Oilfield Review
Summer 2003
Cased Hole Formation Evaluation
Environmentally Sound Surveys
Mechanical Earth Modeling
NMR in Real Time
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Your personal archive of Oilfield
Review, 1989 through 2002
The Oilfield Review Electronic Archive preserves
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OR_03_002_0
Toward Greener Seismic Surveys
No accidents, no harm to people and no damage to the
environment. These are the aspirations that drive the way
BP conducts its operations. Specific targets and goals are
established in support of these aspirations. For example,
all exploration and production (E&P) activities in BP now
are governed to a large degree by the ISO 14001 standards
for environmental management set by the International
Organization of Standardization.
BP is not alone in recognizing that top performance in
the areas of health, safety and environmental (HSE) management is essential for any responsible and successful
company in the E&P sector. Throughout the 1990s, oil companies and their contracting partners made great strides in
improving HSE performance. The initial focus was on safety.
By 2001, BP had reduced its lost-time injury frequency
to almost one tenth of the figure of one decade earlier.
In recent years, increasing attention has been paid to
environmental matters.
The field of seismic acquisition has featured strongly in
the drive for demonstrable excellence in environmental
management. Many countries now have a legislative policy
that requires the completion of an environmental impact
assessment (EIA), including clear mitigation processes
as well as consultation with potentially impacted parties,
before seismic work can proceed. Even where there is no
legislative requirement, most responsible operators will
have an internal requirement for an EIA.
In the offshore setting, interest is currently focused on
the question of possible physical and behavioral impacts of
seismic energy on marine mammals. In the Gulf of Mexico,
the Sperm Whale Seismic Study (SWSS), of which BP is a
cosponsor, is seeking to provide rigorous data that will
enable the seismic industry, environmental organizations
and government agencies to better understand the behavioral responses of large cetaceans to seismic signals.
Onshore seismic operations have an even greater potential for leaving a footprint on the environment, so it is
encouraging that several seismic vendors are now offering
product lines that focus on minimizing environmental
impact. BP recently operated a major 3D survey on the
North Slope of Alaska, USA, with WesternGeco as the contractor. The environmental standards required to operate
seismic surveys on the North Slope are justifiably some of
the most stringent in the world, so the project presented
an excellent opportunity for BP to test the WesternGeco
EcoSeis† system (see “Promoting Environmental Responsibility in Seismic Operations,” page 10). This system is a
tool for monitoring and tracking performance against the
requirements of clients, governmental agencies and local
communities. Inspections are conducted regularly using a
format specific to the prospect. These inspections are then
scored to measure the level of compliance. Completed
inspections are accumulated and scores plotted to show
how the crew is performing against its plan. Remedial
actions are set in place in response to low inspection scores.
For the BP North Slope project, inspections were conducted daily on the crew’s staging area, with a separate
inspection made each time the staging area was moved
to a new location. Inspections focused on drip pads being
in place, minimizing residual trash, and monitoring drips
and beverages that had spilled onto the snow. The process
had the desired outcome of ensuring negligible environmental impact.
In a world where the BP HSE goals are becoming less of
an aspiration and more of an expectation, it is good to see
that the seismic industry is providing products that will
help meet that expectation. Only by judicious partnering
with suppliers that share common goals can E&P companies hope to meet their HSE goals.
James W. Farnsworth
Technology Vice President
BP
Houston, Texas, USA
Jim Farnsworth is BP technology vice president responsible for worldwide
exploration and is also the senior manager for the BP Global Initiative for Seismic Services. Prior to this he was vice president of North America Exploration.
His other positions with BP have included vice president of deepwater exploration in Houston, Texas; Alaska exploration manager; and Central North Sea
subsurface manager. Jim obtained BS and MS degrees in geophysics and geology from University of Western Michigan and Indiana University, respectively.
† EcoSeis is a mark of WesternGeco.
Advisory Panel
Abdulla I. Al-Daalouj
Saudi Aramco
Udhailiyah, Saudi Arabia
David Patrick Murphy
Shell Technology E&P Company
Houston, Texas
Syed A. Ali
ChevronTexaco E&P Technology Co.
Houston, Texas, USA
Eteng A. Salam
PERTAMINA
Jakarta, Indonesia
Andreina Isea
Petróleos de Venezuela S.A. (PDVSA)
Los Teques, Venezuela
Richard Woodhouse
Independent consultant
Surrey, England
George King
BP
Houston, Texas
Executive Editor/
Production Editor
Mark A. Andersen
Advisory Editor
Lisa Stewart
Senior Editors
Gretchen M. Gillis
Mark E. Teel
Editors
Matt Garber
Don Williamson
Contributing Editors
Rana Rottenberg
Stephen Prensky
Design/Production
Herring Design
Mike Messinger
Steve Freeman
Illustration
Tom McNeff
Mike Messinger
George Stewart
Printing
Wetmore Printing Company
Curtis Weeks
Oilfield Review is published quarterly by Schlumberger to communicate
technical advances in finding and producing hydrocarbons to oilfield
professionals. Oilfield Review is distributed by Schlumberger to its
employees and clients. Oilfield Review is printed in the USA.
Contributors listed with only geographic location are employees of
Schlumberger or its affiliates.
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Oilfield Review
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Annual subscriptions, including postage, are
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On the cover:
A rig crew prepares a nuclear magnetic resonance logging tool for
running into a borehole. This proVISION* tool provides identification
of pay and estimates of producibility in real time. The tan portion of
the tool is one of two antennas.
*Mark of Schlumberger
Schlumberger
Oilfield Review
Summer 2003
Volume 15
Number 2
2 Evaluating and Monitoring Reservoirs Behind Casing
Advanced formation-evaluation services accurately determine porosity,
lithology, shale content, fluid saturations and pressure, and recover formation-fluid samples in cased holes. Innovative tool designs and processing
software make formation evaluation behind casing a viable option to evaluate bypassed zones, intervals that must be cased before openhole logs are
run, and the effects of time on producing zones. This article examines how
exploration and production companies cost-effectively deploy novel cased
hole services in difficult operating environments.
10 Promoting Environmental Responsibility in Seismic Operations
Land seismic operations can promote stewardship of the environment and
respect for local culture. An environmentally responsible process instituted
by WesternGeco starts in the planning stage, runs through survey acquisition, and includes postproject analysis to help plan future work. This article
describes the new approach to acquiring seismic data with examples from
North and South America, Australia and Southeast Asia.
22 Watching Rocks Change—Mechanical Earth Modeling
The state of stress in the Earth affects many aspects of hydrocarbon
exploitation. Information about rock stresses around a borehole or in a field
is usually incomplete and must be obtained by inference from a wide variety
of sources. A consistent mechanical earth model that can be updated with
real-time information is becoming essential in many difficult drilling and
development projects around the world.
40 Nuclear Magnetic Resonance Logging While Drilling
Nuclear magnetic resonance logs can now be obtained while drilling. Realtime identification of pay and predictions of producibility can be used to
place the borehole for optimal productivity. This article introduces developments in nuclear magnetic resonance logging while drilling and discusses
how operators are using this technology to place wellbores and evaluate
formations in real time.
52 Contributors
55 New Books and Coming in Oilfield Review
1
Evaluating and Monitoring Reservoirs
Behind Casing
Advanced formation-evaluation services help accurately determine porosity,
resistivity, lithology, shale content, fluid saturations and pressure, and recover
formation-fluid samples in cased wells. Innovative tool designs and processing
software make formation evaluation behind casing a viable option to evaluate
bypassed zones and intervals that must be cased before openhole logs are run.
Cased hole data reveal the effects of time on producing zones. Exploration and
production companies now are able to obtain cost-effective, useful data in
difficult operating environments.
Kevin Bellman
EnCana Corporation
Calgary, Alberta, Canada
Scott Bittner
Ankur Gupta
Sugar Land, Texas, USA
David Cameron
Bruce Miller
Stavanger, Norway
Edwin Cervantes
Anthony Fondyga
Diego Jaramillo
Venkat Pacha
Quito, Ecuador
Trent Hunter
Al Salsman
Calgary, Alberta
Oscar Kelder
Statoil
Stavanger, Norway
Ruperto Orozco
EnCanEcuador Corporation
Quito, Ecuador
Trevor Spagrud
Enterra Energy Corporation
Calgary, Alberta
2
Imagine trying to read a newspaper in a dark
room, or to sense with your hands the temperature of a baked potato or the texture of a rock
while wearing insulated gloves. Measuring rock
properties using logging tools is equally difficult
when the formation is on the other side of steel
casing and cement. Significant software and tool
developments now make possible rigorous evaluation of formations behind casing.
Advanced formation-evaluation services help
exploration and production (E&P) companies
search for additional or initially unrecognized
zones and identify bypassed hydrocarbons after
casing is set. These innovative, cased hole wireline services facilitate determining porosity,
lithology, shale content, fluid saturations and
pressure. A state-of-the-art testing tool recovers
formation-fluid samples from cased holes. The
ABC Analysis Behind Casing suite of services
offers a robust, cost-effective method for E&P
companies to analyze or monitor formations in
wells that are already cased.
Whether dealing with aging fields or new discoveries, cased hole services bolster effective
decision-making. For example, ABC services provide backup logs when openhole logging is too
risky. The tools also offer valuable data when
looking for bypassed pay in older wells or when
monitoring saturation, depletion and pressure to
optimally manage oil and gas fields.
In this article, we review cased hole formationevaluation tools and examine their effectiveness
in operations in Canada, Ecuador and the
Norwegian North Sea.
For help in preparation of this article, thanks to Darwin Ellis,
Ridgefield, Connecticut, USA; Enrique González, Quito,
Ecuador; Martin Hyden, Dwight Peters and Miguel
Villalobos, Clamart, France; Martin Isaacs, Sugar Land,
Texas, USA; and Marvin Markley, New Orleans,
Louisiana, USA.
ABC (Analysis Behind Casing), AIT (Array Induction Imager
Tool), CBT (Cement Bond Tool), CHDT (Cased Hole
Dynamics Tester), CHFD (Cased Hole Formation Density),
CHFP (Cased Hole Formation Porosity), CHFR (Cased Hole
Formation Resistivity), CHFR-Plus (Cased Hole Formation
Resistivity), CNL (Compensated Neutron Log), DSI (Dipole
Shear Sonic Imager), GPIT (General Purpose Inclinometry
Tool), InterACT, MDT (Modular Formation Dynamics Tester),
Platform Express, PowerSTIM, PS Platform, RST (Reservoir
Saturation Tool), RSTPro (Reservoir Saturation Tool for PS
Platform string), SpectroLith, TLC (Tough Logging Conditions),
USI (UltraSonic Imager) and Variable Density are marks of
Schlumberger.
Evaluation Between a Rock and a Hard Place
Given the choice, many operators prefer evaluating formations that are not yet cased. There are
many instances, however, when the risk of openhole logging is too great, or when it makes
economic sense to conduct logging operations
after drilling operations have ceased and the
drilling rig has been released. For example, in a
multiwell drilling campaign, some operators prefer
Oilfield Review
to case all the wells and evaluate them afterwards. There also are existing wells and fields in
which the potential rewards behind casing are
too rich to bypass.
In mature fields, commonly known as brownfields, operators reevaluate zones that might have
been logged decades ago using only gamma ray,
spontaneous potential and resistivity devices.
In other situations, wellbores might penetrate formations that were not logged at all. New measurements facilitate formation evaluation no matter
how old the well is. Typically, the cost of acquiring
data from these cased holes is far less than that of
drilling a new well solely to gather data. The risk
of cased hole logging operations is also substantially less than that of drilling operations.
Summer 2003
When drilling new wells, operators occasionally
encounter formations in which openholelogging conditions are difficult. Rather than risk
losing tools due to sticking in these formations,
operators may opt for cased hole formation evaluation, or they may acquire cased hole logs to
complement logs acquired while drilling. In
areas where openhole logging is difficult, operators save time and money and optimize their
formation-evaluation programs by planning
cased hole logging operations ahead of time.
Cased hole logging also helps operators
evaluate the effects of production, such as the
movement of fluid contacts, changes in saturation and pressure, and depletion and injection
profiles. An integrated suite of new and not-so-new
tools makes these types of evaluations possible
and cost-effective.
Formation Evaluation Behind Casing
Several key elements contribute to effective formation evaluation behind casing. A thorough
understanding of the condition of the casing and
cement is a prerequisite for successful evaluation.
A cement-evaluation log, ideally a combination of
USI UltraSonic Imager and CBT Cement Bond
Tool data, reveals any anomalies in the cement
sheath that might affect results from throughcasing formation-evaluation tools. Of course,
the diameter of the wellbore and completion
configuration influence logging-tool selection.
3
Skilled log interpreters incorporate completion details—wellbore geometry, tubulars, inclination angle and any downhole restrictions—
and the well-log data into production estimates
and recommendations for perforating or other
procedures, such as stimulation treatments.
These recommendations stem from a detailed
description of the formation—porosity, lithology
and fluid saturation—derived from density,
gamma ray, neutron, resistivity, sonic and spectroscopy data. Fluid-mobility data from cased
hole testers complement the petrophysical analysis. Time-lapse evaluations require two sets of
these data.
Many ABC services are available to meet
diverse customer requirements (below). To evaluate saturation, the CHFR Cased Hole Formation
Resistivity tool applies groundbreaking technologies for deep-reading resistivity measurements
beyond steel casing.1 The new CHFR-Plus Cased
Hole Formation Resistivity tool offers enhanced
hardware and measurement techniques that
improve the operational efficiency of cased hole
resistivity measurements. Both tools operate in a
Property
Logging Tools
Casing condition
USI tool and caliper devices
Cement condition
USI and CBT tools
Lithology
RST and RSTPro tools and
SpectroLith lithology
processing of spectra
Lithology
Gamma ray, density and neutron tools
Porosity
CHFD, CHFP, CNL and DSI tools
Oil content
RST and CHFR tools
Gas content
Neutron and sonic tools
Fluid identification
CHDT tool
Pressure
CHDT tool
> Components of ABC Analysis Behind Casing
services. ABC tool combinations may be selected
to complement openhole data or to achieve
specific formation-evaluation objectives.
4
similar way, by introducing current into the casing. A voltage drop occurs as a small amount of
the current escapes into the formation. The voltage drop is proportional to formation conductivity, allowing calculation of formation resistivity.
Commercially available since 2000, the original CHFR device has proved its value worldwide
for applications such as evaluation of bypassed
pay, reevaluation of old fields, reservoir and
saturation monitoring and primary evaluation of
wellbores cased before complete formation evaluation. The CHFR-Plus tool, introduced in 2002,
offers similar measurement capabilities, but at
twice the speed of the CHFR device, because of a
new measurement technique.2 To date, the CHFR
and CHFR-Plus tools have performed more than
800 logging jobs.
The RSTPro Reservoir Saturation Tool for the
PS Platform string also helps determine saturation. Formation sigma measurements are most
effective in high-salinity formation fluids for
water-saturation answers.3 As part of the RSTPro
service, SpectroLith lithology processing of
spectra from neutron-induced gamma ray
spectroscopy tools quantifies lithology interpretations.4 Carbon/oxygen logging, commonly
known as C/O logging, can give saturation results
in fresh water and in waters of unknown salinity,
for example in zones where there is ongoing
water injection and the salinity of the injected
water differs from that of the original water in
place. When made more than once on a given
reservoir, saturation measurements from the
CHFR and RSTPro devices are key elements of
time-lapse monitoring for reservoir management.
To complement saturation analyses, the
CHFP Cased Hole Formation Porosity tool measures formation porosity and sigma. This tool has
an electronic neutron source, also known as a
minitron, eliminating the need for a chemical
source. Borehole shielding and focusing allow
petrophysicists to perform environmental corrections. The CNL Compensated Neutron Log device
also may be run in cased holes, but requires more
extensive environmental corrections because it
lacks the borehole shielding and focusing of the
CHFP device.
The CHFD Cased Hole Formation Density tool
uses a new characterization of the three-detector
density device incorporated in the Platform
Express tool specifically for cased hole operations.
The DSI Dipole Shear Sonic Imager tool
provides accurate measurements of formation
compressional transit times—used to establish
porosity and as a gas indicator. The tool also
measures shear slowness—key for evaluating
mechanical properties such as wellbore or
perforation stability, hydraulic fracture-height
prediction or sanding analysis.5 DSI results can
also be used to determine stress anisotropy, a key
component for oriented fracturing. The data also
contribute to geophysical interpretations using
synthetic seismograms, vertical seismic profiles
and amplitude variation with offset analysis.
Fully combinable with other cased hole logging
tools, the DSI device operates at logging speeds
up to 3600 ft/hr [1100 m/hr]. Prior to running the
DSI tool, it is crucial to evaluate cement integrity
because a high-quality cement sheath improves
the quality of DSI results.
The CHDT Cased Hole Dynamics Tester tool is
a unique tool that measures multiple pressures
and collects fluid samples behind casing.6 The
tool drills a small hole through casing and cement
and into the formation. After measuring pressure
and collecting fluid samples, the tool plugs the
hole drilled through the casing. The device has
been used to drill more than 300 holes and has a
success rate of more than 91% when the operator
has chosen to plug the test hole. CHDT operations
Oilfield Review
0
100
400
200
300
< Location of the Snorre field, Norwegian North
Sea. The paleogeographic map (lower right)
shows that the Tampen area sits in normally
faulted, continental or lacustrine sediments of
the Statfjord formation. These complex reservoirs are now undergoing water-alternating-gas
(WAG) injection. Successful WAG operations
depend on a thorough understanding of reservoir compartments and their pressures.
600 km
400 miles
ea
0
200
S
offer a cost-effective method to optimize recompletion plans, enhance old or incomplete log data,
assess pay zones and evaluate wells for their economic potential. The tool also can be used to
monitor flood fronts and measure their effectiveness in secondary-recovery operations.
Customized software, known as the ABC
Composer, helps log interpreters prepare meaningful composite log presentations. The software
can incorporate PDS and ASCII files.7
Thorough prejob planning is essential for successful ABC services. Job preparation includes a
bit and scraper run to clear debris from the wellbore. Wellbore conditions affect certain tools
more than others. For example, in the presence
of corrosion, the CHFR tool is susceptible to poor
electrical contact with the casing. USI and CBT
logs identify potential casing corrosion, so running these tools before deploying the CHFR
device is recommended practice.
No
rt
h
SWEDEN
FINLAND
NORWAY
Snorre
Oslo
Bergen
Paleogeographic map of the Late Triassic in the northern North Sea
Stavanger
Tampen Spur and Snorre field
NORWAY
DENMARK
Bergen
Contingency Logging in Norway
To develop the Snorre field, located in the
Tampen area offshore Norway in the North Sea,
Statoil and its partners are drilling development
wells from two platforms (right).8 In the
Norwegian sector, this field is second in size only
to the Ekofisk field. Thanks in part to continual
application of new technology, the Snorre field
has been producing oil and gas for more than a
decade. Horizontal production wells drain several complex reservoirs by water-alternating-gas
(WAG) injection. WAG injection creates distinct
pressure regimes in separate reservoir compartments. Understanding these pressure regimes is
critical to effective reservoir management.
In a Snorre injection well with deviation of
63° from vertical, logging-while-drilling (LWD)
measurements were acquired from 4070 to
1. For more on the CHFR tool: Aulia K, Poernomo B,
Richmond WC, Wicaksono AH, Béguin P, Benimeli D,
Dubourg I, Rouault G, VanderWal P, Boyd A, Farag S,
Ferraris P, McDougall A, Rosa M and Sharbak D:
“Resistivity Behind Casing,” Oilfield Review 13, no. 1
(Spring 2001): 2–25.
2. The CHFR-Plus device introduces current on the side of
the casing opposite where current is flowing to reduce
the sensitivity of the measurement to the resistance of
the casing. Also, the calibration step for this device
occurs at the same time as the formation-resistivity
measurement, saving additional time.
3. Sigma is the macroscopic cross section for the absorption of thermal neutrons, or capture cross section, of a
volume of matter, measured in capture units (c.u.). Sigma
also refers to a log of this quantity. Sigma is the principal
output of the pulsed neutron capture log, which is mainly
used to determine water saturation behind casing. Sigma
typically increases as water saturation increases, or as
oil saturation decreases. For more on pulsed neutron
cased hole logging: Albertin I, Darling H, Mahdavi M,
Summer 2003
Oslo
Shetland Platform
Stavanger
pian
h
Hig
m
Gra
DENMARK
Edinburgh
100 km
Cratonic, mainly low relief
Normal fault
Continental, lacustrine sediments
Carbonate rocks
Deltaic, coastal and shallow
marine clastic sediments
Shallow-marine, mainly shales
with minor carbonate sediments
Direction of clastic influx
Plasek R, Cedeño I, Hemingway J, Richter P, Markley M,
Olesen J-R, Roscoe B and Zeng W: “The Many Facets of
Pulsed Neutron Cased Hole Logging,” Oilfield Review 8,
no. 2 (Summer 1996): 28–41.
4. The term spectroscopy refers to the study of the composition and structure of matter using various analytical
instruments to measure the emission and dispersion of
particles or energy. For more on the use of the RSTPro
device in carbonate rocks: Akbar M, Vissapragada B,
Alghamdi AH, Allen D, Herron M, Carnegie A, Dutta D,
Olesen J-R, Chourasiya RD, Logan D, Stief D,
Netherwood R, Russell SD and Saxena K: “A Snapshot of
Carbonate Reservoir Evaluation,” Oilfield Review 12, no. 4
(Winter 2000/2001): 20–41.
5. For more on DSI technology: Brie A, Endo T, Hoyle D,
Codazzi D, Esmersoy C, Hsu K, Denoo S, Mueller MC,
Plona T, Shenoy R and Sinha B: “New Directions in Sonic
Logging,” Oilfield Review 10, no. 1 (Spring 1998): 40–55.
6. For more on the CHDT tool: Burgess K, Fields T, Harrigan E,
Golich GM, MacDougall T, Reeves R, Smith S,
Thornsberry K, Ritchie B, Rivero R and Siegfried R:
Direction of intrabasinal
clastic transport
“Formation Testing and Sampling Through Casing,”
Oilfield Review 14, no. 1 (Spring 2002): 46–57.
Fields T, Gillis G, Ritchie B and Siegfried R: “Formation
Testing and Sampling Through Casing,” GasTIPS 8, no. 3
(Summer 2002): 32–36.
7. Picture Description Script (PDS) is a proprietary
Schlumberger graphics format for displaying log data.
American Standard Code for Information Interchange
(ASCII) is another industry standard for computer
data formats.
8. On January 1, 2003, Norsk Hydro turned over operatorship of the Snorre field to Statoil. For more information:
“Snorre Turns 10 With Second-Highest Remaining
Reserves” (March 6, 2003):
http://www.hydro.com/en/press_room/news/archive/
2002_08/SnorreBirthday_en.html
For more on the Snorre field: “Snorre” (March 13, 2003):
http://www.statoil.com/STATOILCOM/SVG00990.NSF?ope
ndatabase&lang=en&artid=7840C91E88FEBE93C1256B3D
003B8F41
5
Casing Condition
Cement Map
-1000.0
-500.0
0.3
2.6
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.5
7.0
7.5
8.0
Bonded
Formation
CHDT Pressures
Well Depth,
Sketch m
Hydrocarbon
0
0
200
100
400 km
200 miles
Sand
Bound Water
Internal
Radius
Average
ALBERTA
Shale Solids
4 in. 5
Effective Porosity
Hydrostatic Pressure External
1.0
vol/vol
0.0 250.0
bar
400.0 Radius
Formation Pressure Average
Clay Volume
Cement Map
0.0
vol/vol
1.0 250.0
bar
400.0 4 in. 5
Calgary
X050
11-26-34-7
well
CANADA
X100
X150
X200
X250
> Location of the 11-26-34-7 well, Caroline field, central Alberta, Canada.
