PLATFORM
EXPRESS equipment hanging
in the derrick
and ready to
go downhole
in Bakersfield,
California, USA.
In this region of
1200-ft [360-m]
wells, reductions in rig time
and rathole are
cutting logging
costs 20 to 30%.
New measurements and
answer products are leading to better
detection of
bypassed
pay and more
efficient
steamdrive
strategies.
4
A First Look at
PLATFORM EXPRESS Measurements
For more than 20 years, the triple combo has provided fundamental
formation evaluation in wells worldwide. Now the next generation of
wireline technology has arrived, addressing industry’s growing demand
for diverse, high-quality data and greater operational efficiency.
Alison Goligher
Montrouge, France
Bill Scanlan
Bakersfield, California, USA
Eric Standen
Clamart, France
A.S. (Buddy) Wylie
Santa Fe Energy Resources
Bakersfield, California
For help in preparation of this article, thanks to John
Amedick, Wireline & Testing, Buenos Aires, Argentina;
Rob Badry, John Kovacs and Curtis MacFarlane, Wireline
& Testing, Calgary, Alberta, Canada; Ashok Belani,
Charles Currie, Henry Edmundson and Stuart Murchie,
Wireline & Testing, Montrouge, France; Vincent
Belougne, Ollivier Faivre, David Hoyle, Laurent Jammes,
Wireline & Testing, Clamart, France; Mark Bowman,
Phillips Petroleum, Amarillo, Texas, USA; Charles Case,
Darwin Ellis, Charles Flaum, Paul Gerardi and Michael
Kane, Schlumberger-Doll Research, Ridgefield,
Connecticut, USA; John Cunniff, Wireline & Testing,
Midland, Texas; Bill Diggons and Stephen Whittaker,
Schlumberger Oilfield Services, Sugar Land, Texas;
Michael Garding, Wireline & Testing, Liberal, Kansas,
USA; Jim Hemingway and Pete Richter, GeoQuest, Bakersfield, California; John McCarthy and Mark Rixon,
Wireline & Testing, Oildale, California; Bob Mitchell,
Wireline & Testing, Amarillo, Texas; Dwight Peters,
Wireline & Testing, Sugar Land, Texas.
AIT (Array Induction Imager), FMI (Fullbore Formation
MicroImager), Litho-Density, MAXIS Express, MDLT
(Dual Laterolog Tool), MicroSFL and PLATFORM EXPRESS are
marks of Schlumberger.
Specification
Length, ft (m)
Weight, lbm (kg)
OD, in.
Temperature rating, °F (°C)
Pressure rating, psi
Max logging speed, ft/hr (m/hr)
Summer 1996
Low oil prices over the last decade have
forced a steady improvement in the efficiency of oilfield operations. This efficiency
continues to evolve in two ways—gradually,
like a river continuously reshaping its
course, and suddenly, like a river overflowing and cutting a new channel that redirects
its course. Every so often, an abrupt jump in
efficiency comes from a new technology
that increases productivity. In wireline logging, the latest catalyst of such a leap is the
recently introduced PLATFORM EXPRESS technology—a wireline instrument that
addresses the industry’s demand not only for
efficiency, but also for improved reliability,
flexibility and accuracy (previous page ).
The PLATFORM EXPRESS name explains the
technology’s most striking departures from
convention. Platform because multiple
functions are integrated into a single package and sensors are interlaced on the same
sonde, rather than assembled as a series of
separate, connectable units. As a result, the
measurement package is less than half the
length of a conventional triple combo—
38 ft [12 m] versus 90 ft [27 m]—and, at
690 lbm [311 kg], about half the weight
(below and right ). Express because nearly
90 ft
[27 m]
38 ft
[12 m]
(continued on page 7)
Triple combo
PLATFORM EXPRESS
typically 90 (27)
38 (12)
1500 (675)
690 (311)
3 3/8 to 4 1/2
3 3/8 to 4 5/8
350 (175)
250 (120)
20,000
10,000
800 (540)
3600 (1080)
■Light is good, short is better. The shorter
length and lighter weight of PLATFORM
EXPRESS equipment (right) compared to the
conventional triple combo logging string
are made possible by integration of sensors
and telemetry equipment. Specifications of
this technology allow it to be used in 90%
of operations worldwide.
5
Triple Combo vs. PLATFORM EXPRESS Logging Time
Triple Combo vs. PLATFORM EXPRESS Rig Time
16
Average lost time
Repeat section
Calibration
Logging time
Rig up/down
Drill rathole
7
Phillips-Schlumberger Alliance
14
6
12
5
Hours
Hours
10
8
4
3
6
2
4
1
2
0
0
Converted to PLATFORM EXPRESS
on 8/15/95
Triple
Combo
PLATFORM
EXPRESS
Land
Triple
Combo
PLATFORM
EXPRESS
Offshore
■Comparison of logging time expenditure before and after initiation of PLATFORM EXPRESS services (left) and rig time comparison of triple
combo versus PLATFORM EXPRESS services averages for land and offshore wells (right). In the Phillips-Schlumberger alliance in the Texas
Panhandle, average time in hole with conventional logging was 9.5 hours and with PLATFORM EXPRESS equipment 3.7 hours, a savings of
5.8 hours in rig time per well. “Once the logging tool is on bottom, we know within minutes if we’re going to set pipe,” said Mark Bowman, a geologist with Phillips, “whereas before, we had another 6 to 8 hours of logging before we’d even begin printing the logs.” Some
operators have achieved greater time savings by using PLATFORM EXPRESS log quality measurements to justify elimination of routine
repeat sections.
1
2
■A sample of PLATFORM EXPRESS presentations.
Track 1: Conventional track 1 data,
including a water saturation, Sw ,
calculation. Gamma ray backup is used
to find zones that are more radioactive
than normal. Typically, the backup is
scaled 100 to 200 API units when the track
is scaled 0 to 100 units.
Track 2: Calculated micronormal and
microinverse curves, from the microresistivity measurement. Separation (arrows) is
a qualitative permeability indicator since
it occurs in front of mudcake, which accumulates at permeable intervals.
6
3
4
Tracks 3 and 4: AIT Array Induction
Imager logs, comparing 90- and 10-in.
resistivity readings with the 4-ft vertical
resolution 90-in. conductivity reading and
the microresistivity log. Conductivity can
be easier to read when values reach
extremes, and is helpful in making comparisons to old logs. Track 4 shows all five
depths of investigation for the induction
log and Rxo with an 18-in. [45-cm] vertical
resolution for easier comparison with
induction measurements. Vertical resolution of the Rxo measurement can be as
good as 1 in.
5
6
7
8
Track 5: Real-time resistivity-derived dip
from the PLATFORM EXPRESS laterolog (red)
and FMI Fullbore Formation MicroImager
measurements (black). The two tracks of
densely spaced color stripes are laterologderived images. The first image is the
second derivative of the log curve, in
which color changes indicate bed boundaries that are used to compute dip. The
next image is normalized to show bedding.
These images help estimate structural
dip trends.
Oilfield Review
■Torture chamber,
Clamart, France.
Bernard Brefort,
mechanical technician, securing a
wireline tool into a
machine that performs shock testing
on PLATFORM EXPRESS
equipment, prior to
start-up of a test
(top). The blue
I-beam moves
repeatedly up and
down, subjecting
tool electronics to
thousands of 250-g
shocks (bottom).
These qualification
criteria are similar
to those used for
logging-whiledrilling equipment.
(In the bottom
photo, the top of the
shock chamber is
open for the photograph, but is normally closed for
safety and noise
abatement.)
all operations take less time (previous page,
top). Shorter tool length saves time drilling
rathole and in rigging up and down; new
technology speeds calibration and doubles
logging speed; faster, more comprehensive
real-time data processing reduces
turnaround time and provides answers previously unobtainable at the wellsite.
During the initial commercialization of
PLATFORM EXPRESS, reliability was five times
that of conventional technology, mainly due
to shock-resistant designs adapted from logging-while-drilling equipment developed by
Anadrill (right). Greater flexibility is both literal and figurative. Two hinge joints combined with the shorter 38-ft length allow
more successful logging of higher angle
holes and provide new opportunities to log
the increasing number of short-radius wells.
The articulated pad, which is also shorter
than previous designs, improves sensor
positioning to provide better data in rough
holes. Coupling this new service with the
high-efficiency MAXIS Express surface system provides data in formats that can be
configured to diverse markets—from the
most cost-sensitive to those demanding the
most comprehensive and accurate information (previous page, bottom and below ).
For drillers, flexibility, efficiency and reliability all contribute to higher productivity.
But perhaps the most significant advance-
100%
Increasing red
Vcl 95%
Vcl 65%
AIT signals
Vcl 35%
Vcl 5%
0%
9
Track 6: Lithocolumn display, at 1:1300, a
scale geologists use for correlation. The left
track is a laterolog-derived image that
shows the degree of bedding. Light is lowresistivity contrast and dark is high. The
right track, in which the right margin of
the track is effective porosity and the
left is bounded by the gamma ray log,
shows lithology.
Track 7: A resistivity invasion profile, 90 in.
from the center of the borehole, in which
red is high resistivity and blue is low.
Summer 1996
10
Track 8: A laterolog-derived image, in
which light bands are resistive and dark
are conductive. This image is used mainly
for bedding identification and correlation,
but can also be used for dip analysis on a
workstation. The white trace represents the
path followed by the high-resolution pad.
Track 9: Log quality control (LQC) output.
The seven stripes to the left of the induction
log are LQC tracks for resistivity measurements. Each stripe represents a parameter.
The five stripes to the left of the nuclear
track are five parameters for the nuclear log
and accelerometer, including accelerometer, density hardware, neutron porosity
correction, density processing and photoelectric factor processing checks. A flag
appears in the green tracks if any critical
parameters exceed predetermined values.
11
12
Track 10: Rt and mud resistivities from
induction and laterolog measurements,
and invaded zone microresistivity, filtered
at 18 in.
Track 11: Environmentally corrected neutron porosity and a standard-resolution
density porosity. Although not shown here,
the density reading has been computed at
resolutions as good as 2 in. [5 cm].
Track 12: A lithology quicklook at a more
expanded scale than in track 6. Inputs
are density, photoelectric effect and
gamma ray or SP. The left margin is clay
volume. The color scheme (inset) indicates
quartz, dolomite, calcite and anhydrite
values. The points remain fixed and, as
clay content increases, the color tone shifts
toward red.
7
ment is in the measurements and answers
they provide, since this information
improves the geoscientist’s understanding of
reservoirs and, ultimately, enhances the
profitability of field developments. With
nearly a year of experience so far, the influence of new data is yet to be felt fully, but
early results give a sense of how this new
information leads to a clearer picture of
reservoir properties. Summarized here are
highlights of the new technology, some
common problems addressed by PLATFORM
E XPRESS logs, and a recent case study
from California.
Better Measurements, New Answers
PLATFORM E XPRESS technology contributes
new measurements, improved processing
approaches and real-time log quality controls. For all three, common features are
greater accuracy, breadth of data and speed
of interpretation. Many computations that
formerly took place after some delay—on
the surface at the wellsite after logging, or
hours to days later at the log interpretation
center—can now be done downhole in real
time. We will look first at the measurements
themselves.
From top to bottom, the platform makes
seven petrophysical measurements: gamma
ray, neutron porosity, bulk density, photoelectric effect (Pe), flushed zone resistivity
(Rxo ), mudcake thickness (Hmc ), also called
pad standoff, and true resistivity (Rt ) derived
from laterolog or induction imaging measurements (right ).1 Integrated into the package is a z-axis accelerometer, permitting
real-time speed correction (next page, top ).
This correction for irregular motion is performed on first-generation raw data, rather
than on multisensor data that have been
through one or more processing cycles,
resulting in more accurate and precise realtime depth matching for all measurements
(next page, bottom ).2 Other measurements
include caliper, mud temperature and mud
resistivity and, with a special head, downhole cable tension.
Except for the gamma ray and neutron
measurements, which have standard vertical
resolutions, other measurements elevate the
standards of wireline logging.3 In the density
measurement, a reengineered pad, addition
of a third detector and data processing provide improvements over conventional dualspacing measurements. 4 These improvements yield better compensation for large
standoff (up to 1 in. [2.5 cm]), higher precision in denser formations and less sensitivity
to barite, which compromises Pe measurements. A shorter measurement pad and
8
Tool
acceleration
GR
24 in.
Highly Integrated
Gamma Ray
Neutron Sonde
(HGNS)
ØN
12 to 24 in.
ρb, Pe
2, 8, 18 in.
Electronics
cartridge
Rxo, Hmc
2, 8, 18 in.
Hinge
joint
■PLATFORM EXPRESS
measurements. The
lower section of the
string can be an
induction- or laterolog-type device,
depending on borehole mud resistivity
and borehole/formation resistivity
contrast. Hinge
joints above and
below the High-Resolution Mechanical
Sonde allow the
tool to better negotiate rough boreholes and improve
pad contact.
High-Resolution
Mechanical
Sonde
Caliper
Hinge
joint
High-Resolution
Azimuthal Laterolog
Sonde (HALS)
AIT Array Induction
Imager Tool
Rt, Rm
HALS
1. Standoff refers to the distance between the pad and
formation, regardless of whether this is filled with mud
or mudcake. Standoff usually equals mudcake thickness in permeable formations.
2. Belougne V, Faivre O, Jammes L, and Whittaker S:
“Real-Time Speed Correction of Logging Data,” Transactions of the 37th SPWLA Annual Logging Symposium, New Orleans, Louisiana, USA, June 16-19,
1996, paper F.
3. Vertical resolution of the gamma ray and neutron
porosity measurements is 24 in. [60 cm] and for the
neutron up to 12 in. [30 cm] with enhanced resolution processing. See:
Flaum C, Galford JE and Hastings A: “Enhanced Vertical Resolution Processing of Dual Detector GammaGamma Density Logs,” The Log Analyst 30, no. 3
(May-June) 1989: 139-149.
AIT
Galford JE, Flaum C, Gilchrist WA and Duckett SW:
“Enhanced Resolution Processing of Compensated
Neutron Logs,” paper SPE 15541, presented at the
61st SPE Annual Technical Conference and Exhibition,
New Orleans, Louisiana, USA, October 5-8, 1986.
4. Eyl K, Chapellat H, Chevalier P, Flaum C, Whittaker
SJ, Jammes L, Becker AJ and Groves J: “High-Resolution Density Logging Using a Three Detector Device,”
paper SPE 28407, presented at the 69th SPE Annual
Technical Conference and Exhibition, New Orleans,
Louisiana, USA, September 25-28, 1994.
Oilfield Review
PLATFORM EXPRESS
Standard LLS
Caliper
in.
Standard LLD
16
2.0
0.2
0
API
0.2
125
Caliper
Standard MicroSFL
0.2
Speed-Corrected High-Resolution LLS
Speed-Corrected
Gamma Ray
ohm-m
2.0
6
in.
16
Speed-Corrected High-Resolution LLD
0.2
X550
X580
X580
2.0
Speed-Corrected High-Resolution RXO
0.2
X550
2.0
ohm-m
2.0
Zone
of interest
6
2.0
125
Depth, ft
API
0
0.2
Depth, ft
Standard
Gamma Ray
■Dramatic effect of PLATFORM EXPRESS real-time speed correction (right). In the nonreservoir section of a West Texas well, off-depth log readings were related to sticking. Lack of speed correction can lead to incorrect logs, improper correlation and, possibly, undetected pay.
MDLT Dual Laterolog
5.0
ohm-m
50,000
HALS Standard-Resolution Laterolog
0.5
HCAL
8
5000
HALS High-Resolution Laterolog
13 0.05
0.005
Depth, ft
1:100
500
Invaded Zone Resistivity
X450
ohm-m
Pad
deg
50 -180 180
■Real-time resolution matched measurements, from the
Middle East. The
standard laterolog
curve appears at
far left and the
highest resolution
PLATFORM EXPRESS
data are presented
on the right. In the
laterolog-type
image track on the
right, light bands
are resistive and
dark bands are
conductive.
X500
Summer 1996
9
Correlation
Depth, ft
articulated arms improve contact with the
formation, which enhances tool response in
rough boreholes (next page, top left and
bottom left ). A new, short-spacing detector
crystal with a shallow depth of investigation
and a high counting rate provides additional
measurements that result in reduced sensitivity to standoff and improved statistics in
hard formations, yielding higher vertical resolution (next page, right ). In addition, the
device also gives a rough estimate of mudcake density and Pe.
Resistivity
Porosity
A new microresistivity technology makes
measurements—at three depths of investigation—that are analyzed to evaluate flushed
zone and mudcake properties—Rxo , Rmc
and standoff—overcoming a limitation of
conventional microresistivity sensors, which
can measure resistivity in the flushed zone
or mudcake, but not both (see “A New Look
at Microresistivity,” below ). Improved focusing of this measurement helps increase Rxo
vertical resolution to 1 in.5 In addition, mud
resistivity, typically taken with a mud cell at
µ Res Perm
Oil
Sat
X900
X1000
surface and corrected with an estimated
downhole temperature, can now be measured downhole in real time by the induction or laterolog component. The multipurpose microresistivity sensor on the platform
has reintroduced, and sometimes introduced for the first time, microresistivity
measurements in places where they were
not used routinely, providing new insights
into formation properties (below ).
The induction measurement provides logs
with vertical resolution of 1, 2 and 4 ft, each
■Finding elusive sands with the new focused microresistivity log.
In Bakersfield, California, sands often elude detection with
gamma ray and SP. The gamma ray measurement is often misleading because the arkosic sands are rich in radioactive potassium and, when steamed, become more radioactive as mobile
radionuclides concentrate in them. The SP cannot find sands
because fresh water from steaming changes formation Rw , altering the static SP deflection as water shifts between fresh and salty.
Historically, fewer than 10% of logging programs in the region
included a microlog or Rxo measurement. Estimation of sand
count relied on other methods, with mixed results. The new
microresistivity log provides a more consistent answer as well as
being available on every service run without additional tools in
the logging program. In the new microresistivity processing (track
labeled µ Res), Rxo (left curve) and mudcake or standoff (right curve)
are computed. The program then back-calculates micronormal
and microinverse values from the microlog.
In this well, the microresistivity log is also used to calculate net
pay and define shale barriers, which can be interpreted as horizontal, low-permeability layers that are critical in steam injection
strategy. In addition, the microresistivity log, in combination with
deep-reading resistivity, is also used to distinguish movable from
immovable (heavy) oil. If the deep water-saturation value (Sw )
equals the shallow (Sxo ), then the hydrocarbons are not movable.
X1100
Right: Standoff
Left: Rxo
A New Look at Microresistivity
The new focused microresistivity measurement
surements sample the same formation volume at
about two thirds that of MicroSFL measurements.
differs in four main respects from existing Rxo
nearly the same time. As a result of these fea-
Therefore it is less affected by the noninvaded
measurements: electrodes are mounted on a stiff
tures, vertical resolution of raw measurements is
zone and gives a truer Rxo value, and hence Sxo.
pad that is not deformed by the borehole, making
improved to less than 1 in. An Rxo value and esti-
for a more consistent standoff measurement; sur-
mate of mudcake parameters are obtained through
vey currents are independently focused in planes
inversion processing that simultaneously solves
parallel and perpendicular to the tool axis, reduc-
for all the unknown variables—Rxo, Rmc and Hmc.1
ing sensitivity to borehole geometry; the three
In this way, positive curve separation is recorded
depths of investigation permit solving for mudcake
only when the program computes the presence of
and formation properties more reliably via inde-
mudcake in front of the pad. Through inversion
pendent equations of tool response; and sensors
processing, raw measurements are corrected for
are adjacent to the density sensors, so both mea-
thick mudcakes. This measurement is insensitive
to thin mudcake and has a depth of investigation
10
1. Rmc is not quite an unknown. Its value is fixed by the Rm
value obtained by the PLATFORM EXPRESS induction or
laterolog measurement.
Inversion processing is a simultaneous solution for a
number of unknowns with constraints defined by the
physics of the measurements. In the case of the new
microresistivity log, there are three measurements of
microresistivity. Rather than run each through a series of
chart corrections, which leads to systematic, additive
errors, the inversion program minimizes error on each
output. This results in a solution that not only is more
accurate, but also has a quantifiable precision.
Oilfield Review
2-in. PEF
1
6
in.
16
Hinge joint
Gamma Ray
0
API
Depth, ft
Caliper
11
Neutron Porosity
0.6
g/cm3
0
2-in. Density
150
1.7
2.7
X230
Force applied
at center of
skid
Hinge joint
X240
■Improving contact in rough boreholes.
Hinge joints improve density-Rxo pad contact with the borehole wall and formation
face, especially in rugose hole and
washouts. Better pad contact improves
measurement accuracy and interpretation
in difficult boreholes.
PLATFORM EXPRESS Formation Density
Litho-Density RHOB
Caliper
X250
RHOB > NPOR
Washout
■Log-core comparison, Bakersfield,
California. In this
comparison, the
high-resolution
density confirms
that 2-in. streaks
seen on the microresistivity log are
limey, which can
act as vertical permeability barriers.
Locating these
streaks helps the
operator identify
where steam breakthrough, which can
kill a producing
well, will not occur
and where producers can therefore be
perforated closer to
the water leg. Limey
streaks visible in the
core at X234 ft and
X242 ft correspond
to density peaks at
those intervals.
5. Eisenmann P, Gounot M-T, Juchereau B, Trouiller J-C
and Whittaker SJ: “Improved Rxo Measurements
Through Semi-Active Focusing,” paper SPE 28437,
presented at the 69th SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA,
September 25-28, 1994.
■Improved density measurement in rough
hole. The conventional and new threedetector density measurements track
together in smooth hole, but the shorter,
better articulated pad of the new measurement gives superior results where the
caliper indicates washouts (arrow). The
PLATFORM EXPRESS measurement also compensates for standoff of up to 1 in. Shown here is
the standard-resolution measurement.
Summer 1996
11
HCAL
CORPOL Dips
Hole AZ
0
All
deg
90
2
Pad
1A Z
DEVI
-1
FMI Dips
9
0
deg
ohm-m
2000
High-Resolution
Deep Resistivity
All
90
2
ohm-m
2000
Depth, ft
1:1200
Log Quality Control
High-Resolution
Shallow Resistivity
in. 12
7
X200
X400
■A PLATFORM EXPRESS first: Real-time resistivity-derived dip, from West Texas, USA. This
structural dip presentation compares PLATFORM EXPRESS laterolog and FMI measurements.
Track 2 shows good agreement in dips derived from the two techniques. Changes in dip
azimuth and magnitude at X200 and X230 ft are probably associated with faults or
unconformities. The laterolog-derived image in track 3 is the second derivative of the log
curve. Color changes here correspond to inflection points on the log curve, which indicate bed boundaries and are used to compute dip. The laterolog-derived image in track
4 is normalized to show bedding. Taken together, these two tracks help detect the structural dip trend.
with depths of investigation of 10, 20, 30,
60 and 90 in.6 In addition, an integrated
mud resistivity measurement allows for
accurate, real-time environmental corrections to be made.7
The azimuthal laterolog combines a dual
laterolog array for standard deep- and shallow-resistivity measurements with an
azimuthal array of electrodes that makes deep
and shallow resistivity measurements around
the borehole with 8- or 16-in. [40-cm] vertical resolution.8 The new azimuthal readings
are especially helpful for interpreting horizontal well logs and invasion profiles, evaluating fractures and other formation heterogeneities, and for estimating both formation
dip and resistivity of dipping beds (above ).
Like the induction sensor, the laterolog also
measures mud resistivity in real time and
downhole.
