surface electronics, 79
tool operation, 78
Schlumberger–s fullbore spinner, 77, 78
theory of spinner response, 79–80
vs. turbine meter, 77
spinner flowmeters
annular-mist flow, 119
apparent downward flow, 118–119
arrays, 121
dispersed-bubble flow, 119
efficacy, 118
emulsion flow, 119
in gas/water flow, 136, 139
high-rate well, 120–121
pipe inclination function, 118–119
spinner-tool responses, 118–119
standard interpretation methods, 119–120
velocity fluctuation, 118–119
velocity measurement, 118
steady-state flow, 115
surface gas flow, 173, 174
T
Taitel-Dukler flow-regime map, 106
temperature logging
application of, 15
differential curve, 15
DTS, 15
fiber optic distributed temperature sensors, 16–18
geothermal temperature profile, 19
hypothetical behavior, 16, 18
thermal characteristics of reservoir rocks, 18, 19
gradient and differential temperature logs, 15, 17
gradient curve, 15
in horizontal wells
gas well flow profile, 40–41
Joule-Thomson effects, 39
multistage hydraulic fracturing diagnosis, 41, 43, 44
oil and water flow profiles, 41, 42
hydraulic fractures detection in vertical wells
cool anomaly, 36, 38
fracturing fluid, 35
helical well trajectory, 39
pre-and post-fracture temperature profiles, 37, 39
rock thermal conductivities, 37
warm anomaly, 36–40
interpretation techniques
computer simulations, 35
guidelines, 42
qualitative temperature log interpretation, 31–37
quantitative analysis, 25, 28–33
production-well characteristics evaluation, 15
recommendations, 44–45
schematic diagram, 15, 16
wellbore temperature profile (see wellbore temperature profile)
temperature-tracer method, 153–154
theory of noise logging
characteristics, 169
flow from perforations, 180–182
flow through restrictions, 170–177
liquid-level detection, 188
matrix flow, 176–180
third-interface echo (TIE), 218–220, 224
three-phase flow, 111
quantitative analysis in, 133–134
tool eccentering, 193, 195, 199, 204–206, 211
tracer-loss log
area method, 52–56
baseline gamma ray log, 50
channel identification, 55–58
full-scale tests, 52
gamma ray intensity measurement, 50, 51
injection profile determination, 51
limitations, 57, 59
resultant log, 51
self method, 55
tractor conveyance, 146–148
traditional noise, 167–169
transit time, 60–64, 69, 70, 73, 152, 193–197, 201–203, 205, 211, 216, 221
cycle-skipping, 201–202
eccentering, 201–202
floating-gate measurement, 194
peak-to-peak transit time, 59
stretch, 202–203
velocity-shot log, 57, 62
turbulent flow, 9–11, 13, 59, 60, 63, 65, 70, 73, 82, 95, 102, 178–180, 183
two-pass method, spinner-flowmeter logging
actual down response, 88
advantages, 89
assumptions and limitations, 89
down response curve, 88, 89
fluid velocity, 89
gas/condensate well, 89, 91, 92
shifted down response, 89
spinner frequency responses, 88
up-run response curve, 89
velocity profile correction factor, 89
two-phase flow
effect of pipe inclination, 108–111
gas holdup measurement, 126–127
high-rate well, 120–121
holdup phenomenon, 99–102
horizontal two-phase flow regimes, 104, 105
multiphase-flow log interpretation, 116–117
pressure-drop behavior, 106–108
spinner-tool responses, 118–119
velocity profiles, 118
vertical two-phase flow regimes
in annular (annular-mist, mist) flow, 102
bubble (dispersed-bubble) flow, 102
bubble-to-slug transition, 103
dispersed-bubble-to-slug transition, 103
Duns-Ros flow-regime map, 102, 104
Griffith-Wallis flow-regime map, 102, 103
in slug flow, 102
slug-or dispersed-bubble-to-annular transition, 104
slug-to-churn transition, 103–104
two-pulse tracer logging, 71–72
U
ultrasonic Doppler velocimetry, 148–150
ultrasonic-flexural-wave logs
annulus geometry, 219, 224
casing contact from TIE measurement, 219, 224
cement identification, 218, 222
channel identification, 218–219, 223
flexural attenuation, 219, 224
tools and theory of, 218–220
ultrasonic-pulse-echo logs
cement column, 214–215
cement quality, 214–215
channeling, 214, 216
displays, 213–214
free pipe, 214–215
microannulus effect, 216–217
Schlumberger cement evaluation tool, 210–211
tools and theory of operation, 210–213
ultrasonic casing inspection, 216, 218, 219
V
variable density log, 200–205, 209, 213, 214, 216, 218
velocity-shot log, 33, 50, 68, 69, 73
correction factor, 59
detector spacings, 59
effect of fluid exit between detectors, 61–65
flow profile, 61
fluid velocity, 59
the Ford method, 59
guidelines, 73
peak-to-peak transit time, 59
transit time, 57, 62
transit-time measurements, 60
typical velocity-shot response, 59
variable wellbore cross-sectional area, 61
velocity profile correction factor, 60
volumetric flow rate, 62
velocity-shot method, 50, 61, 121
vertical two-phase flow regimes
in annular (annular-mist, mist) flow, 102
bubble (dispersed-bubble) flow, 102
bubble-to-slug transition, 103
dispersed-bubble-to-slug transition, 103
Duns-Ros flow-regime map, 102, 104
Griffith-Wallis flow-regime map, 102, 103
in slug flow, 102
slug-or dispersed-bubble-to-annular transition, 104
slug-to-churn transition, 103–104
W
water channeling, 4, 5
water coning, 4
water fraction, 116, 123–125
water velocity, 110, 111, 116, 152–153, 158, 160
wellbore temperature
in no reservoir flow regions
heat-transfer problem, 19, 20
for incompressible fluid, 19
Ramey equation, 20–22
temperature behavior in injection/production wells, 18, 20
thermal conductivity, 22
thermal diffusivity, 20
time function, 20
opposite gas zones, 24, 26–27
opposite injection/production zones, 22–24
well geometry factors, 173
wheeled tractor, 147
Y
young well, flowing and shut-in temperature logs, 34, 36