X300
X350
X400
X450
X500
X550
> ABC services in the North Sea. Logging-whiledrilling (LWD) results from this Snorre well,
shown in Track 2, demonstrate alternating sand
and shale layers. This composite log is one of
many possible ways to display data acquired
using ABC services.
6
4820 m [13,353 to 15,814 ft]. Additional measurements from the DSI, MDT Modular
Formation Dynamics Tester and Platform
Express tools using the TLC Tough Logging
Conditions system were originally planned for
the entire openhole section.
The Platform Express integrated wireline logging tool, the DSI device and the MDT tool were
run in combination to acquire openhole data and
three formation pressures. The MDT pressure
measurements were sufficient to characterize
the pressure regime in the upper reservoir section. This Snorre well was not considered high
risk, but the logging tools reached a depth of just
4440 m [14,568 ft] because of hole problems,
measuring only 50 m [164 ft] of the reservoir
interval and leaving a critical 380-m [1247-ft]
interval through the remaining reservoir section
without porosity logs of any type.
The operator decided to set casing and deploy
an ABC tool suite to obtain the required data.
This ABC logging program, which was the first use
of the ABC suite, included the USI, CBT and GPIT
General Purpose Inclinometry Tool devices to
evaluate cement quality across the interval (left).
The CHFD, CHFP, DSI and GPIT devices were run
for formation evaluation. The operation was
planned and executed without problems, and
the data were transmitted using the InterACT
real-time monitoring and data delivery system for
processing by Schlumberger Data & Consulting
Services in Stavanger, Norway, and New Orleans,
Louisiana, USA, and the Schlumberger-Doll
Research Center in Ridgefield, Connecticut, USA.
The cased hole logs closely match the openhole
logs in overlapping intervals.
The operator characterizes certain wells as
high-risk because the time between drilling and
achieving zonal isolation of the reservoir units is
critical.9 Time spent running openhole logs—
primarily the MDT device for pressure data—
allows borehole conditions to deteriorate, sometimes to the degree that the casing cannot be run
successfully or cement quality is suboptimal and
zonal isolation cannot be achieved. To eliminate
this problem, the operator selected the CHDT
service to obtain formation pressures through
casing and cement.
Oilfield Review
Casing Segment
Resistance–
First Pass
0 ohm-m 0.0001
Casing Segment
Resistance–
Repeat Pass
CHFR Resistivity–First Pass
0 ohm-m 0.0001
Gamma Ray
0
API
2
Cement
Bond
150
ohm-m
2000
Cased Hole Neutron Porosity
0.45
CHFR Resistivity–Repeat Pass
2
ohm-m
2000
vol/vol
-0.15
Cased Hole DSI Delta T
300
µs/m
DSI Sonic
Coherence
100 100 µs/m 700
XX00 m
> Cased hole evaluation of primary objective, Caroline field, Canada. The CHFR resistivities (Track 3),
combined with porosity measurements from the sonic and neutron tools (Track 4), indicated high water
saturation in the primary, deeper objective near XX00 m. Since there was no gas indication from the
neutron and sonic combination, this zone was abandoned.
To date, three CHDT jobs have been completed in the Snorre field; additional jobs are
planned. These have been some of the most challenging tractor-conveyed CHDT wells in the
world.10 The first Snorre well in which the tool
was run was highly deviated—approximately
83°—and, therefore, the first ever tractorconveyed CHDT operation. It also was the first
commercial use of the CHDT tool in the Snorre
field. The second well was the first CHDT job in a
horizontal well—in this case, a well with a 95°
deviation. At 1460 kg [3219 lbm], the tool string
for that job, which included both pressure and
sampling modules, remains the heaviest
conveyed by tractor to date. Recently, the first
dual-probe CHDT tool string was run in a Snorre
well to maximize the number of test points in a
single trip. Valuable formation-pressure data
have been obtained from these three CHDT operations. The main lesson learned is that good
cement quality is crucial for a proper and reliable CHDT formation-pressure interpretation.
For high-risk Snorre production wells, formation-pressure data help establish uniform
pressure zones in the completion design and
optimize the completion-fluid weight. Without
Summer 2003
pressure data, completion-fluid weight is based
on the maximum pore-pressure prognosis for
well control. If the reservoir pressure is considerably lower than this prognosis, the well will not
flow, which delays production. In addition, the
well will require an intervention for stimulation
operations, which cost more than USD 1 million
in rig time alone.
Pressure data in the high-risk injection wells
are vital for confirming communication between
injection wells and production wells located in
the same fault block. If the reservoir pressure in
a newly drilled injector is at initial pore pressure,
then the injector is not in communication with
producing wells and will not increase oil recovery. A new injector is required—at a cost of
approximately USD 10 million—to sweep hydrocarbons from the producing reservoir.
Formation Evaluation Behind Casing
in Canada
In the Caroline field of Alberta, Canada, Big Horn
Resources, Ltd. (now part of Enterra Energy
Corp.), drilled the 11-26-34-7 well to test two
potential hydrocarbon zones (previous page,
top). A downhole bridge prevented openhole
logging tools from accessing the bottom 50 m of
the well, which was the location of the primary
objective. The secondary objective was evaluated
using openhole resistivity and porosity logs.
Big Horn Resources wanted to evaluate gasdetection indications from mud logging, but had
to run casing because of poor wellbore conditions
for openhole logging. The company planned to
gather additional reservoir information by logging behind casing, deploying the USI and CBT
tool combination to assess cement quality, the
DSI and CNL tools to determine porosity, the
CHFR tool to evaluate fluid saturations and the
CHDT device to acquire formation-fluid samples
and pressure measurements.
The primary and deeper objective—the
Elkton carbonate formation in the bottom zone
at XX00 m—proved to be nonproductive on the
basis of ABC results (above). The CHFR resistivities, combined with porosity measurements
9. For more on zonal isolation in the Tampen area: Abbas R,
Cunningham E, Munk T, Bjelland B, Chukwueke V, Ferri A,
Garrison G, Hollies D, Labat C and Moussa O: “Solutions
for Long-Term Zonal Isolation,” Oilfield Review 14, no. 3
(Autumn 2002): 16–29.
10. A tractor is a device used to convey equipment in wells
beyond the point where gravity alone would help the
equipment reach the bottom of the hole.
7
Resistivity
Decision Track
Cement Map Depth, m
Hydrostatic Pressure
4050
psi
4550
Formation Pressure
4050
psi
4550
Openhole Thermal Neutron Porosity
0.45
Bit Size
6
in.
CHFR Resistivity
16 0.2
Caliper
6
in.
API
2000 0.45
10-in. AIT-H Investigation
16 0.2
Cased Hole Gamma Ray
0
ohm-m
150 0.2
ohm-m
vol/vol
-0.15
Cased Hole Thermal Neutron Porosity
vol/vol
-0.15
Openhole Bulk Density
2000 1.95
g/cm3
90-in. AIT-H Investigation
Casing
ohm-m
in.
2000 0
2.95
20
XX50
XX75
> Cased hole evaluation of another Caroline field zone, Canada. The upper sandstone reservoir is
clearly visible in the green gamma ray curve (Track 1) above XX75 m. CHFR data (blue circles) overlay
deep-reading resistivity data (red curves) in Track 2. The operator decided to acquire CHDT pressure
data from the lower part of the sandstone (blue and red circles in Track 3). The cement map (Track 4)
guided CHDT test points. This cased hole evaluation prompted the operator to complete the well in the
lower part of the sandstone interval.
from the sonic and neutron tools, indicated high
water saturation, and since there was no gas indication from the neutron and sonic combination,
this zone was abandoned.
The secondary, upper zone at XX75 m, a
Cretaceous sandstone of the Mannville Group,
the Rock Creek formation, was expected to be
gas-bearing; its productivity was evaluated with a
CHDT sample (above). The CHDT fluid sampling
confirmed the presence of hydrocarbon in this
8
zone. On the basis of fluid-mobility estimates
(the ratio of permeability to viscosity in units of
mD/cp), however, the potential mobility of the
fluid was uncertain, but considered likely to be
low. Big Horn Resources elected to perforate this
zone using tubing-conveyed perforating technology. Pressure-transient measurements from a
flow test confirmed the low mobility estimate
from the CHDT device, so the company abandoned the upper zone. (next page, top). Without
the data from the CHDT tool, the company might
have invested over CAD 250,000 for hydraulic
fracturing and flow testing of this well.
The experience of Big Horn Resources
demonstrates that formation evaluation behind
casing can be a viable alternative to openhole
logging when wellbore conditions make openhole
logging difficult and increase the risk of sticking
logging tools in the hole while performing these
operations. For operators deciding whether to
perform expensive operations, such as well completions, stimulation or testing operations, on
the basis of incomplete formation evaluations,
ABC services are a cost-effective alternative.
Formation Evaluation in Ecuador
Openhole logging operations in the Dorine field,
Oriente basin, Ecuador, are risky and often expensive because of borehole-stability issues. The field
is in development, so the operator, AEC Ecuador
Ltd. (now EnCana Corporation), is emphasizing
rig efficiency and minimizing capital and operating expenses. AEC decided to acquire cased hole
logs for a well in which openhole logs had been
acquired several months earlier. By comparing
openhole and cased hole logs, the operator sought
to gain confidence in an evaluation technique
that would help reduce field-development costs.
Rather than spending time and money acquiring
suboptimal openhole data from difficult wells, the
operator was considering acquiring only cased
hole logs in future wells. Cased hole density,
porosity and sonic data closely matched openhole
data (next page, bottom).
Several conditions led to the high quality of
the cased hole data. The operator and
Schlumberger performed extensive prejob
planning to ensure that the well was a suitable
candidate for ABC services. Specifically, engineers checked the condition of the cement
sheath to ensure that the well was an appropriate candidate for using the CHFP, DSI and CHFD
devices. The USI and CBT tool used in combination indicated the cement quality was generally
good. Corrosion can be a particular concern
when using the CHFR device in older wells, but
the casing in this well was new.
As operations began, the wellsite crew ran
scrapers in the wellbore to remove cement
stringers or scale that might interfere with cased
hole data acquisition. Data were transmitted to
11. For more on PowerSTIM well optimization services:
Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,
Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,
Norville MA, Seim MR and Ramsey L: “From Reservoir
Specifics to Stimulation Solutions,” Oilfield Review 12,
no. 4 (Winter 2000/2001): 42–60.
Oilfield Review
Pressure, kPa
40,000
Bit penetration position
Pretest volume
120
35,000
100
30,000
80
25,000
60
20,000
40
15,000
20
10,000
0
5000
Pretest volume, cm3
Quartz gauge pressures
Strain gauge pressures
-20
0
0
2000
4000
Casing-seal test
6000
Drill casing
8000
10,000
Elapsed time, sec
12,000
Formation pretests
14,000
-40
16,000
Plug casing
> CHDT results from Caroline field, Canada. This plot of CHDT pressure versus time shows a complete
test cycle, beginning with the casing-seal test, drilling into the casing, performing multiple formation
pretests and plugging the casing. The pressure changed as soon as the tool drilled through the casing,
which is typical for this region. The USI log in this well revealed the existence of cement channels in
the zone, which might have influenced the pressure response. The test required more than four hours
to complete because of the low permeability of the zone. An openhole formation test of similar duration
would present a higher risk of sticking the tool. In this case, the logging tools were run from a service
rig, which cost much less than a drilling rig.
0
Openhole Gamma Ray
API
Openhole Bulk Density
g/cm3
Cased Hole Bulk Density
g/cm3
2.65
1.65
0
Cased Hole Gamma Ray
API
150
Openhole Thermal Neutron Porosity
0.6
0
vol/vol
Cased Hole Thermal Neutron Porosity
0.6
0
vol/vol
6
Caliper
in.
16
Openhole Compressional Slowness
µs/ft
140
40
Cased Hole Compressional Slowness
µs/ft
140
40
MD, ft
2.65
1.65
150
X060
X070
X080
X090
X100
> Comparison of openhole and cased hole density, porosity and sonic data. Openhole and cased hole
data (Tracks 2 and 3) match closely.
Summer 2003
Schlumberger Data & Consulting Services in
Quito in real time using the InterACT service.
This example from the Dorine field demonstrates
that logging after setting casing is a costeffective method of formation evaluation when
borehole stability presents unacceptable risks.
ABC services have been used elsewhere in
Ecuador. For example, an operator selected the
CHFR device to reevaluate saturation in a zone of
interest in which openhole logs indicated a relatively high water saturation; the CHFR results
indicated a lower water saturation. The ABC
services also have proved to be a critical part of
the candidate-recognition process to evaluate
wells for PowerSTIM well optimization services.11
ABC results helped determine Young’s modulus,
Poisson’s ratio and the formation-fracture gradient, which are crucial inputs for optimizing the
design of the hydraulic fracturing operations.
ABC services also have been used in wells
that had to be cased before openhole logs
were acquired.
Staying Ahead Behind Casing
As more E&P companies emphasize brownfield
activity, formation evaluation behind casing will
become more essential as a cost-effective
method to optimize production. ABC services,
including interpretation support, allow companies to acquire and interpret data and then make
informed decisions, such as sidetrack drilling,
offset drilling, well interventions, wellbore or
field monitoring, and other operations.
ABC services make it possible for E&P companies to obtain well logs in situations that
previously would have impeded or prevented
data acquisition. In adverse wellbore conditions,
such as wells experiencing borehole-stability
problems, operators now can decide to run
casing and conduct logging operations afterwards using the ABC services. For older fields,
operators may use these services to evaluate
potential pay behind pipe rather than drill a new
well simply to acquire data. Producing wells and
fields are easily monitored using ABC tools. In
many situations, planning these operations
ahead of time minimizes rig-time costs. Perhaps
the only obstacles to successful data acquisition
with these tools are well accessibility and the
condition of the casing, cement and well-completion hardware. As service companies and E&P
companies gain familiarity with comprehensive
formation evaluation through casing, they will
continue to seek first-class answers to questions
about ever-changing reservoirs.
—GMG
9
Promoting Environmental Responsibility in Seismic Operations
David Gibson
Houston, Texas, USA
As it moves into the 21st Century, the oil and gas industry is placing a high priority on
Shawn Rice
Gatwick, England
enhance efficiency in all aspects of evaluating and managing the reservoir, but also
developing and implementing new technology. The most successful advances not only
promote stewardship of the environment and respect for local cultures. A new system
for planning and monitoring land seismic operations is one such technology that is
showing remarkable results.
10
Oilfield Review
Summer 2003
> Production derricks in the Kern River field, Bakersfield, California, USA, in 1932. Development
of this field, which was discovered before the advent of seismic surveys, had a sizable impact on
the environment.
100
7
80
6
70
60
5
50
4
40
3
30
2
Million barrels of oil equivalent
8
90
Exploration success ratio, %
Finding and developing the resources to meet
the world’s demand for oil and gas has always
presented challenges to oil companies.
In the early days of exploration, deciding
where to drill for oil or gas was based largely on
surface geology and hunches. Drilling additional
wells to define reservoir extent was expensive
and intrusive; the results were unpredictable,
and in some cases, the impact on the local environment was devastating (right).
The practice has evolved considerably. Over
the years, this system of exploration drilling by
“best guess” has been replaced with science in
the form of systematic geological mapping, geochemical analysis of seeps and potential source
rocks, and seismic-surveying technology.
Seismic surveying uses acoustic waves to
obtain an image of structures beneath the surface. On land, a seismic source—usually either
vibroseis vehicles or an explosive charge—is
used to generate acoustic waves, which propagate deep into the earth. Each time a wavefront
encounters a change in rock-mechanical properties, part of the wave is reflected back to the surface, where an array of sensors records the
returning signal. The recorded information is
processed to develop an image of the subsurface.
Exploration and production (E&P) companies
use these images and attributes derived from
them to decide where to drill by identifying
subsurface rock formations that are most likely
to contain trapped oil or gas.
As an exploration technology, seismic surveying has been remarkably successful. E&P experts
rank three-dimensional (3D) surface seismic
surveys as the technology with the greatest
impact on the E&P industry. In the last decade,
since application of 3D seismic surveys became
widespread, exploration success has risen from
40% in 1992 to 70% in 2001 (right). At the same
time, the average number of barrels of oil found
per successful well has increased fourfold.
Seismic surveys have saved oil companies
millions of dollars and have helped keep fuel
prices low, but at what cost to the environment?
Acquisition of seismic data involves transitory use of the land surrounding a prospect.
Traditionally, surveys have been conducted
predominantly in the exploration cycle; however,
the data are used throughout the life of the field.
During survey acquisition, temporary—and in
rare cases, permanent—changes can occur if the
project is not managed well. Actual land use during acquisition affects only between 2.5% and
5.0% of the land surface area covered by the seismic survey.1 Depending on survey design, this
impact typically equates to between 750 and
20
1
10
0
0
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
Year
> Increasing drilling success since the introduction of 3D seismic surveys,
for a sampling of 70 exploration and production (E&P) companies from
around the world. Success ratio is the total number of exploration wells
classed as commercial success divided by the total number of wells drilled.
Another measure of exploration success is the increasing number of barrels of oil reserves added per well (green curve) since the introduction of
3D surveys. Data are taken from financial disclosures made to the United
States Securities and Exchange Commission, supplied to the Oilfield
Review by Robin Walker, WesternGeco, Gatwick, England.
1000 linear km [470 and 625 linear miles] of seismic line or between 2.5 and 5.0 km2 [0.9 and
1.8 sq miles] of the surface area per 100 km2
[39 sq miles] of area surveyed.
Although the impact is considered temporary
and mainly aesthetic, poorly performed seismic
surveys have the potential for significant ecological impact. In the last decade, heightened environmental awareness and focus by government,
industry and interest groups have increased
pressure to leave no “footprint,” or trace of
activity, following such surveys. At the same time,
For help in preparation of this article, thanks to Rhonda
Boone, Tony Bright and Robin Walker, Gatwick, England;
and Bruce Clulow and Ryan Szescila, Anchorage, Alaska,
USA. For the oil painting depicted on page 10, thanks
to George Stewart, Stewart Graphics, Ridgefield,
Connecticut, USA.
Desert Explorer, EcoSeis and Navpac are marks of
WesternGeco.
1. Sweeney DF, Hughes JR and Cockshell D: “Integrating
Environmental Impact Evaluation into a Quality, Health,
Safety and Environmental Management System,” paper
SPE 74009, presented at the SPE International Conference
on Health, Safety and Environment in Oil and Gas
Exploration and Production, Kuala Lumpur, Malaysia,
March 20–22, 2002.
11
the industry is increasingly conducting timelapse, or four-dimensional (4D), surveys.
Onshore application of 4D surveys could have
even greater environmental impact because
repeat surveys may have to be acquired before
the baseline survey area has had time to recover.2
These repeat surveys are conducted over the
same area to monitor changes in reservoir fluids
with time.
Against this backdrop of heightened environmental awareness, the industry continues to
demonstrate its commitment to protecting the
environment by insisting on safer and more
environmentally sound drilling, logging, testing
and production practices. Because most E&P
companies hire seismic contractors to acquire
geophysical data on their behalf, rather than collecting the data themselves, geophysical service
providers must also manage their operations to
prevent health, safety and environmental (HSE)
incidents. The client and the contractor must
work together to prepare HSE management plans
for each geophysical project.
To lower the risk of a potential environmental
incident during seismic data acquisition,
WesternGeco developed and introduced the
EcoSeis environmental performance monitoring
system for seismic operations. The EcoSeis system
focuses the WesternGeco quality, health, safety
and environment (QHSE) management system on
the environmental concerns in an area. This
structured and systematic approach is customized
for each seismic project to achieve a desired
low-impact environmental outcome. QHSE
experts develop project-specific environmental
processes and procedures in accordance with
client and regulatory requirements, project hazard assessments, reference guidelines, and local
cultural considerations and concerns. These processes and procedures are then monitored in real
time and compared with the desired outcome to
ensure that the project footprint is minimized.
This article describes current practices in
onshore seismic data acquisition, along with new
methods for avoiding environmental damage and
for monitoring compliance with regulatory guidelines. Case studies from around the world show
how the EcoSeis system works to minimize
survey impact and helps E&P companies acquire
data safely and cost-effectively.
Planning to Minimize Seismic Impact
The best way to begin planning a seismic survey
is to understand the needs of all interested
parties, including local inhabitants, clients, governmental regulatory bodies, nongovernmental
organizations and single-interest groups. These
parties contribute to the creation of an environmental-impact assessment (EIA), sometimes
called an environmental-impact statement
(EIS), which describes the existing conditions in
the area under consideration and any risks that
a survey may pose to flora, fauna, cultural
heirlooms or other aspects of the environment.
Many governments require compliance with EIA
documents, which typically are assembled by
specialized consulting companies and can
number hundreds of pages in length. In the
absence of governmental or client-imposed regulations, contractors usually follow their own company guidelines, and also those set by
the International Association of Geophysical
Contractors (IAGC).3
Ideally, the EIA should be seen and understood by all potential contractors before they bid
on a seismic project. Service companies that
agree to acquire a seismic survey without prior
knowledge of restrictions and environmental
requirements can encounter unexpected costs
and delays during survey acquisition. Most contractors routinely conduct preliminary scouting
investigations into potential survey areas before
bidding, to identify obstacles and difficulties.
Survey planners can then use this initial
information to design a survey that meets
geophysical as well as environmental objectives.
Often, E&P company geophysicists provide
detailed specifications regarding shot spacing
and depth, receiver line spacing and orientation,
and source type, frequency content and size.
Paleosol
> A paleosol, or ancient soil layer (darker surface), exposed by wind-blown shifting sands in Abu
Dhabi, UAE. These ancient surfaces host many kinds of easily disturbed wildlife, so seismic lines and
access roads deviate to avoid them.
12
Oilfield Review
> The Navpac portable inertial navigation unit. This navigation system, which can be carried in a
backpack, allows survey coordinates to be mapped without cutting overhead foliage to achieve
clearance for global positioning system (GPS) surveys. The unit contains a hand-held controller to
check coordinates and record data, and can be supplemented with a GPS receiver board for use in
areas where GPS can be accessed.
Major seismic contractors also have the capability to design surveys and to modify survey plans if
necessary.4 For example, the orientation of
client-specified receiver lines may need to be
changed to fit local conditions. A survey in a
desert sand-dune environment may need a
different orientation relative to prevailing wind
directions, to allow acquisition between dunes
rather than across them. In some desert environments, such as in the southern deserts of Abu
Dhabi, UAE, paleosols, or ancient soils, have
been exposed by shifting sands and made vulnerable to the elements (previous page). These paleosols, which contain fossilized coral formed in a
previous warm-water environment, are home to
many forms of modern wildlife, and need to be
avoided when deploying seismic lines.
Once a seismic contractor secures an acquisition contract and understands the survey specifications, guidelines need to be set for the crew
that will survey seismic source and receiver positions. Surveying the positions of source and
receiver lines requires access by land-surveying
experts and their equipment. In open areas, seismic crews typically survey lines by driving
lightweight trucks mounted with global positioning systems (GPS) along the predetermined grid,
then setting stakes at specified source and
receiver locations.