12
New tool physics and tool design have
led to better environmental corrections
made in real time. For example, a new
measurement of standoff in the microresistivity and density logs allows for improved
environmental corrections and log quality
control. 9 In addition, measurements of
mudcake Pe and bulk density permit calculation of an environmentally corrected formation Pe for better response in bad hole
conditions (next page, bottom left ). Realtime environmental corrections to the density log, using a temperature log, are proving valuable in steamflood regions (next
page, bottom right ). Temperature-corrected
density and neutron logs can more reliably
distinguish steam breakthrough from zones
that are hot, but may still contain
producible oil. Finally, measurements of
downhole temperature, Rm and calipers
allow for real-time correction with measured, rather than estimated or derived,
parameters of the borehole environment
(page 15, left ).
Since the dawn of well logging, the repeat
run has provided proof of satisfactory tool
function. Now, PLATFORM EXPRESS log quality
control (LQC) procedures are giving an
increasing number of operators confidence
to log without the time-honored repeat run
and gain significant time savings and other
operational efficiencies.
Real-time log quality indicators allow
monitoring of two categories of LQC data:
hardware performance parameters, which
indicate tool function; and data validity
parameters, which are geared to indicate
environmental problems that may skew
readings. Functions are checked at every
sampling interval, typically 6 in. [15 cm] or
less. When any value falls outside a predefined limit, a solid square appears in the
LQC tracks (next page, top ). At the end of
the log, an LQC summary reports the percentage of the logged interval with LQC
values outside the defined limits. This summary provides a quick indicator of the
degree of confidence in overall log quality,
and the flags show whether significant
problems arose in intervals critical enough
to warrant a repeat run. Not usually displayed on the logs, but available to the field
engineer, are diagnostics that zero in on the
specific failure. Five variables each are
measured for nuclear and electrical measurements—two hardware parameters,
three for data validity.
In the data validity category, one example
is the quality parameters for Pe measurements. The Pe measurement is sensitive to
barite, and up to a point can be corrected
for the influence of barite. But when the
correction exceeds a certain value, the flag
appears, signaling data are of limited confi6. Barber T, Orban A, Hazen G, Long T, Schlein R,
Alderman S and Seydoux J: “A Multiarray Induction
Tool Optimized for Efficient Wellsite Operation,”
paper SPE 30583, presented at the 70th SPE Annual
Technical Conference and Exhibition, Dallas, Texas,
USA, October 22-25, 1995.
7. Barber TD and Rosthal RA: “Using a Multiarray
Induction Tool to Achieve High-Resolution Logs with
Minimum Environmental Effects,” paper SPE 22725,
presented at the 66th SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, October
6-9, 1991.
8. Smits JW, Benimeli D, Dubourg I, Faivre O, Hoyle D,
Tourillon V, Trouiller J-C and Anderson BI: “High Resolution From a New Laterolog with Azimuthal Imaging,” paper SPE 30584, presented at the 70th SPE
Annual Technical Conference and Exhibition, Dallas,
Texas, USA, October 22-25, 1995.
9. Eyl K et al, reference 4.
Oilfield Review
Resistivity Track
HAIT array (1-2)
HAIT hardware
HAIT array (3-4)
RXO processing
HAIT array (5-6)
MCFL hardware
HAIT array (7-8)
Nuclear Track
Neutron porosity
Density detector
Density computation
Accelerometer
Pe computation
4350
Depth, ft
AIT borehole/
formation
digital ratio
HGNS
deviation
AIT signals
Caliper
Density
standoff
Gamma
ray
Resistivity
standoff
4400
Tool sticking here...
...probably related to this accelerometer flag
■Interpretation of PLATFORM EXPRESS log quality measurements, which are presented as green stripes. In some provinces, the completeness
of LQC data has given operators the confidence to log many wells without repeat runs. In the density and resistivity standoff curves (left
track, right margin), if a threshold value is reached, a flag appears, indicating several causes—mud is too fresh for microresistivity measurements, barite is present in the mud or the density tool has been miscalibrated.
RXOZ
2
HMNO
125
mm
375
HCAL
125
mm
375
Gamma Ray
0
API
mV
HMNO
ohm-m
0 20
m
HDRA
200 -50
2
AIT-H30
200 0.6
10
m3/m3
0
NPOR
AIT-H90
ohm-m
450
DPHZ
AIT-H60
2
kg/m3
PEF
200 0
2
1:240
20
Oil
µ Res Perm Sat
200
AIT-H20
2
150
SP
-80
ohm-m
0 20
Porosity
AIT-H10
HMIN 2
Bit Size
Resistivity
200
200 0.6
m3/m3
0
Densityneutron
crossover
X40
X50
X60
■Bad hole, good logs. Depth-matched and speed-corrected PLATFORM EXPRESS logs in this
Canadian well react vigorously to calcitic and shaly laminations, giving the operator a
clearer understanding of the distribution of shale laminae and shale clasts, which is
important in steam-injection strategy. Even the large breakout at X46 m does not
dramatically distort density or Pe readings. Improved density response derives from
tool articulation and a smaller pad.
Summer 1996
■Steam breakthrough or just a hot tamale?
In the steamflooded fields of Bakersfield,
California, a density-neutron crossover is
often associated with the high temperature
of steam breakthrough. However, crossover
is not always a reliable indicator of breakthrough. Conventional logs may mistake a
zone adjacent to steam for a zone where
steam has broken through. PLATFORM EXPRESS
density-neutron logs can be temperaturecorrected in real time to show crossover
only in zones with breakthrough. In wells
of the Midway-Sunset field, use of this
technique has yielded an additional 50 ft
of pay, which otherwise would have been
plugged. The technique relies on a temperature sensor that has a four-fold improvement in response time compared to previous technology.
13
Gamma Ray
Depth, ft
50
API
in.
in.
mV
AIT-H20 in.
AIT-H20 in.
AIT-H20 in.
AIT-H30 in.
AIT-H30 in.
AIT-H30 in.
AIT-H60 in.
AIT-H60 in.
AIT-H60 in.
16
SP
-100
AIT-H10 in.
16
Caliper
6
AIT-H10 in.
200
Bit Size
6
AIT-H10 in.
AIT-H90 in.
0 0.2
ohm-m
AIT-H90 in.
200 0.2
ohm-m
AIT-H90 in.
200 0.2
ohm-m
200
X470
X490
■Resistivity signatures of tricky sands in the San Joaquin Valley. The PLATFORM EXPRESS
induction log can be presented at three vertical resolutions, from left, 1, 2 and 4 ft.
The 4-ft scale can be useful for comparison with older logs, and shows how high temperature—this interval measures 200°F [93°C]—affects resistivity readings. Between X472 and
X474 ft, the small bump on the 4-ft log appears to be shale. At the 1-ft scale, however, it
shows a 3-ft sand with potential pay, with a high gamma ray reading due to radioactive
elements concentrated in the formation from steaming. Below X480 ft, the 1-ft log reveals
laminated sands that appear as a coarsening upward sequence.
dence. For resistivity measurements, LQC
diagnostics may indicate that the tool is
working fine, but that environmental conditions, for example, may be responsible for
an aberrant reading. This would typically be
the case for the shallow-reading devices in
washed-out zones, where the borehole signal would be larger than the formation signal. In the realm of hardware LQC, a flag
will indicate, for instance, whether a density
detector voltage is out of tolerance.
Case Study: Finding Bypassed Pay
in Bakersfield
Tight margins are a way of life in the Midway-Sunset field of southern California, in
one of the oldest, most productive basins in
the lower 48 states. Heavy oil (10 to 15°
API) lies as shallow as a few hundred feet,
but production usually requires costly
steamflooding. A typical well might produce
20 to 30 barrels of oil per day (BOPD) [3.2
to 4.8 m3/d] for several decades, with an
exceptional producer reaching 50
14
barrels/day [7.9 m 3 /d]. Santa Fe Energy
Resources, which produces more than
48,000 BOPD [635 m3/d] from three main
fields in the area, faces several technical
challenges.
A major challenge is identifying oil left
behind after steam injection, when conventional logs sometimes present ambiguous
interpretations. In a steamed zone, the density-neutron log curves may cross over
because the tools read the steam, a light
fraction of hydrocarbons released from the
heat, or gases from in-situ combustion of
hydrocarbons. The gamma ray log reads
high because steaming causes migration
and concentration of radionuclides. High
temperature lowers Rw , reducing apparent
true resistivity—sometimes even in the presence of hydrocarbons (above ). The challenge is finding oil that eludes detection
conventionally.
A critical step in addressing this problem is
correcting logs—in this case, the neutron,
but sometimes also the Rw—for the high
temperature. For the special needs of this
field, the PLATFORM EXPRESS system was fitted
with a new contact temperature sensor,
which measures temperature of the forma-
tion rather than the mud. It responds four
times faster than previous technologies,
enabling Santa Fe Energy to acquire a highresolution temperature measurement for a
temperature-corrected neutron log (next
page, left ). A better fix on porosity yields a
more accurate water saturation (S w ) . A
quicklook log with customized a, m and n
values, and temperature-corrected neutron
and Rw values goes into a real-time computation of saturation.10 With this log, casing
decisions that used to take hours can now
be made in minutes.
Better understanding of desaturation yields
other dividends. It leads to more effective
steaming strategies, such as better identification of thief zones or intervals receiving
insufficient steam. In addition, it improves
completion strategies, like leaving slotted
pipe in zones previously thought to be
depleted of hydrocarbons, and which were
formerly completed with blank pipe.
In diatomite formations of California’s San
Joaquin Valley, PLATFORM EXPRESS measurements have shed new light on possible production mechanisms. These diatomites are
massive, low-permeability formations that
must be hydraulically fractured. Electrical
imaging logs sometimes revealed high-resistivity streaks, which were not well understood. When PLATFORM EXPRESS microresistivity and Rxo measurements were first run, the
microresistivity reported mudcake—not previously observed—and the R xo showed
unusual spikes (next page, right ). To look for
possible causes, the FMI Fullbore Formation
MicroImager tool was run, which revealed
mudcake and Rxo spikes in front of the highresistivity streaks, suggesting that they are
fractured zones. The PLATFORM EXPRESS density measurement, presented with a 2-in.
vertical resolution—the highest axial resolution possible for a density measurement—
indicated that the streaks are possibly cherty.
This adds one more piece to the oil origins
and distribution puzzle.
Santa Fe Energy has also ceased running
repeat sections, due mainly to the combination of PLATFORM EXPRESS log quality data and
better tool reliability. The log quality display
provides enough information about tool
function and wellbore conditions to confirm
10. Exponents m and n in the Archie formula relate oil
saturation in porous rock to the resistivity of the fully
water-saturated rock. The constants a and m relate
the measured resistivity of a fully saturated porous
medium to the water resistivity. Both constants are
related to the nature of the connection between pore
spaces; a , often taken as 1, is called the cementation
factor, and m , the porosity exponent, reflects the tortuosity of the current flow through the rock pores.
The saturation exponent, n , often taken as 2, is
related to the wettability of the rock surface.
Oilfield Review
0.6
Std. Resolution
Density Porosity
Density
0
Temp. Converted TNPH
0.6
vol/vol
0
60
Density
Standoff
MicroLog
50
API
200
HCAL
6
in.
16
mV
0
in.
0
1
AIT-H90 in.
Microresistivity
in.
ohm-m
0 0.2
ohm-m 0
0
20
1:60
ft
Horizontal Scale 1:6
Azimuth Scale
120
240
360
FMI. FUN [A860948]
SW
Resistivity
Standoff
2
HMIN
Zone of Interest
AIT-H RT
Density
Standoff
2
SP
-100
Crossover
Resistivity
Standoff
Gamma Ray
0
1000
HMNO
HILT Porosity Crossplot
p.u.
ohm-m
1
9
3
RXO
Very High Resolution
Formation Pe
-1
g/cm3
1
0 TNPH Temp. Correction
AIT-H
Water
Saturation
2000
905
Env. Corr. Thermal
Neutron Porosity
0.6
vol/vol
0
X350
Depth, ft
910
X380
915
■Water saturation, with and without heatstroke. The PLATFORM EXPRESS water saturation
display (second track from right) shows a real-time Sw curve corrected for the effect of
temperature on the neutron input. In the right track, the corrected neutron (left margin of
the green area) is offset from the uncorrected by up to about one division (6 p.u.).
measurement validity without repeat runs.
Lost time due to hardware failure is
approaching 300 jobs per lost-time failure,
nearly a ten-fold improvement over conventional technology. Given Santa Fe’s annual
300-well logging program, eliminating
repeat logs and reducing lost-time failures
translates into significant savings. Santa Fe
estimates that the time savings allows more
wells to be put on line, and the improved
petrophysics provides better characterization of desaturated zones. Together, these
benefits are expected to translate into an
increase in production of more than 22,000
barrels [3180 m3] per year.
Summer 1996
Where It Leads
With less than one year of commercial service, most operators are still in the handshake stage, getting to know P LATFORM
EXPRESS technology. For some, a significant
step is resolution-matching new logs to
older logs for easier comparison, and adapting data bases to the new mnemonics. For
many, the easy availability of more comprehensive wellsite answers is raising questions
about long-standing formation evaluation
practices. “At first we thought: ‘We don't
need microresistivity,’” said A.S. (Buddy)
Wylie at Santa Fe Resources, “but we found
that it could give us good additional value at
only an incrementally higher price.”
■A new view of possible production mechanisms in San Joaquin Valley diatomites. An
FMI log reveals high-resistivity streaks that
are shown to be permeable by the PLATFORM
EXPRESS microresistivity log (blue curve), and
to have the high grain-density signature of
chert by the 2-in. vertical resolution density
log (purple curve).
The immediate and most obvious rewards
are operational efficiencies. In the petrophysical realm, deeper, sharper reading and
more robust measurements are showing
details sometimes not seen before, whose
full significance will unfold with the
expanding library of PLATFORM EXPRESS logs
and with the growth of interpretation techniques to get the most from them.
—JMK
15
Simulation Throughout
the Life of a Reservoir
Gordon Adamson
Reservoir Management Ltd.
Aberdeen, Scotland
Martin Crick
Texaco Ltd.
London, England
Brian Gane
British Petroleum
Aberdeen, Scotland
Omer Gurpinar
Denver, Colorado, USA
Jim Hardiman
Henley on Thames, England
Dave Ponting
Abingdon, England
For help in preparation of this article, thanks to Bob
Archer, Chip Corbett, Ivor Ellul, Roger Goodan and Jim
Honefenger, GeoQuest, Houston, Texas, USA; Randy
Archibald, GeoQuest Reservoir Technologies, Henley on
Thames, England; Ian Beck, GeoQuest Reservoir Technologies, Abingdon, England; George Besserer,
PanCanadian Petroleum Limited, Calgary, Alberta,
Canada; Kunal Dutta-Roy, Simulation Sciences Inc.,
Brea, California, USA; and Sharon Wells, GeoQuest
Reservoir Technologies, Denver, Colorado.
ECLIPSE, FloGrid, GRID, Open-ECLIPSE, PVT and
RTView are marks of Schlumberger. NETOPT and
PIPEPHASE are marks of Simulation Sciences Inc.
1. Peaceman DW: “A Personal Retrospection of Reservoir Simulation,” Proceedings of the First and Second
International Forum on Reservoir Simulation, Alpbach,
Austria, September 12-16, 1988 and September 4-8,
1989.
2. Wycoff RD, Botset HG and Muskat M: “The Mechanics of Porous Flow Applied to Water-flooding Problems,” Transactions of the AIME 103 (1933): 219-249.
Muskat M and Wyckoff RD: “An Approximate Theory
of Water-Coning in Oil Production,” Transactions of
the AIME 114 (1935): 144-163.
3. Darcy’s law states that fluid flow velocity is proportional to pressure gradient and permeability, and
inversely proportional to viscosity.
4. Coats KH: “Use and Misuse of Reservoir Simulation
Models,” SPE Reprint Series No. 11 Numerical Simulation. Dallas, Texas, USA: Society of Petroleum Engineers (1973): 183-190.
16
Simulation is one of the most powerful tools for guiding reservoir
management decisions. From planning early production wells and
designing surface facilities to diagnosing problems with enhanced
recovery techniques, reservoir simulators allow engineers to
predict and visualize fluid flow more efficiently than ever before.
Reservoir simulators were first built as diagnostic tools for understanding reservoirs that
surprised engineers or misbehaved after
years of production. The earliest simulators
were physical models, such as sandboxes
with clear glass sides for viewing fluid flow,
and analog devices that modeled fluid flow
with electrical current flow.1 These models,
first documented in the 1930s, were constructed by researchers hoping to understand water coning and breakthrough in
homogeneous reservoirs that were undergoing waterflood.2
Some things haven’t changed since the
1930s. Today’s reservoir simulators generally
solve the same equations studied 60 years
ago—material balance and Darcy’s law.3
But other aspects of simulation have
changed dramatically. With the advent of
digital computers in the 1960s, reservoir
modeling advanced from tanks filled with
sand or electrolytes to numerical simulators.
In numerical simulators, the reservoir is represented by a series of interconnected
blocks, and the flow between blocks is
solved numerically. In the early days, computers were small and had little memory,
limiting the number of blocks that could be
used. This required simplification of the
reservoir model and allowed simulation to
proceed with a relatively small amount of
input data.
As computer power increased, engineers
created bigger, more geologically realistic
models requiring much greater data input.
This demand has been met by the creation
of increasingly complex and efficient simulation programs coupled with user-friendly
data preparation and result-analysis packages. Today, desktop computers may have
5000 times the memory and run about 200
times faster than early supercomputers.
However, the most significant gain has not
been in absolute speed, but speed at a moderate price. Computational efficiency has
reached a stage that allows powerful simulators to be run frequently.
Numerical simulation has become a reservoir management tool for all stages in the life
of the reservoir. No longer just for comparing
performance of reservoirs under different
production schemes or trouble-shooting
when recovery methods come under
scrutiny, simulations are also run when planning field development or designing measurement campaigns. In the last 10 years,
with the development of computer-aided
geological and geostatistical modeling, reservoir simulators now help to test the validity
of the reservoir models themselves. And simulation results are increasingly used to guide
decisions on investing in the construction or
overhaul of expensive surface facilities.
Motivation for Simulation
A numerical simulator containing the right
information and in the hands of a skilled
engineer can imitate the behavior of a reservoir. A simulator can predict production
under current operating conditions, or the
reaction of the reservoir to changes in conditions, such as increasing production rate;
production from more or different wells;
response to injection of water, steam, acid
Oilfield Review
Core plugs
Whole cores
Borehole geophysics
Well logs
Outcrop studies
Well testing
3D Seismic data
Large-scale structure
Geological expertise
Small-scale structure
1st generation geomodel
or foam; the effect of subsidence; and production from horizontal wells of different
lengths and orientations.
Reservoir simulation can be performed by
oil company reservoir engineers or by engineering consultant contractors. Some contractors specialize in engineering consulting,
while others offer a full range of oilfield services. In either case, the simulator is a tool
that allows the engineer to answer questions
and offer recommendations for improving
operating practice.
To make simulation worthwhile, there must
be a well-posed question of economic
importance: Where should wells be located
to maximize incremental recovery per dollar
of additional investment? How many wells
are required to produce enough gas to meet
a contractual deliverability schedule? Should
oil be recovered by natural depletion or
water injection? What is the optimum length
of a horizontal well? Is carbon dioxide [CO2]
injection feasible? Should we keep this reservoir alive? As observed by K.H. Coats while
at the University of Texas at Austin, USA,
“The complexity of the questions being
asked, and the amount and reliability of the
data available, must determine the sophistication of the system to be used.”4 In all
cases, a simulation study should result in
recommendations for intervention. This may
include a new strategy for data acquisition,
or an infill drilling plan with the number,
location and direction of wells and a completion strategy for each well.
How a Simulator Works
Calibration
Risk analysis
Surface network
input
Production
Static reservoir model
Up-gridding
Simulation model
Execution model
■ Creating models for input to reservoir simulators. The first-generation geomodel is created through the combined efforts of geologists, geophysicists, petrophysicists and
reservoir engineers. Reservoir properties are then upscaled to produce the static reservoir model. Optimizing the grid and calibrating with dynamic data yield the simulation
model. Finally, input from surface facilities analysis and risk calculations results in an
execution model that can guide reservoir management decisions.
Summer 1996
The function of reservoir simulation is to
help engineers understand the productionpressure behavior of a reservoir and consequently predict production rates as a function of time. The future production
schedule, when expressed in terms of revenues and compared with costs and investments, helps managers determine both economically recoverable reserves and the limit
of profitable production.
Once the goal of simulation is determined,
the next step is to describe the reservoir in
terms of the volume of oil or gas in place,
the amount that is recoverable and the rate
at which it will be recovered. To estimate
recoverable reserves, a model of the reservoir framework, including faults and layers
and their associated properties, must be
constructed. This so-called static model is
created through the combined efforts of
geologists, geophysicists, petrophysicists and
reservoir engineers (left ). Much of the multibillion-dollar business of oilfield services is
centered on obtaining information that
17
eventually feeds reservoir simulators, leading to better reservoir development and
management decisions.5
The simulator itself computes fluid flow
throughout the reservoir. The principles
underlying simulation are simple. First, the
fundamental fluid-flow equations are
expressed in partial differential form for
each fluid phase present. These partial differential equations are obtained from the
conventional equations describing reservoir
fluid behavior, such as the continuity equation, the equation of flow and the equation
of state. The continuity equation expresses
the conservation of mass. For most reservoirs, the equation of flow is Darcy’s law.
For high rates of flow, such as in gas reservoirs, Darcy’s law equations are modified to
include turbulence terms. The equation of
state describes the pressure-volume or pressure-density relationship of the various fluids present. For each phase, the three equations are then combined into a single partial
differential equation. Next, these partial differential equations are written in finite-difference form, in which the reservoir volume
is treated as a numbered collection of
blocks and the reservoir production period
is divided into a number of time steps.
Mathematically speaking, the problem is
discretized in both space and time.
Examples of simulators that solve this
problem under a variety of conditions are
found in the ECLIPSE family of simulators.
These simulators fall into two main categories. In the first category are three-phase
black-oil simulators, for reservoirs comprising water, gas and oil. The gas may move
into or out of solution with the oil. The second category contains compositional and
thermal simulators, for reservoirs requiring
more detailed description of fluid composition. A compositional description could
encompass the amounts and properties of
hexanes, pentanes, butanes, benzenes,
asphaltenes and other hydrocarbon components, and might be used when the fluid
composition changes during the life of the
reservoir. A thermal simulator would be
advised if changes in temperature—either
with location or with time—modified the
fluid composition of the reservoir. Such a
description could come into play in the case
of steam injection, or water injection into a
deep, hot reservoir.
18
Block-Centered Geometry
0
2000
4000
6000
8000
4000
6000
8000
5800
6200
6600
7000
7400
Corner-Point Geometry
0
2000
5800
6200
■ Block-centered
and corner-point
geometries. Blockcentered geometry
features flattopped rectangular
blocks that match
the mathematical
models behind the
simulator. Cornerpoint geometry
modifies the rectilinear grid so that
it conforms to
important reservoir
boundaries. Threedimensional grids
are constructed
from a 2D grid by
laying it on the top
surface of the
reservoir and projecting the grid
vertically or along
fault planes onto
lower layers.
6600
7000
7400
Local Grid Refinement
■ Local grid refinement (LGR). Local
grid refinement
allows engineers to
describe selected
regions of the reservoir in extra detail.
Radial refined grids
are often used
around wellbores to
examine coning or
other phenomena
resulting from rapid
variation in properties away from the
well. Refined grids
are also one way to
treat property variations near faults.