Summer 2003
Environmental concerns at this stage include
not only damage that may occur during the survey, but also the potential damage that the newly
created access might cause. The paths created
during a seismic survey can become unofficial
roads that subsequent visitors may use to take
vehicles into remote locations. To mitigate this
effect, and also to minimize impact on soil and
vegetation, surveying crews may drive in a weaving, or crooked-line, pattern instead of straight
lines. This practice helps reduce erosion, eliminates visual impact and discourages people from
later driving the routes taken by the vibroseis
vehicles. Vehicles also access survey lines by exiting a main road at an angle, so that survey lines
are not as visible.
In the past, surveys in areas that have significant vegetation have used bulldozers to clear
tracks for survey access. Bulldozers uproot trees
and shrubs, and are a fast and cost-effective way
to clear lines for GPS-equipped survey vehicles.
In some environments, and with landowner
consent, bulldozing remains the method of
choice for line preparation. However, new
equipment and techniques allow for lower
impact surveys to be acquired, minimizing the
amount of vegetation disturbance.
When the survey is in difficult terrain, remote
locations or environmentally sensitive areas,
conventional line preparation is often impossible
or undesirable. An alternative is the Navpac
lightweight, portable inertial navigation unit
(above). Contained in a backpack, this unit
allows surveyors to set a route without cutting
overhead foliage—otherwise needed to achieve
clearance for GPS surveys. This alternative also
allows survey lines to safely follow the path of
least resistance. The unit contains a hand-held
controller to navigate and record data, and can
be augmented by an embedded GPS-receiver circuitry board that automatically uses differential
GPS when available.
Differential GPS works by taking starting
coordinates at a known, stationary reference
point, then tracking the GPS signal as the Navpac
unit moves and sending a correction value to the
moving unit. If the GPS cannot function, such as
under dense foliage that hides the Navpac
antenna from orbiting satellites, the unit operates in inertial mode. Inertial mode uses a
rugged, precise gyroscope to keep track of all
horizontal and vertical changes in position. The
2. For more on time-lapse seismic monitoring: Pedersen L,
Ryan S, Sayers C, Sonneland L and Veire HH: “Seismic
Snapshots for Reservoir Monitoring,” Oilfield Review 8,
no. 4 (Winter 1996): 32–43.
3. http://www.iagc.org
4. Ashton CP, Bacon B, Mann A, Moldoveanu N, Déplanté C,
Ireson D, Sinclair T and Redekop G: “3D Seismic Survey
Design,” Oilfield Review 6, no. 2 (April 1994): 19–32.
13
> Laying out receiver lines (top) and planting geophones (bottom) in a
desert environment. Geophones need to be planted, rather than simply laid
on the ground, to ensure good coupling with the earth and to reduce wind
noise. The geophones are so sensitive that a gentle wind will cause noise
on the recorded traces. This survey featured a 72-geophone per group layout in a trapezoid pattern. A more typical layout is 6 or 12 geophones in a
straight line.
> Five vibroseis units at a shotpoint in a Middle East survey. These source vehicles are examples
of the Desert Explorer family of land seismic vibrators developed by WesternGeco. The proprietary
design includes safer walkways, a desert-light kit and a zero-leak refueling system. These and other
improvements provide safety and reliability and minimize environmental impact. The inset (top) shows
a source vehicle with articulated chassis, allowing stable operation in rough terrain.
14
Navpac unit compares these position changes
with the starting coordinates to give the coordinates at any new point.
The Navpac system is an excellent example of
a technology that was developed and implemented to provide efficiency gains in productivity while also minimizing the impact on the
environment. Used routinely in Canada, it has
proved to output superior surveying data in difficult terrain with a single survey pass,
minimal cutting of vegetation and improved crew
safety. It is useful in heavily forested areas,
among tall crops, under vegetation, and in urban
areas—places where surveying is difficult and
minimal impact is desired.
Once the source and receiver positions are
surveyed and marked, the recording crew
deploys receivers. These are geophones that are
planted into the ground, typically with one
geophone group plugged into the acquisition line
every 25 to 30 meters [82 to 98 ft] (left). The geophones record an analog signal; the analog
signals from each station—usually comprising 6
to 72 geophones—are grouped into one channel,
sent to a digitizer and recorded on tape. After
each day’s acquisition, quality-control specialists
perform preliminary data processing on the
digitized data to verify the suitability of the
acquisition geometry. Typically, 8 to 12 receiver
lines are active at any given time, with up to
500 channels each. In a standard survey with
12 geophones per channel, 400 channels per line
and 8 active lines, there are 38,400 geophones
deployed over a few square miles. After recording
a source position, the crew rolls the acquisition
geometry along by gathering the receivers in the
back of the survey and placing them at the front.
For explosive seismic sources, the seismic
crew drills a shot hole, typically 30 to 100 ft [9 to
30 m] deep, to contain the charge. The shot hole
has a diameter from 2.5 to 4 in. [6 to 10 cm].
Usually, the hole is drilled with a rotary drill that
is mounted on any one of a variety of carriers,
including trucks, trailers, articulating buggies,
low-impact track vehicles and all-terrain vehicles. The drill is driven or otherwise transported
from shotpoint to shotpoint. When a circulating
fluid is required, 50 to 150 gallons [190 to 570 L]
of water or mud may be needed for each hole.
Mud is recirculated and collected in a portable
mud pit. The cuttings, which may amount to
8 cubic feet [0.2 m3] per hole, are deposited back
into the borehole or spread evenly on the ground.
Since the subsurface is made up of different
5. Sweeney et al, reference 1.
Oilfield Review
types of rock layers, the cuttings can create a
patch of discolored earth that may remain for
several years. In some areas, access by truckmounted drills and associated water trucks can
require clearing heavy vegetation from a path 12
to 16 ft [4 to 5 m] wide.
In inaccessible areas, the drilling crew moves
a portable drilling system from point to point by
helicopter operations (right). Helicopter operations impose minimal additional environmental
impact on shot-hole drilling.
Finally, to detonate a charge, a member of the
acquisition crew connects a radio-controlled unit
to the charge, which is then fired remotely from
a recording truck.
The other typical seismic energy source is a
vibroseis source. Each vibroseis truck weighs
approximately 65,000 lbm [29,500 kg], but in the
desert, crews usually deploy articulated vibroseis
buggies, which are heavier (85,000 lbm)
[38,600 kg]. In all cases, the vehicles lower a
heavy plate to the ground that vibrates and
imparts energy to the earth. Two to ten such
vehicles shaking the earth in synchrony—timed
by a simultaneous radio signal to all vehicles, and
nominally at one source position—constitute a
single source point (previous page, bottom). After
generating energy at one source point, the vibroseis sources move to the next point along the
source line, which will be at some angle to the
receiver lines.
In snow-covered terrain and fragile sandy
environments, vibroseis sources can be mounted
on articulated rubber-tracked vehicles.
WesternGeco has used these in several different
environments, most recently for BP in the
Alaskan arctic. The rubber tracks help prevent
damage to delicate tundra when the vehicle
turns, and also are more effective than tires at
distributing the weight of the vibroseis unit. This
minimizes ground pressure and provides further
protection for the vegetation under the snow.
Their enhanced maneuverability provides an
additional benefit; they do not require a track to
be plowed ahead of them, further reducing the
amount of travel required when surveying a
specific location.
Planning ahead and applying the proper technology to minimize environmental impact are vital
steps in survey acquisition. The next step, measuring the success with which a seismic survey
complies with environmental requirements, can
be a difficult task. To effect this measurement,
WesternGeco has developed the EcoSeis system to
help seismic crews perform surveys while minimizing harm to the earth and to living things.
Summer 2003
> A portable drill for drilling shot holes in Bolivia. Portable drills use air
pressure for hole cleaning and often are light enough to be disassembled
and carried to the next shotpoint. In difficult terrain, this portable equipment
is transported by helicopter.
The EcoSeis System
The EcoSeis management tool helps crews
monitor and assess the environmental performance of their land seismic activities. It uses a
process called goal-attainment scaling that was
developed in the 1960s and 1970s in the USA as a
tool for monitoring and evaluation in the field of
health services.5 This tool was adapted by the
petroleum industry through collaboration
between government—Primary Industries and
Resources, South Australia (PIRSA)—industry
(Santos) and environmental interest groups.
WesternGeco used the system in Australia on
several Santos projects.
The EcoSeis method provides a credible
means for establishing environmental objectives
that are relevant and appropriate to the
activities being undertaken, and establishes a
practical means for evaluating the level of
attainment of those objectives. To allow
widespread access, the program is integrated
with the global Schlumberger QHSE reporting
system known as QUEST. Through the QUEST
database, Schlumberger personnel report all
work-related HSE observations, accidents, hazardous situations and service-quality events. The
site also documents each employee’s safetytraining record and schedule, records audits and
meetings, organizes remedial work plans and
compiles company-wide statistics.
The EcoSeis system uses an objective
approach toward environmental management
that involves establishing a set of meaningful and
measurable environmental objectives acceptable
to the geophysical service contractors and their
15
Fly Camp Exit Inspection
Prospect Area
Site Location
Department
Survey Date
All camp construction material
removed
All rubbish, burn and food-waste
pits backfilled
All toilet units backfilled
Bathing areas free of
rubbish and construction material
Site free of rubbish
Site free of signs of
pollution and spills (including
nearby water bodies)
Re-greening implemented (state
number of seedlings planted)
No signs of excessive cutting
Camp drainage system backfilled
Access routes to bathing and
toilet areas have no steps cut
into soil surface and left in place
No sign of burning in area apart
from rubbish pits
Minimal impact on surrounding area
Date of inspection
Conducted by
Client representative (if required)
Site exit score
Poor
Inadequate
Satisfactory
Good
Very Good
–2
–1
0
+1
+2
>5 open rubbish and
kitchen-waste pits
<5 open rubbish and
kitchen-waste pits
<3 open rubbish and
kitchen-waste pits
<2 open rubbish and
kitchen-waste pits
No open rubbish and
kitchen-waste pits
>10 meters
drainage system open
<10 meters
drainage system open
<5 meters
drainage system open
<2 meters
drainage system open
No drainage system open
>2 toilet facilities open
<2 toilet facilities open
All toilet facilities closed
All toilet facilities closed
All toilet facilities closed
>20 items of camp
construction material left
on site
<20 items of camp
construction material left
on site
<10 items of camp
construction material left
on site
<5 items of camp
construction material left
on site
No camp construction
material left on site
>25 items of rubbish on site
<25 items of rubbish on site
<15 items of rubbish on site
<10 items of rubbish on site
No rubbish on site
Moderate signs of
pollution or spills
Small patches or signs of
pollution or spills
No signs of pollution
or spills
No signs of pollution
or spills
No signs of pollution
or spills
Excessive signs of
impact on surrounding area
Moderate signs of
impact on surrounding area
Minimal signs of impact on
surrounding area
Minimal signs of impact on
surrounding area
No sign of impact
on surrounding area
>5 steps cut into soil
surface
<5 steps cut into soil
surface
No steps cut into soil
surface
No steps cut into soil
surface
No steps cut into soil
surface
> Scorecard for measuring goal-attainment scores using the EcoSeis environmental performance-monitoring system at a fly
camp in Indonesia. Points ranging from –2 to +2 are awarded for proper cleanup in categories including rubbish pits, toilet facilities, construction material, spills and pollution, soil disruption and visual impact on the environment.
clients, regulators and the community. The aims
of the approach include assessing environmental
activities more effectively and efficiently; achieving better environmental outcomes; providing
greater flexibility in terms of the application
of new and improved technology to achieve
environmental objectives; and assuring clients,
regulators and the community that environmental objectives are being achieved. The EcoSeis
approach is different from prescriptive environmental management systems, which outline specific practices to be followed. Instead, the
EcoSeis method focuses on the outcome.
Goal-Attainment Scaling
Goal-attainment scaling makes the EcoSeis
technique easy to apply to a variety of situations.
An important feature of goal-attainment scaling
is that all stakeholders—those individuals or
groups with an interest in the outcome—can be
16
involved in evaluating and seeking consensus on
the most important aspects of any goal, and the
likely range of desirable and undesirable outcomes of activities undertaken, environmental
or otherwise.
For each aspect assessed, outcomes are
graded on a scale of –2 to +2. It is expected that
most outcomes will meet the criteria allocated to
a score of 0. This is the level that stakeholders
agree is a satisfactory level of achievement. In
most surveys, outcomes sometimes are better or
much better than the acceptable standard. These
cases are allocated a score of +1 and +2.
Similarly, outcomes that are less than the acceptable standard are given scores of –2 and –1.
Generally, scores of +1 and –1 occur much less
frequently than scores of 0, while +2 and –2
situations occur rarely.
The occasional occurrence of a score of –1
should serve as a warning that more attention is
needed in that particular aspect of operations
and that some sort of remedial action is required.
If scores of –1 happen regularly, a systematic
problem in operations needs to be addressed.
The occurrence of a –2 situation normally indicates the need for immediate remedial action.
This may take the form of physical rehabilitation,
system review or other reporting and revision
mechanisms. The appearance of several scores of
+1 indicates that the operator and contractor are
doing a better-than-expected job. Cases of +2
indicate an ideal outcome; some degree of
commendation is warranted to reward excellent
outcomes, unless it is found that the standards
were not high enough.
An example from Indonesia shows the
EcoSeis system goal-attainment scaling in
action. In arranging a survey in a remote
location, the first step is to set up a base camp,
which will occupy the site for several months.
However, some members of the crew, including
Oilfield Review
Summer 2003
25
Line preparation
20
Number of inspections
surveyors, shot-hole drillers and the recording
crew, need to live closer to the work. Up to
1000 crewmembers may spend 10 days to several
weeks housed at a distant fly camp—named for
the fly, or tent, under which the crew lived in the
early years of seismic surveying.
For the Indonesia survey, there were no
governmental regulations, environmental impact
assessments or local restrictions to guide flycamp activities. The WesternGeco crew resolved
to treat the area containing the fly camp as they
would a campground area near home, and clean
up after themselves. They set up objective guidelines for cleanup, site inspections and compliance
definitions (previous page). Criteria for satisfactory performance—a goal-attainment score of
0—are fewer than three open rubbish or kitchenwaste pits; fewer than 5 meters [16 ft] of raindrainage system left unfilled; all toilet facilities
closed; fewer than 10 items of camp construction
material left on site; fewer than 15 items of
rubbish left on site; no signs of pollution or spills;
minimal sign of impact on the surrounding area;
and no steps cut into the soil surface.
Crew management advised crew members
and subcontractors in advance that the grounds
would be inspected as part of the cleanup process, and acquainted all staff with the guidelines
that would be used to monitor compliance.
Inspections conducted after dismantling the fly
camp showed a satisfactory level of compliance
with specified guidelines (above right). Most
inspections assigned scores of 0 to cleaned-up
conditions, and recorded few scores of –1 and
+1, with even fewer scores of –2 and +2.
In addition to helping crews assess how surveys affect land and vegetation, the EcoSeis system has been used to monitor the impact of
surveys on native inhabitants and archeological
sites. The first EcoSeis project, conducted in
Australia, ensured that the survey would not
disturb the archeological sites of native peoples.
The native inhabitants traveled on foot throughout the country, and the tracks they created are
considered archeological sites. The challenge
was to lay out a survey that avoids these sites. To
minimize impact on these sites, WesternGeco
trained bulldozer operators to recognize them.
Environmental monitoring experts revisited the
survey site one year later, and confirmed that
disrupted vegetation had grown back to cover
lines and access roads (right).
In Mexico, survey crews have discovered monticulos, or small mounds, that are manifestations
of ancient communities. Now that they are aware
that mounds may be present in many parts of the
country, WesternGeco crews scout potential
Camp site
Waste pit
15
Oil-change sites
Waste storage
10
5
0
Poor
Inadequate
Satisfactory
Good
Very good
> Compilation of inspection results after dismantling the Indonesia fly
camp, showing a satisfactory level of compliance with specified guidelines. Most inspections assigned scores of satisfactory (0) and good (+1)
conditions and recorded few scores of -2, -1 and +2.
> Photographs taken during Australia survey acquisition (top) and one year after (bottom), showing
that vegetation had grown back.
17
> An environmental brush cutter in Chad. These large mowing machines are
used to remove underbrush without damaging roots or soil. Brush cutters are
slower and more expensive than bulldozers, but have less environmental
impact. Leaving the roots in place helps reduce erosion and allows
vegetation to grow back rapidly.
> A drill buggy for drilling a small percentage of shot holes in the Bolivia survey.
survey areas, paying special attention to these
archeological features.
For a survey in an area containing these
mounds, an unsatisfactory score of –2 on the
EcoSeis scorecard would be obtained if the line
traverses and damages a monticulo. A score of –1
would result if a site is encountered and narrowly
avoided during line deployment, but not seen,
flagged or reported during line preparation. A
satisfactory score of 0 would require that every
mound be identified, flagged and reported before
the survey commences, and that survey lines
weave to avoid the site. A score of +1 could be
obtained if all sites are scouted, flagged, reported
and the coordinates logged, and the line deviates
to avoid the site by 25 m [82 ft]. A score of +2
requires that all sites be scouted, flagged,
reported and the coordinates logged, and that
the line deviate to avoid a site by 50 m [164 ft].
18
Since WesternGeco crews often venture
where no one has gone for hundreds of years,
they often encounter archeological sites that are
unknown even to government organizations.
Care is always taken to hand over maps and locations of culturally significant sites to the proper
authorities so the sites can be protected.
Minimizing Survey Footprint in Chad
The goal-attainment scaling scorecard and preand postproject photographic evidence are just
two of the QHSE management tools available for
promoting environmentally responsible actions
in land seismic acquisition. WesternGeco crews
also develop unconventional technology to
achieve their goals.
One example comes from the Doba field in
southern Chad, where WesternGeco began survey
operations in 1996. With proven reserves of more
than 1 billion bbl [159 million m3] stretched
across a heavily forested area of some 600 km2
[232 sq miles], Doba was a prime candidate for
innovative line preparation. For years, the least
expensive and most effective means for clearing
surveying lines has been the bulldozer, which
removes topsoil and roots, creates large piles of
vegetation to be cleared after surveying, and
leaves landscapes more susceptible to erosion.
Conventional swaths bulldozed every 200 m
[656 ft] over an area the size of the Doba field
would have left a gigantic grid etched in the
Earth surface.
The initiative behind developing a more environmentally friendly line-clearing method came
from the World Bank and the oil company client,
who agreed on the need to preserve the fragile
ecosystem in southern Chad. This meant
minimizing damage and discouraging future
access to the forested area. To meet that need,
WesternGeco introduced environmental brush
cutters (above left). These large industrial mowing machines reduce scrub trees and weeds to
mulch without damaging their root structure or
the underlying soils. The roots left in place and
mulch remaining on the surface reduce erosion
and allow vegetation to grow back rapidly. Brush
cutters are slower and more expensive than
bulldozers, but inflict less damage.
Photographs taken during line preparation
and at intervals after survey completion show
how quickly vegetation returns when lines have
been cleared by brush cutters (next page). After
one month, the lines are still visible, but vegetation is growing. After two months, larger plants
are beginning to flourish. Postproject assessment
has shown that survey lines are impossible to see
after 6 to 12 months. Today, even the most recent
lines are no longer visible. The same lines
cleared by a bulldozer might still be visible after
30 years.
WesternGeco crews are expanding use of
environmental brush cutters, and have deployed
them in Chad, Bolivia and the United States for
multinational operators who desire to apply the
same environmentally sound technology in
foreign locations that they would want used in
their home countries.
Beyond the Call of Duty in Bolivia
Recent seismic operations in a sensitive ecosystem in southern Bolivia followed strict standards
to minimize impact of the base camp, fly camps
and line preparation on the environment and on
the indigenous community.6 The survey, covering
1090 km2 [421 sq miles] of the Bolivian Chaco
region, adhered to the crew’s project-specific
environmental-management plan, which included
Oilfield Review
WesternGeco environmental standards, Bolivian
environmental law, the client’s policies, and
International Organization for Standardization
(ISO) Standard 14001.7
The prospect area contains a mix of desert vegetation from scrub to 20-m [66-ft] trees. In this
arid climate, with extreme temperatures ranging
from 48°C [119°F] in November to –10°C [14°F]
in June, the sparse human population exists
mainly by cattle farming. Of the 11 communities in
the region, only one has an electric generator.
Water supplies, roads and other services are in
poor condition. Every aspect of the seismic
project’s potential impact on the environment had
to be considered and monitored.
In compliance with the requirements of the oil
company client, the Bolivian government,
WesternGeco and the ISO 14001 rules, every new
employee had to complete a course on environmental education before signing a contract. Topics
covered in the course included QHSE organization
and policies, base-camp procedures, line-cutting
guidelines, waste management, handling of environmental incidents, archeological information
and environmental-restoration measures.
The base camp was constructed near a village
in an area that had been cleared previously for
seismic camps. The crew pumped water for the
camp from a well near a school, and built a watertreatment plant to produce water for cooking and
washing, along with a septic system to handle
wastewater. All solid waste—biodegradable,
petroleum-based and recyclable—was collected,
separated, weighed and disposed of according to
ISO 14001 standards and Bolivian law.8
To minimize survey impact, the maximum survey-line width was 1.5 m [5 ft]. Only trees smaller
than 20-cm [7.8-in.] diameter at a specified height
could be cut. Certain trees and cacti were classified as protected species, and could not be cut at
all. The survey design accommodated crooked-line
geometry, so any line could be moved to steer clear
of obstacles. To avoid unnecessary damage to
vegetation, the crew cut survey lines by hand—
using machetes—leaving topsoil intact.
Portable drills that use air pressure for hole
cleaning were brought in to drill almost 95% of
the shot holes. The portable equipment was light
enough to be taken apart and carried to the next
shotpoint if the terrain permitted. In dangerous
terrain, helicopters and cargo nets moved the
equipment. Drill buggies were used where possible for a small percentage of holes (previous
page, middle).
After the survey, a restoration group walked
all the lines and checked all fly camps and heliports to restore the areas to their natural states.
Summer 2003
> Environmental-monitoring photographs taken during line preparation
(top), one month after (middle) and two months after survey completion
(bottom). Vegetation returns quickly to lines that have been cleared by
brush cutters.
6. Fyda JW and Eales RM: “Using an Environmental
Management System During Seismic Activities to
Minimize Environmental Impact and Provide a Civic
Action Plan for Local Population in Proximity to a
Sensitive Bolivian Ecosystem,” paper SPE 74007,
presented at the SPE International Conference on Health,
Safety and Environment in Oil and Gas Exploration and
Production, Kuala Lumpur, Malaysia, March 20–22, 2002.
7. ISO 14001 is the first level in the ISO family of international
environmental standards. For more information:
http://www.iso.ch/iso/en/prods-services/otherpubs/
iso14000/index.html
8. Fyda and Eales, reference 6.
19
> Caribou coexisting with seismic acquisition vehicles.
This group was responsible for picking up trash,
survey flags and cap wires from shotpoints; filling
in shot holes that had blown out during survey
recording; and placing the cut vegetation on the
survey lines to act as mulch.