Oilfield Review
These and all other commercial reservoir
simulators envision a reservoir divided into
a number of individual blocks, called grid
blocks. Each block corresponds to a volume
in the reservoir, and must contain rock and
fluid properties representative of the reservoir at that location. The simulator models
the flow of mobile fluid through the walls of
the blocks by solving the fluid-flow equations at each block face. Parameters
required for the solution include permeability, layer thickness, porosity, fluid content,
elevation and pressure. The fluids are
assigned a viscosity, compressibility, solution gas/oil ratio and density. The rock is
assigned a value for compressibility, capillary pressure and a relative permeability
relationship.
Creating the grid and assigning properties
to each grid block are time-consuming tasks.
The framework of the reservoir, including its
structure and depth, its layer boundaries and
fault positions and throws, is obtained from
seismic and well log data. The well-bred grid
respects the framework geometry as much as
possible. Traditionally, reservoir simulation
grid blocks are rectilinear with flat, horizontal tops in an arrangement called block-centered geometry (previous page, top). This
configuration ensures that the grids remain
orthogonal and exactly match the mathematical models used in the simulators.
However, this approach does not easily
represent structural and stratigraphic complexities such as nonvertical faults, pinchouts or erosional surfaces using purely
rectangular blocks. The 1983 introduction
of corner-point geometry in the ECLIPSE
simulator overcame these problems. In a
corner-point grid, the corners need not be
orthogonal. In modeling a faulted reservoir,
for example, engineers have the flexibility to
choose between an orthogonal areal grid
with the fault positions projected onto the
grid or a flexible grid to exactly honor the
positions of important faults. Three-dimensional (3D) grids are constructed from an
areal, or 2D, grid by laying it on the top surface of the reservoir and projecting it vertically or along fault planes onto lower layers.
Engineers’ requirements for more detail in
the model, particularly to examine coning
and near-wellbore effects, has led to the
concept of local grid refinement (LGR) (previous page, bottom ). This allows parts of the
model to be represented by a large number
of small grid blocks or by implanting radial
Summer 1996
grids around wells in a larger Cartesian
grid. 6 Locally refined grids also capture
extra detail in other areas where reservoir
properties vary rapidly with distance, such
as near faults. And LGR, combined with grid
coarsening outside the region of interest,
allows engineers to retain fine-scale property variation without surpassing computer
space limitations. The interactive GRID program was designed to help construct the
complex reservoir grid efficiently (see
“Developments in Gridding,” page 21 ).
Once the grid has been constructed, the
next step is to assign rock and fluid properties from the reservoir framework model to
each grid block. Populating the grid with
properties is another time-consuming and
difficult task. Each grid block, typically a
few hundred square meters areally by tens
of meters thick, has to be assigned a single
value for each of the reservoir properties,
including fluid viscosity, relative permeability, saturation, pressure, permeability, porosity and net-to-gross ratio. 7 Log measurements made in wells yield high-density
data, typically every 6 in. [15 cm], but provide little information between wells. Data
from cores may provide high-density
“ground truth,” but these represent perhaps
one part in 5 billion of the volume of the
reservoir. Surface seismic reflections cover
the reservoir volume and more, but do not
translate directly into the desired rock and
fluid properties. How are these disparate
data sets merged?
Two processes are required: extrapolating
the well data into the interwell reservoir volume, then upscaling the fine-scale data to
the scale of a simulation grid block. Traditionally log or core data were upscaled, or
averaged, over lithological units at the wells.
Then these data were interpolated and
extrapolated through the reservoir and maps
produced for each layer—formerly a handdrafting exercise by geologists. The maps
would be passed to the reservoir engineer
who would then generate grids, run preliminary simulations on a series of grid sizes,
and attempt further upscaling based on the
reservoir flow characteristics.
In recent years, the process has been
reversed. The current trend is to use computer programs to build 3D geological models bounded by seismic data, and to populate the models using geostatistical or
deterministic methods to distribute log and
core data.8
Scaling core and log properties up to gridblock scales is still a challenging task. Some
properties, such as porosity, are considered
simple to upscale, following an arithmetic
averaging law. Others, such as permeability,
are more difficult to average. And relative
permeabilities—different permeabilities for
different fluid phases—remain the most difficult problem in upscaling. There is no universally accepted method for upscaling, and
it is an area of active research.9
After the model has been finalized, the
simulator requires boundary conditions to
establish the initial conditions for fluid
behavior at the beginning of the simulation.
Then, for a given time later, known as the
time step, the simulator calculates new pressures and saturation distributions that indicate the flow rates for each of the mobile
phases. This process is repeated for a number of time steps, and in this manner both
flow rates and pressure histories are calculated for each point—especially the points
corresponding to wells—in the system.
But even with the best possible model,
uncertainty remains. One of the biggest jobs
5. For specific examples: Bunn G, Cao Minh C, Roestenburg J and Wittman M: “Indonesia’s Jene Field: A
Reservoir Simulation Case Study,” Oilfield Review 1,
no. 2 (July 1989): 4-14.
Briggs P, Corrigan T, Fetkovich M, Gouilloud M, Lo
Tien-when, Paulsson B, Saleri N, Warrender J and
Weber K: “Trends in Reservoir Management,”Oilfield
Review 4, no. 1 (January 1992): 8-24.
Corbett P, Corvi P, Ehlig-Economides C, Guérillot D,
Haldorsen H, Heffer K, Hewitt T, King P, Le Nir I,
Lewis J, Montadert L, Pickup G, Ravenne C, Ringrose
P, Ronen S, Schultz P, Tyson S and Verly G: “Reservoir
Characterization Using Expert Knowledge, Data and
Statistics,”Oilfield Review 4, no. 1 (January 1992):
25-39.
Al-Rabah AK, Bansal PP, Breitenback EA, Hallenbeck
LD, Meehan DN, Saleri NG and Wittman M: “Exploring the Role of Reservoir Simulation,” Oilfield Review
2, no. 2 (April 1990): 18-30.
6. For more on local grid refinement: Heinemann ZE
and von Hantelmann G: “Using Local Grid Refinement in a Multiple-Application Reservoir Simulator,”
paper SPE 12255, presented at the Reservoir Simulation Symposium, San Francisco, California, USA,
November 15-18, 1983.
Forsyth PA and Sammon PH: “Local Mesh Refinement
and Modelling for Faults and Pinchouts,” paper SPE
13524, presented at the Reservoir Simulation Symposium, Dallas, Texas, USA, February 10-13, 1985.
7. Net-to-gross ratio, sometimes called just net to gross
(NTG), is the ratio of the thickness of pay to the total
thickness of the reservoir interval.
8. For examples of the technique: Schultz PS, Ronen S,
Hattori M, Mantran P and Corbett C: “Seismic-Guided
Estimation of Log Properties,” The Leading Edge 13,
no. 7 (July 1994): 770-776.
Caamano E, Corbett C, Dickerman K, Douglas D, Gir
R, Martono D, Mathieu G, Nicholson B, Novias K,
Padmono J, Schultz P, Suroso S, Thornton M and Yan
Z: “Integrated Reservoir Interpretation,” Oilfield
Review 6, no. 3 (July 1994): 50-64.
9. Thibeau S, Barker JW and Souillard P: “Dynamical
Upscaling Techniques Applied to Compositional
Flows,” paper SPE 29128, presented at the 13th SPE
Symposium on Reservoir Simulation, San Antonio,
Texas, USA, February 12-15, 1995.
19
Preproduction Planning
8674.00
■ Visualizing the reservoir model in 3D. Visualization is a reliable means of checking
reservoir models before input to a simulator. Inconsistencies in model parameters
may be flagged and corrected. After simulation, results may also be viewed, allowing
faster evaluation of comparative simulation runs and providing insight into recovery
behavior. In this example reservoir pressure is color-coded to show regions of high
and low pressure.
of a simulator is to evaluate the implications
of uncertainty in the static reservoir model.
Sometimes uncertainty or error is introduced through low data quality. Another
source of error arises because laboratory,
logging and geophysical experiments may
not directly measure the property of interest,
or at the right scale, and so some other
property is measured and transformed in
some way that adds uncertainty. There is
also uncertainty in how a property varies
between measurement points. Many reservoir descriptions rely on core sample measurements for rock and fluid property information. This information is uncertainly
extended through the reservoir volume, usually in some geostatistical or deterministic
fashion, guided by seismically derived surfaces or other geological constraints.
One way to reduce uncertainty is to spot
inconsistencies in the properties of the reservoir model before simulation. Three-dimensional visualization software, such as the
RTView application, helps engineers be
more efficient in finding inconsistencies by
allowing them to view the reservoir model in
3D. Results of simulation runs may also be
viewed, allowing faster evaluation of simulation runs and providing immediate insight
into recovery behavior and physical processes occurring in the reservoir (above ).
20
A simulation run itself can also help
reduce uncertainty. Outside the oil industry,
simulators are used to determine the reaction of a known environment to externally
applied perturbations. An example is a flight
simulator that tests varying visibility conditions. Although a reservoir environment is
largely unknown, simulators can help
improve the description. In a process known
as history matching, reservoir production is
simulated based on the existing, though
uncertain, reservoir description. That
description is adjusted iteratively until the
simulator is able to reproduce the observed
pressures and multiphase flow resulting
from applied perturbations—that is, the
known production and injection. If the production history can be matched, the engineer has greater confidence that the reservoir description will be a useful, predictive
tool. The history-matching process is timeconsuming and requires considerable skill
and insight, but is a necessary prerequisite
to the successful prediction of continued
reservoir performance.
These new techniques and programs for
loading data, computing simulations and
viewing results are allowing engineers to use
simulators to guide reservoir management
decisions throughout the life of many fields.
The following case studies highlight some of
the uses of simulators in four different stages
of reservoir maturity.
Forties e
pipelin
Forties
Everest
Lomond
Aberdeen
Erskine
elin
e
Pressure, psi
pip
6250.13
An example of early use of simulation
comes from the Texaco Erskine Project in
the North Sea Central Graben region
(below ). The Erskine field comprises four
high-pressure, high-temperature (HPHT)
condensate reservoirs, and will be the first
HPHT field in the North Sea to come on
line when production commences in 1997.
Production will be from an unmanned
platform, with a multiphase pipeline to the
Amoco Lomond Platform for separation.
Gas will be exported via the Central Area
Transmission System (CATS) pipeline, and
liquids via the Forties pipeline. Initial production with be from three wells, with three
more to be added. The production mechanism will be natural depletion, with no gas
recycling. Other operators in the region who
have similar reservoirs to develop are
watching how Texaco handles the hostile,
overpressured field.
Simulation was selected as a way to
predict production of gas for drawing up
deliverability contracts—contracts promising delivery of designated volumes of gas at
a specified time. The main challenge in simulating these reservoirs is accounting for
both the permeability reduction due to rock
compaction and the productivity loss due to
condensate banking—explained below—in
the near-wellbore region of the formation
when the reservoir pressure falls below the
dewpoint pressure.10
CA
TS
RTView 96A
N
UK
■ Texaco Erskine Project in the North Sea
Central Graben region. The high-temperature, high-pressure condensate field is
due to go on production in 1997.
Oilfield Review
Because of overpressure conditions in the
reservoir, the rock is expected to compact
with depressurization. This means the rock
is expected to decrease its porosity and
effective permeability as production progresses. To quantify these effects, laboratory
experiments were conducted on rock samples. The experiments showed that at the
assumed well abandonment pressure of
4000 psi, permeability would be reduced by
about 33% from the initial value, while
porosity would be negligibly reduced.
Modeling flow in condensate reservoirs
requires additional considerations. As pressure drops around the well, condensation,
or dropout, occurs and liquid forms. The liquid saturation increases—in what is called
condensate banking—until it is great
enough to overcome capillary trapping
forces and the liquid becomes mobile. But
until the liquid becomes mobile, the presence of immobile liquid reduces the relative
permeability to gas, resulting in a loss in
productivity. The rapid change in fluid saturation away from the well requires a fine
grid to accurately model reservoir properties. The ECLIPSE compositional simulator
modeled the regions around the wells with
a refined radial grid, and the remainder with
a Cartesian grid.
In addition, condensate yields vary
between the four different reservoirs, so
each reservoir fluid was represented by its
own equation of state. The local grid refinement and multiple equation of state capabilities were added to the ECLIPSE simulator
for this project, and now form part of the
commercial package.
The simulation was used to conduct
uncertainty analysis for risk management.
To maximize revenues, the tactic is to maximize gas rates without being penalized for
coming up short. To understand the risks
behind promising a given gas rate, it is
desirable to understand the sensitivity of the
simulation results to each important input
parameter. In this case, repeated simulations indicated that the parameters with the
Developments in Gridding
Since the first grids were built, the variety, range
Perpendicular Bisector (PEBI) Grid
and resolution of oilfield measurements have
increased, and computer power and efficiency
have grown. To take advantage of these developments, reservoir engineers require better and
more comprehensive simulation software tools.
Modern 3D seismic acquisition, processing and
interpretation techniques have resulted in more
reliable and higher-resolution definition of faults
and erosional surfaces. The engineer wants to
represent the full complexity of nonvertical faults,
curving or listric faults, and faults that intersect or
truncate against one another. Another development that requires more complex models is the
increasing use of high-angle and horizontal wells
and multilateral wells. These requirements
stretch the traditional gridding programs based on
corner-point geometry—such as the GeoQuest
GRID program—to the limit.
This has led to the development of new gridding
41
Water saturation % 100
■ A perpendicular bisector (PEBI) grid showing local
grid refinement around wells. Grid blocks may have
a variety of shapes and can fit any reservoir geometry. The smoother grid-block shape also gives a
more accurate simulation solution because there is
less chance of choosing the wrong grid orientation.
software techniques such as the FloGrid utility,
which will produce grids that conform to the reser-
voir models than exist in analytical models.
voir framework as defined by fault surfaces and
Unstructured PEBI grids are of great benefit in
lithological boundaries. Unstructured perpendicu-
these situations, allowing the radial components of
lar bisector (PEBI) and tetrahedral grid systems
flow into the wellbore to be combined with linear
are being developed and included in gridding and
or planar features such as the trajectory of a hori-
simulation programs (above right). “Blocks” in a
zontal well or a fault plane. Simulations run with
PEBI grid may have a variety of shapes, and they
PEBI grids tend to take longer than those run on
may be arranged to fit any reservoir geometry.
structured grids, but the ability to capture the
The smoother gridblock shape gives a more accu-
structural complexity of the reservoir’s flow units
rate simulation solution because there is less
outweighs the need for speed. A compromise can
chance of choosing the wrong grid orientation—
be reached by building a structured grid in the geo-
a potential problem with traditional grids. A PEBI
logically simple parts of the reservoir, and splicing
grid also allows flow in more directions from a
in an unstructured grid when geologic complexity
given grid block, important in the modeling of hor-
requires more flexibly shaped grid blocks.
izontal wells, gas injection schemes or the interaction of wells in an interference test. These grids
are also being used as a basis for a new genera-
10. Crick M: “Compositional Simulation for HPHT Gas
Condensate Reservoirs: Follow-up,” presented at the
Second ECLIPSE International Forum, Houston,
Texas, USA, April 15-19, 1996.
Hsu HH, Ponting DK and Wood L: “Field-Wide
Compositional Simulation for HPHT Gas Condensate Reservoirs Using an Adaptive Implicit Method,”
paper SPE 29948, presented at the International
Meeting on Petroleum Engineering, Beijing, China,
November 14-17, 1995.
Summer 1996
tion of upscaling techniques.
A further gridding development is the linking of
well test analysis with simulator programs to give
the engineer a greater range of numerical reser-
21
Percentage Changes in Reserves
-20
-15
-10
-5
0
5
10
15
20
Gas in place
Permeability
Pentland
continuity
Compaction
Critical
condensate
saturation
Trapped gas
saturation
Well skin
factor
Fault
transmissibility
■ Sensitivity of Erskine simulation results to input parameters. Repeated
simulations indicate parameters that have the most influence on simulation results. Quantifying the uncertainty in the most sensitive parameters
is an important step toward quantifying project risk. Additional simulations were run with the high, low and middle values of each parameter,
forming input sensitivities for the risk analysis shown below.
most influence on the results included gas
in place, permeability and compaction
(left ).
Deliverability and cumulative production
distributions were calculated from the sensitivity results using the parametric method
developed for oilfield applications by P.J.
Smith and coworkers at British Petroleum.11
A normalized average profile was combined
with these distributions in a Monte Carlo
simulator to give a probabalistic production
profile (below ).
The results of the risk analysis showed the
effects of different production scenarios on
the level of confidence in ability to deliver
various possible contracted rates of gas over
the initial plateau period. ( next page,
bottom ). The required 90% confidence
level for a three-year plateau period was
achieved by modifying the production rate
in the first year, adding a contingency well
in the third year, and commingling production in one well between the main Erskine
reservoir and the smaller but higher-permeability Kimmeridge reservoir.
As a result, Texaco has modified production plans, which now call for a lower production rate in the first year than in subse-
Initial
Deliverability Distribution
Parametric
Method
Probabilistic Production Profile
Normalized Average Profile
Sensitivities
Deliverability
Deliverability
Predicted
production
Monte Carlo
Analysis
Cumulative Production
Reserves Distribution
Parametric
Method
■Schematic of deliverability and cumulative production computed for best- and worst-case scenarios. The sensitivity profiles (left)
represent curves for best and worst cases, such as the lowest and highest permeability, lowest and highest compaction and all other
parameters mentioned above. Not all curves were plotted because of space constraints. All the sensitivities were combined through
a parametric method modified for oilfield application. (From Smith et al, reference 11.) A normalized average profile (center) was
combined with initial deliverability and reserves distributions in a Monte Carlo method to give a probabilistic—90% confidence—production profile (right). The upper curve is the deliverability and the lower curve is predicted production. The cyclic nature of the production curve reflects the alternation between summer and winter demand for gas.
22
Oilfield Review
quent years. Risk analysis suggested an
additional well in the third year, so platform
construction has allowed a slot for a contingency well. In addition, production from the
Erskine and Kimmeridge reservoirs will also
be commingled.
Bravo
Alpha
Charlie
Echo
Infill Drilling
Delta
Forties field
Claymore
■ The Forties field in
the North Sea, operated by BP with five
platforms and 103
wells.
Brae
Piper
Beatrice Britannia
Buchan
Forties
Lomond
Montrose
Aberdeen
Erskine
Fulmar
N
UK
600
Production, 103 B/D
Infill drilling is an expensive stage in the life
of a reservoir. Simulation, in conjunction
with other tools, can help guide the placement of wells and minimize their number.
British Petroleum has harnessed simulation
along with new reservoir description to optimize infill drilling in the Forties field in the
North Sea (right ).
The Forties field was discovered in 1970,
and produced its first oil in 1975 (middle ).
Current production is from five platforms,
with 78 producers and 25 peripheral injectors. Estimated recovery of the 4.2 billion
stock tank barrels (STB) of original oil in
place (OOIP) is 60%, or 90% of the movable oil.
The field is characterized by high permeability, high net-to-gross (NTG) pay thickness and a strong aquifer. A few years ago
the Forties was considered to be essentially
a homogeneous reservoir. But early water
breakthrough and water fingering indicated
a greater level of heterogeneity than
expected, and suggested the need for more
wells to be drilled to reach bypassed zones.
To understand the potential of infill drilling
in the field, a simulation study was conducted, including careful reinterpretation of
existing 3D seismic data and a new reser-
500
Current
production
400
300
200
Oil production
Water production
100
11. Smith PJ, Hendry DJ and Crowther AR: “The Quantification and Management of Uncertainty in
Reserves,” paper SPE 26056, presented at the SPE
Western Regional Meeting, Anchorage, Alaska,
USA, May 26-28, 1993.
0
1975
1980
1985
1990
Number
of wells
Commingling
2000
2004
■ Production in the Forties field since 1975.
Confidence levels, %
Yearly rate,
MMscf/D
1995
Year
Tubing
size, in.
Year
Normalized reserves
Confidence level, %
1
2
3
4
90
50
10
90/90/90
3
None
4.5
75
75
75
40
0.707
0.898
1.139
80/90/90
3
None
4.5
85
75
75
40
0.699
0.889
1.119
90/90/90
3
Erskine and
Kimmeridge in E1
4.5
85
85
75
45
0.738
0.937
1.176
80/90/90
3
Erskine and
Kimmeridge in E1
4.5
90
90
80
55
0.738
0.932
1.170
90/90/90
3
Erskine and
Pentland in E1
4.5
70
70
65
30
0.682
0.858
1.082
90/90/90
4
None
4.5
95
95
65
30
0.704
0.892
1.119
90/90/90
3
None
5.5
95
95
70
30
0.685
0.863
1.091
80/90/90
Extra well
in year 3
3
Erskine and
Kimmeridge in E1
4.5
90
90
95
85
0.789
1.000
1.264
Summer 1996
■ Results of risk
analysis ranking
some of the simulated production
scenarios. The
required 90%
confidence level
(bottom line) was
achieved by reducing the production
rate in the first year,
adding a well in
the third year and
commingling production from the
Kimmeridge and
Erskine reservoirs.
23
voir characterization to describe the heterogeneities encountered in the turbidite sandstone reservoir.
Simulation with a coarse full-field model
allowed identification of regions that might
benefit from infill wells, but the results were
not refined enough for detailed well placement. Once a region was identified as containing possible infill well locations, other
aspects were considered, such as: water cut
and production of surrounding wells; interference tests confirming continuity or lack
thereof with other layers; and reinterpretation of 3D seismic data for channel identification—prospective locations tend to be
along submarine channel margins, where
there is lower vertical permeability and so
less efficient sweep.
Having passed these tests, the area was
tapped for a new simulation study with local
grid refinement spotlighting the volume of
interest (below right ). The refined grid block
size was about 50 by 50 m [164 ft by 164 ft]
in area by 8 m [26 ft] in depth. Reservoir
properties were distributed in the LGR grid
based on a geostatistical model. Then the
flow in the LGR grid was simulated with the
ECLIPSE black-oil simulator and checked
against the production history from wells in
the grid. The property distribution was
modified and simulation rerun. This process
was repeated until a history match was
obtained, with only six iterations required.
The final simulation based on the refined
grid predicted a fluid distribution at the Forties Alpha 31 sidetrack (FA31ST) location
(above right ). The predicted fluid distribution closely resembled that encountered and
the predicted oil production matched the
current rate. However, the predicted net-togross rock volume of the upper zone was
optimistic relative to measured values.
Lessons learned from this work have been
fed back into subsequent studies with, for
example, seismic attributes helping to characterize the NTG variation in the reservoir.
Simulation played a similar role in assessing
the potential for infill drilling around the
other platforms.
Prediction
Actual
FA31ST
Shale
Water
FA31ST
Oil
■ Fluid and formation distributions predicted (left) and encountered (right) at the Forties
Alpha 31 sidetrack (FA31ST) location. The predicted distribution closely resembled the
layering encountered, and predicted oil production matched the current rate.
300-m Grid
50-m Grid
■ Steps in the simulation study of the
Forties Alpha platform area. Simulation with a coarse
full-field model
(top) identified
regions that would
benefit from infill
wells. Once a
region was identified as a possible
infill well location,
the location was
selected for a new
simulation study
with local grid
refinement (middle)
spotlighting the
volume of interest.
Reservoir properties were distributed in the LGR
grid based on a
geostatistical
model (bottom) of
the turbidite sandstones.
Geostatistical
Model
24
Oilfield Review
Weyburn Unit
Planning Enhanced Oil Recovery
In an example of simulation later in reservoir life, PanCanadian Petroleum Limited is
relying on simulation to examine the feasibility of CO2 injection in Unit 1 in the Weyburn field of Saskatchewan, Canada
(right ).12 This field was discovered in 1955
and put on waterflood in 1964. By 1994,
recovery had reached 314 million STB, or
28% of the unit’s original oil in place. Ultimate waterflood recovery is expected to be
348 million STB, or 31%, leaving a large
target for enhanced recovery methods. An
opportunity to take advantage of one
method, gravity segregation via CO2 injection, is presented by the division of the
reservoir into swept and unswept layers.
Carbon dioxide injected into the lower,
more permeable formation has the potential
to contact large amounts of unswept oil in
the tight upper formation since CO2 is 30%
less dense than the reservoir fluids at the
expected operating pressures (below right ).
Evaluating the feasibility of CO2 injection
proceeded in stages. First, using the GeoQuest fluid PVT simulation software, a ninecomponent equation of state was developed
that reproduced the behavior of the oil-CO2
system. The equation of state also had to
predict the development of dynamic miscibility in flow simulations while still representing the physical properties of the oilCO2 mixtures. The equation was validated
by comparison of simulated and laboratory
floods on cores.
Second, general performance parameters
were established for the formations to be
swept. These included CO 2 slug size, a
water-alternating-gas injection strategy, CO2
start-up pressure and post-CO2 blow-down
pressure. 13 Then various orientations of
injectors, producers and horizontal wells
were tested with the ECLIPSE compositional
R.13
R.12W2
T.7
T.6
T.5
Saskatchewan
Saskatoon
Yorkton
Swift
Current
Regina
Moose Jaw
Canada
United Sta
tes
■ Weyburn field of southeastern Saskatchewan, Canada. Discovered in 1955, the Weyburn field has produced 314 million STB, or
28% of the unit’s original oil in place.
Producer
CO2 Injection
Density Porosity
Gamma Ray
0
API
Neutron Porosity
150 45
Marly
%
-15
Unswept Zone
Vuggy
5m
12. Burkett D, Besserer G and Gurpinar O: “Design of
Weyburn CO2 Injection Project,” presented at the
Second ECLIPSE International Forum, Houston,
Texas, USA, April 15-19, 1996.
13. Blow-down pressure is the average field pressure
maintained after CO2 injection is stopped. Usually
this is lower than during CO2 injection to maximize
oil recovery due to expansion of CO2.
R.14
Swept
Zone
■ Division of the reservoir into swept and unswept layers, opening
the opportunity for gravity segregation of injected CO2. Carbon
dioxide (blue arrows) injected into the lower, more permeable formation will rise to displace the oil (green arrows) remaining in the
tight, unswept upper formation.
Summer 1996
25
■ Reservoir link with surface facility. Integrating surface network simulators with reservoir simulators will allow production managers
to optimize flow and fine-tune field planning.
Weyburn Unit
km
ax
60-acre
vertical infill
Original
80-acre infill
40-acre
vertical infill
in
km
Horizontal
sidetrack
26
■ A Weyburn
inverted nine-spot
pattern showing
vertical and
horizontal infill
well locations
and directions of
maximum and
minimum permeabilities (kmax ,
kmin ). Various
orientations of
injectors, producers and horizontal
wells were tested
with the ECLIPSE
compositional
simulator to
determine optimal
orientations and
spacings.
simulator (left ).14 Each original nine-spot
pattern was found to require two symmetrically positioned horizontal wells in the
upper zone to take advantage of the CO2
segregation process. Results of the parametric pattern studies, using a 30% pore volume CO2 slug, indicated ultimate recovery
without any new horizontal wells to be an
estimated 37% of OOIP. By adding two
horizontal wells in each injection pattern,
simulation predicted incremental recovery
of 7.2%.
On the Surface
Once hydrocarbons have made it up the
wellbore, most reservoir engineers consider
their job done. But tracking fluid movement
through a complex surface network with
chokes, valves, pumps, pipelines, separators
and compressors remains a daunting task.
Optimizing flow through the surface network allows production managers to minimize capital investment in surface facilities
and fine-tune field planning.
Reservoir simulators are not designed to
solve for fluid flow all the way through the
surface-gathering facility, but they can be
integrated with network simulators built for
this purpose. An example of such a network
simulator is the Simulation Sciences
PIPEPHASE system. The PIPEPHASE simula-
Oilfield Review
Summer 1996
Simulation Speedup with Parallel Processors
2500
2000
Run time, sec
tor, based on a pressure-balance technique
developed originally at Chevron in the
1980s, has been adapted to handle large,
field-wide, multiphase flow networks,
including wells, flowlines and associated
surface facilities. Through a joint project
between GeoQuest Reservoir Technologies
and Simulation Sciences, the PIPEPHASE
simulator and the NETOPT production optimizer are being integrated with the OpenECLIPSE system to provide a way to simulate
fluid flow seamlessly from reservoir through
surface network (previous page, top).15 Integration is achieved through an iterative algorithm that minimizes the differences
between the well flow rates calculated by
the two simulators from a given set of flowing well pressures.
The recent focus on integrated reservoir
management teams is a major step in the
direction of integrated reservoir and surface
network simulation. But the emphasis has
been on integration at the upstream end.
The next step is to focus at the production
and surface facilities end.
Traditionally, the integrated study has been
approached along two independent paths.
For a project involving pressure maintenance through water injection, for example,
the impact on the reservoir has been studied
in isolation. The reservoir simulation is carried out with a simplified well model:
hydraulic behavior of injection or production wells is approximated through flow
tables derived from single-well analysis. A
second study is typically performed by the
facilities engineering group to evaluate the
impact of the injection water requirements
on the surface facilities. The reservoir
behavior at the well is incorporated through
an injectivity index relating injection rate to
pressure drop at the formation.
A limitation of this divided approach is
that it ignores the true interaction between
the elements of the surface network, the
production and injection wells, and the
reservoir. The results of a truly integrated
study could be quite different.
The iterative approach to integrating the
PIPEPHASE and ECLIPSE systems, while rigorous, may be limited by convergence
issues in more complex applications. The
truly integrated solution, with the surface
and reservoir equations solved simultaneously, is expected to require a large effort,
since significant restructuring will be
needed in both simulators. One promising
approach is to initially develop a simple single-phase application for a gas field. The
experiences developed in this effort could
then be extended to address the larger problem of multiphase fluids.
1500
1000
500
0
1
2
4
8
16
Number of processors
■ Speeding up simulation with
parallel processors. For a typical
simulation, the 16-processor run
is more than 10 times faster than
a single-processor run.
The Next Step
The future of reservoir simulators may parallel developments in other oilfield technologies that provide a view of fluid and rock
behavior in the subsurface. For example, the
seismic industry, operating on a similar
physical scale and on equally staggering
amounts of data, has turned to massively
parallel processors (MPPs) for data processing and to high-performance graphics workstations for visualization of the results.
Simulation computer codes are being prepared for implementation on MPPs, but the
switch cannot be made quickly. A simulator
typically solves the fluid-flow equations one
grid block at a time. The solution does not
necessarily benefit by processing several
steps in parallel.
For a typical simulation, doubling the
number of processors cuts simulation time
almost in half, and increasing to 16 processors reduces the time to one-tenth (above ).
Departure from ideal speed gains—16 times
faster for 16 processors—is due to three factors. First, the parallel linear equation solution method is less efficient than the nonparallel solution. Second, it takes time to
assemble and transfer data between processes. And third, load balancing between
processors is uneven: some parts of the
reservoir are easier to solve than others, but
the simulation must wait for the slowest.
Also, the high cost of MPPs targets them for
sharing within departments or companies,
so one user is less likely to get sole access.
Early tests on parallelized versions of the
ECLIPSE simulator indicate that gains in
speed depend on the complexity of the
reservoir model. A North Sea case with two-
phase flow of oil and water in a relatively
simple reservoir with 50,000 grid blocks
exhibited a four-fold speed up using eight
processors, and even greater gains for bigger
models. But three-phase flow simulation in
a 1.2-million block model filled randomly
with geostatistically derived data with highly
variable permeability showed less dramatic
improvement.
One application of simulators that will
undoubtedly benefit from implementation
on MPPs is that of testing multiple scenarios. Simulation results are most valuable in a
comparative sense. Comparisons can be
made of the production behavior of different
reservoir models to gain understanding of
sensitivity to input parameters. Or different
production scenarios may be tested on a
single reservoir model. Running such simulations simultaneously will save time and
allow comparisons to be made efficiently.
In the family of tools designed to help oil
companies make effective use of expensive,
hard-won data, simulation plays a key role
in making sense of data acquired through
different physical experiments, at different
times, at different spatial scales. Simulation
is one of the few tools available for understanding the changes a reservoir experiences
throughout its life. Used together with other
measurements, simulation reinforces conclusions based on other methods and leads
to a higher degree of confidence in our
understanding of the reservoir.
—LS
14. Mullane TJ, Churcher PL, Tottrup P and Edmunds
AC: “Actual Versus Predicted Horizontal Well
Performance, Weyburn Unit, S.E. Saskatchewan,”
Journal of Canadian Petroleum Technology 35, no. 3
(March 1996): 24-30.
15. Dutta-Roy K: “Surface Facility Link: Production Planning with Open-ECLIPSE and PIPEPHASE,” presented at the Second ECLIPSE International Forum,
Houston, Texas, USA, April 15-19, 1996.
27
The Many Facets of
Pulsed Neutron Cased-Hole Logging
■ The multipurpose
RST service. Carbon-oxygen ratio,
inelastic and
capture spectra,
sigma, borehole
holdup, porosity,
water and oil
velocities, and
borehole salinity
are some of the
measurements that
can be made with
RST equipment.
Ivanna Albertin
Harold Darling
Mehrzad Mahdavi
Ron Plasek
Sugar Land, Texas, USA
Italo Cedeño
City Investing Company Ltd.
Quito, Ecuador
Jim Hemingway
Peter Richter
Bakersfield, California, USA
Marvin Markley
Bogota, Colombia
Jean-Rémy Olesen
Beijing, China
Brad Roscoe
Ridgefield, Connecticut, USA
Wenchong Zeng
Shengli Petroleum Administration Bureau
China National Petroleum Corporation
China
For help in preparation of this article, thanks to Darrel
Cannon, Wireline &Testing, Sugar Land, Texas; Efrain
Cruz, GeoQuest, Quito, Ecuador; Steve Garcia,
GeoQuest, Bakersfield, California, USA; Michael Herron
and Susan Herron, Schlumberger-Doll Research, Ridgefield, Connecticut, USA; Chris Lenn and Colin Whittaker,
Schlumberger Cambridge Research, Cambridge, England; and Chris Ovens, GeoQuest, Aberdeen, Scotland.
In this article, CNL (Compensated Neutron Log), CPLT
(Combinable Production Logging Tool), ELAN (Elemental
Log Analysis), FloView, FloView Plus, FMI (Fullbore
Formation MicroImager), Phasor (Phasor Induction SFL),
RST (Reservoir Saturation Tool), SpectroLith, TDT
(Thermal Decay Time) and WFL (Water Flow Log) are
marks of Schlumberger.
1. For a detailed description of the RST tool hardware
and the latest scintillation detector technology:
Adolph B, Stoller C, Brady J, Flaum C, Melcher C,
Roscoe B, Vittachi A and Schnorr D: “Saturation
Monitoring With the RST Reservoir Saturation Tool,”
Oilfield Review 6, no. 1 (January 1994): 29-39.
Sigma is a measure of the decay rate of thermal neutrons as they are captured.
2. Holdup is a measure of the volumetric percentage of
each phase in the borehole. Water holdup plus oil
holdup plus gas holdup equals unity. Flow rate equals
holdup multiplied by area and by velocity.
28
Advanced neutron generator design and fast, efficient gamma ray
detectors combine to make a reservoir saturation tool that is capable
of detailed formation evaluation through casing and more. Lithology
determination, reservoir saturations and flow profiles are some of the
comprehensive answers provided by this multipurpose tool.
To manage existing fields as effectively and
efficiently as possible, reservoir engineers
monitor movement of formation fluids
within the reservoir as well as production
from individual wells. Pressure measurements play a vital role in reservoir management. However, these data need to be augmented by other measurements to detect
fluid movement within the producing well
and the surrounding formation. One
recently introduced cased-hole logging tool,
the RST Reservoir Saturation Tool, provides
abundant single-well data to help reservoir
engineers locate bypassed oil and detect
waterflood fronts, fine-tune formation evaluation and monitor production profiles.
A Multipurpose Service
The RST service was introduced in June,
1992 with a through-tubing pulsed neutron
tool capable of providing both carbon-oxygen ratio (C/O) and sigma reservoir saturation measurements.1 Interpretation of either
measurement, under suitable formation and
borehole conditions, provides quantitative
oil saturation. The high-yield neutron generator and high-efficiency dual-detector system provide higher gamma ray count rates,
and hence better statistics, than previous
generations of pulsed neutron devices. This
has led to the development of many other
applications, including spectroscopy mea-
Oilfield Review
Summer 1996
Inaccurate
Alpha processing
Windows
■Accuracy and
precision. Alpha
processing combines
the accuracy of the
elemental yields
computation of oil
volume (bottom left)
with the precision of
the windows
approach (top right).
The result is an oil
volume that is both
accurate and precise (top left).
Imprecise
Yields
0.5
0.4
Sw=0%, Yo=100%
0.3
0.2
Sw=0%, Yo=0%
Sw=100%, Yo=100%
0.1
x
Reservoir Saturation
Reservoir saturation is derived from C/O or
inferred from sigma measurements (see “Saturation Monitoring, South American Style,”
next page ). Inelastic gamma ray spectra are
used to determine the relative concentration
of carbon and oxygen in the formation. A
high C/O indicates oil-bearing formations; a
low ratio indicates water-bearing formations. Sigma is derived from the rate of capture of thermal neutrons—mainly by chlorine—and is measured using capture
gamma rays. Saline water has a high value
of sigma, and fresh water and hydrocarbon
have low values of sigma. As long as formation water salinity is high, constant and
known, water saturation Sw may then be
calculated.
Carbon-oxygen—Carbon-oxygen ratio is
measured in two ways. A ratio (C/Oyields ) is
obtained from full spectral analysis of carbon and oxygen elemental yields. A second
C/O (C/O windows) is obtained by placing
broad windows over the carbon and oxygen
spectral peak regions of the inelastic spectrum. The C/Oyields is the more accurate of
the two ratios, but lower count rates and,
therefore, poorer statistics make it less pre-
Accurate
Precise
Far carbon/oxygen ratio
surements, accurate time-lapse reservoir
monitoring and evaluation in difficult logging environments such as variable formation water resistivity and complex lithology.
Other features of the tool design allow
several auxiliary measurements such as
borehole salinity and thermal neutron
porosity. The tool comes in two
diameters—the 111/16-in. RST-A tool and
21/2-in. RST-B tool. Both use the same type
of neutron generator, detectors and electronics. However, the larger diameter RST-B tool
incorporates shielding to focus the near
detector towards the borehole and the far
detector towards the formation, allowing
logging in flowing and unknown borehole
fluids and also providing a borehole holdup
measurement.2 More recent applications for
the RST-A tool include WFL Water Flow Log
measurements and separate oil and water
phase velocities in horizontal wells—Phase
Velocity Log (PVL) measurements.
Essentially the RST service provides three
types of measurements:
• reservoir saturation from C/O or sigma
measurements
• lithology and elemental yields from
analysis of inelastic and capture gamma
ray spectra
• borehole fluid dynamics from holdup,
WFL and PVL measurements.
This article summarizes the many facets of
RST logging and reviews several examples.
0.0
xxx x
x
xxxxx
xxx
x xx x
xx
xx
Sw=100%, Yo=0%
-0.1
-0.1
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Near carbon/oxygen ratio
■ Water saturation, Sw, and borehole oil holdup, Yo, crossplot. Far carbon-oxygen ratio (FCOR) is more influenced by formation carbon, and
near carbon-oxygen ratio (NCOR) is more influenced by borehole carbon. A crossplot of FCOR versus NCOR (crosses) can, therefore, be used
to determine water saturation and borehole oil holdup. Overlying the
crossplot is a quadrilateral whose end points are determined from an
extensive data base that depends on environmental inputs such as
lithology, casing size and hydrocarbon carbon density. The corners
correspond to 0 and 100 % Sw and 0 and 100 % Yo. Interpolation provides Sw and Yo at each depth.
cise than the C/O windows . Conversely,
C/Owindows is often less accurate but has better statistics and so is more precise. Each
ratio is first transformed to give an oil volume, and then the two oil volumes are
combined using an alpha processing
method to give a final oil volume with good
accuracy and good precision ( top ). The
transforms of C/O ratio to volume of oil use
an extensive data base covering multiple
combinations of lithology, porosity, hole
size, casing size and weight, as well as a
correction for the carbon density of the
hydrocarbon phase.
Carbon-oxygen ratios are generated for
the near and far detectors. These two ratios
are used to give water saturation and borehole oil holdup (above ).
Sigma—Sigma is a measure of how fast
thermal neutrons are captured, a process
typically dominated by chlorine. Hence
formation sigma may be considered a mea-
29
Saturation Monitoring, South American Style
Fanny field, situated among the oil fields east of
Sw RST<<SwOH
Sw RST<<Sw OH
Water
Oil
Bound water
Sw from
Total
the RST
Porosity
100 p.u. 0
the Andes mountains, in the Oriente basin,
Ecuador, was discovered in 1972 and is presently
operated by City Investing Company Ltd. (below).
Caliper
Lith.
in. 16
inelastic 6
Sigma
RST
Near C/R
0
c.u. 30
Far C/R
Sand SP from OH
0 25
0
Near C/R 100
p.u.
p.u.
Clay 120 mV 30 -0.10 -0.15
GR
Lime
Far C/R
Fluid Analysis
10 API 110 0
0.25 50
p.u.
100
Differential compaction of sands and shale
probably created the structural high that forms
the field. Primary production is from the M-1
sandstones of the Upper Cretaceous Napo with
secondary production from the Lower U sandstones of the Lower Cretaceous Napo.
There are six wells in Fanny field and these are
Depth,
ft
0
Water
Oil
Bound water
Calcite
Coal
Silt
Quartz
Clay
Combined Model
p.u.
100
M-1 sand
coupled to three others from the adjoining 18B
field drilled by the national oil company of
Ecuador, PetroProduction. Total output is 4000
7700
BOPD of 22.2° API oil with a fluctuating water cut
of between 37% and 91%. Production is by
hydraulic pump.
Fanny-1 was completed as a commingled producer in 1978 and after 18 years it was still producing about 150 BOPD with 90% water cut from
two zones in the M-1 sand body. The high water
cut prompted City Investing to investigate.
A 111/16-in. RST-A tool was run with the well shut-
7750
in to record carbon-oxygen ratio, formation
sigma, borehole sigma, thermal neutron porosity
and borehole salinity measurements.
Tumaco
Esmeraldas
Balao
Fanny
Lower U sand
Quito
ECU AD O R
Tiputini
8400
Tigre
■ Fanny-1 RST log results. ELAN Elemental Log Analysis interpretation of Sw and lithology (track 3) shows the
original openhole water saturation. Since then the oil-water contact has risen to 7752 ft (track 2) shown by the
RST Sw of nearly 100% through the bottom section of the M-1 sand. The high carbon-oxygen ratio from 7702
to 7709 ft is a coal seam. Very little of M-1 above the oil-water contact is depleted and the Lower U sand also
shows high hydrocarbon saturation.
Formation sigma and thermal neutron porosity
■ Fanny field location.
South America
Tests on the interval 7710 to 7720 ft [2350 to
improved on the original formation evaluation by
2353 m] confirmed the RST results with a produc-
providing a better estimation of shale volume in
tion rate of 900 BOPD at only 10% water cut. The
the silty, sometimes radioactive, sandstones,
two new zones were also tested and they pro-
and also more accurate lithology identification.
duced 1300 BOPD at 4% water cut.
The final interpretation showed that high water
The old perforations were cement squeezed
production was caused by a rise in the oil-water
and the well, reperforated and recompleted, is
contact to 7752 ft [2363m] (above). It also
now producing 1000 BOPD with low water cut—
showed that other sections of the M-1 sand were
a sixfold production increase.
still at original water saturation and identified
30
two virgin oil zones.
Oilfield Review
sure of the chlorine content or salinity of
the formation, and tracks openhole resistivity curves.
The raw sigma measurement contains contributions from the borehole as well as the
formation. To isolate the formation sigma,
the neutron generator is pulsed in a dual
burst pattern: a short burst followed by a
long burst. Near-detector measurements are
strongly influenced by the borehole environment and hence borehole sigma— especially for the short neutron burst measurement. Far-detector measurements are
influenced more by formation sigma—especially the long neutron burst measurement.
Raw sigma measurements are also affected
by neutron diffusion and environmental
variables related to the borehole, casing,
cement and formation. At the heart of the
correction process for these effects is a data
base detailing thousands of combinations of
borehole sizes, casing types, formations of
differing porosity and lithology, and borehole and formation salinities. Instead of trying to define the response to these variables
by a single set of equations with fixed
parameters, a dynamic parameterization
algorithm uses the data base to compute the
corrected response in real-time, during
acquisition (see “The Sigma Data Base,”
next page ).3
Time-lapse—Once carbon-oxygen measurements or sigma measurements have
been interpreted to produce saturation logs,
these measurements may be repeated later to
monitor reservoir fluid movement such as
oil-water contacts, secondary recovery processes or hydrocarbon depletion ( right ).
Good precision is important for time-lapse
Gamma Ray
0
API
0
SP
-90
mV
120
Porosity from Core
SO from Core
300
p.u.
100
100
SW (11/7/93)
p.u.
0
-10
DCAL
in.
0
100
p.u.
0
Clay
Quartz
K-Feldspar
0
DIT-E SO (11/7/93)
p.u.
100
0
RST SO (11/27/93)
p.u.
100
0
RST SO (4/16/94)
p.u.
100
0
RST SO (1/30/96)
p.u.
100
Bound Water
Irreducible Water
Formation Water
Phasor Oil Volume
Steam/Air 1993
Depth,
ft
Steam/Air 1995
X100
(continued on page 34)
■ Time-lapse logging in California. This log
is from a well in the middle of a field that is
produced by heating the oil in place with
steam. Steam takes a narrow path from
one wellbore to another and will, therefore,
not flush out all the heavy oil. After some
time, the steam needs to be redirected to
produce bypassed oil. RST time-lapse data
are used to monitor steam location and
changes in oil saturation.
There has been little change in oil saturation of the upper intervals X100 to X190 ft
(track 2). The lower interval, X200 to X270
ft, shows some oil movement. Steam has
been turned off in the zone X195 to X205 ft
which has resaturated with water (track 3).
3. For more on the dynamic parameterization algorithm
approach:
Plasek RE, Adolph RA, Stoller C, Willis DJ and Bordon
EE: “Improved Pulsed Neutron Capture Logging With
Slim Carbon-Oxygen Tools: Methodology,” paper SPE
30598, presented at the 70th SPE Annual Technical
Conference and Exhibition, Dallas, Texas, USA, October 22-25, 1995.
Summer 1996
X200
X300
31
The Sigma Data Base
■The Schlumberger
Environmental Effects
Calibration Facility,
Houston, Texas, USA.
Over 4000 measurements were made in
more than thirty formations of differing lithology and porosity, with
different combinations
of formation salinities,
borehole salinities, and
completions to produce
the sigma data base.