Sometimes, the effort to avoid environmental
damage goes beyond what is required, and entails
enhancements to the surrounding area. To help
improve some of the basic services in the area of
the Bolivia survey, the base-camp crew participated in social-action programs. The aims of the
programs were to increase community awareness
of environmental issues and help residents learn
how to improve the quality of life in this difficult
area. Through workshops at the local schools, the
inhabitants learned about measures they could
take to make their world safer and healthier.
Courses covered aspects of home and kitchen
safety, water sanitation, waste disposal and
medical-emergency preparedness. The crew
doctor visited the communities and arranged for
some patients to be transported by crew vehicles
to a distant hospital. The crew donated construction supplies to repair community buildings, delivered educational supplies to schools, repaired
roads in the area and refurbished the generator
and water pumps in the nearby community.
Social-action programs are vital to operations
in many areas. They promote good relations
between the seismic contractor, the community
and the oil company client, and ensure that the
projects conducted by the contractor help
achieve the long-term goals of the community.
Acquisition in Arctic Environments
In arctic environments, daunting conditions
require dedication, planning and experience on
20
the part of seismic crews to ensure that data
acquisition is completed safely and on schedule.
Seismic crews have been conducting surveys on
Alaska’s North Slope since the 1950s, when
WesternGeco began setting the standards for performance and safety in arctic conditions.
The arctic ecosystem is a delicate one.
Fragile tundra vegetation, if disturbed, can take
decades to grow back. Roads, rigs, pipelines and
the presence of humans can affect caribou, birds
and other migrating species (above). Human
activity can affect not only numbers but also the
geographic distribution of plants and animals.9 If
not managed properly, greater numbers of people
temporarily living on the North Slope could
potentially create more refuse for scavenging
bears, foxes, ravens and gulls. The E&P industry
has identified this concern, so refuse is well protected from access by animal species in the area.
To minimize environmental impact, arctic
land surveys are carried out during winter months
when the tundra is frozen and a blanket of snow
protects the vegetation. WesternGeco has developed special equipment, operations and training
for these harsh conditions. Vehicles on tracks,
as opposed to wheels, have been used for several years in arctic regions.10 These vehicles
are used not only to carry vibroseis sources,
but also to deploy and retrieve acquisition equipment (next page, top). Continued advances in
track technology have made it possible to use four
rubber tracks, one on each corner of an articulated vehicle, to minimize skid steering on the
delicate tundra. Wider tracks also mean lower
pressure on the ground and improved ride quality
that reduces operator fatigue and other healthrelated concerns. The plastic and wire-pin flags
that once were positioned to indicate source and
receiver points have been replaced with wooden
stakes that will biodegrade if inadvertently left in
the field.
A recent example encompassing multiple
environmental-protection efforts is the survey
WesternGeco conducted in the Greater Prudhoe
Bay Unit, Alaska, USA, for BP Exploration Alaska
(BPXA) in the winter of 2002 to 2003. The survey
was designed to augment data acquired in the
1980s and to improve the image of oil-bearing
formations, with a view to identifying new well
locations in an aging field. With improved infill
drilling, BPXA expects to enhance production
and better control natural field-production
decline. The proposed survey area included
numerous lakes and creeks and two main river
drainages, the Kuparuk and Sagavanirktok. Also,
throughout the survey area, the infrastructure of
the Prudhoe Bay oil field—flow stations, well
pads, roads and pipelines—presented potential
man-made obstacles. The survey area included
the community of Deadhorse and its airport. The
survey covered 180 sq miles [470 km2] and
mobilized a crew of approximately 80 personnel.
The crew utilized two fleets of rubber-tracked
equipment to minimize environmental impact
(next page, middle).
9. “Effects of Oil and Gas Development Are Accumulating
on Northern Alaska’s Environment and Native Cultures,”
a Report by the National Academies: March 5, 2003.
http://www4.nationalacademies.org/news.nsf/isbn/03090
87376
10. Read T, Thomas J, Meyer H, Wedge M and Wren M:
“Environmental Management in the Arctic,” Oilfield
Review 5, no. 4 (October 1993): 14–22.
11. A staging area is a piece of ground where the crew
prepares equipment before field use. The area can vary
in size from 50 by 50 m to 200 by 200 m [164 by 164 ft to
656 by 656 ft].
Oilfield Review
With so many vehicles on hand, special care
must be taken to avoid contaminating the snow
with drops or spills of hydrocarbon-based products during refueling, maintenance and ordinary
operation. A vibroseis truck circulates hydraulic
oil at pressures of hundreds of bars [thousands of
psi] to power the vibrator. If a hose breaks, up to
150 liters [40 gal] of oil may escape. Today, to
avoid any drips from the vehicles, all vehicles
carry absorbent materials that are placed underneath them when they stop. In the past, any
contaminated snow would have been scooped up,
contained, and sent along with the contaminated
absorbent materials by tracked support vehicle
or airplane to a disposal facility in the town of
Deadhorse, which is distant from many active
exploration areas.
Today, WesternGeco crews can accumulate
all contaminated snow and absorbent materials
at remote field locations and dispose of them
using a specialized waste-disposal and incineration technology. The collected liquids and
contaminated snow are drained into a computercontrolled, high-temperature separator. The
extracted water is recycled to launder shop rags
and personnel coveralls. The oil is used to fire an
incinerator burner that disposes of waste
materials and rubbish from the crew. The only
remaining waste is ash that is then packaged
at the remote site and sent to a proper
disposal location.
A tundra-monitoring program has been
implemented to help understand the complexities of this fragile ecosystem and to develop ways
to avoid long-term damage. During recent
surveys, specific metrics were put in place to
monitor staging areas, camp sites and campmove trails.11 Items monitored included drips,
spills, trash, drip pads, spilled beverages and
tundra impact, all of which were tracked on a
scorecard. Additionally, managers were required
to provide environmental monitoring and feedback through a remedial workplan for visits to
crew locations. The Alaska EcoSeis program
includes summer over-flying to monitor the
longer term impact of tundra contact. This is performed in conjunction with other stakeholders.
Monitoring has been instrumental in helping
crews minimize the footprint of seismic surveys,
prevent any potential long-term environmental
impact and educate stakeholders on the
advances in the way WesternGeco performs
surveys in this special environment.
Successful seismic surveys like the Alaska
survey for BP do not happen easily, but rather
with planning, training and rigorous attention to
detail. WesternGeco worked with BP for almost a
Summer 2003
> A rubber-tracked line-deployment vehicle. A crew member known as a
cable hand deploys seismic cable as the vehicle moves along.
> Two fleets of five vibroseis units each, deployed in the Greater Prudhoe
Bay Unit for BP Exploration Alaska.
year to plan the acquisition process and environmental activities before implementing the plans
in 2003. In 2002, the WesternGeco Alaska
procedures were audited by Det Norske Veritas
(DNV) against the International Environmental
Rating System (IERS), for which an IERS Level 5
is equivalent to the ISO 14001 standard. The
WesternGeco Alaska environmental-management process received DNV IERS certification
Level 7, indicating an improvement over existing
ISO 14001 standards. In addition, the specialized
waste-separation and incineration system won
the 2002 Commissioner’s Pollution Prevention
Award for Outstanding Achievement in Waste
Reduction, conferred by the Alaska Department
of Environmental Conservation. The wastetreatment system also received the Schlumberger
environmental excellence award for demonstrating environmental leadership and commitment.
Environmental Awareness—An Industry
Responsibility
For most communities, the arrival of the seismic
contractor is their first encounter with the E&P
industry. As such, contractor performance in
terms of health, safety and environment issues is
closely watched, and becomes the standard for
other services that follow as a prospect develops.
The geophysical industry takes this responsibility
seriously, and continues to develop technology
that promotes sound management of environmental and cultural resources.
The examples in this article highlight
methods that WesternGeco has developed in the
effort to leave no footprint. With continued focus
from the entire E&P community, similar efforts
and expectations will become the norm in the
industry. It is through cooperative effort that we
will achieve our multiple goals—preservation of
ecosystems and cultural treasures, technically
superior solutions and efficient exploration and
production of resources.
—LS
21
Watching Rocks Change—Mechanical
Earth Modeling
In many complex drilling, completion and exploitation operations today, failure to
understand a field’s geomechanics represents an expensive risk. Developing a
consistent mechanical earth model can mitigate that risk and provide benefit
throughout the life of the field.
Anwar Husen Akbar Ali
Cairo, Egypt
Tim Brown
Marathon
Oklahoma City, Oklahoma, USA
Roger Delgado
Pluspetrol
Lima, Peru
Don Lee
Dick Plumb
Nikolay Smirnov
Houston, Texas, USA
Rob Marsden
Abu Dhabi, UAE
Erling Prado-Velarde
Al-Khobar, Saudi Arabia
Lee Ramsey
Sugar Land, Texas
Dave Spooner
BP
Aberdeen, Scotland
Terry Stone
Abingdon, England
Tim Stouffer
Marathon
Moscow, Russia
22
The Earth is a stressful place. The science of
geomechanics attempts to understand earth
stresses, whether they are in a simple subsiding
basin or at the intersection of colliding tectonic
plates. A basic model might suffice in the first
case, but complex tectonic settings and other
situations encountered in the exploration and
development of hydrocarbons require increasingly
sophisticated geomechanical tools and models.
Stresses on people often lead them to change
their behavior or personality. Similarly, stresses
in the Earth often change its features, sometimes
creating conditions for hydrocarbon trapping.
Salt diapirism creates traps where porous formations abut impermeable salt; salt movement also
creates complex stress fields. Tectonic plates collide, uplifting formations into mountain ranges,
and also form conditions for hydrocarbon accumulation. The rapid deposition of sediment in
places like the Gulf of Mexico generates pressure
differentials that can result in shallow-water
flows and deeper overpressured zones, both of
which are hazards to drilling operations.1
Understanding hazards generated by stresses
in the Earth is important for safe and effective
drilling and drives the development of geomechanical models. Earth stresses also influence
other aspects of reservoir evaluation and development. Stress magnitude and orientation affect
fracture initiation and propagation. Weakly consolidated formations may fail into the wellbore
because of compressional stresses at the borehole
wall—borehole breakout. Formation compressibility can be an important drive mechanism in
weak reservoirs; the resulting subsidence can
damage surface facilities and pipelines or
decrease the gap between the bottom of an offshore platform deck and the top of the highest
waves, a potentially hazardous condition.
These few examples illustrate the need for a
coherent picture of earth stresses. Unfortunately,
data obtained within a geographic area are often
For help in preparation of this article, thanks to Usman
Ahmed, Karen Glaser and Eduard Siebrits, Sugar Land,
Texas, USA; Tom Bratton, Pat Hooyman and Gemma Keaney,
Houston, Texas; Jim Brown, BG Tunisia, Tunis, Tunisia;
John Cook, Cambridge, England; Juan Pablo Cassenelli,
Pluspetrol, Lima, Peru; Marcelo Frydman, Bogatá,
Colombia; Alejandro Martin and Julio Palacio, Lima, Peru;
Adrian Newton, Gatwick, England; Bill Rau, ChevronTexaco,
New Orleans, Louisiana, USA; and Ken Russell and
Kate Webb, Aberdeen, Scotland. Thanks also to Pluspetrol,
Hunt Oil, SK Corporation and Tecpetrol for their contributions
and release of the Camisea case.
APWD (Annular Pressure While Drilling), CMR (Combinable
Magnetic Resonance), DrillMAP, DSI (Dipole Shear Sonic
Imager), ECLIPSE, FMI (Fullbore Formation MicroImager),
FracCADE, MDT (Modular Formation Dynamics Tester),
PowerDrive, PowerSTIM, RFT (Repeat Formation Tester),
UBI (Ultrasonic Borehole Imager) and USI (UltraSonic
Imager) are marks of Schlumberger.
1. Alsos T, Eide A, Astratti D, Pickering S, Benabentos M,
Dutta N, Mallick S, Schultz G, den Boer L, Livingstone M,
Nickel M, Sønneland L, Schlaf J, Schoepfer P, Sigismondi M,
Soldo JC and Strønen LK: “Seismic Applications
Throughout the Life of the Reservoir,” Oilfield Review 14,
no. 2 (Summer 2002): 48–65.
Carré G, Pradié E, Christie A, Delabroy L, Greeson B,
Watson G, Fett D, Piedras J, Jenkins R, Schmidt D,
Kolstad E, Stimatz G and Taylor G: “High Expectations
from Deepwater Wells,” Oilfield Review 14, no. 4
(Winter 2002/2003): 36–51.
2. Andersen MA: Petroleum Research in North Sea Chalk.
Stavanger, Norway: RF–Rogaland Research (1995): 142.
3. Andersen, reference 2: 1.
Oilfield Review
Geology
Mechanical
stratigraphy
Elastic strength
10
0
Earth stress and
pore pressure
Young's
100 0 Friction angle, 70
Φ, degrees
modulus, E, MPa
Poisson's ratio, ν
1
20
UCS, MPa
400
Stress,
MPa
0
Pp
σ h σH
200 W
Direction of σH
N
E
σV
> Concept of the mechanical earth model (MEM). The first step in constructing an MEM is to understand the local and regional geology (left). The detailed
mechanical stratigraphy provides information about facies types and local deformation mechanisms (middle). From this detailed study come profiles of
elastic and rock-strength parameters including unconfined compressive strength (UCS) (right). These parameters are used to predict pore pressure, Pp,
minimum and maximum horizontal stresses, σh and σH, and vertical stress, σV. Determining horizontal stress direction is also important for drilling and
completion operations.
sparse and sometimes may even seem conflicting. In addition, stress conditions at a given well
may differ significantly from conditions at offset
wells. Experts must be able to adjust the stress
model to fit a specific location.
As complex as the state of stress can be at any
particular place, drilling a borehole and extracting hydrocarbons make this state even more
complex. Drilling and production activities alter
the local stresses, sometimes to the detriment of
reservoir-exploitation activities. Drilling removes
material from a formation, changing the nearwell stresses. Drilling over- or underbalanced,
respectively, increases or decreases formation
pore pressure. These changes can make drilling
more difficult or easier, depending on local conditions, and it is important to know in advance
which outcome is most likely. Increasing pressure in a wellbore can alter the local stresses so
much that the rock breaks. This can be good if it
is a planned hydraulic fracture or bad if it generates fluid losses while drilling. Production
decreases pore pressure, which may result in
permeability decrease or formation compaction.
These effects of depletion might not be
reversible, even if the pore pressure increases as
a result of water or gas injection.
Summer 2003
Positive or negative results can be predicted
more reliably if the stress state is understood.
Monitoring the state of stress while drilling is
particularly important in providing a measure of
local rather than offset conditions. In addition,
there often are gaps in the predrill data that continuous recording of stress conditions can fill.
Real-time stress measurement supplies key information for mitigating drilling risks. These data
are input into a mechanical earth model (MEM).
As implemented by Schlumberger, the MEM
is a logical compilation of relevant information
about earth stresses and rock mechanical
properties in an area, a means to update that
information rapidly and a plan for using the
information for drilling operations and reservoir
management. An MEM can use input from geophysical, geological and reservoir-engineering
models, but it is not simply a gridded model with
attributes assigned to each cell. The critical
additional aspect an MEM provides is a unified
view of the rock mechanical properties for a
given area (above).
This article describes construction and use of
MEMs as illustrated by examples from Peru, the
North Sea, the Gulf of Mexico, Russia, the Middle
East and Tunisia.
Planning for the Life of a Field
Geomechanics involves predicting and managing
rock deformation. Unplanned rock deformation
events cost the industry billions of dollars per year.
Lost time due to wellbore instability and tools lost
in a borehole leads to higher drilling expenditures
and delayed production. When severe, these
problems can force a company to sidetrack or
abandon a well. Poorly understood geomechanical
conditions may result in suboptimal completions
and ineffectual reservoir stimulations.
Development of the science and practice of
geomechanics has been driven by industry need.
Reservoir compaction and surface subsidence
have been severe in some North Sea chalk
reservoirs, notably the Ekofisk field, where
Phillips—now ConocoPhillips—raised platforms
6 m [19.7 ft] in 1987. The central portion of the
field had subsided another 6 m by 1994 and
several platforms were later replaced.2 Both the
Valhall—operated by Amoco, now BP—and
Ekofisk fields have had wellbore-stability problems while drilling and later during production.
Starting in 1982, some of the companies involved
in producing North Sea chalk reservoirs joined
with the Norwegian and Danish petroleum
ministries to study chalk geomechanics in a
series of Joint Chalk Research programs.3
23
Property profiled
Source logs
Other sources
Mechanical stratigraphy
Gamma ray, density, resistivity,
sonic compressional velocity (Vp)
Cuttings, cavings,
sequence stratigraphy
Pore pressure (Pp)
Vp, check-shot survey, resistivity
Interval velocity from seismic
data, formation-integrity test,
daily drilling reports
Overburden stress (σv)
Bulk density
Cuttings
Stress direction
Oriented multiarm calipers,
borehole images, oriented
velocity anisotropy
Structural maps,
3D seismic data
Minimum horizontal stress (σh)
Vp and sonic shear velocity (Vs),
wireline stress tool
Pp , leakoff tests, extended
leakoff tests, microfrac,
step-rate injection tests, local
or regional database, daily
drilling reports, modeling
Maximum horizontal stress (σH)
Borehole images
Pp , σh, rock strength, database,
wellbore stress model
Elastic parameters [Young’s
modulus (E), shear modulus (G),
Poisson’s ratio (ν)]
Vp and Vs, bulk density
Database, laboratory core
tests, cavings
Rock-strength parameters
[unconfined compressive strength
(UCS), friction angle (Φ)]
Vp and Vs, bulk density,
mechanical stratigraphy
Database, laboratory core
tests, cavings
Failure mechanisms
Borehole image, oriented
multiarm caliper
Daily drilling reports, cavings
> Sources of information used to build an MEM.
In the early 1990s, BP encountered severe
wellbore-stability problems in the Cusiana field
in Colombia.4 Conventional approaches to solving
wellbore-stability problems were ineffective in
this field. A multicompany team of geoscientists
and engineers spent almost a year compiling
sufficient geomechanical information to enable
them to improve drilling performance.
Experience gained during this project led
Schlumberger experts to develop the concept of
a mechanical earth model.5 An MEM comprises
petrophysical and geomechanical data relating
to the state of a reservoir, its overburden and
the nearby bounding layers, and, in addition, a
unified understanding of that data.
Several MEM principles originated with the
Cusiana field study. First, all available data
should be used to develop the geomechanical
model of a field. The complexity of any data
analysis must be balanced against available time
constraints and the potential value of information gained. Three specific types of information
are of key importance: failure mechanisms, state
of stress and rock mechanical properties. Finally,
real-time information to update the model, data
management and good communications are
necessary for successful execution of the drilling
program using an MEM.
24
To a great extent, the development of geomechanics has coincided with the development of
increasingly sophisticated logging tools, such as
sonic and imaging logs. An MEM uses these data,
correlations to convert from log responses to
mechanical properties, core and cuttings data,
and information from daily drilling reports and
other sources (above). The challenge is to take
the data from all these sources, organize them
within a computer system, and process and interpret them in a timely fashion to effect a positive
economic outcome.
A complete MEM is more than the sum of the
data it comprises; it is a unified understanding of
all relevant data. When information is segmented
and kept in separate sets—such as problems
encountered while drilling offset wells in one
category and seismic results in another, with
pressures measured while drilling in yet another
data set—models can be incoherent or even
inconsistent. With a unified MEM, rigorous
relationships can be applied uniformly, providing
easier access, visualization, real-time updating
and a single point for discussion as new information flows in from the rig or the production platform (see “Components of a Mechanical Earth
Model,” page 26).
The degree of detail in an MEM varies from
field to field, based on operational needs and risks.
It may be a simple, one-dimensional set of depth
profiles indicating elastic or elasto-plastic parameters, rock strength and earth stresses within the
context of the local stratigraphic section. In a more
fully developed model, lateral variations are
incorporated to generate a three-dimensional
(3D) geophysical framework incorporating a 3D
description of mechanical properties.
Of course, any MEM created before drilling
will be based on historical and offset data, so it
will inevitably contain uncertainties and be
somewhat out of date as soon as the bit hits
earth. Updating the model while drilling is vital
to reduce uncertainties, achieve proper control
4. Last N, Plumb RA, Harkness R, Charlez P, Alsen J and
McLean M: “An Integrated Approach to Managing
Wellbore Instability in the Cusiana Field, Colombia,
South America,” paper SPE 30464, presented at the
SPE Annual Technical Conference and Exhibition, Dallas,
Texas, USA, October 22-25, 1995.
Addis T, Last N, Boulter D, Roca-Ramisa L and Plumb D:
“The Quest for Borehole Stability in the Cusiana Field,
Colombia,” Oilfield Review 5, no. 2/3 (April/July 1993):
33–43.
5. Plumb R, Edwards S, Pidcock G, Lee D and Stacey B:
“The Mechanical Earth Model Concept and Its
Application to High-Risk Well Construction Projects,”
paper SPE 59128, presented at the IADC/SPE Drilling
Conference, New Orleans, Louisiana, USA,
February 23–25, 2000.
Oilfield Review
of the drilling process and obtain superior results
in subsequent development. An MEM can be
updated using newly acquired information
including logging-while-drilling (LWD) and
measurements-while-drilling (MWD) data.
Small problems encountered while drilling
can become costly when decisions must be made
rapidly based on insufficient and incomplete
information. With an MEM in place, the team can
anticipate potential trouble and check incoming
data for consistency with the model. When
problems do occur, the team can make rapid,
informed decisions and prevent minor occurrences from becoming major problems.
Sometimes stress conditions indicate that a
wellbore should be stable, but field experience
shows it is not. In these cases, an MEM provides
guidance for drilling-fluid selection. For
example, if the instability is due to sensitive,
expandable clays such as smectite, a drilling
fluid compatible with this type of formation
should be used. Often, the wellbore instability is
associated with planes of weakness, such as
bedding planes or small, centimeter-scale, preexisting fractures, and a low-fluid-loss drilling
fluid with crack-blocking additives is
recommended. In some Gulf of Mexico fields, the
safe pressure window is so small that the gel
strength of the drilling fluid must be reduced to
avoid fracturing a formation.
The investment in developing an MEM can
repay itself many times during the life of a field
(below). Most MEMs to date have been developed during a drilling program, but that is changing as more MEMs are being developed for
recompletion programs.
An actively updated MEM provides a vital tool
for managing the field throughout its life, so data
management is a key issue. Many times, operators obtain information for one purpose that can
be useful for a broader understanding of their
asset. Without a single, coherent model, engineers may be unaware of important information
that the company already has, or they may be
unaware of the potential value in the information
they have. Constructing an MEM is an important
step in extracting that value.
Schlumberger has significant expertise in
constructing and using MEMs. The company
provides geomechanics expertise worldwide,
with centers at Houston, Texas, USA; Gatwick
and Cambridge, England; Kuala Lumpur,
Malaysia; and Abu Dhabi, UAE. New technology
being developed by Schlumberger in Abingdon,
England, couples 3D stress calculations with
the ECLIPSE reservoir simulator. Within
Schlumberger, an organized geomechanics community shares knowledge through meetings and
bulletin boards, ensuring that best practices
spread quickly throughout the company.
Exploration
Delineation
Development
Auditing Camisea Data
The first step in constructing an MEM is to organize available information through a data audit.