Diffusion, borehole and lithology effects must be
■ EUROPA facility, Aberdeen, Scotland.
considered when transforming raw pulsed neu-
umes of the rocks, fluids and tanks used. CNL
tron capture measurements to actual physical
Compensated Neutron Log measurements veri-
quantities. These effects are difficult to account
fied the porosity values and the homogeneity of
for in direct analytical approaches across the
the formations.
entire range of oilfield conditions. Therefore, an
Matrix sigma values were determined by gross
extensive data base of laboratory measurements
macroscopic cross-section measurements pro-
is used to correct for these effects in real time.1
vided by commercial reactor facilities and by pro-
Over several years, the data base was acquired
cessing complete elemental analyses through
for the RST-A, RST-B and TDT-P logging tools at
Schlumberger Nuclear Parameter (SNUPAR)
the Schlumberger Environmental Effects Calibra-
cross-section tables.2
tion Facility (EECF), Houston, Texas (above and
Water salinity was determined by a calibrated
right). This enables raw tool measurements to be
titration procedure and then converted into fluid
referenced to calibrated values of formation
sigma again using SNUPAR cross-section tables.
sigma, borehole salinity and formation porosity
for a variety of environmental conditions. Each
Algorithm—RST Sigma Processing
tool was run in over 30 formations of different
eling was used to extend the range of available
A three-step sequence is performed to translate
lithologies and porosities. Formation and bore-
sandstone formations. To date, the data base con-
raw log measurements into borehole salinity,
hole fluid salinities were varied and different
tains over 4000 points.
completions were introduced into the borehole
The sigma values of the database formations
representing different casing sizes and cement
are calculated classically
thicknesses.
∑ = (1-Φ ) ∑ ma + Φ S fl∑ fl
where Φ is the formation porosity, ∑ ma is
matrix sigma, Sfl is the formation fluid saturation
and ∑ fl is fluid sigma.
Altogether more than 1000 formation-borehole
combinations were measured for each tool. Mod-
Porosity of the EECF tank formations was determined by carefully measuring all weights and vol-
32
porosity, corrected near and far sigma and formation sigma (next page, top).
The first step is to correct the near and far
detector time-decay spectra for losses in the
detection and counting system, and for back1. Plasek RE et al, reference 3, main text.
2. McKeon DC and Scott HD: “SNUPAR—A Nuclear
Parameter Code for Nuclear Geophysics Applications,”
Nuclear Physics 2, no. 4 (1988): 215-230.
Oilfield Review
ground radiation. Typically the background is
Input
Time decay spectra
averaged to improve statistics.
The next step is to generate the apparent quan-
STEP 1
Correction to Spectra
Counting loss corrections
Background adaptive filtering
Background subtraction
tities from the spectra, such as near and far
apparent formation sigmas. These quantities are
not environmentally corrected.
The third step is to apply transforms and envi-
STEP 2
Compute Apparent Quantities
Near apparent borehole sigma
Far apparent formation sigma
Near/far capture count rate ratio
ronmental corrections to the apparent tool quanti-
SBNA
SFFA
TRAT
ties to arrive at borehole salinity, porosity and
formation sigma. The technique uses dynamic
database parameterization that handles both the
transformation and environmental corrections.
Environmental
Parameters
Borehole size
Casing size/weight
Lithology
Data Base
External
Knowledge
(Optional)
Porosity
Borehole salinity
Tool
Calibration
Near/far ratio
Accuracy
A series of benchmark measurements has been
made to assess the accuracy of the algorithm
used with the data base to compute borehole
salinity, porosity and formation sigma (below).
These benchmark measurements include repro-
STEP 3
Transform from Apparent to
Corrected Quantities
cessing the entire data base as well as logging in
industry standard facilities such as the EUROPA
sigma facility in Aberdeen, Scotland (previous
page, top right) and the API porosity test pit,
Outputs
Borehole salinity
Porosity
Corrected near and far sigma
Formation sigma
at the University of Houston, in Texas.
BSAL SIBF
TPHI
SFNC SFFC
SIGM
Database points were reprocessed with the
dynamic parameterization algorithm and the
results were compared with the assigned values.
■Simplified RST sigma processing.
60
35
40
30
20
10
-1.5
0.0
1.5
Deviation from assigned
sigma, c.u.
0
0
10
20
30
40
Assigned sigma, c.u.
50
60
250
Borehole salinity, kppm NaCl
Measured sigma, c.u.
Measured sigma, c.u.
Limestone
Sandstone
Dolomite
30
50
25
20
15
10
5
0
41 p.u.
18 p.u.
0 p.u.
200
150
100
50
0
0
5
10
15
20
25
Assigned sigma, c.u.
30
35
0
10
20
30
40
50
Sigma, c.u.
■ Processing accuracy. Benchmark measurements were made to assess the accuracy of the algorithm in computing formation and borehole sigma, porosity and borehole salinity. Sigma measured with the RST-A tool versus assigned database sigma (left) shows average errors are small—0.22 c.u. Sigma measured at the EUROPA
facility in Aberdeen (middle) again shows excellent agreement with the assigned values. Comparison of RST-A tool sigma (right) versus borehole salinity shows that
corrected sigma is independent of borehole salinity—vital for time-lapse surveys or log-inject-log operations. In the crossover region (shaded area), formation sigma
approaches or even exceeds borehole sigma. Historically, pulsed neutron capture tools erroneously identify the borehole decay as formation sigma and formation decay
as borehole sigma in this region. However, the RST dynamic parameterization method solves this long-standing problem, correctly distinguishing between formation and
borehole sigma components.
Summer 1996
33
The algorithm does exceptionally well in match-
30 p.u.
ing the assigned values. For example, the average errors for formation sigma were 0.22 capture
20 p.u.
500
units (c.u.) for the RST-A tool and 0.20 c.u. for
10 p.u.
the RST-B tool.
calibration facility partially funded by the UK
Atomic Energy Authority with major support from
a consortium of 15 oil companies and government agencies. The RST-A tool was run in all the
20 p.u. 15% Calcite
400
Permeability, md
The EUROPA facility is an independent sigma
■ Effect of clay and
calcite on permeability. A small
percentage of clay
has a dramatic
effect on permeability. Calcite also
reduces permeability. So to determine a well’s producibility or the
cause of any formation damage, it
is important to
understand the
mineralogy.
600
300
200
openhole formations and several cased-hole formations. A smaller number of measurements
100
were made with the RST-B tool. Both tools read
the true formation sigma over a wide range of
lithologies, porosities, formation and borehole
0
0
fluids, borehole sizes and completions. Even in
the difficult crossover region, where formation
sigma approaches or exceeds borehole sigma,
the errors are small and the tool does not lock on
to the wrong sigma component.
Both EUROPA and the University of Houston API
pits were used to check porosity readings. The
0. 2
techniques, which by definition look at differences from one log to another over a
period of several months. RST data can be
gathered at logging speeds nearly three times
those of previous-generation tools for the
same precision.4
agreement between the two sets of porosities
Lithology
was excellent.
Assessing reservoir deliverability and
enhancing zone productivity rely on a thorough understanding of the rock matrix. For
example, clay content dramatically affects
permeability ( above ). 5 Elemental yields
derived from RST spectroscopy measurements provide the input to determine clay
and other mineral content and hence
improve understanding of the rock matrix.
Elemental yields—Neutrons interact with
the formation in several ways. Inelastic and
capture interactions produce spontaneous
release of gamma radiation at energy levels
that depend on the elements involved. Measurement of the gamma ray spectra produced by these interactions can then be
used to quantify the abundance of elements
in the formation. Elemental yields are often
used in various combinations or ratios to aid
complex lithology interpretation, to determine shale volume or to augment incomplete openhole data (see “Making Full Use
of RST Data in China,” page 36 ).
Precision
Key to time-lapse monitoring techniques is
repeatability or precision. Time-lapse uses differences in measured quantities to monitor, for
example, the progress of waterflooding, the
expansion of gas caps and the depletion of reservoirs. The RST tool has been benchmarked to log
nearly three times faster than previous generation tools for the same level of precision.3
3. For examples of repeatability—precision—see:
Plasek et al, reference 3, main text.
4. For more details on time-lapse monitoring see sections on precision and auxiliary measurements:
Plasek RE et al, reference 3.
5. Herron M: “Estimating the Intrinsic Permeability of
Clastic Sediments from Geochemical Data,” Transactions of the SPWLA 28th Annual Logging Symposium,
London, England, June 29-July 2, 1987, paper HH.
6. Roscoe B, Grau J, Cao Minh C and Freeman D:
“Non-Conventional Applications of Through-Tubing
Carbon-Oxygen Logging Tools,” Transactions of the
SPWLA 36th Annual Logging Symposium, Paris,
France, June 26-29, 1995, paper QQ.
34
0.4
Dispersed clay, %
At high neutron energies, inelastic interactions dominate. After a few collisions, neutron energy is reduced below the threshold
for inelastic events. The probability of an
inelastic interaction occurring is also reasonably constant for all major elements.
As neutrons slow to thermal energy levels,
capture interactions dominate. Some elements are more likely to capture neutrons
than others and so contribute more to the
capture gamma ray spectrum.
Inelastic and capture gamma ray spectra
are recorded by opening counting windows
at the appropriate time after a neutron burst
from the RST neutron generator. Tool design
allows not only for much higher gamma ray
count rates than previous generation tools,
but also for gain stabilization that enables
lower gamma ray energy levels to be
recorded for both inelastic and capture
measurements. A major advantage of this is
the inclusion of the inelastic gamma ray
peaks on the spectrum at 1.37 MeV for
magnesium and at 1.24 MeV and 1.33 MeV
for iron.6
A library of standard elemental spectra,
measured in the laboratory for each type of
tool, is used to determine individual elemental contributions (next page ).
SpectroLith interpretation—SpectroLith
processing is a quantitative mineral-based
7. Herron SL and Herron MM: “Quantitative Lithology:
An Application for Open and Cased Hole Spectroscopy,” Transactions of the SPWLA 37th Annual
Logging Symposium, New Orleans, Louisiana, USA,
June 16-19, 1996, paper E.
8. See Roscoe B et al, reference 6.
Oilfield Review
Inelastic Spectra
Oxygen
Silicon
Relative counts
Magnesium
Iron
Calcium
Sulfur
Background
Carbon
1
2
3
4
5
6
7
8
6
7
8
■ Elemental standards for the RST-A
tool. Lower gamma
ray energy levels
are recorded by the
RST tools than by
previous generation
pulsed neutron tools.
This allows measurement of elemental contributions
from elements such
as magnesium and
iron. Elemental
yields are processed
from standard spectra obtained using
laboratory measurements. Shown are
the standards for
inelastic (top) and
capture (bottom)
spectra for the
1 11/16-in. RST-A tool.
Energy, MeV
Capture Spectra
Iron
Chlorine
Relative counts
Silicon
Titanium
Calcium
Sulfur
Hydrogen
Gadolinium
1
2
3
4
5
Energy, MeV
lithology interpretation derived from elemental yields. Traditional lithology interpretation
relied on measurements of elements such as
aluminum and potassium to determine clay
content. Aluminum, especially, is difficult to
measure and requires a combination of logging tools; the interpretation is also complex.
A recent detailed study of cores showed
that a linear relationship exists between alu-
Summer 1996
minum and total clay concentration. Of
more importance, it also showed that silicon, calcium and iron can be used to produce an accurate estimation of clay without
knowledge of the aluminum concentration.7
The concentrations of these three elements
can be obtained from RST spectroscopy
measurements.
In addition, carbonate concentrations—
defined as calcite plus dolomite—can be
determined from the calcium concentration
alone with the remainder of the formation
being composed of quartz, feldspar and
mica minerals.
SpectroLith interpretation involves three
steps:
• production of elemental yields from
gamma ray spectra
• transformation of yields into concentration logs
• conversion of concentration logs into
fractions of clay, carbonate and framework minerals.
Borehole Fluid
The producing wellbore environment may
include a combination of oil, water and gas
phases in the borehole as well as flow
behind casing. Borehole fluid interpretation
is primarily based on fluid velocities and
borehole holdup. The RST equipment
makes these measurements using several
independent methods, with enough redundancy to provide a quality control cross
check:
• The WFL Water Flow Log measures water
velocity and water flow rate using the
principle of oxygen activation. This
method detects water flowing inside and
outside pipe, and in up and down flow.
• The Phase Velocity Log (PVL) measures
oil and water velocities separately by
injecting a marker fluid, which mixes and
travels with the specified phase. This
method may be applied to up and down
flow, but only fluids in the pipe are
marked and therefore detected.
• Two-phase—oil and water—borehole
holdup may be measured in continuous
logging mode with the RST-B tool.8
• Three-phase—oil, water and gas—borehole holdup is currently an RST-A station
measurement based on a combination of
C/O and inelastic count rate ratio data.
• Borehole salinity is one of the computations made as part of the sigma and porosity log and may be used to compute a
borehole water holdup with either the
RST-A or the RST-B tool.
(continued on page 39)
35
Making Full Use of RST Data in China
Gu Dao and Sheng Tuo are typical of the Shengli
complex of oil fields about 200 km [125 miles]
Sonic and gamma ray data do not provide
MONGOLIA
enough lithology information to account for matrix
CHINA
southeast of Beijing near the Bo Hai Gulf, China
(right).1 Both fields have a similar deltaic deposi-
guished from tight siliclastic streaks. Sonic-
tional environment, with alternating sand-shale
derived porosity may also be inaccurate if litholBeijing
sequences. Thin, tight, calcareous streaks within
the depositional sequences are common. Reser-
ogy and formation fluids are unknown, and also, if
Beijing
the sands are unconsolidated and the compaction
Qingdao
voir layer thickness varies from more than 10 m
[31.2 ft] to less than 1 m [3.1 ft] and each layer is
Bo Hai Gulf
Chinese oil fields have been under water injection to maintain pressure and improve sweep of
because the reservoir sands are rich in micas and
Shanghai
Shengli Complex
Sheng Tuo
sigma-mode pass provided sigma for shale volume estimation and thermal neutron porosity
TAIWAN
gram uses a mix of the low-salinity connate water
Hong Kong
and fresh surface water, which has resulted in
variable and unknown water resistivity in many
(TPHI) for effective porosity evaluation. The
inelastic-capture data were analyzed in detail not
only for the carbon-oxygen ratio (C/O), but also for
reservoirs.
enhanced oil recovery program and maximize oil
feldspars—both radioactive minerals.
To augment the limited openhole data, an RST
Gu Dao
the heavy hydrocarbons. The water injection pro-
In order to efficiently manage the waterflood
factor is unknown. The gamma ray curve alone is
unsuitable for accurate shale volume evaluation
produced separately.
For more than 30 years, many of these eastern
carbon. For example, carbonates cannot be distin-
elemental yields to provide other ratios. For exam■Location of Gu Dao and Sheng Tuo fields.
•Through-tubing logging, while the well was
ple, the ratio of iron to silicon (IIR) is indicative of
shale volume if kaolinite and heavy minerals are
recovery, it is essential to know the waterflood
flowing, avoids formation damage and also
not present; the ratio of silicon to silicon-plus-cal-
sweep efficiency, determine residual or remain-
increases operational efficiency in a multiwell
cium (LIR) may be used as a lithology indicator;
ing oil saturation, and pinpoint zones bypassed
campaign.
and the ratio of chlorine to hydrogen (SIR) gives a
by the recovery scheme.
Hydrocarbon saturation evaluation from open-
•The 5 1/2-in. casing inside 8 1/2-in. borehole
completion produces a thick cement sheath
formation salinity indicator.
The initial volume of oil was computed from the
hole resistivity logs, run in newly drilled infill
that reduces measurement sensitivity. The RST
openhole resistivity data in 1994 assuming that all
wells, is difficult because the formation water
tool has a high-energy, high-yield neutron gen-
sands were at connate water resistivity. The 1995
resistivity is variable and most of the time
erator and an efficient detection system that
RST carbon-oxygen evaluation computed remain-
unknown. Reservoir saturation monitoring with
provide better statistics in thick cement than
ing oil. A decrease in oil between the two may be
sigma measurements is impractical, as there is
the previous-generation pulsed neutron tools.
due to reservoir depletion, but could also be due
little contrast between the oil and water sigmas
• An additional pass in sigma mode provides
to an overly optimistic openhole evaluation if the
and, in any case, the water sigma is unknown.
data useful to accurately evaluate shaliness,
reservoir water was not at connate salinity, but at
These constraints leave carbon-oxygen measure-
especially in wells with scarce openhole data.
the fresher floodwater salinity.
ments as the only viable option.
The Shengli oilfield operators—Shengli
Petroleum Administration Bureau, China National
• Measurements such as neutron porosity and
The additional RST data proved invaluable. For
count rates can also be recorded to aid inter-
example, in the Gu Dao and Sheng Tuo fields in
pretation when gas is present.
general, sigma responds primarily to changes in
Petroleum Corporation (SPAB-CNPC)—decided to
matrix sigma and therefore provides the best shale
run the 21/2-in. RST-B tool for many reasons:
Evaluation with Scarce Openhole Data
indicator. The lithology indicator ratio LIR was
•The shielded dual-detector system alleviates
Key to the interpretation of carbon-oxygen data is
used to identify the tight calcite streaks at X201 m
the effect of a changing or unknown borehole
a knowledge of lithology to account for matrix
and X218 m.
oil holdup, as well as the effect of waxy
carbon, and effective porosity to calculate oil sat-
deposits on the casing.
uration. A typical Sheng Tuo well illustrates the
1. Olesen J-R, Chen Y, Zeng W, Zhu L and Zhang Z:
“Remaining Oil Saturation Evaluation in Water Flooded
Fields Under Variable Formation Water Resistivity,” to be
presented at the 1996 International Symposium on Well
Logging Techniques for Oilfield Development, Beijing,
Peoples Republic of China, September 17-21, 1996.
36
Interpretation of the salinity indicator ratio (SIR)
is more complicated. However, when the forma-
benefits of additional data provided by the RST
tion water volume remains constant, SIR responds
tool (next page). For this well the openhole data
directly to formation fluid salinity and can be used
were limited to sonic and gamma ray logs.
to determine the progress of injection water—
approximately the case in the large reservoir
between X220 m and X245 m.
Oilfield Review
IIR
0
LIR
2.5 0.625
SIGM
0
c.u.
DT
1.25
150 µsec/ft
SIR
50 -0.5
ppk
TPHI
3.5 60
GR
100
API
Openhole Analysis
50
p.u.
0
0
100
NPHI
250
60
p.u.
p.u.
100
Openhole Fluid 1994
p.u.
0
Shale
0
Bound Water
• The inelastic count rate ratio (CRRA) from the
Quartz
near and far detector is sensitive to porosity
Calcite
RST Oil 1995
Depth,
m
Water
and gas content.
For example, in one Gu Dao well, the upper
sand body, X103 m to X109 m, shows the presence of gas (next page, top). Sigma and CRRA
X200
scales were chosen so that the curves overlay in
clean gas-free formations. In the upper sand they
show negative separation as both sigma and
CRRA are driven lower by the presence of gas.
Similarly, TPHI shows a reduced neutron porosity
when compared to the true formation porosity
taken from the openhole interpretation of 1990.
No gas was apparent on the 1990 openhole
logs, so it is assumed that reservoir pressure has
declined below bubblepoint allowing gas to come
out of solution. Tests indicate that this is a waterbearing zone with some gas, confirming the RST
interpretation.
X250
Determining Water Resistivity and Flood Index
Interpreting openhole logs of newly drilled wells
■ Formation evaluation with additional RST data. Volumetric analysis (track 4) shows remaining hydrocarbon
saturation determined from RST carbon/oxygen ratio. The 1994 openhole fluid curve indicates more oil due to
either depletion or an overly optimistic evaluation. A comparison of RST porosity (TPHI), cased hole CNL
Compensated Neutron Log porosity (NPHI), and sonic transit time (DT), shows good agreement (track 3),
especially when NPHI is put on a sandstone scale—3 to 4 p.u. shift to the left. The lithology indicator (LIR) is
about 1 for siliclastics and decreases for carbonates (track 2). Two tight calcite streaks can be seen at X201
and X218 m. The salinity indicator (SIR) responds to formation salinity if porosity and hydrocarbon saturation
are approximately constant (track 2). The iron indicator (IIR), gamma ray and sigma (track 1) follow the same
trend, and each may be used for shale volume calculation under the correct conditions. Gamma ray indication
of shale will be pessimistic if radioactive sands are present—for example, those containing micas and
feldspars. Clays, except for kaolinite, contain iron. Sigma responds to formation matrix and fluids. Sigma fluid
is almost the same when oil and fresh water are present, so sigma responds primarily to changes in matrix.
In Gu Dao and Sheng Tuo, sigma has proved to be the best shale indicator.
in reservoirs that have been partially or fully
flooded is challenging. Water resistivity, Rw ,
often varies continuously from the relatively high
value of fresh floodwater to the low value of the
more saline connate water. If connate water
resistivity is used for Rw , then hydrocarbon saturation will be optimistic in partially flooded
zones.
However, by combining openhole and RST data
a continuously varying Rw may be calculated
leading to true hydrocarbon saturation. The eval-
In the shaly lower section of the reservoir,
Identifying Gas-Bearing Zones
uation may be taken further if floodwater resistiv-
salinity is high and probably at connate level,
Carbon/oxygen ratio responds to the carbon con-
ity is known and constant. In this case, the total
indicating minimal depletion. The middle section
centration in pore space. In gas-bearing zones,
volume of water may then be split into connate
is the cleanest, most permeable section and
carbon concentration is low, so C/O is low. Low
and floodwater.
shows a progressive drop in salinity. The water-
C/O can easily be misinterpreted as a water-bear-
flood front has reached this section. The upper
ing zone. However, several auxiliary measure-
cal to the interpretation. It must be late enough
section shows an intermediate salinity and shale
ments can help identify gas-bearing intervals:
after well completion to allow drilling fluids to
content, and also a smaller discrepancy between
• Gas sigma is much lower than water sigma or
dissipate, but before significant hydrocarbon
Reservoir saturation acquisition timing is criti-
RST saturation and openhole saturation. Flooding
oil sigma; therefore, at comparable shale lev-
depletion occurs. Four weeks has proven ade-
has reached this section, but is not complete.
els, the RST sigma measurement will be lower
quate for Gu Dao and Sheng Tuo fields.
Similar results have been seen with other RST
in gas-bearing reservoirs.
logs in these fields.
• Hydrogen index is also low in gas-bearing
Water resistivity is computed using standard
openhole interpretation methods. Openhole logs
zones. Therefore, neutron porosity measure-
provide Rt , Rclay, Vclay and effective porosity,
ments such as RST porosity (TPHI) underesti-
Φeff. Water saturation comes from RST interpre-
mate formation porosity.
Summer 1996
37
in.
10
Borehole Fluid
100
p.u.
0
50
p.u.
Openhole Analysis
0
0
100
Assumed Cement
Sheath
5.75
p.u.
0
RST Gas Indicator
1.75
Formation
c.u.
p.u.
100
tation. The flood index is determined as a linear
interpolation between floodwater resistivity and
connate water resistivity.
Bound Water
0
In a Gu Dao field example, connate and floodwa-
RST Fluid Volume 1995
Quartz
ter salinities are 8.5 ppk and 3 ppk, respectively
50
Calcite
(below left). The lower section, X296 to X303 m,
RST Oil 1995
is shaly and water-bearing. The middle section,
p.u.
0
TPHI from Sigma mode
SIGM
-10.0
50
p.u.
Shale
Cased Hole Sw 1995 O.H. Fluid Volume 1990
Casing Wall
Depth,
m
Openhole Porosity
Openhole Sw 1990
Radius of Bit
0
30.0 0.5
p.u.
Water
0
X287 m to X296 m, is the cleanest and is separated
RST Oil 1995
Gas
from the lower section by a thin, clean, sand streak
where the oil-water contact is situated.
X100
The clean midsection has the highest permeability and provides a preferential conduit for waterflooding. The discrepancy between RST-derived
and openhole hydrocarbon saturation is due to the
inadequate Rw estimation for the openhole evaluation. True hydrocarbon saturation is 40% as shown
by RST data and not 60%. Water resistivity, computed from a synthesis of RST and openhole data,
indicates that fresh waterflooding has increased
Rw from the connate water value of 0.35 ohm-m to
X125
about 1 ohm-m. The flood-index calculation confirms that the cleanest levels of this reservoir have
been heavily flooded.
The shalier upper sand section shows general
agreement between RST-derived and openhole
hydrocarbon saturation. Because of the increase in
■ Gas detection. Inelastic count rate ratios of near-to-far detector counts and sigma are both affected by gas
(track 2). Negative separation of these curves indicates gas. RST porosity, TPHI, also reads lower in gas (track
3). Although no gas was shown on the openhole logs, it is assumed that solution gas has accumulated in the
fully depleted zone between X100 m to X109 m. Tests indicate that the layer is mainly water and gas.
RST-derived Rw
Radius of Bit
10 0
0
Borehole Fluid
Casing Wall
Assumed
Cement Sheath
Formation
Depth,
m
Openhole Porosity
2 50
p.u.
Openhole Analysis
0 0
Cased Hole RST Sw O.H. Fluid Volume 1994
100
p.u.
Flood Index
2
0 50
p.u.
0
RST Fluid Volume 1995
0 50
p.u.
Nonmovable Oil
0
p.u.
100
shaliness and the related decrease in permeability,
waterflooding essentially bypasses this section
and little hydrocarbon sweep is achieved.
Campaign Success
The Shengli oilfield RST campaign has shown that
Shale
hydrocarbon monitoring in waterflooded fields with
Bound water
varying salinity is a viable procedure. In addition,
Quartz
Nonmovable oil
Open Hole 1995
Remaining Oil RST1995 Movable RST Oil 1995
Water
Flood Water
ancillary RST measurements complement openhole information, improving both formation evaluation and detection of gas-bearing intervals. Also,
the combination of openhole and RST data
acquired within one month is a powerful tool for
evaluating the waterflooding process. During the
course of the campaign, RST data contributed to
the achievement of the SPAB-CNPC engineers’ goal
of maintaining oil output while controlling water
production. RST results showed a large amount of
X290
remaining hydrocarbon, especially in the massive
sands of the Sheng Tuo oil field.
X300
38
■Water resisitivity, Rw, and flood index. A flood
index can be calculated from variable Rw (track 2)
computed from RST and openhole data collected
before any hydrocarbon depletion and after invasion
fluids have dissipated (track 3).
Oilfield Review
WFL measurements—Water flow logging,
introduced with the last-generation TDT
Thermal Decay Time service several years
ago, is now available with the RST service.
The RST neutron generator provides
improved burst control, which allows detection of water velocities up to 500 ft/min
[150 m/min] with the far detector alone. In
addition, the introduction of energy discrimination and shielding between neutron generator and detectors results in a significant
improvement in the signal-to-noise ratio, and
extends sensitivity to low flow conditions.
Oxygen molecules in water are activated
by a burst of neutrons producing a radioactive cloud. The cloud moves with the water
along the borehole, emitting gamma rays as
activated oxygen decays back to its steady
state (top right ). As the cloud passes, gamma
rays are first detected by the near detector
and then by the far detector of the RST
sonde, producing a characteristic peak in
the count rate of each. The time between
neutron burst and cloud detection—time-offlight—and the distance between neutron
generator and detector give water velocity.
Other detectors can be added farther away
in the tool string to detect extremely high
water velocities. The RST equipment can
also be turned upside-down to detect downward flow.
In addition, the volume of activated oxygen is proportional to the volume of water
flowing by the detectors. The profile of the
detected signal carries information about
the mean water velocity, water holdup and
water flow rate. These quantities are related
in that the water velocity, water holdup and
effective cross-sectional area of the pipe can
be combined to compute the water flow
rate (see “Production Logging in the San
Joaquin Basin,” next page ).
PVL —Phase velocity logging has been
developed for horizontal wells where stratified flow is present. Like WFL logging, the
Phase Velocity Log measures time-of-flight.
Gadolinium has a very high thermal neutron
capture cross section and is injected into the
producing borehole ( bottom right ). The
injection fluid is designed to mix with either
the water or oil phase only. Gadolinium acts
as a sink, sucking in thermal neutrons and
Summer 1996
Near Detector
Far Detector
Additional Detector
Casing
Minitron
Oil
Water
16
β+16O*
p+16N
O+n
16
O+γ
Half-life ~7.1sec
■ WFL Water Flow Log service. A short burst of neutrons interacts
with oxygen in the surrounding water forming an oxygen isotope
with a half-life of 7.1 sec. As the activated oxygen decays back to
its steady state, gamma rays are emitted. In flowing water the
cloud of activated oxygen, and hence gamma rays, travels along
at the water velocity. Characteristic increases in count rate are
seen as the cloud passes the various detectors. The distance
between neutron generator and detector and the time-of-flight
give water velocity. The initial cloud volume is proportional to the
amount of oxygen present and hence volume of water. The area
under the gamma ray peak as the cloud passes a detector is,
therefore, also proportional to the volume of water flowing by
(water holdup)—allowing for effects of diffusion and decay rate.
Combining water velocity and holdup gives water flow rate.
Marker signal
Start of injection
0
10
20
30
40
50
Time, sec
Oil-miscible marker
Phase Velocity Sonde
60
70
RST tool
80
Oil
■ Phase Velocity
Logging (PVL).
A strong neutron
absorber is
injected into the
appropriate phase
of producing fluid.
This is subsequently detected,
allowing a time-of90 flight measurement that gives
the velocity of that
phase.
Water
39
Production Logging in the San Joaquin Basin
Elk Hills is one of the largest oil fields in the San
Gas
Joaquin basin about 20 miles [32 km] west of Bak-
Oil
ersfield, California, USA (below). The field forms
Water
part of the Naval Petroleum Reserve No. 1 and is
Downhole Flow Rate, B/D
operated by Bechtel Petroleum Operations, Inc.
0
for the Department of Energy. Although Elk Hills
was discovered in 1911, production was limited
until the 1974 oil crisis resulted in opening up the
field to full production in 1976. The field has pro-
Pressure
Depth,
ft
1050 psi 1300 206
3000
Temp
Water Flow Stations
Water Flow Log, B/D
°F
211 0
3000
duced over 1.1 billion barrels of oil and a significant quantity of gas, and now produces about
60,000 BOPD of medium-gravity crude.
Earlier this year, Bechtel wanted to determine
X200
the flow profile and quantify the zonal contributions to oil, water and gas production from a well
in which production from a waterflooded sand
reservoir was commingled with production from a
shaly interval. A production log consisting of temperature, pressure and spinner was run and stationary WFL Water Flow Log measurements were
X400
Thief zone
taken with the RST tool.
The flow profile turned out to be complex,
showing a zone of water recirculation near the
bottom and a thief zone above (right).1
A combination of spinner and WFL data located
the recirculation zone. The spinner indicated down
flow, while the WFL data indicated a small
amount of water flowing up. The temperature log
X600
Recirculating water zone
also showed a strong anomaly over this interval.
The flow profile shows a net flow of oil from this
zone simply because a recirculation zone requires
multiphase flow.
Both spinner and WFL data show an increase in
flow above the recirculation zone before an abrupt
X800
Fresno
■WFL Water Flow Log. The flow profile indicates that most of the gas production is from X350 to X370 ft
(tracks 2 and 3). Below this depth is a complex profile of thief zone and water recirculation. WFL stationary readings determined the water production profile, and temperature and pressure (track 1) aided the interpretation.
San Andreas Fault
Coalinga
decrease at X430 ft. The temperature also drops
C A L I F O R N I A
Elk hills
Bakersfield
Taft
occurs across the short perforated interval X350 to
rate and temperature can occur only if the forma-
X370 ft. Here, a large increase in spinner flow rate
tion is taking fluid—a thief zone. Conventional
and a change in slope of the pressure data indicate
openhole logs and the mud log suggest that there
an influx of gas. The WFL log shows doubling of the
is a highly resistive, low porosity carbonate in
water flow rate across the same interval.
this interval. The FMI Fullbore Formation
MicroImager tool shows what has been inter-
U S A
■ Location of
Elk Hills field,
Kern County,
California.
40
The next significant event in the flow profile
at this point. The combination of decrease in flow
preted as a calcite healed fracture. This fracture
has most likely been opened by acid treatment
and has created the thief zone.
1. Water recirculation occurs, usually in deviated wells,
when water and oil are present. Water can flow up with
the oil on the upper side of the well and down on the
lower side in a continuous cycle.
A thief zone occurs when a perforated zone has a lower
formation pressure than the borehole, causing flow
from borehole to formation.
Oilfield Review
CPLT Combinable
Production Logging Tool
Pressure and temperature
RST Reservoir Saturation Tool
Oil holdup
Gas indicator
FloView tool
Flow regime
Water holdup
Fluid marker
injector
Total flow rate
Gamma ray
detector
CPLT
GR
RST
FloView Plus tool
Spinner
WFL Water Flow Log
Water velocity
Water holdup
Water flow rate index
Phase Velocity Log
Marker injection for oil
and/or water velocity
■ The next generation production logging tool string.
changing the borehole sigma. The detection
of this change provides a time-of-flight measurement for the marked phase.
Two-phase borehole holdup —The two
detectors of the RST sonde provide two carbon-oxygen measurements that are sufficient to solve for formation water saturation
( S W ) and borehole oil holdup ( Y O ) (see
crossplot, page 29 ). Four points may be
defined on a plot of far carbon-oxygen ratio
versus near carbon-oxygen ratio to give a
quadrilateral:
• Water in the formation and water in
the borehole (SW = 100, YO = 0 )
• Oil in the formation and water in the
borehole (SW = 0, YO = 0)
• Water in the formation and oil in
the borehole (SW = 100, YO = 100)
• Oil in the formation and oil in the
borehole (SW = 0, YO = 100).
Summer 1996
The exact position of these points depends
on lithology, porosity, hydrocarbon carbon
density, hole size, casing size, casing weight
and sonde type—RST-A or RST-B sonde.
With the larger RST-B sonde, the quadrilateral is wide since the far detector is shielded
to be more sensitive to the formation and
the near detector shielded to be more sensitive to the borehole. This provides good separation of the signals and a good borehole
oil holdup measurement in addition to a formation saturation measurement. The slimmer RST-A sonde is not focused and, therefore, requires knowledge of the borehole
fluids to separate the formation and borehole signals.9
Three-phase holdup—A combination of
RST measurements can be used to compute
three-phase holdup. Gas holdup is indicated
by the inelastic near-to-far count rate ratio.
The near and far C/Oyields depend on gas,
water and oil holdups. By combining these
measurements and applying two conditions—the sum of the holdups must equal
unity and also the sum of the saturations
must equal unity—three-phase holdups may
be calculated. The RST measurement of
borehole sigma can also be combined with
this analysis to enhance the holdup calculation if the water salinity is known.
Comprehensive Cased-Hole Evaluation
Since commercialization of the RST service
four years ago, many applications have
been developed. With the addition of lithology interpretation, phase velocity logging
and three-phase holdup, the tool is rapidly
becoming a comprehensive cased-hole
evaluation service. 10 A future Oilfield
Review article will explain in more detail
some of these new services, including new
production logging combinations (above ).
—AM
9. For an alternative method of measuring borehole
holdup with the RST-A tool: Roscoe B et al, reference 6.
10. Schnorr DR: “Determining Oil, Water and Gas
Saturations Simultaneously Through Casing by Combining C/O and Sigma Measurements,” paper SPE
35682, presented at the SPE Western Regional Meeting, Anchorage, Alaska, USA, May 22-24, 1996.
41
Seamless Fluids Programs:
A Key to Better Well Construction
New insights into displacement mechanics inside casing and in the annulus, combined with integrated
drilling and cementing fluid services, can improve primary cementing. This structured “fluids-train”
approach also optimizes overall drilling and completion performance at lower cost for operators.
Lindsay Fraser
Bill Stanger
Houston, Texas, USA
Tom Griffin
Sugar Land, Texas
Mourhaf Jabri
Balikpapan, Indonesia
Greg Sones
Anadarko Petroleum Corporation
Houston, Texas
Mike Steelman
Calgary, Alberta, Canada
Peter Valkó
Texas A&M University
College Station, Texas
For help in preparation of this article, thanks to
Dominique Guillot, Dowell, Clamart, France, and Jason
Jonas, Dowell, Sugar Land.
In this article, CBT (Cement Bond Tool), CemCADE, CET
(Cement Evaluation Tool), DeepSea EXPRES, EXPRES,
MUDPUSH, SALTBOND, USI (Ultrasonic Imager) and
WELLCLEAN are marks of Schlumberger.
42
Improvements in well construction are possible if long-standing boundaries between
drilling and cementing can be eliminated,
and if mud removal and displacement criteria are properly applied. Efficient slurry
placement for complete and permanent
zonal isolation relies on effective displacement of drilling fluids from the casing-borehole annulus—mud removal—and on avoiding bypassing, mixing and contamination of
fluids in the annulus and casing during
cement placement. Understanding displacement mechanics is essential to successful
cementing, but an integrated drilling and
cementing fluids approach is a first step
toward overall wellbore optimization.
The consequences of poor primary
cementing jobs can be severe. Incomplete
mud removal may leave channels, allowing
communication between subsurface zones
or to the surface. Likewise, failure to properly separate fluids as they are pumped
downhole can negate the most meticulous
plans or the best designs and lead to ineffective mud removal or contamination that prevents cement from ever setting up (hardening). Approaching well construction as a
series of interrelated events in which both
mud and cement play important roles—total
fluids management—results in a more controllable, structured process with optimal
wellbores as the objective.1
Traditionally, drilling fluids and cementing
services have been provided separately and
the lack of stated, common objectives has
been a roadblock to optimizing these operations. Better management of fluid services
requires drillers and cementers to work
together from well start to finish to select
muds that achieve drilling goals, but do not
impede cementing success. Consideration
must be given to providing gauge holes that
allow casing centralization. It may be necessary to reduce rates of penetration—average
to high instead of very high—during drilling
if that means improved borehole conditions,
lower-cost primary cement jobs and reduction or elimination of expensive repair
workovers. Necessary elements are available and, in most cases, in place to do this;
where efforts often fall short is in coordination and management of the entire process
to realize maximum benefits. Success in
terms of the final product—a safe, long-lasting wellbore at the lowest possible
cost—should be an incentive to rethink and
restate fluid objectives.
Better understanding of annular displacement is a key element that is already in
place. 2 By using physical and computer
modeling, cementing criteria have
improved. Simulation and design software
allow the myriad of fluid factors and complicated interactions involved in primary
cementing to be addressed qualitatively, and
most of the time quantitatively as well. The
total process (mud removal and cement
placement) including conditioning, annular
flow regimes, spacer—a buffer between
drilling muds and cement slurries—selection and fluid displacement inside pipe can
now be evaluated in planning and design
stages, during mud maintenance and conditioning, and before or after jobs.
Oilfield Review
High flow rates effectively displace mud if
turbulent3 flow is achieved around the entire
annulus, but are viable only if casing and
hole sizes are relatively small and casing
standoff4 from the borehole is adequate.
Lower flow rates can also successfully
remove mud in many cases where higher
flow rates are not practical, but more sophisticated designs and modified fluids are often
needed to achieve laminar5 displacements.
Spacers with controllable properties—ability
to suspend weighting agents, reasonable turbulent rates, adjustable rheology, compatibility, low fluid loss and a wide range of applications—are needed to meet and better
apply mud removal criteria (see “Engineered,
Fit-To-Purpose Spacers,” page 46 ).6
Finally, to close the fluids loop, displacements inside pipe must be understood
because density differences may cause mixing of fluids or bypassing of mud by spacers,
spacers by cement slurries or lead by tail
slurries.7 Better understanding and application of fluid flow and displacement mechanics are required along with more careful
1. Fraser L and Griffin TJ: “Economic Advantages of an
Integrated Fluids Approach to the Well Construction
Process,” presented at the American Association of
Drilling Engineers Drilling Fluids Technology Conference, Houston, Texas, USA, April 3-4, 1996.
2. Lockyear CF and Hibbert AP: “Integrated Primary
Cementing Study Defines Key Factors for
Field Success,” Journal of Petroleum Technology 41
(December 1989): 1320-1325.
Lockyear CF, Ryan DF and Gunningham MM:
“Cement Channeling: How to Predict and Prevent,”
SPE Drilling Engineering 5 (September 1990):
201-208.
3. Turbulent flow occurs at higher flow rates. Individual
fluid particles swirl around, but their average velocity
results in what is considered a flat velocity profile.
Momentum is constantly transferring from one region
to another, but overall flow is relatively constant.
Summer 1996
4. Specification 10D, Specification for Casing Centralizers,
2nd. Dallas, Texas, USA: American Petroleum Institute,
1983.
Casing standoff (STO) in percent is defined as STO =
2w/D - d x 100 or w/R-r x 100, where D is hole diameter, d is pipe outside diameter (OD), R is hole radius, r is
pipe radius and w is the smallest annular gap. STO is
100% when casing is concentric—perfectly centered.
5. Laminar flow occurs at relatively low flow rates. Fluid
particles move parallel to the casing axis or annulus
walls along straight lines in the direction of flow, with
a parabolic velocity profile. At the walls, where liquids
wet the surface, fluid particles in contact with pipe or
annulus walls are stationary and velocity is zero,
increasing to a maximum—twice the average velocity
for Newtonian fluids—at the center of the flow channel.
6. Couturier M, Guillot D, Hendricks H and Callet F:
“Design Rules and Associated Spacer Properties for
Optimum Mud Removal in Eccentric Annuli,” paper
CIM/SPE 90-112, presented at the International Technical Meeting of the Petroleum Society of CIM/SPE,
Calgary, Alberta, Canada, June 10-13, 1990.
Tehrani A, Ferguson J and Bittleston SH: “Laminar Displacement in Annuli: A Combined Experimental and
Theoretical Study,” paper SPE 24569, presented at the
67th SPE Annual Technical Conference and Exhibition, Washington, DC, USA, October 4-7, 1992.
7. Griffin TJ: Displacement Inside Casing. Schlumberger
Dowell Report (January 3, 1995).
43
Borehole Geometry and Mud Removal
Displacements
Good
Mud
Chemical
wash
Top wiper
plug
Bad
Mud
Mud
Chemical
wash
Bad
Spacer
bypasses
mud
Weighted
spacer
No bottom
wiper plugs
Top of cement
too high
Weighted
spacer
Immobile mud
in narrow gap
Cement
mixes with
spacer
Lost
circulation
Bypassed
or mixed
fluids in
shoe track
Float joints
(shoe track)
Tail
slurry
Zones of
interest
Float shoe
design of mud systems, spacer fluids and
cement slurries to avoid common cementing problems (above ). This article gives an
overview of integrated fluids services, and
reviews mud conditioning and removal
from the annulus by turbulent and effective
laminar flow (ELF). A Dowell and Texas
A&M University study defining downward
flow in pipe and proposing methods to
improve cement placement without sacrificing effective mud removal is also examined.
The Case for Total Fluids Management
In the past, drilling and cementing fluids
were often provided under individual service contracts, often by different companies.
All too frequently, the attitude seemed to be,
“drill as fast as possible and worry about
cementing after reaching TD.” Other needs
and intentions, and deleterious effects that
occur when some fluids commingle were
often ignored. In principle, instead of segregating drilling and cementing fluid services,
operations can be unified in a single, integrated process. Isolated service-line mentalities are replaced by a common goal of providing seamless fluids programs—”fluids
trains”—to optimize overall performance
and results. Territorial considerations are for-
■Common cementing problems (red)
related to drilling,
mud removal and
displacement.
Weighted
spacer
Bottom
wiper plugs
Float
collar
44
Good
Gelled mud
channel
Inflow
Lead
slurry
Tail slurry
ahead of
lead slurry
Tail
slurry
Tail slurry
below zones
of interest
gotten, and the two disciplines work
together to maximize the efficiency and
effectiveness of all well-construction fluids.
Good communications and coordination
are a necessity. Cementing designs are performed before drilling is complete, so
choices about flow regime—turbulent or
laminar—and spacer properties are made
assuming hole size and mud characteristics.
Last-minute changes or unexpected variations in borehole conditions place cementers
at a disadvantage. Irregular holes and
washouts hinder mud removal and casing
centralization, and may preclude use of preferred turbulent flow. Low standoffs result in
large radial variations in annular fluid velocity around casing with higher velocity on the
wide side and lower velocity on the narrow
side. This leads to inefficient annular displacement and potentially poor cement
bonds or channels. For cement jobs, casing
OD to hole diameter ratio is close to unity,
so annular flow can be calculated using a
basic slot model (next page, top ).
Drilling fluid designs also influence
cement job quality. For example, zonal isolation cannot be achieved unless mud and
cuttings are removed from the annulus.
Drilling fluids must be designed, maintained
and treated to provide optimum final hole
conditions, and ultimately be conditioned
before cementing for easy removal by spac-
Bypassed
lead slurry
ers and cement. Ideal muds for efficient displacement are nonthixotropic8 and have
reduced gel strengths, plastic viscosities and
yield points; low density to facilitate
removal by buoyant forces; minimal fluid
loss to prevent thick filter cakes and differential sticking; and are chemically compatible with cements. Perfect muds, however,
cannot be achieved in practice, so efforts
must be made to get close to ideal characteristics during selection, maintenance and
precementing circulation.
Drilling fluid density and rheology must
be kept low to meet mud-removal requirements. Displacing fluid weights and viscosities become higher with each successive
interface, which can lead to unacceptably
high cement densities and viscosities, and
possible lost circulation if initial mud
weight is too high. Just circulating and conditioning mud before cementing is not
enough; effective solids and chemical control of rheology are required throughout
drilling operations. If drilling fluids are not
properly designed or deteriorate during
drilling or logging, gelled mud that is difficult to remove may be left in washouts or
on the narrow side of the annulus.
Fluids compatibility also impacts annular
displacement. Fluid mixtures should have
Oilfield Review
Basic Slot Model
Concentric slot
Local to average velocity ratio
3
-180°
Pump rates
1 bbl/min
3 bbl/min
6 bbl/min
2
0°
180°
Eccentric slot
ws
ns
ws
Polymer profiles
Water profiles
1
0
-180°
0°
-90°
90°
Narrow side (ns)
Wide
side (ws)
180°
Wide
side (ws)
Position around annulus
■Flow velocity profiles around a 60% standoff eccentric annulus. For cement jobs,
outside casing to borehole diameter ratio is close to unity, and annular flow conditions can be evaluated and calculated assuming flow through a slot (inset). If annular flow is uniform, the ratio of local to average velocity is equal to one. For thin
Newtonian fluids like water in turbulent flow, velocity profiles are relatively flat
with lower-than-average flow in the narrow gap and above-average flow in the
wide gap. Viscous non-Newtonian fluids like polymers in laminar flow move mostly
on the wide side and can be static in the narrow annulus gap. Higher pump rates
or increased standoff improve flow velocity on the narrow side of the annulus.
25
20
Cost, $1000
lower rheologies than the individual fluids,
but because this is difficult to achieve for
muds and spacers, designs need to minimize mixture viscosities. Problems also arise
if cement and mud mix inside or outside
casing. Some drilling fluid additives accelerate or retard cement thickening times. But
more commonly, cement-mud combinations result in high-viscosity mixtures and
corresponding friction pressure increases
that lead to excessive surface pump pressures and premature job termination as well
as inefficient displacement. Washes and
spacers isolate these potentially incompatible fluids, but unexpected variations in
composition leave cementers unprepared to
maintain this separation. This can be
avoided by using bottom wiper plugs to separate fluids inside casing and liners.