This is more than a tabulation of quantitative and
qualitative information; the audit team seeks
understanding of potential problems in drilling
future wells or other activities. A team collects
information relating not only to a reservoir but
also to formations above, below and beside it.
Such supplementary information may be difficult
to find, because many data-acquisition programs
focus only on logging productive formations.
Much of the information in a data audit
comes from past drilling and production
experiences. A data audit proceeds through
defined steps:
1. Define target area.
2. Gather geological, geophysical and
petrophysical data associated with the
target area.
3. Review drilling, completion and production
data from offset wells, starting with those
closest to the area of interest and adding
relevant information from other wells
farther away.
4. Review this data to determine the nature of
any previous drilling, completion or production problems and their probable cause.
5. Determine the need for additional data to
construct an MEM.
6. Summarize the results.
Exploitation
Enhanced
Recovery
Pore pressure
Fractured reservoirs
Wellbore stability
Well placement
Casing point
Drill-bit selection
Drilling fluid
Compaction and subsidence
Completion method
Sand control
Drilling waste
Multilateral design
Horizontal wells
Reservoir stimulation
Enhanced recovery
Diagnosis of failures
> Value of MEM for life-of-field activities. The bars indicate the usefulness of an MEM for determining
the indicated properties or performing the indicated activities during different stages of oilfield activities.
Summer 2003
25
Components of a Mechanical Earth Model
Schlumberger spent several years developing a process for constructing a mechanical
earth model (MEM). Although the details
vary depending on the availability of data
and specific business needs for a given situation, the methodology carries across a variety
of instances.
The first step in the method is to accumulate and audit available data. All the relevant
information is combined into a consistent
framework, the MEM, that allows prediction of
geomechanical properties—such as stresses,
pore pressure and rock strength.
Some stress components in a formation
can be measured directly, and others can be
derived from known quantities, but some
must be estimated based on correlations
(above right). Core tests determine the
unconfined compressive strength (UCS) and
some other quantities, such as friction angle
and Poisson’s ratio, ν.1
Vertical stress, σV, is often obtained by integrating the density through the overburden.
In some cases, shallow formations are not
logged, so an exponential extrapolation of vertical stress sometimes is used to model the
unlogged region.
The pore pressure, Pp, and minimum
horizontal stress, σh, can be determined from
formation-integrity tests (FITs) and minifracs,
such as those obtained using an MDT Modular
Formation Dynamics Tester tool in a dualpacker stress-test configuration. Measurements
of these quantities at specific points calibrate
log correlations throughout the formations.
Stress models, such as the Mohr-Coulomb
model, are often used to relate σh to Pp, σV,
and the internal friction angle. Other correlations also can be used, but they require additional input parameters that are often
difficult to obtain. The internal friction angle
can be correlated to clay content obtained
from logs.
26
The maximum horizontal stress, σH, cannot
be determined directly, so clues must be evaluated to determine the best correlation
within a chosen stress model. Information
relating to constraints on σH includes the
presence or absence of borehole breakouts,
minifrac measurements, rock strength and
local or regional databases.
The direction of σH is important for wellbore-stability determination and for fracture
orientation. Seismic data provide information
about regional stress direction by indicating
tensile and compressional faults and features
related to those earth stresses. However, proximity to such faults and major features—such
as the Andes Mountains—may alter both the
magnitude and direction of local stresses,
even if forming such a feature did not alter
the regional stress.2 A local measure of stress
direction is often needed to supplement the
regional information. Faults and natural fractures can be interpreted from UBI Ultrasonic
Borehole Imager data.
By recording data in crossed-dipole mode, a
DSI Dipole Shear Sonic Imager tool indicates
the direction of σH. Shear waves traveling
through a formation split between fast-traveling waves moving along the stiffer σH direction
and slower waves along the more compliant σh
direction. The data also provide a measure of
the azimuthal stress anisotropy.
Young’s modulus can be determined from
compressional and shear velocities recorded
by acoustic logs. However, there is a difference between this dynamic Young’s modulus
and the static Young’s modulus in a test on
core material.3 To use this information to
obtain rock strength, commonly in the form of
the UCS, two correlations are used. First is
the conversion from dynamic modulus to
static modulus, then the transformation from
static modulus to UCS.
σV –density logs
σh –minifracs
σH –correlation
Pp –MDT measurement
> Stress state. The vertical stress, σV, is normally obtained by integrating a density log
from the surface. The minimum horizontal
stress, σh, can be obtained from minifracs, and
the pore pressure, Pp, from an MDT Modular
Formation Dynamics Tester measurement. The
maximum horizontal stress, σH, must be
obtained from correlations to logs.
Tensile strength, T, in most formations is
assumed to be about one tenth of the compressive strength. In some situations, such as
opening a preexisting fracture, the tensile
strength of the rock body is zero.
These mechanical properties are useful
for drilling, completion and production activities. One important question in drilling
that the MEM answers is the range of mud
weights that can be used safely without damaging a formation.
A formation shears at the borehole wall if
the wellbore pressure drops below the formation breakout pressure (next page, top). The
gradient of breakout pressure is determined
from Pp, σH, σh, T and ν. The breakout gradient typically defines the minimum mud
weight for safe drilling.
The maximum mud weight for safe drilling
is usually obtained from the fracture gradient.
This maximum mud weight is one that creates a
borehole pressure that exceeds the sum of the
formation tensile strength and the tangential
stress at the borehole wall (next page, bottom).
Oilfield Review
A safe drilling window is the range of mud
weights between the breakout pressure and
the fracture pressure, including a safety factor when possible. Combining the breakout
and fracture gradients with the direction of
maximum horizontal stress provides a key
input for stability of deviated and horizontal
wells. The most stable direction is usually
along the minimum horizontal stress direction.
With the stress gradients and formation
properties defined, the MEM is ready for
geomechanics experts to use to make predictions. A DrillMAP drilling management and
process software plan, developed from the
MEM, indicates the locations and types of
expected risks, along with a means to mitigate those risks. New information can be
compared with predictions from the MEM.
Anomalies between the new information and
the model provide opportunities
for improving the model and ultimately for
improving understanding of the field.
1. Unconfined compressive strength is the maximum
value of axial compressive stress that a material can
withstand, under the condition of no confining stress.
2. For mathematical details of stress changes near
faults: Jaeger JC and Cook NGW: Fundamentals of
Rock Mechanics. London, England: Chapman and Hall,
Ltd. and Science Paperbacks (1971): 400–434.
3. A dynamic modulus is derived from a traveling acoustic wave with a frequency of a few kilohertz, perturbing the material at a constant stress. A static modulus
is derived from laboratory tests performed at
extremely low rates of stress change, but over a much
larger stress range.
Minimum horizontal
stress (σh)
Borehole
Borehole breakout
Maximum
horizontal
stress (σH)
σH
Drilling-induced
fractures
σh
> Stress direction and borehole damage. Drilling-induced fractures can occur
along the maximum horizontal stress direction if the mud weight is too high.
Borehole breakouts can occur in the minimum stress direction when the mud
weight is too low.
MW
Pore
pressure
ESD
Minimum
ESD
ECD
Minimum
horizontal
stress
Fracture
pressure
> Schematic of breakout and fracturing gradients. The equivalent static density (ESD) is greater than the mud weight (MW), due to cuttings in the mud and
mud compressibility. The equivalent circulating density (ECD) also includes
dynamic effects. Both ESD and ECD should stay within the safe window
(green on bar). The illustrations indicate the type of failure possible within
each stress regime (top). The middle condition is a stable borehole. Moving to
mud weights less than the minimum ESD (left), the formation can break out
into the wellbore in shear failure; if it drops below the pore pressure, well control can be lost, a severe condition. At mud weights greater than the stable
range (right), ECD could exceed the minimum horizontal stress, generating
tensile damage in the formation; if it exceeds the fracture pressure, a fracture
can propagate into the formation.
Summer 2003
27
A data audit is primarily a data review and
summary, but it also identifies gaps in information needed to prepare an MEM. Missing data
can be highlighted and prioritized for collection
in the next drilling or data-collection program.
In many cases, consolidating information into
a 3D graphical format is the best way to appreciate the amount and quality of data available.
Geophysical and geological interpretations,
including locations of faults and formation tops,
can be combined with qualitative or quantitative
information obtained from drilling reports and
mud-log data. Problem zones and geologic event
locations are easier to correlate when both types
of information are combined into one 3D display.
Predrill data—When Pluspetrol and its partners Hunt Oil Company, Tecpetrol and SK
Corporation received rights to the Camisea block
in the Peruvian Andes, they also obtained a large
quantity of information from another company
that had explored in the block previously (below
left). Because the target in this block along the
San Martin anticline lies atop an environmentally sensitive rain forest, the partners had to use
existing development locations, or pads, on the
surface. New trajectories would be deviated to
reach targets from these pads.
PERU
And
es
M
ou
nt
The earlier wells had been difficult to drill,
with severe wellbore-instability and lost-circulation problems. Wells took 60 to 120 days to drill
and complete because of stuck-pipe incidents,
delays caused by LWD tools lost in the hole and
the need to drill sidetracks.
Pluspetrol asked Schlumberger to complete a
data audit for the prospects in the block.
Pluspetrol provided 40 compact discs (CDs)
containing a wide variety of data from previous
wells (below right). Wireline logs cover most of
the depth range, although there is scant log
coverage from surface to about 1700 m [5600 ft]
(next page, top).
Drilling data from the CDs were classified by
type of drilling event or problem:
• Act of God: for example, the rig being shut
down because of torrential rains, electrical
thunderstorms or small earthquakes
• Bit and bottomhole assembly (BHA): for example, low rate of penetration and undesired build
or drop tendencies
• Equipment: events relating to rig-equipment
performance, for example, pump or topdrive
failures
• Hole cleaning
• Kicks and influx, including gas influx into
drilling mud
ai
ns
Camisea prospect
SOUTH AMERICA
+1000 SE
Type
Regional
Tectonic setting
Regional structure
Basin history
1
1
2
Drilling
Daily drilling reports
End-of-well reports
Mud logs
Bit records
Bottomhole-assembly
records
Well surveys
2
1
2
2
2
Geology
Structure maps
Seismic interpretations
Well-location maps
Formation tops
Lithologic descriptions
Core descriptions
Geological studies
Formation pressures
1
2
1
1
3
2
2
2
Geophysical
Seismic lines
Check-shot surveys
Wireline logs
1
2
3
NW
SM-1004
Sea
level
Depth, m
Class
13 3⁄8-in.
Vivian
Basal Chonta
Upper Nia
Lower Nia (fluvial)
Lower Nia (eolian)
Shinai
Upper Noi
Lower Noi
Ene
Copacabana
Ranking
1
-1000
11 3⁄4-in.
9955⁄8⁄8-in.
-in.
-2000
> Camisea prospect, Peru. The Camisea prospect is located in the Andes Mountains (top). The well
trajectories for most of the wells in the drilling program were directionally drilled from a few pads to
minimize ecological impact at the surface (bottom).
28
> Camisea information ranked by class and type.
The qualitative ranking indicates the value of
existing data for drilling planning. Rank 1 information is of sufficient quality and depth coverage
to meet drilling-planning objectives. Rank 3 indicates that significant gaps exist in the type and
coverage of data; Rank 2 is of intermediate value.
Oilfield Review
• Downhole mud losses, typically losses greater
than 10 bbl [1.6 m3] per incident
• Leakoff or formation-integrity tests
• Stuck-pipe incidents
• Tight-hole and wellbore-stability problems,
including excessive backreaming, reaming
while tight in hole or packoffs.
The analysis indicated that tight hole and
wellbore-stability problems caused more than a
third of the events and occupied 36% of the nonproductive time. Other major causes of drilling
problems included bit and BHA, equipment and
stuck-pipe events.
Stresses—With the drilling events identified,
the audit team began evaluating the stress conditions. The direction of the local maximum horizontal stress is NNE. This is almost orthogonal to
the regional stresses that created the Andes
mountain range. These regional stresses uplifted
the mountains and altered the texture of the
rocks, for example by generating fractures. This
conclusion from the audit pointed to an important
question that needed to be resolved: Is wellbore
deformation dominated by local stresses or by
effects the regional tectonics had in creating the
rock structure? This question was answered later
using data obtained while drilling the first well.
Geologic information was put into a 3D visualization model. This model demonstrated the
thrust and fold structure in the formation tops of
the overburden (right). The audit for Camisea
underscored the importance of understanding
the state of stress throughout the depositional
history. It indicated that there was a period
sometime between reservoir deposition and the
present when both maximum and minimum horizontal stresses exceeded the vertical stress.
These intense compressive paleostresses generated evidence such as fractures that were present in the geologic record.6
Fractures in cores taken from nearby wells
provided information on the stress state. The
presence of low-angle shear fractures that are
parallel to bedding is consistent with concentric
folding, so those fractures probably developed
during regional tectonic folding. However, the
Noi and Nia formations contain normal shear
fractures, so locally the maximum paleostress
was vertical when the fractures were formed.
This must have occurred after initial folding
absorbed some of the tectonic compression and
caused the principal stresses to rotate.
Furthermore, tensile fractures instead of normal
shear fractures present in the uppermost, competent Vivian formation indicate that further
folding and stretching must have increased
Summer 2003
1
2
3
4
5
6
7
8
9
10
11
12
> Montage of available well-log data. These logs from 12 offset wells indicate gamma ray (green) and
caliper (black) in the first track of each set; resistivity (red and black) in Track 2; and sonic (green),
neutron porosity (blue) and density (red) in the third track. The blue bands to the right of Track 1—in
well logs 1, 2, 3, 4 and 12—show where FMI Fullbore Formation MicroImager data are available. The
red bands to the left of Track 2—in well logs 3, 5 and 12—show depths at which USI UltraSonic
Imager or UBI Ultrasonic Borehole Imager data are available. The logs are aligned by depth.
W
N
σH
σh
N
> Eastward view through the Camisea San Martin anticline and thrust-fault system. The folds in the
top of the Noi and Ene formations (white surface) indicate regional deformation from compressive
stresses. The other colored surfaces show fault locations. The trajectories of previously drilled wells
(black) start at the surface of the Earth at the well location, and a white dash on the trajectory indicates sea level. The maximum horizontal stress direction is NNE (inset).
the deviatoric stresses.7 The folding of a thick,
underlying, competent formation, possibly the
Copacabana, created a concentric folding of the
reservoir formations. The resultant movement
probably relieved some of the horizontal stress in
the Camisea block. Today, the vertical stress is
the maximum principal stress.
Risks—The final stage of the data audit was
to predict potential drilling risks. Most stuckpipe events had occurred in deviated boreholes,
6. Paleostress indicates the stress state at the time of
deposition or some other time before the present.
7. Deviatoric stress is a measure of the differences
between principal stresses.
29
2
1
3
Drilling
difficulty
90
Horizontal
1.45
80
1.40
5
σh
1
3
2
4
4
5
1.35
60
1.30
SM1002
1.25
50
SM1004
1.20
40
1.15
More difficult
σH
Inclination, degrees
70
30
1.10
20
1.05
1.00
10
SM1001
Vertical
0
0
σH
10
0.95
20
30
40
50
Azimuth, degrees
60
70
80
90
σh
> Drilling-trajectory risk map. Drilling risk changes according to the orientation of a wellbore relative to the major stresses and incidence angle of the trajectory to bedding. The five trajectories show (1) a vertical well through the reservoir crest, (2) a flank near-vertical well penetrating the formation roughly
perpendicular to bedding, (3) a near-vertical well intersecting bedding planes at an angle, (4) deviated wells trending downdip parallel to bedding and (5)
highly deviated wells at an oblique angle to bedding dip (middle). Drilling difficulty can be represented schematically through a drilling-difficulty diagram
(left). The larger the lobe, the more difficult it is to drill in that direction. For example, Trajectory 1 is relatively easy to drill, and being vertical, shows no
preferential direction of difficulty. However, Trajectory 5 is very difficult to drill in the σH direction. Elsewhere in the Andean foothills, Trajectories 4 and 5
have been the most difficult to drill. Wells in Camisea oblique to the anticlinal trend are similar to Trajectory 4. A color-coded trajectory-risk map can be
created for each horizon (right). This map for the Shinai formation indicates that it is easier to drill near-vertical wells (blue), and that it is hardest to drill
along σH at high inclination (red). Moderate-difficulty drilling is represented in yellow. Similar maps were made for other horizons. The trajectory through
the Shinai formation for SM1001 was in an easy direction, while SM1002 and SM1004 were more difficult. Generally, increased mud weight is needed to
control wells that are drilled in the more difficult directions.
which was significant because the planned
boreholes would be deviated. However, previous
wells with stuck-pipe problems were deviated
into a direction almost parallel to the strike of
the San Martin anticline, while the proposed
wells would strike in directions either oblique or
orthogonal to the anticlinal trend (above).
The proposed Camisea wells potentially
would have more drilling risks than the previous
wells. Pluspetrol authorized Schlumberger to
construct an MEM for the Camisea prospects.
This MEM included a DrillMAP plan that
provided a forecast of probable risks—ranked
for each drilling section—and their impact
on drilling.8
Monte Carlo modeling helped identify the
potential variability in some of the quantities
that were poorly constrained by data from earlier
wells. For example, modeling showed that the
unconfined compressive strength (UCS) had the
greatest impact on predicting shear failure, but
measurements of UCS were not in the audited
data. After evaluating this Monte Carlo result,
Pluspetrol determined UCS from tests on core
from a previously drilled well.
30
A Schlumberger No Drilling Surprises (NDS)
team and Pluspetrol used the MEM and DrillMAP
results to create a drilling plan.9 To improve borehole cleaning, Pluspetrol upgraded the drill
motor to a PowerDrive rotary steerable system.10
The team monitored drilling performance using
LWD and MWD systems.
Drilling—The NDS team updated the MEM
and DrillMAP plans while drilling the first well in
the block, filling in data where the data audit indicated gaps. Information gathered while drilling this
well confirmed the stress directions. The drilling
data from the new well provided the answer to the
question about the influence of current local
stresses and paleostresses. Borehole image analysis
of breakouts showed that local stresses, rather than
remnant texture due to regional tectonics, dominated wellbore deformation.
The previously predicted stress magnitudes
were close to the while-drilling observations in
the reservoir, but the model had to be adjusted in
the overburden, where minimal predrill data had
been available (next page, top).
The operator’s first well was completed in
82 days without incident, five days fewer than
planned. Pluspetrol was pleased with the results
of using the No Drilling Surprises approach, and
continued working with Schlumberger on
additional wells.
Drilling on the second well proceeded
uneventfully through the reactive clays in the
lower Red Beds and casing was set successfully.
The bit got stuck in a lower section, so the well
was sidetracked to achieve total depth, which was
reached only three days behind schedule because
of the preplanning provided with the MEM.
While drilling the third well, the NDS team
observed an unusual formation-integrity test
(FIT). This test, usually performed after setting
and drilling through a casing shoe, provides a
calibration for minimum horizontal stress. The
FIT behavior in the first pressure cycle was
normal, but a second cycle had an abnormally
rapid pressure decline. To confirm a hypothesis
that the behavior was caused by natural fractures, the team modeled the FIT result in a fracture simulator using parameters available in the
MEM. Understanding this phenomenon provided
an explanation of losses that had occurred while
cementing and helped reduce the risk of lost circulation in deeper sections.
Oilfield Review
18
16
Equivalent mud weight, lbm/gal
The first two wells indicated that careful
drilling practices were required in the 81⁄2-inch
section through the Shinai formation. The MEM
provided guidelines for drilling, and no problems
were encountered.
Pluspetrol valued the preplanning and the
ability to make informed decisions quickly. Close
communications among team members gave
Schlumberger and Pluspetrol the capability to
immediately incorporate new information and
lessons learned into the work plan.
σh predicted
σh from LOT
14
12
10
8
6
4
2
0
8. For more on the DrillMAP plan: Bratton T, Edwards S,
Fuller J, Murphy L, Goraya S, Harrold T, Holt J, Lechner J,
Nicholson H, Standifird W and Wright B: “Avoiding
Drilling Problems,” Oilfield Review 13, no. 2
(Summer 2001): 32–51.
9. For more on the No Drilling Surprises initiative: Bratton,
reference 8.
10. For more on rotary steerable drilling: Downton G,
Hendricks A, Klausen TS and Pafitis D: “New Directions
in Rotary Steerable Drilling,” Oilfield Review 12, no. 1
(Spring 2000): 18–29.
Summer 2003
0
500
1000
1500
True vertical depth, m
2000
2500
> Updating stresses while drilling. The minimum horizontal stress, σh, prediction before drilling was
valid in the regions where data coverage from offset wells was good, deeper than about 1700 m [5600 ft].
The leakoff test (LOT) at the higher casing shoe, about 1000 m [3280 ft], indicated that σh was higher
than predicted. The model was corrected while drilling to incorporate this result. The background
illustration shows a LOT at a casing shoe.
0
NW
SE
Seabed
Ter 1
1000
Top salt
Depth, m
Ter 2
Ter 3
Ter 4
2000
Ter 5
Sele
3000
Ekofisk
NORWAY
a
Mirren
field
Se
Modeling Local Stresses in Mirren Field
Regional stresses provide a useful starting point
for estimating stresses in many basins. However,
major structures can affect local stresses near a
field or well. For example, mountain ranges that
were formed by compressive stresses long ago
have an effect on present-day stresses nearby.
Mountains can distort local stresses so much that
none of the principal stresses are vertical, and
they can rotate horizontal stresses away from the
regional orientation.
Faults and fracture zones also can affect a
local stress field. Movement along a fault relieves
stress locally, particularly shear stress across the
fault, while the regional stress far from the fault
may not be significantly altered.
To understand the effects of local distortion
on present-day stresses, it is sometimes necessary to create a geomechanical simulation
model. One case requiring such a simulation is
Mirren field, located about 200 km [125 miles]
east of Aberdeen, Scotland, in the North Sea. The
field is connected by subsea tiebacks to the
North Sea ETAP (Eastern Trough Area Project)
platform. The reservoir sands are tucked beneath
a salt diapir (right).
The operator, BP, had data from an exploration well and a sidetrack, but the information
was insufficient to develop a reliable stress
profile for drilling or for completion planning.
The properties from this well and its sidetrack
were used to calibrate a numerical model.
The diapir in the Mirren field is almost
symmetric in vertical cross section, and there
was no indication of local structural anisotropy,
so the team developed a radially symmetric
No
rt
h
UK
> Location and stratigraphy (top) of the Mirren field in the North Sea. A salt diapir created the Mirren
field, with hydrocarbon accumulations in the Sele formation. Formation properties and calibration data
were obtained from the previously drilled exploration well and its sidetrack (blue).
31
Managing Drilling Tolerances in the
Petronius Field
In addition to providing input for simulation modeling, an MEM is useful in predrilling assessment.
A predrill MEM provides the drilling team with a
drilling plan that includes a forewarning of hazards. Verifying stresses in real time allows a team
to refine the MEM and the drilling plan while
drilling progresses. Real-time monitoring can be
vital to the success of a well, particularly when
the safe drilling window is extremely narrow.
Pore pressure and horizontal stresses are
predicted ahead of the bit based on sonic and
resistivity log correlations developed for a field’s
MEM. With a narrow drilling window, these
quantities must be updated continuously to avoid
moving out of the safe window. In addition, the
mud density within the openhole section has to
be monitored.