In addition to displacement considerations, cementing cost is an issue as hole
sizes increase from washout or enlargement.
The cost of larger cement volumes is obvious, but additional centralizer cost to
achieve adequate standoff for effective mud
removal is often overlooked (right ).
Spacer cost is also important. As hole size
increases, higher flow rates are needed for
turbulent flow and spacer volumes must be
increased. For example, if hole diameter
increases from 6.5 to 8.0 in., the rate to
achieve turbulent flow goes from 4 to 14
bbl/min and cost of standard spacers goes
from about $6500 to $15,500.
Workovers are another often overlooked
cost component when drilling and cementing services are segregated. Typically, if a
primary cement job is unsuccessful and a
cement squeeze is necessary, more than one
attempt is needed to achieve zonal isolation. Remedial cementing costs, including
cement, perforating, packers and rig time,
can be as much as, or more than, the primary cement job.
15
Total
10
Cement
5
Centralizers
0
6.5
7.0
7.5
8.0
Hole size, in.
■Cementing costs versus hole size. The cost of additional
centralizers to achieve adequate standoff is often overlooked.
As hole size increases from 6.5 to 8.0 in., combined centralizer
and cement costs to fill from 8000 ft [2440 m] total depth (TD)
up to 5000 ft [1520 m] using a 16.45 ppg slurry with moderate
fluid-loss control almost triples from $7850 to $22,500.
Integrating Fluids Services in Canada
A managed fluids approach proved successful in western Alberta, Canada, where vertical wells are drilled to between 6888 and
7544 ft [2100 and 2300 m] through unconsolidated formations. Historically, drilling
and cementing fluids had been provided by
one company, but individual services were
not working to meet common goals. Drilling
fluids services tried to minimize expenditures directly related to mud use, and
cementers did the best job possible with
resulting hole conditions. Managed separately, drilling fluids cost on four wells
Summer 1996
drilled with bentonite mud and three with
partially hydrolized polyacrylamide (PHPA)
fluids was $26,600/well, or $3.58/ft
[$11.75/m] drilled. Average hole enlargement was 113% by volume and typically 23
days were spent drilling. Lost time due to
hole problems and backreaming was about
24 hr/well.
Some elements of drilling fluids performance were acceptable, but hole geometries
that cementers had to address were not.
Bentonite mud was not conducive to drilling
gauge holes and a PHPA fluid failed to prevent washouts that were responsible for
major cementing cost over-runs. Enlarged
holes were compensated for by pumping
extra cement, knowing that there was risk of
channeling due to reduced fluid velocities in
washouts. Cementing on these seven wells
cost $103,750/well or $13.96/ft [$46/m]
drilled, about four times drilling fluid costs.
Total fluids averaged over $130,000/well, or
$17.56/ft [$57.60/m] of hole.
8. Thixotropic fluids are highly viscous when static, but
become more fluid-like and less viscous when disturbed or moved by pumping.
45
Engineered, Fit-to-Purpose Spacers
The primary functions of spacers are fluid separa-
MUDPUSH Spacer Properties
tion to avoid compatibility problems and ensuring
flow under a specific regime—turbulent or lami-
Excellent ability to suspend
weighing agents
nar—while maintaining hydrostatic well control.
Reasonable turbulent flow pump rates
Improved mud removal guidelines require preflushes for either turbulent flow or effective laminar
flow (ELF) techniques, so weighted MUDPUSH
Adjustable viscosity and density
for laminar flow
spacers were developed for use with WELLCLEAN
Cement, oil- and water-base mud
compatibility
optimal mud removal services (right). XT and XS
Good fluid-loss control
spacers are for turbulent flow. Viscous XL is used
with ELF. All three can be adapted for use with oil-
Applicable for a wide range of fluid
weights and salinities
base muds—XTO, XSO and XLO spacers.
Turbulent spacers were designed to overcome
and to a greater extent, apparent viscosity. Exces-
settling problems experienced with thin spacers.
sive fluid loss introduces the possibility of spacers
Weighting agents are suspended at surface or bot-
coming out of turbulent flow at design rates, which
tomhole temperatures under static and shear con-
can lead to channeling of spacer through the mud.
ditions by a properly designed base-fluid rheology
Fluid loss for these spacers is low and few compat-
that eliminates free water and particle settling over
ibility problems have been encountered. Some
a wide range of densities while allowing turbulent
mixtures of these spacers and cement slurries
flow at reasonable pump rates. The XT spacer is for
develop weak gel strengths when left static at low
turbulent flow regimes in low-salinity environments
temperature, but these gels are broken by shear
(fresh or less than 10% salt by weight of mix water)
rate or small temperature increases.
and the XS spacer is for high-salinity applications
Consistent performance under field conditions is
(30% salt by weight of mix water). Both can be for-
also an advantage in effective mud removal. Spac-
mulated at 10 to 19 lbm/gal [1.2 to 2.3 specific
ers must perform under variable conditions from
gravity (SG)] densities.
low-quality barite and brackish or high-salinity
Laminar-flow spacers have higher viscosities
water to low-shear mixing without major changes
than turbulent-flow spacers, so good particle-carry-
in properties and effectiveness. Spacers should
ing capacity ensures that weighting agents to
also have adequate viscosity and fluid-loss control
achieve required densities do not settle out. To
at field conditions. MUDPUSH spacers perform
meet ELF friction-pressure hierarchy criterion,
successfully under a wide range of operational con-
spacer rheology can be adjusted so that apparent
ditions, and rheological properties are consistent
viscosity across the range of pumping shear rates
with laboratory measurements made prior to jobs.
falls between drilling mud and cement slurry
apparent viscosities. Spacer density can also be
These spacers are limited to maximum bottomhole circulating temperatures of 300°F [149°C], but
designed halfway between mud and cement slurry
the new XEO spacer, a polymer-modified, oil-in-
weights at any density from 10 to 20 lbm/gal
water emulsion spacer, extends applicability to
[1.2 to 2.3 SG].
In addition to proper spacer rheology and parti-
450°F [232°C] for oil-base mud removal only. The
WHT spacer is a water-base spacer developed for
cle-carrying capacity, fluid-loss control and com-
these same higher temperature applications and
patibility are important. Fluid-loss control must be
oil- or water-base mud removal to complement the
considered because water lost during displacement
XEO spacer. However, it exhibits less fluid-loss
increases the spacer solids-to-liquid ratio, density,
control, especially when seawater is used as mix
water. MUDPUSH spacers can also be used for
1. Courturier et al, reference 6, main text.
Tehrani et al, reference 6, main text.
other cementing applications where weighted spacers are needed, such as plug or squeeze cement-
Overall improvement was the goal of a
unified fluids approach on two subsequent
wells. Total fluids costs were targeted to be
reduced by improving hole gauge and
reducing cement volumes. Unconsolidated
formations in these wells were identified as
the cause of washouts, so because of the
lack of success with even a moderately
inhibitive PHPA system, mixed-metalhydroxide (MMH) mud with unique fluid
rheology was chosen to minimize hole
enlargement.
After the revised fluids program was
implemented, gauge holes allowed for better casing centralization and improved displacement designs—a laminar flow regime
was chosen for these wellbore geometries.
Spacers effectively removed MMH fluids
from the annulus and logs indicated good
cement placement and successful zonal isolation. Cement returns compared to cement
volume pumped in excess of caliper hole
volume indicated minimal if any channeling
in both the wells drilled with MMH fluid.
But severe channeling was likely in three of
the previous seven offset wells, and one had
significant losses during cement placement.
Water flow—the first in this field—
occurred while drilling the initial test well.
Although most of the 57% washout was
over the interval where flow occurred on
this well, this still compares well with over
100% average washout on offsets. Drilling
fluid cost exceeded average offset cost
because dilution, borehole instability and
the need to increase density resulted in
excess product use that skewed cost. Positive results, however, were seen in improved
hole gauge and cement cost, which fell to
64% of the average.
The second test well had no losses or flow
and was drilled in the least number of days,
despite moderate rates of penetration. Lost
drilling time on this well was the lowest for
this field and washouts were reduced to
29%. Drilling fluid cost at $43,000 was
above the $25,000/well average, but
cementing costs of $45,000 were less than
half those of previous wells.
Total fluids cost was the lowest on record
for this field—a 32% savings over the average for offsets. The objective of reducing
overall well construction fluid costs was
achieved by reducing washouts, and higher
drilling fluid costs to minimize hole enlargement were more than offset by cement savings. Proper drilling practices cannot assure
cementing success, but poor drilling practices may make cementing success
unachievable.
ing, even when WELLCLEAN services are not
directly applicable.
46
Oilfield Review
Circulation: Mud Conditioning
18
R
16
D
14
Flow-rate ratio
Primary cementing operations often have
multiple objectives. On long intermediate
casing strings, a complete cement sheath
from bottom to top is preferred, but a good
seal near the bottom of the string and
around the casing seat is all that may be
required, making the casing seat the primary
and the full cement sheath the secondary
objectives. For liners, isolation away from
the shoe (bottom) may be important as well
as a seal at the liner-casing overlap (top).
Cementing goals dictate job designs. To
solve cementing problems, better understanding and application of fluid flow, displacements and placement are required
along with careful design of mud systems,
spacer fluids and cement slurries. Cement
placement is important in most cases; mud
removal is critical on all cementing jobs.
The accepted procedure is to circulate and
condition before cement jobs.9 However, in
the past, there were few guidelines for these
procedures, except generally to reduce mud
viscosity, gel strength and fluid loss; maximize standoff—casing centralization; use
preflushes—chemical washes and spacers to
separate mud and cement; move the
pipe—rotate or reciprocate; circulate a minimum of two hole volumes and pump at
d
12
w
10
STO, % =
8
4
2
0
0
10
20
30
40
50
60
Frictional pressure drop, Pa/m
70
80
API standoff, %
90
100
Adjust rheology if necessary
Eccentered Flow Screen
Evaluate flow regimes and range of
flow rates versus hole size; select
flow regime and standoff.
Centralizer Calculation
Select centralizers appropriate for
hole dimensions and desired standoff.
Pump Rate Selection
Select pump rate that meets criteria
for the chosen flow regime, hole
size and standoff.
U-Tube Calculation
Evaluate U-tubing that occurs
while pumping at the selected rate.
1500
w or 2w x 100
R-r
D-d
6
2000
Cementing geometry:
0.81 diameter ratio
r
■Turbulent flow-rate
corrections versus
casing eccentricity.
The critical flow rate
to achieve turbulent
flow completely
around a casingborehole annulus
doubles as casing
standoff (STO)
decreases from 100
to 70% and there is
almost a tenfold
increase if standoff
drops to 30%.
■Optimizing mud
removal. In the early
1990s, pipe eccentricity was first taken
into consideration in
designs and in the
field by using WELLCLEAN optimal mud
removal service in
CemCADE cementing design and
evaluation software.
This comprehensive
software is used to
evaluate all well
parameters, including casing standoff,
Adjust
and to recommend
standoff
or flow rate flow regimes,
preflushes and
volumes, and pumprate sequences
for optimum fluid
displacement.
Evaluate Mud Removal Criteria
1000
Determine if mud removal criteria
are met across all zones of interest.
Drilling geometry:
0.55 diameter ratio
500
0
0
20
40
60
80
100
Pipe standoff (STO), %
■Cementing versus drilling geometries:
the importance of standoff. At lower standoffs, the decrease in frictional pressure
drop in a cementing geometry—large casing in open hole—is significantly greater
than in a drilling geometry— smaller drill
pipe in open hole. Standoff, therefore, has
a double effect on annular displacement in
a cementing geometry. Both wall shear
stress and pressure drop are lower for poor
standoffs in an eccentric annulus, which
further compounds mud removal and
cementing problems. In the past, most
cementing designs used drilling simulators
that assumed a concentric annulus.
Summer 1996
high rates. Also, until a few years ago, critical flow-rate calculations assumed that casing was perfectly centered in the hole. However, the critical flow rate correction to
account for casing eccentricity is significant
and must be taken into consideration (top ).
In the early 1990s, eccentricity was first
taken into consideration in designs and in
the field by using WELLCLEAN optimal mud
removal service in the CemCADE software
(above ).
Gelled mud must be removed from the
annulus before placing cement, but mud in
the narrow side of an eccentric annulus is
often difficult to move. Casing standoff from
borehole walls is less than 100% even in
vertical wells, and frequently no higher than
85%. At low flow rates, drilling mud with
high yield stress and gel strength can be
static in the narrow gap of an eccentric
annulus because of distorted velocities,
lower frictional pressure drops and uneven
wall shear stress distribution (left ). This is
undesirable because stationary mud may gel
or dehydrate by static filtration at permeable
zones and be difficult to mobilize during
mud removal and cement placement.
Conditions leading to zero flow in narrow
annular gaps need to be defined by account9. Howard GC and Clark JB: “Factors to be Considered
in Obtaining Proper Cementing of Casing,” in Drilling
and Production Practices. Dallas, Texas, USA: American Petroleum Institute (1948): 257-272.
Haut RC and Crook RJ: “An Integrated Approach for
Successful Primary Cementations,” paper SPE 8253,
presented at the 54th SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, USA,
September 23-25, 1979.
47
ing for casing eccentricity. In the absence of
pipe movement, frictional pressure drop and
density differences are the only forces acting
to move mud. Mud yield strength must be
less than the wall shear stress generated by
frictional pressure drop from viscous forces
for mud to flow in narrow gaps. Wall shear
stress can be increased by higher flow rates,
improved standoff and increasing density differences, or mud gel strength can be
reduced before casing is run.
Another consequence of uneven velocity
profiles is coexistence of different flow
regimes. In an eccentric annulus, mixed
flow regimes are possible if critical flow rate
for turbulence is calculated, as in the past,
based on a concentric annulus, a common
assumption in drilling hydraulics models.
For fluids exhibiting yield stress and gel
strength like muds and cements, it is possible for three annular flow regimes to coexist—no flow if wall stress is less than fluid
yield strength on the narrow side of the
annulus, turbulent on the wide side and
laminar in between (right ).
40%
2 bbl/min
STO
Rate
40%
8 bbl/min
Increasing flow rate
A
B
Decreasing standoff
No flow
A
Laminar flow
Turbulent flow
■Annular flow regimes. Fluids calculated to be in turbulent flow, assuming perfectly centered casing, are now known to be turbulent only in part of the annulus. In fact, three
flow regimes—no flow, laminar and turbulent—can coexist in an annulus, which means
that mud may be removed effectively on the wide side, while on the narrow side mud is
static, resulting in a channel. Between the extremes of no flow on the annulus narrow
side and full turbulent flow around the annulus, mud removal may be poor, unless laminar flow displacements are properly designed.
60%
2 bbl/min
60%
5 bbl/min
50%
8 bbl/min
10
9
Distance from shoe, m
8
7
6
5
4
3
2
1
0
ws
ns
Cement
ws ws
Spacer
ns
ws ws
Flow Regimes
B
ns
ws ws
ns
ws ws
ns
ws
Mud
Displacement Efficiency
STO = 75%
100
■Mud, spacer and cement distribution for
various displacement rates, standoffs and
spacer properties. In the base case (far left),
mud and spacer channels were left along
the length of a simulated annulus in this
full-scale flow loop. As displacement rate
was increased, mud was displaced from
the annulus narrow side, but full cement
placement did not occur because interfacial velocity was low. Increasing standoff
(STO) had a dramatic effect on mud displacement and cement placement (middle
and bottom), but further rate increase
under these conditions did not significantly
improve cement placement. Rate is, therefore, important in mud displacement, but
less influential in cement placement. Better standoff, higher rate and a thin spacer
for more effective turbulent flow also had a
positive impact on cement placement,
highlighting the importance of proper fluid
rheology designs, especially for spacers
(far right). (From Lockyear and Hibbert, reference 2 and Tehrani et al, reference 6.)
STO = 50%
Efficiency, %
75
50
Experiment
Theory
25
0
0
1
2
3
4
5
6
7
Hole volumes pumped
48
Oilfield Review
The Annulus: Removing Mud,
Placing Cement
A better understanding of annular displacement emerged in the late 1980s and early
1990s.10 Previously, casing eccentricity, or
standoff, was not considered in designs,
even though it was known to be a factor in
channeling and primary cementing failures.
Competent cement sheaths and a good seal
depend on effective mud removal by turbulent or, under certain conditions, laminar
flow. But fluids calculated to be in turbulent
flow assuming perfectly centered pipe might
actually bypass mud in an eccentric annulus
because fluid velocities vary radially around
eccentric casing. Now CemCADE cementing design and evaluation software can be
used to make mud circulation, annular displacement and cementing recommendations based on actual well geometry, casing
standoff and fluid rheologies (right ).
Even if mud gel strength is broken during
circulation and conditioning, the question
of whether cement will flow into the narrow
annulus gap needs to be answered. If
cement flows primarily on the annulus wide
side and leaves a slow-moving mud or
spacer channel in the narrow side, good
cement placement and zonal isolation will
not be achieved. Cementing, therefore, can
be considered in two parts: mud removal
and cement placement—uniform cement
flow without channeling—which both
depend on proper displacements up the
annulus and down casing. Increasing standoff improves mud displacement and cement
placement; displacement rate is important
for effective turbulent mud removal (previous page, bottom ).
Displacing mud with spacers in turbulent
flow is one of the most effective and widely
accepted cementing techniques. Turbulentflow mud removal dates back to the 1940s.
It was subsequently recognized that turbulent scavenger displacing fluids—preflushes—placed in contact with formations
for about 10 minutes improved mud
removal. 11 Increasing displacement rate
improves turbulent mud removal. And thin,
less viscous spacers like water and surfactants that can easily be placed in turbulent
flow at low pump rates work best, probably
because of combined drag, erosion and
10. Bittleston S and Guillot D: “Mud Removal: Research
Improves Traditional Cementing Guidelines,”
Oilfield Review 3, no.2 (April 1991): 44-54.
Summer 1996
CemCADE Design and Evaluation
Fluid editor: rheologies,
slurry design, API
data, spacer design,
wash design, chemicals
and materials
Foamed cement
placement
PPA-gas migration
Enter well data
Administration, well, casing,
caliper, survey and formation
Enter fluids
Evaluate displacement
criteria using “Eccentered
Flow” screen: Turbulent or
Effective Laminar Flow (ELF)
versus hole size, standoff
and rheology
Enter all
sequences
If not
OK
Pressure margins
If OK
Centralizer data from
data base or user
enters vendor
centralizer information
If standoff
not OK
Design
centralizers
based on
eccentered
flow analysis
If standoff OK
Select pumping
rate using
“design rate
selection”
Rate not
acceptable
Acceptable rate
Enter pumping
schedule and
run simulation
Not met
View “Efficient
Time” or “Efficient
Volume” Plots
Mud removal criteria met
Prepare customer
reports, printouts
and plots
3D survey (if significant),
Efficient Time/Volume,
well security and
control, and
surface pressure plots
■Computer-assisted cement job designs. CemCADE software can be used to make mud
circulation, annular displacement and cement placement recommendations based on
actual well geometry, casing standoff and fluid rheologies.
11. Brice JW and Holmes BC: “Engineered Casing
Cementing Programs Using Turbulent Flow Techniques,” Journal of Petroleum Technology 16
(May 1973): 503-508.
Clark CR and Carter LG: “Mud Displacement With
Cement Slurries,” Journal of Petroleum Technology
25 (July 1973): 775-783.
49
dilution at interfaces due to turbulent eddies
( below left ). Chemical washes should
always be used, but weighted spacers
designed for turbulent flow—low rheologies
and temperature stability—can be used
under some conditions if required. The maximum wash or spacer volume without compromising well control should be recommended or the 10-minute annular contact
time should be used. Even moderate chemical wash volumes used with spacers reduce
mud viscosity and are preferable to spacers
alone.
Pump rates to achieve turbulence on the
annulus narrow side depend on hole dimensions and casing standoff. However, achieving turbulence around the entire annulus,
even on the narrow side, requires high
pump rates in large casing that may not be
practical because of surface equipment limits or fracture gradients. Achieving mud
removal by turbulent flow becomes harder
as hole sizes get larger and standoff
decreases, and is even more difficult when
weighted spacers are used. Turbulent flow
criteria for annular mud removal require turbulence around the entire annulus, including the narrow side, thin preflushes in contact with formations for 10 minutes, and
similar displacing and displaced fluid densities (above ).
Local to average velocity ratio
2.5
Turbulent Flow
Displacement Criteria
Preflushes in turbulence all
around the pipe
+
Preflushes in contact with
zones of interest for 10 min
+
Similar displacing and displaced
fluid densities
When turbulent flow is not an option, there
is a need for properly designed mud displacements with spacers and cement in laminar flow. These designs are more complicated, but criteria have been established to
ensure displacement efficiency (below right ).
Effective laminar flow requires positive density contrasts—10% is recommended whenever possible—a minimum pressure gradient
(MPG) to overcome mud yield stress and
positive rheological hierarchies to maintain
increasing friction pressure and minimize
differential velocity between fluids. Positive
density differential, which is independent of
hole geometry, helps generate a flatter, more
stable interface and is the first condition to
check. In cases where cement slurry density
is close to mud density and mud weight cannot be modified, spacer density range is limited and it may not be possible to meet this
criterion.
Yield stress of fluids being displaced must
be exceeded by wall shear stress. Minimum
pressure gradient defines the force needed
to move drilling fluids in the annulus narrow
gap and should also be applied prior to
cementing during mud circulation to ensure
that all the mud is moving and reconditioned. Below this force some mud remains
immobile on the narrow side of the annulus.
When mud is displaced by heavier fluids in
laminar flow, a density differential helps
meet this condition by contributing to wall
shear stress (next page, top left ). MPG verifies fluid mobility and defines a lower flowrate limit to ensure that flow occurs all
around the annulus.
The differential between frictional pressures generated by fluids should be at least
20% to increase interfacial stability. Otherwise the displacing fluid tends to bypass
fluid ahead. Under laminar flow, spacers
with higher rheologies—thicker or more
viscous than the mud—are most effective
(next page, top right ). This is equivalent to
having apparent mud viscosity lower than
that of the displacing fluid for a given flow
rate and annular geometry. The frictional
Velocity Profile
Displacing fluids:
3-lbm/bbl xanthan polymer
2-lbm/bbl xanthan polymer
0.6-lbm/bbl xanthan polymer
Water
2.0
1.5
Effective Laminar Flow
(ELF) Displacement Criteria
Minimum pressure gradient (MPG)
+
1.0
Positive density hierarchy
0.5
+
Positive frictional pressure hierarchy
0
0°
Narrow
side
90°
Position around a 50° STO annulus
180°
Wide
side
■Various viscosity fluids displacing a 3-lbm/bbl xanthan
polymer. Thin fluids like water displace thicker, more viscous
fluids because of increasing turbulence.(From Lockyear, Ryan
et al, reference 6.)
50
+
Minimum differential velocity
at interfaces
■Recommendations for ELF displacements.
These conditions should be applied to both
mud-spacer and spacer-cement interfaces
throughout the zone of interest. The differential velocity criterion is optional because it
is difficult to achieve, but should be applied
whenever possible to get good displacement up to the designed top of cement.
Oilfield Review
Displacement Efficiency
∆ρ = 16%
Displacement Efficiency
Case 1
∆ρ = 2%
75
Efficiency, %
Efficiency, %
75
50
Experiment
Theory
25
50
Experiment
Theory
25
0
0
0
1
2
3
4
5
6
0
7
2
1.5
Local to average velocity ratio
Displacing fluid specific gravity (SG):
1.6
1.29
1.16
1.0
2.0
2
3
4
5
6
7
Velocity Profile
Velocity Profile
2.5
1
Annular volumes pumped
Annular volumes pumped
Local to average velocity ratio
Case 2
100
100
1.0
0.5
Displaced fluids:
3-lbm/bbl xanthan polymer
2-lbm/bbl xanthan polymer
0.6-lbm/bbl xanthan polymer
Water
1
Displacing fluid:
3-lbm/bbl xanthan polymer
0
0
0°
Narrow
side
90°
180°
Position around a 60% STO annulus
Wide
side
■How density (ρ) affects laminar flow displacements.