32
0
1000
2000
Offset, m
3000
4000
5000
6000
0
Depth, m
1000
2000
3000
0 to 1 MPa
Stress Contrast
20 to 30 MPa
1 to 2 MPa 2 to 5 MPa
30 to 40 MPa
5 to 10 MPa
>40 MPa
10 to 20 MPa
Surfaces
4000
0
1000
2000
Offset, m
3000
4000
5000
6000
0
1000
Depth, m
model of the diapir and field. Far-field stresses
were derived from a Mohr-Coulomb model. Since
salt is highly plastic and does not sustain shear
stresses, the stress condition was hydrostatic
within the salt.
Formation properties were taken from the
existing well logs. Overburden stress came from
density logs; the minimum principal stress,
which was not necessarily horizontal, was calibrated using leakoff tests (LOTs). Calculations
from a finite-element model provided the principal stress directions and magnitudes around the
diapir. Caliper data gave further confirmation of
these principal stresses.
Once the model was calibrated, the resulting
properties were rotated around the axis of symmetry to create a 3D model. The model revealed
areas of high deviatoric stresses—where the
minimum and maximum stresses differ greatly—
adjacent to the salt diapir. Drilling in those areas
would require high mud weights to avoid borehole instability. However, in that same area near
the diapir, the modeled fracture pressure was
low, requiring low mud weights. Since the mud
weight could not be simultaneously high and low,
the chosen well trajectory avoided these problem
areas next to the diapir (right).
Properties along each selected trajectory were
taken from the 3D model. This information provided wellbore-stability and sanding projections
that were used to drill new wells and to plan
completions that would minimize solids production. Two wells in Mirren field were drilled and
completed successfully with information from the
model; production began in November 2002.
2000
3000
0 to 1 MPa
Fracture Pressure
20 to 30 MPa
1 to 2 MPa 2 to 5 MPa
30 to 40 MPa
5 to 10 MPa
>40 MPa
10 to 20 MPa
Surfaces
4000
> Modeling results around the Mirren salt diapir. A zone of high stress contrast hugs the bottom of the
salt diapir [dark purple and orange zones (top)], and the fracture pressure is also low in this area [light
and dark purple zones (bottom)]. A well trajectory (green) was selected to avoid this problem area.
Mud density is not the same at the surface as
it is at the bit, and the bottomhole density
changes even more when the mud is circulating.
The equivalent static density (ESD) of the mud
at the BHA differs from the surface mud weight
because of suspended solids and mud compressibility. Mud properties aside, the primary influences on fluctuations in the equivalent
circulating density (ECD) are hole size, BHA and
drillstring configuration, pipe movements and
tripping speed, rate of penetration, and pumping
rates and pressures.
Equivalent density can be measured around a
BHA using an APWD Annular Pressure While
Drilling tool. The ECD is transmitted to surface
in real time. The ESD is recorded downhole while
Oilfield Review
Georgia
Alabama
Mississippi
Texas
Florida
Louisiana
Petronius field
Gulf of Mexic
0
o
N
Platform
S
Seabed
2000
Well
trajectories
Depth, ft
4000
6000
8000
10,000
12,000
–20,000
–15,000
–10,000
–5000
0
Offset, ft
5000
10,000
15,000
20,000
> Location (top) and well trajectories (bottom) for the Petronius field, Gulf of Mexico. The seabed
depth changes significantly above the Petronius field.
the mud is not circulating, and the minimum and
maximum ESD values are transmitted as soon a
circulation begins again. When the safe
drilling—or mud-weight—window becomes
smaller than the difference between ESD and
ECD, normal drilling operations are likely to
cause either fracturing or breakouts, or, in some
cases, both types of failure in the same wellbore.
The importance of maintaining a safe mudweight window was seen during predrill planning
of wells in the Petronius field. The platform for
the Petronius field is at the boundary of shelf and
deep waters in the Gulf of Mexico Viosca Knoll
area. The operator, ChevronTexaco, began
development in 2000, and planned to drill three
extended-reach wells with up to 19,000 ft
[5800 m] of horizontal displacement.11
Seabed depth changes rapidly near the
platform (above). The water depth at the platform is 1750 ft [533 m], but the north end of the
reservoir is under only 700 ft [213 m] of water
and the south end is under almost 3200 ft
[975 m]. This extreme change of water depth,
Summer 2003
with its accompanying change in overburden
stress, had to be considered when designing
these extended-reach wells.
Drilling problems had been encountered in
earlier wells with less lateral extent than the
three planned wells. The earlier wells had problems with hole cleaning, excessive circulation
time, tight hole, packoffs and tools lost-in-hole.
These problems became worse with greater well
inclination because the safe mud-weight window
became narrower.
ChevronTexaco set several goals for drilling
these extended-reach wells. The company
wanted to avoid well problems, specifically stuck
pipe and the high pulls associated with sticking
pipe, lost tools and lost circulation. The drilling
program called for a high mud weight to avoid
breakout in an upper section, then setting the
95⁄8-in. casing past this unstable zone. With casing
set, the mud weight was reduced to avoid lost circulation due to a lower fracture gradient in the
next zone. It was imperative to monitor ECD and
ESD while drilling and keep them within safe
limits at all times.
Mechanical earth model—Planning these
extended-reach wells in Petronius field required
construction of a 3D MEM to integrate existing
data and to model missing information. Dipmeter
and FMI Fullbore Formation MicroImager logs
identified unconformities and faults, which were
used to establish stress directions.
Ordinarily, the vertical stress due to the weight
of the overburden is determined by integrating
the density of the overlying formations. At
Petronius, the steeply dipping seabed complicated this approach. The No Drilling Surprises
team created a 3D model of the reservoir to
account for the varying water depth and resulting
lateral stress change. Density logs from offset
wells had not covered the complete depth interval, so the data were extrapolated to the seabed.
A 3D seismic velocity survey provided information for a 3D density cube, with quality control
from a sonic log. The dipping seabed caused
more than a 1-lbm/gal [0.12-g/cm3] difference
in the predicted overburden stress gradient at
the end of the well trajectory, compared with a
vertical well of the same total depth.
Input data for the MEM came from predrill
data. A complete petrophysical analysis established the mineralogy of the formations and the
rock properties. A 3D seismic cube provided
input for a pore-pressure prediction. Formation
breakdown tests in offset wells gave minimum
horizontal stress in the shales and constrained
the maximum horizontal stress. MDT and RFT
Repeat Formation Tester pressure measurements and leakoff tests calibrated these profiles.
The team extracted a wellbore-stability
prediction along the specified well trajectory
from the MEM. A stable mud window between
the mud weight needed to prevent initiation of
breakouts and the minimum horizontal stress
was less than 1 lbm/gal. The predicted difference
between ESD and ECD was greater than this, so
some wellbore damage would likely occur.
The team decided that limited breakouts
were easier to manage than formation fracturing,
so they set a less restrictive limit on the low side
of the mud-weight window. Given the borehole
size and drillstring design, the MEM helped
determine the maximum magnitude of failure
that could be handled by the rig hydraulics with
a minimum probability of losing the well. The
team determined that borehole breakouts contained within an angle of 60° could occur without
11. For information on the Petronius field contained in this
section: Smirnov NY, Tomlinson JC, Brady SD and
Rau WE III: “Advanced Modeling Techniques with
Real-Time Updating and Managing the Parameters for
Effective Drilling,” paper presented at the XIV Deep
Offshore Technology Conference and Exhibition,
New Orleans, Louisiana, USA, November 12–15, 2002.
33
Stress Gradients
1 lbm/gal/division
Pore Pressure
Lithology
Mud Weight, α=0°
Illite
Mud Weight, α=60°
Sand
Minimum Horizontal Stress
Breakout Prediction
Bound Water
Overburden Gradient
Total Porosity
0°
Borehole Circumference
360°
LOT
1000 ft
σH
Measured depth, ft
Potential fractures
σh
LOT
α
α
σh
α–breakout angle
Zones of shear
failure (breakout)
σH
> Use of breakout analysis to set minimum mud weight. The wellbore-stability analysis (Track 2) indicates that the minimum mud weight to prevent breakout
initiation, MW0 (green), does not have sufficient separation from the minimum horizontal stress, σh (gold). The No Drilling Surprises team analyzed drilling
dynamics and decided the borehole could be kept clean with breakouts up to an angle of α=60º (right). Using this MW60 criterion (red), the locations of
expected borehole failures were predicted (Track 3). In Track 2, a leakoff test (LOT) confirmed the correlation for σh. The overburden stress gradient is on
the right (magenta). Track 1 shows a petrophysical analysis of the formations.
impacting borehole cleaning and well integrity,
so this was the design criterion for the mud
weight (above). However, the conditions had to
be monitored carefully. Once borehole-wall failure initiated, there was no way to predict how
the breakout would behave. Failure would likely
worsen with time as the stress condition
remained outside the safe condition. The ECD
and ESD were monitored carefully while drilling.
A model of the drilling mechanics indicated
that a PowerDrive PD900 rotary steerable system
improved borehole cleaning and permitted flow
with less pressure drop in the tool than a
downhole drilling motor. The wellbore-stability
analysis predicted the ECD and annular
34
velocities necessary to optimize hole cleaning. A
complete drillstring stress analysis established
operating limits to avoid failure and eliminate
potential downtime.12
The lessons learned and good practices
discovered during predrill preparations were
captured in the MEM database. Using root-cause
analysis, the team developed preventive and
remedial actions for potential events.
Drilling—With a plan in place, drilling
began in 2002. Engineers at the rig site continuously monitored drilling operations and real-time
logging, including gamma ray, resistivity, sonic,
density and neutron porosity logs. A multidisciplinary team onshore gave 24-hour support.
Borehole cleaning was critical. The ECD is
sensitive to borehole condition, and, in this case,
the margin between collapsing and fracturing
the formation was narrow. Stress calibration
required monitoring of ECD to within 0.1 lbm/gal
[0.012 g/cm3], as well as calibrations of the predicted gradients from formation-integrity, leakoff
and extended leakoff tests. Conventional hole
cleaning by bottoms-up circulation to surface
yielded few cavings from breakouts. However,
by logging the drilling mechanics conditions—
such as torque and drag—the likelihood of
generating cavings larger than drilling cuttings
was monitored.
Oilfield Review
Controlling Sand Production
The MEM also plays a role in controlling sand
production that is often seen in weak and unconsolidated formations. Sand moving in the flow
stream erodes tubulars and can damage surface
and subsurface equipment. Preventing sand production at the formation face is often the best
approach to minimize this damage, using either
oriented perforating or screenless completions.14
In some situations, indirect vertical fracturing
(IVF) provides sand control by perforating into a
competent zone and fracturing into an adjacent,
less competent productive zone.15 The proper
application of IVF requires a detailed understanding of formation lithology and geomechanical
properties, which can be obtained from an MEM.
Summer 2003
Piltun-Astokhskoye
field
Sakhalin
Island
So
un
d
RUSSIA
ta
r
Special hole-cleaning and tripping procedures provided a mechanical action to remove
larger cavings. Circulation time was increased
before pulling the drillpipe out of the borehole
when drilling reached the casing-shoe depth, the
borehole bottom and at certain critical inclination angles. Caving material reached the shale
shakers after several full circulations, when
normal drilling cuttings were no longer cycling
onto the shakers, and cavings continued to make
it to surface for several hours.
The acceptable mud-weight window was so
narrow that the possibility of fracturing the formation remained. The drilling team saw some
borehole ballooning followed by mud losses.
Fractures in this interval were located by analyzing time-lapse MWD resistivity logs acquired
while drilling and again while pulling out of the
borehole.13 The drilling team treated the fractures with loss-control material and lowered the
mud weight to an acceptable level based on the
real-time MEM.
Analysis indicated minimum horizontal stress
gradient in the sand bodies was 0.3 lbm/gal
[0.035 g/cm3] less than that of the shales, so the
model was updated to account for this lithologic
difference in strength properties.
Full-time monitoring of the wells, coupled
with an MEM that allowed an understanding
of unwanted events, resulted in three wells
successfully reaching total depth. There were no
stuck-pipe incidents, tools lost-in-hole or sidetracks. The minor fluid losses encountered were
managed successfully. All targets were reached;
all the casing strings landed at the planned
depth. On average, the total time savings on
constructing these three wells was 15%.
Considering only the time spent drilling, the
savings was about 45% compared with the
Petronius predrill plan.
Ta
RUSSIA
CHINA
Okhotsk
Se
a
JAPAN
> Piltun-Astokhskoye field, offshore Sakhalin Island, Russia.
In 2000, operator Sakhalin Energy Investment
Company applied the IVF technique in the
Piltun-Astokhskoye field, located about 12 km
[7 miles] northeast of Sakhalin Island, Russia
(above).16 Wells in the field are prone to sand production from poorly consolidated pay zones.
Wells had been completed using frac-pack
and high-rate water-pack (HRWP) treatments.17
After treatment, the wells had a high positive
skin.18 The operator tried IVF to test whether the
formation itself could control sand production,
working with Schlumberger to examine the
lithology and geomechanics of the candidate well
in detail. Several wells were studied to generate
an MEM.
12. The drillstring analysis included bending stresses,
sinusoidal buckling, effective axial load, total and inclinational side forces, and torsional and tensile capacity.
13. Inaba M, McCormick D, Mikalsen T, Nishi M, Rasmus J,
Rohler H and Tribe I: “Wellbore Imaging Goes Live,”
Oilfield Review 15, no. 1 (Spring 2003): 24–37.
14. For more on screenless completions: Acock A,
Heitmann N, Hoover S, Malik BZ, Pitoni E, Riddles C
and Solares JR: “Screenless Methods to Control Sand,”
Oilfield Review 15, no. 1 (Spring 2003): 38–53.
For more on frac-packing: Ali S, Norman D, Wagner D,
Ayoub J, Desroches J, Morales H, Price P, Shepherd D,
Toffanin E, Troncoso J and White S: “Combined
Stimulation and Sand Control,” Oilfield Review 14, no. 2
(Summer 2002): 30–47.
15. Bale A, Owren K and Smith MB: “Propped Fracturing as
a Tool for Sand Control and Reservoir Management,”
paper SPE 24992, presented at the SPE European
Petroleum Conference, Cannes, France, November
16–18, 1992.
For an early use of this technique to control chalk production: Moschovidis ZA: “Interpretation of Pressure
Decline for Minifrac Treatments Initiated at the Interface
of Two Formations,” paper SPE 16188, presented at the
SPE Production Operations Symposium, Oklahoma City,
Oklahoma, USA, March 8–10, 1987.
16. Akbar Ali AH, Marti S, Esa R, Ramamoorthy R, Brown T
and Stouffer T: “Advanced Hydraulic Fracturing Using
Geomechanical Modeling and Rock Mechanics—An
Engineered Integrated Solution,” paper SPE 68636, presented at the SPE Asia Pacific Oil and Gas Conference
and Exhibition, Jakarta, Indonesia, April 17–19, 2001.
17. High-rate water packing is a sand-control method
involving fracturing a formation to place gravel outside
of casing and perforations beyond the damage radius
of a well. The fracture is typically designed to have a
2- to 10-ft [0.6- to 3-m] half-length with moderate (2to 3-lbm/ft2) [10- to 15-kg/m2] fracture conductivity;
usually it is created with Newtonian fluids such as
completion fluid.
18. Skin is a dimensionless factor calculated to determine
the production efficiency of a well by comparing actual
conditions with theoretical or ideal conditions. A positive
skin value indicates that some damage or influences are
impairing well productivity.
35
The highest permeability portion of the oilbearing zone consists of poorly consolidated
sandstone comprising fine- to medium-grained
clean sands with little clay. The depositional
environment was a marine shelf, featuring a
coarsening-upward sequence; lower sections are
more consolidated because of higher clay
concentrations and cementation. Barrier zones
that are highly consolidated vary from shaly siltstone and sandstone to shales.
Although the average formation permeability
is about 150 to 200 mD, the clean sandstones
have high permeabilities, up to 4 D. The permeability in the well was calculated using the
Total Porosity
25
percent
0
Effective Porosity
25
100
1
25
Sandstone
0 API 150
Hydrocarbon
Depth, m
Water
0
kPa/m
Young‘s Modulus
0
GPa
100 0.0
percent
36
25
percent
Hydrocarbon
Poisson‘s Ratio
0.6
Water
2240
2250
2260
2270
> Geomechanics of the Piltun-Astokhskoye field. A FracCADE fracture simulator uses petrophysics
(Track 3) and formation lithology (Track 1) to evaluate formation mechanical properties (Track 2). In
Track 2, the variability of fracture closure stress (red), a measure of minimum horizontal stress, is
represented in the model as zones of constant stress (blue).
36
0
0
Density Porosity
Closure Stress Gradient
Limestone
percent
Neutron Porosity
Shale
Gamma
Ray
0
Water Saturation
Lithology Summary
0
percent
0
Timur-Coates permeability transform from the
CMR Combinable Magnetic Resonance log.19
Core data calibrated these measurements.
The direction of maximum horizontal
stresses, σH, was determined using a DSI Dipole
Shear Sonic Imager tool operating in a crosseddipole mode. The DSI response indicated that σH
lay in a northeast-southwest direction. This was
corroborated by breakout results from a four-arm
caliper tool.
Other properties for the MEM, such as
Poisson’s ratio and Young’s modulus, also were
obtained from the DSI log. Core measurements of
unconfined compressive strength calibrated the
UCS from a DSI log correlation.
Perforating—The locations selected for perforations accounted for the stress magnitudes
and directions to minimize perforation tunnel
failure.20 Although the preferred orientation for
the perforations in these highly deviated wells
was vertical, it was not always possible to use
that orientation.
A perforation interval was selected in the
lower permeability, more consolidated interval
slightly below the highly permeable target zone.
Based on information from the MEM, FracCADE
fracturing design and evaluation software
modeling indicated the IVF would grow from the
competent zone into the weaker, more productive interval above (left). The model helped
design the perforation density, penetration and
hole size to minimize the chance of proppant or
formation sand production.
The first well treated with IVF in PiltunAstokhskoye field had considerably higher flow
efficiency than wells treated with conventional
frac-pack and HRWP treatments. A pressure
buildup test provided information about the IVF
fracture treatment. The well was shut in at
surface, so wellbore-storage effects—pressure
changes caused by the wellbore and fluid
response to the shut-in—masked the short-time
response of bottomhole pressure data from
permanent downhole gauges. Buildup data after
wellbore storage effects ended showed a successful completion. The results indicated the fracture
extended from all perforations, and the conductivity of the fracture was so high that the buildup
behaved as though there were no fracture, only
direct completion into both the consolidated,
perforated zone and the weak, high-permeability
pay zone.
Oilfield Review
The buildup tests in this and later PiltunAstokhskoye wells with IVF treatments showed
low to no skin, indicating successful treatments.
This series of wells completed using IVF had an
average production of 9800 BOPD [1560 m3/d]
after 90 days, and produced essentially sandfree through June 2003 (right). The IVF method
provided the operator with an efficient completion at a substantially lower price than with a
frac-pack.
Jauf reservoir—The Jauf reservoir in Saudi
Arabia also has unconsolidated layers that are
prone to sanding, but, in contrast to the PiltunAstokhskoye field, they have low to moderate
permeability.21 Beginning in 2000, the operator
collaborated with Schlumberger to use a
PowerSTIM well-optimization process to successfully stimulate and control solids production. The
wells were completed in a gas zone using
propped fractures and screenless completions.22
A petrophysical analysis, including examination of cores from several wells through this
zone, showed weak and unconsolidated sands
separated by tighter zones of sand containing
illite clay as pore-lining and pore-filling cement.23
The team constructed an MEM based on core
and log information, which confirmed the weakness of many of the gas-bearing sands (right).
Well
number
Completion
Completion
date
PA-106
Frac-pack
July 1999
PA-105
HRWP, shunt tubes
August 1999
PA-103
Frac-pack, shunt tubes
PA-104
Screenless
PA-109
Screenless
PA-102
Oil rate,
B/D
Gas rate,
scf/D
N/A
13,757
8462
N/A
7,347
3873
August 1999
N/A
6,003
3712
October 1999
16,000
6,735
4332
May 2000
130,000
13,573
7715
Screenless
May 2000
N/A
14,941
8263
PA-113
Screenless
May 2000
N/A
7,643
4563
PA-111
Screenless
May 2000
25,000
3,774
2013
PA-114
Screenless
June 2000
N/A
8,284
4256
> Comparison of productivity for screenless completions and other methods in
the Piltun-Astokhskoye field. The screenless completions used indirect vertical
fracturing. The designation N/A indicates that information is not available.
Poisson‘s Ratio Young‘s Modulus
Moved Hydrocarbon
Water
Gas
Carbonate
Quartz
Illite
19. For more on nuclear magnetic resonance logging:
Allen D, Crary S, Freedman B, Andreani M, Klopf W,
Badry R, Flaum C, Kenyon B, Kleinberg R, Gossenberg P,
Horkowitz J, Logan D, Singer J and White J: “How to
Use Borehole Nuclear Magnetic Resonance,” Oilfield
Review 9, no. 2 (Summer 1997): 34-57.
20. Almaguer J, Manrique J, Wickramasuriya S, Habbtar A,
López-de-Cárdenas J, May D, McNally AC and
Sulbarán A: “Orienting Perforations in the Right
Direction,” Oilfield Review 14, no. 1 (Spring 2002): 16-31.
21. Solares JR, Bartko KM and Habbtar AH: “Pushing the
Envelope: Successful Hydraulic Fracturing for Sand
Control Strategy in High Gas Rate Screenless
Completions in the Jauf Reservoir, Saudi Arabia,”
paper SPE 73724, presented at the SPE International
Symposium and Exhibition on Formation Damage
Control, Lafayette, Louisiana, USA, February 20–21, 2002.
22. For more on the Jauf reservoir: Acock, reference 14.
For more on the PowerSTIM process: Al-Qarni AO,
Ault B, Heckman R, McClure S, Denoo S, Rowe W,
Fairhurst D, Kaiser B, Logan D, McNally AC, Norville MA,
Seim MR and Ramsey L: “From Reservoir Specifics
to Stimulation Solutions,” Oilfield Review 12, no. 4
(Winter 2000/2001): 42–60.
23. Al-Qahtani MY, Rahim Z, Biterger M, Al-Adani N,
Safdar M and Ramsey L: “Development and Application
of Improved Reservoir Characterization for Optimizing
Screenless Fracturing in the Gas Condensate Jauf
Reservoir, Saudi Arabia,” paper SPE 77601, presented at
the SPE Annual Technical Conference and Exhibition,
San Antonio, Texas, USA, September 29–October 2, 2002.
Permeability
thickness,
kh, mD-ft
Measured
Depth, ft 1
Volumes
vol/vol
Laboratory
Laboratory
Static
Static
Dynamic
Dynamic
0
0.5 0 million psi 20
Log Correlation Log Correlation
Static
Static
0
0.5 0 million psi 20
Sanding
Tendency
UCS
Laboratory
Fracture Gradient
0.7 psi/ft 1.2
0
psi
50,000
Log Correlation Log Correlation
Log Correlation
Minifrac Test
Dynamic
Dynamic
0.5 0 million psi 20 0 psi 50,000 0.7 psi/ft 1.2
0 0
No Sanding
Tensile Strength
0 psi 10,000
Shear Strength
0 psi 10,000
Sanding Tendency
0
psi 5000
Tight
Very Low
Low
Medium
High
XX900
XX000
XX100
XX200
XX300
XX400
XX500
> Sanding tendency for a Jauf reservoir well. Mechanical-strength parameters provided a prediction
of sanding tendency (far right track), color-coded to distinguish areas of greater sanding potential.
Summer 2003
37
Vertical rock displacement, m
0
7.8
15.6
23.4
31.2
> Reservoir simulation map of Miskar field. The color code indicates vertical rock displacement as a result of stress changes
after one year of depletion.
Young’s modulus, and the correlated UCS value,
decreased by about a factor of six from the
competent zones to the unconsolidated layers.
The weak layers were prone to sanding. On
the basis of the MEM, wherever possible,
perforations were placed 10 to 20 feet [3 to 6 m]
away from these areas, and the perforation interval was restricted to be shorter than 30 or 40 feet
[9 or 12 m].
The MEM and stimulation plan were updated
with results from each well. Close collaboration
between the operator and Schlumberger experts
was essential in successfully designing and implementing this stimulation program. The operator
established a balance between eliminating solids
production and achieving maximum well deliverability. Cleanup time and cleanup costs declined
as the PowerSTIM program progressed.24
24. Ramsey L, Al-Ghurairi F and Solares R: “Wise Cracks,”
Middle East & Asia Reservoir Review 3 (2002): 10–23.
25. Ruddy I, Andersen MA, Pattillo PD, Bishlawi M and
Foged N: “Rock Compressibility, Compaction, and
Subsidence in a High-Porosity Chalk Reservoir: A Case
Study of Valhall Field,” Journal of Petroleum Technology
41, no. 7 (July 1989): 741–746.
38
Coupling Geomechanics and Fluid Flow
Schlumberger performed a data audit and
created an MEM of the Miskar field for operator
BG. The field is located about 110 km [68 miles]
east-southeast of Sfax, Tunisia in the Gulf of
Gabes. The predrill report identified hazards
and recommendations for safe drilling in this
gas-condensate field. Most of the drilling difficulties in earlier wells occurred while drilling into
mechanically weak, overpressured, chemically
active, and fractured or faulted formations. Using
the MEM, BG began a new drilling campaign
in the field.
During the drilling of the lower portion of the
first well in the program, a Schlumberger geomechanics engineer was present on the rig to monitor the daily drilling reports and update the
MEM. This well was drilled without the nonproductive time incidents of previous wells. BG
used the updated MEM for two additional wells,
which successfully reached their primary and
secondary directional targets without instability
events. With each well drilled, the database
could be updated, providing a basis for continuing drilling improvements in Miskar field.
With an MEM constructed for the field,
Schlumberger applied a new tool for reservoir
studies (above). The ECLIPSE-GM coupled
geomechanical and reservoir model provides a
basis to determine the effect of rock stress
changes on reservoir flow properties.
In the absence of pressure support from an
aquifer or injection of water or gas, production of
hydrocarbons from a field decreases pressure in
formation pore spaces. The weight of the overburden shifts from being supported by pore pressure to being supported by the rock fabric,
increasing the stresses on that solid framework.
This change of stress state can result in loss of
porosity and permeability and, in extreme cases,
can cause wellbore deformation or failure.
In the past, modeling this behavior used
loosely coupled flow and mechanical models.25
Reservoir flow simulators generally contain relatively simple rock-mechanical models, and
mechanical simulators generally contain simple
single-phase flow models. In a loosely coupled
simulation, the pressure and volume results from
one step in the flow model become inputs to the
mechanical model, and vice versa. The process
iterates this same time step until the input and
output values are within an acceptable tolerance.
Then the models move to the next time step.
Oilfield Review
Summer 2003
Permeability reduction factor
0.9
0.8
0.7
0.6
-600
180,000
-400
-200
Maximum principal stress, bar
0
800
Gas production rate, m3/d
600
140,000
500
120,000
400
100,000
300
80,000
200
60,000
Gas production, million m3
700
160,000
100
40,000
0
0
2
4
6
8
10
12
14
Time, number of years
16
18
20
> Productivity reduction with stress-dependent permeability. The ECLIPSE-GM
simulator can incorporate a stress-dependent permeability (inset) coupled
with changes in the stress field. Taking the stress-dependent permeability into
account decreases the predicted gas productivity by 29% after 20 years (purple), compared with the base case (blue). Gas rates are also shown.
180,000
800
160,000
700
600
140,000
500
120,000
400
100,000
300
80,000
200
60,000
Gas production, million m3
Watching Models Develop
The number of fields worldwide with a welldeveloped mechanical earth model is increasing,
but it is still a small number. Many fields have a
substantial body of geomechanical data, but
those data have not been put into a single,
coherent framework, and a complete audit of the
data usually is not available.
While it is not economical to generate an
MEM for every field in a company’s portfolio, it is
prudent to ask, before embarking on a major field
development or redevelopment, whether constructing an MEM as part of the project planning
will save money for the company in the long term.
Most earth models to date have been constructed for drilling purposes, but that is changing, as the well-completion cases described
above indicate. One of the many advantages of
using the MEM process is that the information is
then readily available for other purposes, such as
reservoir management or production enhancement. The investment in building a model can be
repaid throughout the life of the field, as the
MEM becomes a tool for monitoring and managing reservoir stress changes.
—MAA
1.0
Gas production rate, m3/d
Modeling using loose coupling is awkward
and slow. Separating the detailed flow from the
detailed mechanical modeling also creates a
potential for inconsistencies and incorrect
physical modeling of coupled flow and mechanical phenomena.
The ECLIPSE-GM simulator uses a model
that couples geomechanics and flow physics into
one set of equations, eliminating the problems of
loose coupling and ensuring a more accurate
representation of reservoir dynamics.
The simulation of Miskar field combined the
field geology with synthetic values for flow and
fluid properties. The simulation showed how
a stress-dependent permeability decreased predicted gas production (right). In a separate run,
sand-management software predicted the
restriction on drawdown required to prevent formation failure at the wellbore. The resulting
reduced drawdown was used with the ECLIPSEGM Miskar field model to show the predicted production loss due to that restriction (below right).
Output from ECLIPSE-GM modeling also can
define stress conditions for fracture analysis,
wellbore stability and compaction.
100
40,000
0
0
2
4
6
8
10
12
14
Time, number of years
16
18
20
> Productivity decline with formation failure. Predictions of formation failure
in different locations of the production interval were obtained from sandmanagement software. The result can be input to the ECLIPSE-GM model to
show the predicted decline of gas productivity (green) compared with the
base case (blue), when these failed locations are isolated to minimize solids
production. Gas rates are also shown.
39
Nuclear Magnetic Resonance Logging
While Drilling
Innovative drilling and measurements technologies now provide increasingly
comprehensive borehole and formation-evaluation data in real time. Recent
developments in nuclear magnetic resonance logging while drilling are helping
operators make more informed drilling and completions decisions, reduce risk and
nonproductive time and optimize wellbore placement and productivity.
R. John Alvarado
Houston, Texas, USA
Anders Damgaard
Pia Hansen
Madeleine Raven
Maersk Oil
Doha, Qatar
Ralf Heidler
Robert Hoshun
James Kovats
Chris Morriss
Sugar Land, Texas
Dave Rose
Doha, Qatar
Wayne Wendt
BP
Houston, Texas
40
Nuclear magnetic resonance (NMR) logging while
drilling (LWD) represents a significant advancement in geosteering and formation-evaluation
technology, bringing the benefits of wireline NMR
to real-time drilling operations. Critical petrophysical parameters, such as permeability and
producibility estimates, can now be obtained
while drilling, providing information that helps
petrophysicists, geologists and drillers achieve
optimal wellbore placement within a reservoir.
Real-time while-drilling measurements are
especially important in high-cost and timesensitive drilling environments. With rig costs
running as high as USD 175,000 per day,
errors in well placement, formation evaluation
or well-completion design can result in
significant additional well costs or the drilling
of expensive sidetracks.1
For help in preparation of this article, thanks to Emma Jane
Bloor, Jan Morley, Marwan Moufarrej and Charles
Woodburn, Sugar Land, Texas, USA; Kevin Goy, Doha,
Qatar; Mohamed Hashem, Shell, New Orleans, Louisiana,
USA; Martin Poitzsch, Clamart, France; Joe Senecal,
Maersk Oil, Doha, Qatar; and Brett Wendt, ConocoPhillips,
Houston, Texas.
CMR (Combinable Magnetic Resonance), CMR-200,
CMR-Plus, IDEAL (Integrated Drilling Evaluation and
Logging), MDT (Modular Formation Dynamics Tester),
PowerDrive, PowerPulse, proVISION and VISION are
marks of Schlumberger.
1. Aldred W, Plumb D, Bradford I, Cook J, Gholkar V,
Cousins L, Minton R, Fuller J, Goraya S and Tucker D:
“Managing Drilling Risk,” Oilfield Review 11, no. 2
(Summer 1999): 2–19.
Bargach S, Falconer I, Maeso C, Rasmus J, Bornemann T,
Plumb R, Codazzi D, Hodenfield K, Ford G, Hartner J,
Grether B and Rohler H: “Real-Time LWD—Logging for
Drilling,” Oilfield Review 12, no. 3 (Autumn 2000): 58–78.
Bratton T, Edwards S, Fuller J, Murphy L, Goraya S,
Harrold T, Holt J, Lechner J, Nicolson H, Standifird W
In this article, we review basic NMR concepts, introduce developments in NMR logging
while drilling and discuss how operators are
using this technology for wellbore placement and
formation evaluation in real time.
Development of Wireline NMR
In the decade that NMR logs have been available,
they have undergone continual improvement.2
The CMR Combinable Magnetic Resonance tool
family, beginning with the introduction of the
CMR-A service in 1995, provided measurements
of effective porosity, bound-fluid volume (BFV),
permeability and T2 distributions, a concept
described later in this article. The CMR-200
Combinable Magnetic Resonance tool introduced
advances in electronics that provide an increased
signal-to-noise ratio (S/N) while shorter echo
and Wright B: “Avoiding Drilling Problems,” Oilfield
Review 13, no. 2 (Summer 2001): 32–51.
2. Kenyon B, Kleinberg R, Straley C, Gubelin G and
Morriss C: “Nuclear Magnetic Resonance Imaging—
Technology for the 21st Century,” Oilfield Review 7, no. 3
(Autumn 1995): 19–33.
Allen D, Crary S, Freedman B, Andreani M, Klopf W,
Badry R, Flaum C, Kenyon B, Kleinberg R, Gossenberg P,
Horkowitz J, Logan D, Singer J and White J: “How to
Use Borehole Nuclear Magnetic Resonance,” Oilfield
Review 9, no. 2 (Summer 1997): 34–57.
Allen D, Flaum C, Ramakrishnan TS, Bedford J, Castelijns K,
Fairhurst D, Flaum C, Gubelin G, Heaton N, Minh CC,
Norville MA, Seim MR and Pritchard T: “Trends in NMR
Logging,” Oilfield Review 12, no. 3 (Autumn 2000): 2–19.
For more on the history and development of NMR logging:
Dunn KJ, Bergman DJ and LaTorraca GA: Nuclear
Magnetic Resonance—Petrophysical and Logging
Applications, Seismic Exploration No. 32. Amsterdam,
The Netherlands: Pergamon Press (2002): 3–10.
3. Allen et al (2000), reference 2.
Oilfield Review
spacing, on the order of 200 µs, improved petrophysical measurement quality, including total
porosity. Further improvements led to the CMRPlus logging tool with high-speed capability to
acquire data at logging rates up to 2400 ft/hr
[730 m/hr] for full porosity logging and 3600 ft/hr
[1100 m/hr] for bound-fluid logging, rates three to
five times faster than the CMR-200 tool.3
To date, more than 7000 CMR logging jobs
have been performed. For many applications,
NMR measurements are superior to other logging
techniques and can provide critical answers to
Summer 2003
questions concerning the presence, type and
producibility of reservoir fluids. For many
operators, NMR logging has become a routine
service in typical logging programs.
Dance of the Protons
NMR logging measures the magnetic moment of
hydrogen nuclei (protons) in water and hydrocarbons. Protons have an electrical charge and
their spin creates a weak magnetic moment.
NMR logging tools use large permanent magnets
to create a strong, static, magnetic-polarizing
field inside the formation. The longitudinalrelaxation time, T1, describes how quickly the
nuclei align, or polarize, in the static magnetic
field. Full polarization of the protons in pore
fluids takes up to several seconds and can be
41
done while the logging tool is moving, but the
nuclei must remain exposed to the magnetic field
for the duration of the measurement. The relationship between T1 and increasing pore size is
direct, yet inverse, to formation fluid viscosity.
A series of timed radio-frequency (rf) pulses
from the logging-tool antenna can be used to
manipulate proton alignment. The aligned protons
are tilted into a plane perpendicular to the static
magnetic field. These tilted protons precess
around the direction of the strong induced
magnetic field. The precessing protons create
oscillating magnetic fields, which generate a
weak but measurable radio signal. However,
since this signal decays rapidly, it has to be
regenerated by repeatedly applying a sequence
of radio-frequency pulses. The precessing protons
in turn generate a series of radio-signal pulses or
peaks known as spin echoes. The rate at which
the proton precession decays, or loses its alignment, is called the transverse-relaxation time, T2.
T1 and T2 processes are affected predominantly by interaction between pore-fluid
molecules, or bulk-relaxation characteristics,
and from pore-fluid interactions with the grain
surfaces of the rock matrix, also known as
surface-relaxation characteristics. In addition, in
the presence of a significant magnetic-field
gradient within the resonant zone, there is relaxation by molecular diffusion that influences only
T2 processes.4
NMR While Drilling
Following the widespread acceptance of wireline
NMR, development and field-testing of LWD NMR
tools began in the late 1990s.5 Research and
development efforts and lessons learned from
wireline-conveyed NMR logging ultimately led to
the introduction of the proVISION real-time
reservoir steering service in 2001, capable of
Anticipated
productivity
Oil
Oil and gas
providing precise high-resolution NMR measurements under the harsh conditions typically
encountered while drilling. Similar to the CMR
tool, the proVISION LWD tool delivers measurements that include mineralogy-independent
porosity, bound-fluid volume (BFV), free-fluid
volume (FFV), permeability, hydrocarbon detection and T2 distributions.
Flexible design allows engineers at the wellsite to modify the measurement sequence and
operational characteristics of the tool for one of
three drilling modes: rotating, sliding or stationary. The tool can be programmed manually or
set to switch automatically based on drilling
conditions (below). Engineers can program the
tool to measure T1, T2, or both simultaneously.
Although both measurements can generate NMR
formation-evaluation data, the proVISION system relies primarily on T2 measurements, which
produce higher statistical repeatability and vertical resolution.
Both T1 and T2 measurements sample an
exponential time evolution process. T1 measurements sample an exponential buildup and T2
measurements, an exponential decay. The T1
measurement consists of a few samples on this
buildup, each of which requires an additional
wait time depending on the point measured. The
T2 measurement, on the other hand, captures the
complete decay within a single Carr-PurcellMeiboom-Gill (CPMG) measurement after only
one wait time, resulting in a greater number of
echoes per measurement. Thus the T2 measurement can be taken more quickly leading to either
a higher sample rate or to more averaging and,
therefore, enhanced data quality.
For LWD NMR measurements to be available
in real time, they must be transmitted to the
surface by mud-pulse telemetry. From the raw
measurements performed by the tool, an optimal
Wait time,
sec
Repetitions
Number of
echoes
6.00
0.60
0.04
2
2
40
500
300
20
13.00
0.60
0.04
2
2
40
500
300
20
> The proVISION tool pulse-sequence parameters. The tool’s programmability
is demonstrated in this triple-wait-time acquisition sequence that was used
to evaluate oil-productive (upper set) and oil- and gas-productive (lower set)
intervals in a deepwater Gulf of Mexico well, USA.
42
signal-processing algorithm is implemented
downhole to perform the critical T2 inversion
process. As a result of this inversion, important
petrophysical measurements can be derived
in real time, namely: lithology-independent
porosity, T2 spectral distributions, bound- and
free-fluid volumes, permeability and information
about fluid saturations and characteristics.
However, because of telemetry bandwidth limitations, real-time data transmission is limited to
magnetic resonance-derived porosities, BFV,
FFV, motion-dependent quality control parameters and T2LM, or logarithmic mean of the T2 distribution. These are used in conjunction with the
standard formation evaluation and survey measurements to optimize wellbore placement
within the reservoir.
Transmission of T2LM, BFV or FFV and porosity allows calculation of permeability using the
Schlumberger-Doll Research (SDR) or TimurCoates equations.6 Although T2 distributions
themselves can be provided in real time, telemetry bandwidth limitations require prioritization
of data; less critical information is stored in
memory for later processing.
Data are transmitted to surface in real time
by the PowerPulse MWD telemetry system. As
with other VISION Formation Evaluation and
Imaging While Drilling LWD tools, maximum
environmental conditions for the proVISION tool
are 300°F [150°C], 20,000 psi [138 MPa], and
dogleg severity of 8°/100 ft [8°/30 m] while rotating and 16°/100 ft [16°/30 m] while sliding.
The proVISION opposing-dipole magnet
design produces a symmetric magnetic field. The
vertically oriented tubular samarium-cobalt
permanent magnets are stable within the operating temperature range of the tool. A predictable
and repeatable NMR measurement is produced
(next page, top).
The interaction of the rf field and static magnetic field produces a resonant region, or shell,
with a diameter of 14 in. [36 cm] and height of
6 in. [15 cm] (next page, bottom). Magnetic-field
strength within the shell is approximately 60
gauss, with a field gradient of about 3 gauss per
centimeter. The width of the measurement shell
allows formation measurement in slightly
enlarged or deviated wellbores and when the tool
is eccentered. The formation depth of investigation (DOI) varies with borehole diameter. For
example, in an 81⁄2-in. diameter borehole, the DOI
is 23⁄4 in. [7 cm]. At a drilling rate of 50 ft/hr
[15 m/hr], vertical resolution is 3 to 4 ft [0.9 to
1.2 m] after data stacking.
Oilfield Review
4. For more on T2 relaxation mechanisms: Kenyon et al and
Allen et al (2000), reference 2.
5. Prammer MG, Drack E, Goodman G, Masak P, Menger S,
Morys M, Zannoni S, Suddarth B and Dudley J: “The
Magnetic Resonance While-Drilling Tool: Theory and
Operation,” paper SPE 62981, presented at the SPE
Annual Technical Conference and Exhibition, Dallas,
Texas, USA, October 1–4, 2000
Drack ED, Prammer MG, Zannoni SA, Goodman GD,
Masak PC, Menger SK and Morys M: “Advances in LWD
Nuclear Magnetic Resonance,” paper SPE 71730, presented at the SPE Annual Technical Conference and
Exhibition, New Orleans, Louisiana, USA, September 30–
October 3, 2001.
Horkowitz J, Crary S, Ganesan K, Heidler R, Luong B,
Morley J, Petricola M, Prusiecki C, Speier P, Poitzsch M,
Scheibal JR and Hashem M: “Applications of a New
Magnetic Resonance Logging-While-Drilling Tool in a
Gulf of Mexico Deepwater Development Project,”
Transactions of the SPWLA 43rd Annual Logging
Symposium, Oiso, Japan, June 2–5, 2002, paper EEE.
Morley J, Heidler R, Horkowitz J, Luong B, Woodburn C,
Poitzsch M, Borbas T and Wendt B: “Field Testing of a
New Magnetic Resonance Logging While Drilling Tool,”
paper SPE 77477, presented at the SPE Annual Technical
Conference and Exhibition, San Antonio, Texas, USA,
September 29–October 2, 2002.
6. Akbar M, Vissapragada B, Alghamdi AH, Allen D,
Herron M, Carnegie A, Dutta D, Olesen J-R,
Chourasiya RD, Logan D, Stief D, Netherwood R,
Russell SD and Saxena K: "A Snapshot of Carbonate
Reservoir Evaluation," Oilfield Review 12, no. 4
(Winter 2000/2001): 20–41.
Summer 2003
Magnetic field
(14-in. diameter x 6-in. height)
Mud flow
Tubular
samarium-cobalt
magnets
Optional stabilizer
> The proVISION tool design. Housed within a 37 ft [11.3 m] long, 6 3⁄4-in.
[17.1-cm] diameter drill collar, the tool’s outside diameter is 7 3⁄4 in. [19.7 cm].
When configured with no external upsets and with wearbands in place, the
tool can be run in boreholes ranging from 8 3⁄8 in. up to 10 5⁄8 in. diameter. Onsite field engineers may attach a screw-on stabilizer to reduce lateral motion
and centralize the tool in a borehole. Telemetry connections on both ends of
the tool assembly allow configuration to any section of a bottomhole assembly (BHA). The tool is turbine-powered, rather than battery-powered, and can
accommodate flow rates ranging from 300 to 800 gal/min [1136 to 3028 L/min].
14 in.
2 3⁄4 in. DOI
Diameter of investigation
14 in.
6 in.
Mud flow
For geosteering purposes, field engineers can
place the tool directly behind the downhole
motor or PowerDrive rotary steerable system or
directly above the bit sub. To further enhance
geosteering capabilities, the proVISION antenna
section, which contains the permanent magnets,
is located at the bottom of the tool, placing the
measurement point as close to the bit as possible.
The existence of powerful magnets within the
bottomhole assembly (BHA) has the potential to
adversely affect azimuthal magnetic-survey
instruments used for determining spatial coordinates of the borehole. However, Schlumberger
engineers have demonstrated through modeling
and experimentation that the axially symmetric
magnetic field of the proVISION tool has little
influence on azimuthal magnetic measurement.
Since the magnitude of magnetic-field interference is small and directly proportional to the
intensity of the magnetic field produced by the
proVISION tool, errors are significant only when
the proVISION tool is placed directly above the
survey instrument. Based on numerical models
and physical measurements, Schlumberger
engineers have developed survey correction
algorithms for NMR magnetic interference.
These algorithms are included in the IDEAL
Integrated Drilling Evaluation and Logging wellsite software.
Resonant zone
Magnetic field
Annular magnet
8 1⁄2-in.
borehole
8 1⁄2-in.
borehole
> Cross sections of the proVISION tool. The axial section through the
antenna (left) illustrates the symmetric tool design. The dark blue bars are
hollow cylindrical magnets. Lines of constant field strength (blue) indicate a
gradient magnetic field that decays away from the tool. The section through
the coaxial wound antenna coil is shown in black. The interaction of the
antenna and the magnets produces a cylindrical resonant shell (red stripes)
that is 6 in. [15 cm] long, 0.4 in. [10 mm] thick, with a 14-in. [36-cm] diameter of
investigation. The transverse section through the coaxial wound antenna coil
(right) illustrates the axisymmetric resonant shell (red). The resonant shell is
the only place the measurement is made—no measurement is made
between the tool and the resonant shell or from the resonant shell farther
into the formation. The formation depth of investigation (DOI) in an 8 1⁄2-in.
[21.5-cm ] diameter borehole is 2 3⁄4 in. [7 cm].
43
13 1⁄2 in.
13 1⁄2 in.
Resonant region
Borehole wall
Polarized
region
Resonant region
Revolutions per min. (RPM)
> Effect of lateral motion on the proVISION NMR measurement. The tool is
centered in the borehole at the beginning of the measurement cycle (left).