Positive density hierarchies—increasing the density of each
successive displacing fluid—greatly improve mud removal
and minimize channeling because of buoyancy effects. The
greater the differential density, the better the displacement
efficiency (top left). Like the classic example of communicating vessels from basic physics where liquids come to the
same level regardless of container size or shape, denser
displacing fluids try to equalize in an eccentered annulus
(top right). Increasing displacing fluid density greatly
improves the interfacial velocity profile and displacement
efficiency as shown by various specific gravity (SG) fluids displacing a 1.0 SG fluid (bottom). (From Lockyear, Ryan et al, ref-
0°
Narrow
side
90°
180°
Position around a 50° STO annulus
Wide
side
■How viscosity affects laminar displacements. A positive
rheological hierarchy between displacing and displaced
fluids at a low flow rate (Case 2 top) results in more efficient
displacement than displacing and displaced fluids of similar
rheologies at a high flow rate (Case 1 top) Thick fluids displace
thin fluid more uniformly than the reverse. Interfacial velocity
on the annulus narrow side improves as displacing fluid plastic viscosity and yield point increase—higher rheologies—
because of the large frictional pressure drops generated by
more viscous fluids (bottom). (From Lockyear, Ryan et al, reference 2 and Tehrani et al, reference 6.)
erence 2 and Tehrani et al, reference 6.)
Summer 1996
stable interface and reduce the possibility of
one fluid fingering or channeling through
another. The sum of gravitational and friction forces for displacing fluids in the wide
side must be greater than those of the fluid
being displaced on the narrow side of the
annulus to balance forces so flow is uniform
around the annulus. This condition can be
satisfied if annular flow rate is below a critical value (right ).
Annular velocity differential can be minimized by reducing mud yield point during
conditioning, maximizing standoff, meeting
density and friction pressure heirarchy conditions by using viscous weighted spacers,
displacing at low pump rates and moving
the pipe. When displacement rates are too
high, displacing fluids tend to flow faster in
the wide side of the annulus, regardless of
gravitational effects that tend to flatten the
interface. Therefore, differential velocity cri-
Displaced mud
or spacer (1)
Pressure drop
pressure criterion is important and an initial check should be always be made. If
there is not at least a 40% friction pressure
differential between mud and cement, both
spacer and cement cannot meet this condition and rheological properties must be
changed by reducing mud yield point, density and solids contents to a minimum during mud conditioning prior to cementing or
by increasing spacer and cement rheology
(plastic viscosity and yield point). Improving casing standoff and increasing density
differentials also helps satisfy this criterion.
Friction pressure hierarchy and MPG establish minimum flow rates.
Differential velocity around the annulus at
fluid interfaces must be minimized to establish a relatively flat interface. The combination of density and frictional pressure differentials helps generate a relatively flat and
Displacing spacer
or cement (2)
V2 <
V1 Vc
Velocity
■How differential velocity affects laminar
displacements. Friction pressure develops
faster on the annulus narrow side because
of the smaller flow area (effective slot size),
so the two friction pressure curves cross,
since displaced and displacing friction
pressures increase at different rates. To
maintain a stable interface between fluids,
velocity must remain below the critical
value (Vc ) represented by the intersection
of the two curves. And displacing fluid
velocity must be less than displaced fluid
velocity.
51
teria establish maximum annular flow rates
and contradict “pump-as-fast-as-you-can”
philosophies.
Unlike turbulent displacements in which
annular flow is maintained above a critical
rate, displacements by ELF must be maintained between maximum and minimum
rates. In turbulent flow, preflush volume is
determined from the 10-minute contact time
at a critical rate. For ELF displacements,
spacer volumes should be at least 500 ft
[150 m] of annular fill, with a 60 bbl [10 m3]
minimum. Increased wellbore inclination
reduces displacement efficiency by decreasing gravitational effects, but this reduction
can be compensated for by optimizing pump
rates and fluid rheologies. Complicated laminar displacements highlight how properly
designed spacers are essential in annular
mud removal.
Down Casing: Displacing Cement
Much effort goes into selecting proper fluids, flow regimes and displacement
mechanics to remove mud from the annulus
and place cement. This usually means
pumping fluid stages with increasing densities. For downward flow inside pipe, however, a positive density hierarchy is counter
to effective displacement. Mixing and contamination occur when interfaces between
fluids are unstable or displacing fluids
bypass—fall through—fluids ahead, problems that can be overcome by using wiper
plugs for mechanical separation. Sometimes
only one bottom wiper plug is run, but more
often, none is used.
After investigation of primary cementing
failures in which fluid mixing inside casing
was a possible cause, P. Valkó performed an
in-depth study of frictional and gravitational
forces on fluids flowing downward in
pipe.12 The mechanics of heavier fluids displacing lighter fluids down casing when
wiper plugs are not used were defined, and
methods were developed to calculate displacement efficiency and interfacial boundary shapes. This project was based on earlier work involving upward flow in annuli
52
Spacer
Mud
Mud
Interfacial
boundary
■Velocity profiles for displacement inside pipe. Overall flow direction was defined to be
downward, but allowed to be locally positive (down) or negative (up). Arrows represent
velocity relative to radial position at an axial location. To compute interfacial boundary
shape, computations are made along the entire length of the pipe. A software called
Mathematica (version 2.2.3, Wolfram Research) derived displacement calculation routines for displacement efficiency versus time and interfacial boundary position at various
times during displacement, using fluid density, yield stress, plastic viscosity, pipe length
and diameter, and pump rate.
and packed, fluid-filled columns (above ).13
The software to make these calculations
uses fluid densities and rheologies along
with gravitational effects, assuming vertical,
laminar flow and no mixing.14 This software
is only qualitative and not a simulation, and
cannot determine when bottom wiper plugs
should not be run.
Problems associated with
incomplete casing displacement
Retarded (delayed) cement set time
Poor zonal isolation
Unset cement at liner tops
Lack of hard cement in “shoe tracks”
High displacement pressures from
viscous incompatible fluids mixtures
Subsequent work with this software shows
that there may be three forms of displacement inside pipe (next page, top ). Fluid
interfacial boundaries may form smooth
parabolas with moderate displacement efficiency or there may be an outer cylinder of
the first fluid that is not moving, so efficiency is lower. It is also possible to have a
region where the first fluid tends to move
upward, in opposition to primary flow, so
displacement efficiency is quite low. In
cementing applications it is not possible for
fluids in the casing to flow up because of
the cementing head, but this force can lead
to a high degree of mixing at fluid interfaces. As expected, displacement is never
completely effective, demonstrating the
need for mechanical separation—bottom
wiper plugs.
Incomplete fluid displacement inside casing is likely to mean an unsuccessful
cement job (left ). The tendency for upward
flow at interfaces can cause spacer or
cement leading edges to be contaminated or
complete mixing of mud, spacer and
cement, leading to inefficient mud removal.
Extreme viscosity increases and corresponding high pump pressures can also result if
slurries and muds are incompatible. Fluid
mixing can have disastrous results, including appearance of premature set if incompatibility is severe enough. It is also possible
for displacing fluids to bypass fluids that
were pumped ahead. This is often evident
on pressure charts in the form of early lift
pressure and from returns at the surface as
heavier fluids bypass lighter fluids and “turn
the corner”—U-tube—from the casing into
the annulus sooner than expected.
Cement contamination by spacer or mud
can change slurry rheology or retard thickening time, as evidenced by friction pressure increases during displacement or
apparent lack of set cement on evaluation
logs. In some cases, mixing may be only at
the slurry leading edge and result in lower
than expected cement tops or low-strength
cement up hole. It is also possible for tail
Oilfield Review
100
80
60
40
20
0
0
1
2
3
4
5
6
60
40
20
0
0
Normalized time, t
t=1
Displacement
efficiency, %
100
80
Displacement
efficiency, %
Displacement
efficiency, %
100
80
1
2
3
4
5
6
60
40
20
0
0
t=1
1
2
3
4
Normalized time, t
Normalized time, t
t=1
5
6
■Displacement
efficiencies (top)
and fluid interfacial
boundary shapes
when the leading edge
reaches the end of
pipe (bottom). Depending on fluid properties,
pipe (wireframe)
diameter and flow
velocity, the interface
between fluid stages
may be stable and
approach the shape of
a parabola (left). There
may be a region in
which the lighter bottom fluid is static and
the heavier top fluid is
flowing down through
the middle of the pipe
in an internal
parabola (middle).
Or there may be a
region where the
lighter fluid is flowing
upward, counter to the
primary downward
flow direction (right).
Increasing casing size or density difference between fluids
slurries to fall through lead slurries; in this
case, cement evaluation logs may show
good cement bond across most of the interval, but poor cement at the bottom, where
good, strong tail cement should be. There
may also be spotty occurrences of good and
bad cement. In some cases, no evidence of
cement may be found even after several
days because of complete mixing and retardation of cement by spacer.
Two common problems are failure of
cement to provide a seal at the shoe and
lack of hardened cement in shoe tracks
(float joints) during drill out. Shoe failure
may be related more to formation characteristics where casing is set than to cement job
quality, but there are cases when slurries
bypass spacers and the cement seal is actually being tested.
Displacement efficiency also affects
cement quality in shoe joints. If bottom
plugs are not run and cement bypasses
spacer or mud, the top wiper plug can push
bypassed spacer and mud into the shoe
joint. Since wiper plugs stop at float collars,
there may also be low-quality cement or
mixed fluids between the float collar and
float shoe. Even when bottom plugs are run,
cement may bypass other fluids in the shoe
track. Also, float collar outlet orifices establish a thin fluid jet through casing or liner
Summer 1996
joints below float collars, compounding a
difficult situation.
Sensitivity analyses using this new software indicate that effective displacement
inside casing cannot be achieved by modifying fluids without adversely affecting
annular displacements. Properties that might
influence interface shape and displacement
efficiency include average velocity, yield
point, density, plastic viscosity and pipe
size. Displacement efficiency improves as
flow velocity and yield point difference
between bottom and top fluids increase.
Efficiency decreases as fluid-density differences increase; even at similar densities,
displacement is only 70% after a pipe volume of fluid is pumped. Differences in plastic viscosity have little effect on displacements in the range of geometries and shear
rates studied. As pipe sizes increase, dis-
placements become more inefficient, and in
larger pipe sizes, reverse flow of lighter fluids causes unstable conditions.
Although there are often acceptable results
when bottom plugs are not used, theory and
field data indicate that mechanical separation at each interface is the only way to
ensure that competent fluids leave the casing and enter the annulus. This work suggests that bottom plugs should be used
whenever possible and that many undesirable results can be explained by the phenomenon of heavier fluids “falling through”
or mixing with fluids being displaced ahead
in the casing. Running bottom wiper plugs
is strongly recommended and, in critical
cases, bottom plugs should be run at each
interface (see “Using Multiple Wiper Plugs,”
next page ).
12. Valkó P: Fluid Displacement in Pipe. College
Station, Texas, USA: Texas A&M University,
October 30, 1994.
13. Flumerfelt RW: “Laminar Displacement of NonNewtonian Fluids in Parallel Plate and Narrow Gap
Annular Geometries,” SPE Journal 15 (April 1975):
169-180.
Beirute RM and Flumerfelt RW: “Mechanics of the
Displacement Process of Drilling Muds by Cement
Slurries Using an Accurate Rheological Model,”
paper SPE 6801, presented at the 52nd SPE Annual
Technical Conference and Exhibition, Denver, Colorado, USA, October 9-12, 1977.
Hill S: “Channelling in Packed Columns,” Chemical
Engineering Science 1, no. 6 (1952): 247-253.
Flumerfelt RW: in B Elvers, ed: Ullman’s Encyclopedia of Industrial Chemistry, vol. B1. Cambridge, England: VCH Publishing (1990): 4-35.
14. Wolfram S: Mathematica‚ A System for Doing
Mathematics by Computer, 2nd ed. Reading, Massachusetts, USA: Addison-Wesley Publishing Company, 1993.
53
Using Multiple Wiper Plugs
Use of the EXPRES Extrusion Plug Release
from two plugs to three plugs and to subsea
System, a next generation cementing head,
cementing using a Surface Dart Launcher (SDL)
continues to expand. This innovative design
and Subsea Tool (SST) (next page). The first
DeepSea EXPRES prototype was used off the west
automates release procedures and gives a
positive indication of plug launch. Plugs are held
Hydraulic
launcher
coast of Africa in mid-1994 and two other
in a basket below the head and inside casing so
prototypes were placed in service in the Gulf of
that cementing fluids—chemical washes,
Mexico earlier this year. Over 28 jobs have been
spacers and cement slurries—can flow around
performed with these tools. The SDL holds
the basket (right). Over 2000 lb of force from a
identical darts, which are individually released
hydraulic ram launches the plugs, minimizing
from surface during cementing jobs. These darts
chance of premature or accidental release.
launch the wiper plugs when they reach the
Mechanical stops in the launcher provide an end
downhole SST, but unlike free-falling balls, are
to each phase of the job. An oil-level gauge
pumped down drillstrings to separate fluids and
indicates launcher-rod position and gives a clear
wipe pipe walls. Other advantages over dropping
balls include positive fluid displacement and
indication of plug departure. Top plug departure
is verified by sensors mounted on the casing that
detect drillable magnets in the plug, sounding a
horn and sending a signal to the cementing unit.
Modular design, quick-latch connectors and
Clamp
2-in.
inlet
Casing
adapter
conditioning prior to cementing and the unique
Casing
collar
effects and improves mud removal. High
The heart of DeepSea EXPRES, the downhole
SST, allows use of high-performance, easily
that eliminate problems associated with pumping
fluids through wiper plugs. The tool retains wiper
plugs, preloaded in a basket with over 2000 lb
ability to launch plugs on the fly—without
interrupting pumping—which reduces U-tube
for balls to reach bottom.
drillable EXPRES plugs with simplified designs
remote operating capability save rig-up and job
execution time. This means better mud
elimination of the time and uncertainty of waiting
Wiper
plugs
force, until they are launched by arrival of a dart
from the SDL. Friction holds plugs in place during
pressure ratings allow pressure-integrity testing
pumping operations. The current design accepts
immediately after cementing, saving rig time and
up to three 8 5/8- to 13 5/8-in. plugs, or two 16- to
20-in. plugs that are under development. During
reducing possibility of forming a microannulus.
An exclusive wiper plug fin design ensures
Plug
basket
through a sliding sleeve and out two orifices into
complete fluid separation and effectively wipes
casing walls, so cement slurry reaches the float
collar without being contaminated. Exposure to
high pressure is minimized by remote control and
Wiper
plug
fins
the casing-SST annulus. When a dart reaches the
tool, drillpipe pressure forces the sliding sleeve
down, ensuring that each dart travels a full
length. Continued pumping forces the dart and
light, well-balanced modules make the EXPRES
system easy and safe to handle.
circulation, mud flows down the drillpipe,
Casing
rod down, pushing a plug out of the basket. After
a dart reaches its final position, a spring retracts
The concept, developed several years ago, of
the sliding sleeve to ensure complete,
preloading plugs in a basket has been expanded
unobstructed flow through the orifices. Darts
■EXPRES cementing head. The automated Extrusion
Plug Release System improves mud circulation and
conditioning, and cement job quality in addition to
reducing high-pressure hazards. Plugs are held in a
basket below the head and inside casing that cementing fluids can flow around. Over 2000 lb of force from
a hydraulic ram launches plugs, minimizing chance of
premature or accidental release. A safety latch prevents top plug release until the hydraulic ram begins
its final stroke.
54
remain in the holder and are retrieved with the
tool after the job.
Rod travel is slowed by a shock absorber filled
with hydraulic oil that flows past a small gap
Oilfield Review
Cement and Spacer Mixing
between the rod piston and bore. The resulting
pressure differential resists rapid movement
and stops the rod after plugs are released.
Combined with plug friction, this causes a
Sliding sleeve
1500 psi [10,350 kPa] pumping pressure increase
and provides a positive indication of plug launch.
Spring
Three brass shear pins increase top-plug release
Orifice
pressure to 3000 psi [20,700 kPa]. A sleeve
First dart
holding these pins slides down, but remains
inside the basket after the top plug leaves the
Dart holder
tool. Spacers that keep plugs from sticking
together also slide down the basket and are
Rod
retrieved with the tool.
Systems are also available to improve liner
Hydraulic
shock
absorber
Hydraulic oil
cement jobs. In the past, one pump-down plug
and a top plug were used, but new top and
bottom, four-plug systems prevent cement
contamination inside liners. Spacer is pumped
down drillpipe followed by a pump-down plug,
cement slurry, another pump-down plug and
displacement fluid. The first pump-down plug
passes through the top wiper plug and into the
Shear pins
bottom wiper plug at the top of the liner where it
latches into a catcher. Pressure shears pins
Top plug
attaching the bottom wiper plug to a mandrel and
the plug is pumped down the liner to the float
Plug basket
Plug spacers
collar. A further increase in pressure shears the
catcher from the bottom wiper plug, allowing it to
move into a circulating tube, which permits
Bottom
plug being
released
cement slurry to pass through float equipment
into the annulus. The second pump-down plug
latches into the top wiper plug, which is
displaced through the liner until it reaches the
A mixed 9 5/8- by 9 7/8-in. intermediate casing string was set at 12,673 ft [3863 m] in
the Gulf of Mexico by Anadarko Petroleum
Corporation. A bottom wiper plug was run
between mud and spacer. From all indications, pipe was cemented normally and the
job was successful. On surface, full returns
were taken and samples for quality control
set up as expected. However, two days after
cementing, while testing casing to 5000 psi,
pressure dropped to zero. After casing
integrity was checked with a packer and
found to be intact, the float shoe was
drilled, but no cement was found. After primary cementing, the well circulated around
the intermediate casing annulus during a
cement squeeze. Evaluation with CBT
Cement Bond Tool, CET Cement Evaluation
Tool and USI UltraSonic Imager logs indicated no cement with strength.
Common problems with cement hardening and over-retardation by cement additives were ruled out as causes, but tests on
cement-spacer mixtures indicated that moderate amounts of spacer could cause long
setting times. A total of 382 bbl [60.6 m3] of
cement and 80 bbl [12.7 m3] of spacer were
used. If these two fluids mixed completely,
the ratio of spacer to cement would be
about 17%. Cement contaminated by 20%
spacer attained a compressive strength of
only about 25 psi in 48 hours, which
matched the actual behavior observed in the
field. Cement-mud mixtures were even
more retarded.
Software to evaluate casing displacements
was not available during this investigation,
but mixing due to poor rheological displacement and cement retardation by
spacer were suspected. Later, displacement
calculations using these well conditions
showed that the spacer-cement interface
was unstable and displacement efficiency
bottom wiper plug where it forms a seal.
■The heart of DeepSea EXPRES. The downhole Subsea Tool (SST) allows use of high-performance, easily
drillable EXPRES plugs with simplified designs that
eliminate pumping fluids through wiper plugs. During
pumping operations, wiper plugs, preloaded in a basket with over 2000 lb force, are held in place inside a
basket until they are launched by arrival of a dart from
the Surface Dart Launcher (SDL).
Summer 1996
1. Drelkhausen H: “Quality Improvement of Liner
Cementations by Using Bottom and Top Plugs,”
paper SPE/IADC 21971, presented at the SPE/IADC
Drilling Conference, Amsterdam, The Netherlands,
March 11-14, 1991.
55
MUDPUSH XS/SALTBOND
Cement Slurry
MUDPUSH/Lead Slurry
100
80
Displacement
efficiency, %
Displacement
efficiency, %
100
80
60
40
20
0
0
1
2
3
4
5
60
40
20
0
0
6
1
2
3
4
5
6
5
6
Normalized time
Normalized time
9 5/8-in. casing
Lead/Tail Slurries
100
Displacement
efficiency, %
■Gulf of Mexico case history. On this intermediate-casing primary
cement job, a bottom plug was run between mud and spacer.
Since there was no plug between spacer and cement, cement could
mix with spacer while flowing down casing. Displacement efficiency is less than 50% when cement reaches the bottom of the
string. The interfacial boundary shape highlights the magnitude of
the problem. There is a region of no spacer flow around the inside
diameter of the pipe as cement flows down through the center. This
plot assumes no interfacial mixing, but in reality, there is probably
a high degree of interfacial mixing between the two fluids.
80
60
40
20
0
0
1
2
3
4
Normalized time
was well below 50% (above left ). Running a
bottom wiper plug only between mud and
spacer allowed cement to fall through and
mix with spacer.
Tail Bypassing Lead Slurry
In Balikpapan, Indonesia, Unocal cemented
a long, 7-in, liner with two slurries—12.5
ppg lead and 15.8 ppg tail. The liner top
was at 2240 ft [683 m] and the bottom was
at 9844 ft [3000 m]. In liner applications, of
course, an added difficulty is dropping bottom plugs, and in this case, the problem
was compounded because viscosities had to
be kept low to avoid fracturing the well due
to high friction pressures. During displacement, high frictional pressures resulted in
the premature termination of the job, leaving cement in the liner. Evaluation of displacements for this liner cement job indicated that lead slurry fell through spacer
and tail slurry fell through the lead.
Interfacial boundary shapes between
spacer and lead slurry, and lead and tail
slurries show a tendency for reverse flow of
lighter fluids at the interface in both cases,
indicating high likelihood of fluid mixing
between stages. Calculations also show
low displacement efficiencies—10 and
20% (above right ). Tests on cement and
mud mixtures resulted in high viscosities
that correlated with high displacement
pressures during the actual job.
56
7-in. liner
■Balikpapan, Indonesia case history. Efficiency plots show very
low displacement—10 and 20%, respectively—for interfaces
between lead cement and spacer, and lead and tail slurries for
cementing operations on this long liner. Interfacial boundary
plots also show a region of negative velocity, indicating high
likelihood of interfacial mixing between fluids.
Integrating Fluid Services
Quality cement jobs depend fundamentally
on the ability to predict and manage fluids
and displacement performance over a wide
range of conditions. Personnel training,
from management through engineering to
field operations, is high on the list of issues
that must be addressed to properly integrate
drilling and cementing fluids and implement total fluids management. Mud engineers do not have to run cement pumps
and cementers do not have to supervise
drilling fluids programs, but it is helpful if
each understands the other’s needs. If the
entire fluids process is to be optimized,
cooperation must develop through appreciation of needs and intentions of the other
discipline. Formal crosstraining must be
supplemented by practical experience, with
the goal of establishing wellsite “fluidsengineering” teams dedicated to optimizing
all fluid operations.
Rather than view other services from afar,
drilling fluids engineers and cementers need
to cooperate in designing structured fluid
sequences—fluids trains—for wells. At
wellsites, cementers should gain hands-on
fluids experience as backup mud engineers
and act as mentors to mud engineers during
cementing operations. At offshore and
remote locations where engineers reside on
location, this approach can be formalized
with one service-line specialist acting as
team leader in addition to performing primary product-line responsibilities. Effective
team leaders must be experts in their primary field, familiar with other disciples and
be good communicators. With available
fluids technology, efficiencies can be found
in cooperation and interfacing between fluids services, and between fluids teams and
operators. By restructuring the approach to
well construction fluids, savings are available with no up-front increase in either cost
or risk.
—MET
Oilfield Review