Subsequent to the initial polarization, drillstring motion causes the tool to rest
against the borehole wall, partially outside the polarized region (right). Ideally,
the tool would not move during the course of a CPMG pulse-echo sequence.
However, lateral motion of the tool during rotation causes the measurement
shell, or resonant region, to move out of the polarized region of investigation.
This can result in T2 amplitude and distribution errors.
600
400
200
0
-200
0
2
6
8
10
Time, s
Lateral velocity 15 mm/s
5
4
4
3
3
2
2
1
0
-1
-3
-4
-4
-3
-2
-1 0
1
Position, mm
2
3
4
5
18
20
Lateral velocity 33 mm/s
0
-3
-4
16
-1
-2
-5
14
1
-2
-5
12
5
Position, mm
Position, mm
4
-5
-5
-4
-3
-2
-1 0
1
Position, mm
2
3
4
> Lateral drillstring motion plots. During the 20-sec time interval, the lower left and right panels show
examples of benign and severe motion recorded by the proVISION tool while rotary drilling. Intervals
of motion amplitude less than 1 mm (bottom left) correspond to the low-rpm intervals shown (top) and
represent a nearly stationary condition. Violent motion occurs during the remaining time intervals,
when the tool is spinning freely and has lateral motion amplitudes up to 5 mm.
44
5
Making Measurements
The proVISION tool operates in a cyclic mode
rather than a continuous mode. The operating
cycle consists of an initial polarization wait time
followed by the transmission of the highfrequency rf pulse and then the reception of the
coherent echo signal, or echo train. The cycle of
pulsing and echo reception is repeated in
succession until the programmed number of
echoes has been collected. Typically, the acquisition is defined by the Carr-Purcell-Meiboom-Gill
(CPMG) sequence. An initial 90° pulse followed
by a long series of timed 180° pulses characterizes the CPMG sequence. The time interval
between the successive 180° pulses is the echo
spacing and is generally on the order of hundreds
of microseconds.
To cancel the intrinsic noise in a CPMG
sequence, the CPMGs are collected in pairs. The
first of the pair is a signal with positive phase.
The second of the pair is collected with an 180°
phase shift, also known as the negative phase.
The two CPMG sequences are then combined to
give a phase-alternated pair. Compared with the
individual CPMG sequence, the combined or
stacked CPMG sequence has an improved S/N.
Measurements of T1 and T2 and their distributions are key elements of NMR logging. The
primary T1 quantity measured is signal amplitude
as a function of polarization recovery time. The
primary T2 quantities measured are echo-signal
amplitudes and their decay. Pulse parameters
such as echo spacing, wait times and the NMR
measurement cycle define all aspects of the NMR
measurement and are completely programmable
in the proVISION tool.
Drillstring Dynamics and NMR Measurements
NMR measurements are not instantaneous. Tool
movement may cause the resonant or excited
region to move during data acquisition (above
left). The proVISION tool is equipped with sensors that measure the amplitude and velocity of
lateral motion, and instantaneous revolutions
per minute (rpm).
Tool movement can affect both T1 and T2 measurements. Motion-induced decay primarily
affects long T2 values, resulting in faster echo
decays that may reduce the accuracy of NMR
measurement, particularly in light hydrocarbon
and carbonate formations. These motion effects
are most severe when the measurement shell is
thin in relation to the tool displacement, often
resulting in movement of the resonant shell out
of the region of investigation, even for small tool
movements. A high-gradient static magnetic field
Oilfield Review
Optimizing Well Productivity
Proper well placement and completion design
are key to optimizing productivity. To accomplish
this, drillers must place wellbores in the most
productive part of a target reservoir, and engineers must design completions to maximize oil
production and recovery while simultaneously
limiting water production. Real-time LWD NMR
logging provides the data necessary for informed
decision-making.
Determining which intervals of a reservoir
should be completed requires an estimate of a
well’s productivity index (PI). Traditionally, this
question has been addressed after completion of
drilling, wireline logging and production testing.
The PI is based on a permeability profile, which
is the product of reservoir permeability and
vertical thickness. These measurements are
obtained from well logs, formation tests, or both.
For more than a decade, operators have
sought real-time estimates of permeability and
PI. In 1994, BP engineers successfully experimented with real-time PI determination methods
Summer 2003
400
RPM
200
0
-200
0
5
10
Time, s
15
30
Number of rotations
results in a thin measurement shell, which
rapidly decays with distance away from the tool.
In contrast, the proVISION tool has a low gradient design that results in a thick measurement
shell and insensitivity to tool motion.
Since lateral motion can potentially shorten
T2 decay rates, understanding this motion is
critical for developing data quality-control
techniques. To assess motion-induced effects,
engineers must know the frequency, amplitude,
trajectory and timing of the motion.7 Rapidsampling accelerometer and magnetometer
systems measure real-time drillstring motion
(previous page, bottom). Motion data are processed in 20-sec snapshots. Raw snapshot data
are compressed and can be stored in memory,
while the processed results are recorded continuously to provide an uninterrupted log of lateral
motion. The theoretical maximum T2 value
resolvable during motion is calculated and a flag
indicating NMR data quality is transmitted with
the real-time data set.
Motion data obtained with the proVISION
tool have broad independent utility. These data
can alert the driller to excessive lateral motion,
an unfavorable resonant mode or excessive
shocks allowing corrective action to be taken to
reduce potential BHA or drill-bit damage and to
optimize drilling rates, improving drilling efficiency. Timely response to excessive drillstring
motion can also minimize borehole enlargement
(above right).
20
6 wraps ahead
20
10
7 wraps behind
0
0
5
10
Time, s
15
20
> An example of extreme stick-slip. The upper graph shows instantaneous rotation (rpm). At about
8 sec into the time interval, the BHA becomes stuck for about 7 sec until the continued buildup in torque
releases the BHA and the stored energy accelerates the drillpipe to over 300 rpm after which the BHA
becomes stuck again. The lower graph shows the number of cumulative rotations. The number of rotations increases until the BHA becomes stuck, at which point the topdrive continues turning and builds
seven wraps in the drillstring before the BHA breaks free. The BHA releases the built-up energy, and
inertia causes it to overrotate and advance six wraps ahead of the topdrive, potentially unscrewing
sections of the BHA.
at their Wytch Farm project located in the south
of England. Geological studies of the Sherwood
sandstone oil reservoir established that reservoir
productivity is a function of permeability, and
that permeability is controlled by grain size
and porosity. Core data were used to create
permeability bulk-density transforms for each
grain-size class and these, in turn, were used to
estimate PI. As drilling progressed, a permeability log was generated in real time using grain size
obtained from sieve analysis of drill cuttings and
combining porosity measurements from a lithodensity-neutron logging tool. Petrophysicists
then calibrated the model against offset wells.
Engineering and petrophysical teams used
these early real-time permeability-productivity
estimates to model and optimize a well’s economic potential in several ways. Decisions to
adjust well trajectory were based on real-time
productivity predictions. By optimizing perforation intervals, the team maximized production
and minimized the potential for water breakthrough. These data were used to estimate
reserves remaining in wells where intervals had
been plugged back for water shutoff.8
At Wytch Farm, BP’s method was relatively
simple to implement. The Sherwood sandstone is
not highly cemented and grain size, porosity and
permeability have a clearly defined relationship.
Also, well cores were available for model calibration. In many other reservoirs, the petrophysical
characteristics are less straightforward. While
similar processes might provide comparable
results while drilling in more complex reservoirs,
the petrophysical community wanted a more
accurate and complete formation-evaluation
solution. NMR in real time can provide this
information and help in optimizing wellbore
placement and completion design.
7. Speier P, Crary S, Kleinberg RL and Flaum C: “Reducing
Motion Effects on Magnetic Resonance Bound Fluid
Estimates,” Transactions of the SPWLA 40th Annual
Logging Symposium, Oslo, Norway, May 30–June 3, 1999,
paper II.
8. Blosser WR, Davies JE, Newberry PS and Hardman KA:
“Unique ESP Completion and Perforation Methodology
Maximises Production in World Record Step-Out Well,”
paper SPE 50586, presented at the SPE European
Petroleum Conference, The Hague, The Netherlands,
October 20–22, 1998.
Harrison PF and Mitchell AW: “Continuous Improvement
in Well Design Optimises Development,” paper SPE
30536, presented at the SPE Annual Technical
Conference and Exhibition, Dallas, Texas, USA,
October 22–25, 1995.
Hogg AJC, Mitchell AW and Young S: “Predicting Well
Productivity from Grain Size Analysis and Logging While
Drilling,” Petroleum Geoscience 2, no. 1 (1996): 1–15.
45
NMR in Real Time
Modern NMR logs measure mineralogyindependent porosity and provide an estimate of
permeability and bound-fluid volumes. They can
also detect the presence of hydrocarbons. When
combined with other LWD measurements,
NMR data can be used to generate potential
production estimates in real time.
In 2002, BP engineers applied the proVISION
system on a deepwater project in the Gulf of
Mexico, USA (right). During drilling with oil-base
mud, real-time NMR logs were obtained in three
separate 81⁄2-in. diameter wells. The proVISION
pulse sequence consisted of a single wait time
and burst sequence. A relatively long wait time of
12 sec was used to ensure adequate polarization
of the light hydrocarbons that were expected
in this reservoir. Six hundred echoes were collected after the long wait time. The burst
sequence consisted of 20 echoes following a
0.08-sec wait time. Echoes were collected with
spacing of 0.8 and 1.2 msec. The overall NMR
cycle time was about 30 sec at a drilling rate of
approximately 70 ft [21 m] per hour. This combination of cycle time and rate of penetration
(ROP) gave a depth sample rate of about 0.75 ft
[0.23 m] per phase-alternated pair.
To determine BFV, a T2 cutoff of 90 msec was
chosen. This T2 cutoff value was based on experience with wireline NMR measurements in this
field. Evaluation by the petrophysical team indicated that neutron, density and NMR porosity
were in agreement through the sandstone, which
has a porosity of about 28 p.u. In addition to NMR
data, the proVISION data set provided the operator with drilling performance, lateral motion and
downhole RPM logs to detect erratic drilling conditions, such as stick-slip motion, and allowed
the driller to take corrective actions, potentially
extending the life of the bottomhole assembly
and optimizing ROP.
The Quest for Carbonate Evaluation
Hydrocarbons in the Al Shaheen field, offshore
Qatar, are currently produced from three
Cretaceous formations, the Kharaib, Shuaiba and
Nahr Umr. The Kharaib and Shuaiba reservoirs
are carbonate, while the Nahr Umr comprises
thin sandstones (next page, top).
Maersk Oil operating the Al Shaheen field in
cooperation with Qatar Petroleum is developing
these complex formations with extended-reach
horizontal wells that occasionally exceed
30,000 ft [9144 m] measured depth (MD) while
46
Hydrocarbon
proVISION Porosity
Washout
Caliper
-2
API
4
0.2
Rotation
150
Rate of Penetration
0
0
10
Sample
ohm-m
ohm-m
2000
Real-time proVISION
Permeability
0.2
mD
g/cm3
1.65
ft3/ft3
0
Bulk Volume Water
Bulk Density
2000
Attenuation Resistivity
0.2
RPS
Rate of Penetration
0.25 ft/sec
0.6
Hydrocarbon Flag
in.
Total Porosity
0
Phase Resistivity
Gamma Ray
0
ft3/ft3
0.6
0.6
2.65
ft3/ft3
0
T2 Distribution
Bound Water
Thermal Neutron Porosity
ft3/ft3
0.6
0
Hydrocarbon Flag
2000 1
ft3/ft3
Water
0
proVISION BFV
-10 0.6
ft3/ft3
40
proVISION T2LM
0 1
msec
10,000
XX650
XX700
XX750
> Formation analysis in deepwater Gulf of Mexico, USA. The proVISION resistivity-independent oilindicator information, bound-fluid volume data and permeability data are integrated with wireline
log-derived water-saturation information to deliver key producibility estimates while the well is being
drilled. Tracks 1 through 4 are available as real-time data channels. Changes in the signature of the
recorded mode T2 distribution (Track 5) confirm the oil/water contact. The hash marks in the depth
track are NMR raw-data sample points.
only 3000 ft [914 m] in true vertical depth.9 In
such wells, drillpipe cannot be rotated in the
hole with logging cable attached. Frictional
effects eventually prohibit sliding beyond about
13,000 ft [3962 m]. Thus, wireline-conveyed logging tools are typically unable to reach the farthest part of a horizontal section. LWD tools are
conveyed over the entire length of the borehole
while providing data for geosteering and primary
formation evaluation.
NMR techniques can help determine reservoir fluid flow and permeability characteristics.
These characteristics may vary significantly with
changes in geologic facies. Detection of facies
variation is critical to reservoir understanding
and optimal wellbore placement. Often, particularly in carbonate reservoirs, the lack of consistent relationships between porosity and
permeability on a reservoir scale limits LWD
Oilfield Review
9. Damgaard A, Hansen P, Raven M and Rose D: “A Novel
Approach to Real Time Detection of Facies Changes in
Horizontal Carbonate Wells Using LWD NMR,”
Transactions of the SPWLA 44th Annual Symposium,
Galveston, Texas, USA, June 22–25, 2003, paper CCC.
Summer 2003
IRAN
Al Shaheen
field
SAUDI ARABIA
TURKEY
QATAR
SYRIA
IRAQ
AFGHANISTAN
IRAN
0
50
0
100
100
PAKISTAN
150 miles
200
300 km
UNITED ARAB EMIRATES
SAUDI ARABIA
> Location of the Al Shaheen field
operated by Maersk Oil Qatar AS in
cooperation with Qatar Petroleum.
OMAN
YEMEN
Bound Fluid
Free Fluid
Bins 1-2
Total CMR Porosity
Bin 3
0.6
Bin 4
0.6
Bin 5
1.7
SDR Permeability
Bins 7-8
ft3/ft3
0
100
Depth,
ft
g/cm3
2.7
NMR T2 Distribution
Neutron Porosity
0.6
Gamma Ray
API
0
Bulk Density
Bin 6
0
m3/m3
CMR Free Fluid
Timur-Coates Permeability
m3/m3
0 0
Photoelectric Effect
2
12 0.3
29
T2LM
msec
Deep Image
3.45
11.25
16.67
19.49
22.77
2?.14
30.38
34.42
37.57
40.32
42.?7
4?.27
50.05
54.83
62.42
82.88
22115.12
petrophysical characterization using porosity
logs. Conventional wireline-conveyed NMR logging
has improved the characterization of geologic
facies and other petrophysical carbonate properties such as permeability (bottom).
Drilling extended-reach wells in the Al
Shaheen field is challenging. Rotary steerable
BHAs are typically used for directional control
in the drilling of the long horizontal sections. The
petrophysical team was concerned about
diminished LWD NMR data quality due to
motion-dependent T2 decay resulting from
the typically high levels of BHA shock, stick-slip
and lateral tool motion during drillstring rotation. With ROPs occasionally in excess of
500 ft/hr [152 m/hr], further data-quality loss
was expected.
Carbonate rocks typically have lower surfacerelaxation times, which leads to extended T2
times. Since much of the important petrophysical information is contained in the later echoes,
acquisition sequences in carbonates typically
require a longer wait time and a greater number
of echoes than in clastic formations. It was
unknown whether the late T2 components typically seen in the Al Shaheen carbonate rocks
would be detected under the expected difficult
drilling conditions.
Engineers attempted to alleviate as many
variables as possible during prejob planning. To
improve the S/N, raw echo stacking was also
planned. Since facies changes typically occur
over tens or hundreds of feet in extended-reach
wells, and the detection of small-scale variations
was not the main objective, a loss of resolution in
exchange for improved S/N was acceptable.
The world’s first proVISION deployment in a
carbonate reservoir was in an extended-reach,
81⁄2-in. diameter horizontal well, drilled to more
than 24,000 ft [7315 m] MD with water-base mud.
A rotary steerable assembly controlled trajectory
while LWD NMR data were obtained in real time
along the entire borehole length.
Limited amounts of core material were available from this particular section of the Shuaiba
reservoir. Historically, carbonate facies identification and interpretation were based on a combination of drill cuttings, thin sections and log
ohm-m
Image Orientation
6000 U
R
B
L
U
XM900
Sliding–no image
XN000
Sliding–no image
> Identifying changes in the Shuaiba limestone reservoir with wireline NMR data. The NMR data show
a large decrease in free fluid, an increase in bound fluid (Track 3, shown shaded yellow) and a decrease
in NMR permeability (Track 2) from a depth of XN010 to XN070. It would be difficult, if not impossible,
to identify these changes with standard porosity (Track 3, neutron porosity in blue and bulk density in
red) and gamma ray logs (Track 1, solid green curve).
47
Bound Fluid
Free Fluid
Bulk Density
1.7
g/cm3
2.7
Thermal Neutron Porosity
Binned NMR Porosity
Early
Late
Gamma Ray
0
API
ROP
100 500 ft/hr 0
SDR Permeability
Total NMR Porosity
Timur-Coates Permeability
BFV–NMR
NMR T2 Distribution
NMR T2LM
3
msec
6000 U
Image Orientation
R
B
L
U
XX200
XX300
XX400
XX500
XX600
> A clear image of borehole trajectory. The LWD resistivity image (Track 5) shows the wellbore trajectory encountering an overlying marl. The NMR data clearly show a bimodal T2 (Track 4) with the short
T2 peak, centered at 6 msec, coming from the argillaceous material above the borehole from XX329 to
XX429 ft, and the longer T2 peak, centered at 200 msec coming from the limestone below the borehole.
Lateral changes in the limestone are also indicated. Facies 3 occurs from XX460 to XX474 ft and XX488
to XX500 ft, characterized by the lower T2 LM value (Track 4).
analysis. The borehole was expected to penetrate
multiple carbonate facies with varying permeabilities and producibility characteristics.
Maersk Oil hoped to gain significant reservoir
information in real time from the proVISION
48
tool, including differentiating various carbonate
facies along the wellbore path and comparing
LWD NMR log quality with that of selected
intervals of wireline-conveyed NMR logs.
As expected, a high level of downhole shock
and stick-slip occurred. ROP was variable, sometimes exceeding 500 ft/hr. Because of tool motion
and fast ROP, NMR LWD data had a moderate
degree of noise compared with a wireline-
Oilfield Review
Bound Fluid
Free Fluid
Bulk Density
1.7
Gamma Ray
API
ROP
100
2.7
Thermal Neutron Porosity
Binned NMR Porosity
Early
Late
0
g/cm3
SDR Permeability
Total NMR Porosity
Timur-Coates Permeability
BFV–NMR
500 ft/hr 0
NMR T2 Distribution
NMR T2LM
3
msec
6000
XX800
XX900
XY000
XY100
> Facies 1 from LWD NMR. The LWD data shown indicate an interval of clean carbonate where the T2
(transverse relation time) distribution (Track 4) contains a significant percentage of late T2 values. The
solid blue line is an empirically determined T2 cutoff that is used to partition the T2 distribution into a
fast component representing bound fluids and a slow component indicating the free fluids. The red
trace represents the T2 LM distribution. The T2 LM is generally well above the T2 cutoff value, indicating
that most of the fluid in the pore space is free fluid. The total porosity computed from the NMR data,
shown as a dashed black line in Track 3, is in agreement with the conventional limestone matrix neutron porosity in blue, and with the formation bulk density displayed in red. The yellow area represents
the bound-fluid volume, while light green indicates the portion of the total porosity that is filled with
free fluids, or the effective porosity. The longest T2 times indicate the largest pores, while the shortest
are attributed to the smallest pore sizes. Large pores appear to make up a significant portion of the
total porosity, with only a small percentage comprising small and very small pores.
conveyed NMR log. However, data stacking
improved the S/N. Results from multiple MDT
Modular Formation Dynamics Tester runs provided data to estimate fluid mobility and adjust
the constants in NMR permeability equations.
Summer 2003
Analysis based on NMR permeabilities,
porosities, T2LM, bound-fluid volumes and freefluid volumes discerned three distinct porosity
systems. The team used changes in T2 character
to map facies variation along the borehole
(previous page). A low bound-fluid volume and a
high ratio of free to bound fluid typify Facies 1
(above). Facies 2 has moderate bound-fluid volume and a lower bound- to free-fluid ratio. The
average T2 of Facies 2 is shorter than that of
49
Bound Fluid
Free Fluid
Bulk Density
1.7
g/cm3
2.7
Neutron Porosity
Binned NMR Porosity
Early
Late
SDR Permeability
Total NMR Porosity
Timur-Coates Permeability
BFV–NMR
NMR T2 Distribution
ROP
Gamma Ray
0
API
ft/hr
100 0
500
NMR T2LM
3
msec
6000 U
Image Orientation
R
B
L
U
XX400
XX500
Facies 2
XX600
XX700
XX800
Facies 3
XX900
XX000
> Contrasting NMR data with resistivity images. An LWD resistivity image log is shown in Track 5. The
image is scaled such that conductive formations are dark and more resistive formations are light with
no absolute scale. The resistivity image shows a significant change in the formation resistivity while
the porosity remains more or less constant, implying a possible textural change. The NMR log over the
interval identified as Facies 2 indicates some large pores. The T2 LM is above the cutoff value, but with
a broad distribution of pore sizes resulting in a significant percentage of the total porosity being occupied by bound fluid. The estimated permeability of Facies 2 is lower than that of Facies 1 (see figure,
page 49). The NMR log over the interval identified as Facies 3 indicates few, if any, large pores. The
T2 LM is below the cutoff value, and most of the total porosity is occupied by bound fluid. The estimated
permeability of Facies 3 is lower than that of Facies 1 or 2.
50
Facies 1 and the complete data spectrum is
shifted to shorter T2 values. Facies 3 is typified by
high bound-fluid volume and a low ratio of free to
bound fluid. In Facies 3, the T2 spectrum is
shifted farther toward shorter values. Thin
sections made from cuttings confirmed the facies
significance of the LWD NMR T2 response.
LWD NMR porosity agreed with density porosity in Facies 1 and 2 with an average 3 p.u. deficit
in Facies 3 believed to be due to a percentage of
faster-decaying T2 signals. LWD NMR data indicate different T2 decay rates for each of the three
facies, allowing clear differentiation; this would
not have been possible with neutron-porosity
measurements alone (left).
To improve confidence that the LWD NMR
data were identifying petrophysical changes in
the carbonate facies, the team had to rule out the
possibility that the interpreted T2 response was
being dominated by motion-induced T2 decay.
Measured lateral velocity data were used to confirm that the T2 data were accurate and correctly
indicating changes in the carbonate facies (next
page, top left). This particular data set shows a
large amount of T2 data acquired even at elevated lateral velocities. The current proVISION
design does not directly allow compensation for
downhole tool motion in the T2 decay measurement. However, highlighting intervals of increased
tool motion can be used as a log-quality indicator.
To examine the effects of downhole tool
motion on LWD NMR data, wireline CMR measurements acquired after drilling were compared
with real-time proVISION data. Porosity, FFV,
BFV, T2LM and NMR permeabilities all compare
favorably (next page, right). The CMR data were
acquired over limited intervals for comparison,
primarily in the proximal part of the well that
had been open to invasion the longest. Some
CMR logged intervals displayed a small decrease
in T2LM values consistent with the additional filtrate invasion time prior to wireline logging.
None of the LWD NMR intervals indicated any
identifiable motion-induced T2 decay. The favorable comparison of the late T2 components indicates that downhole lateral tool motion is not a
dominant T2 decay mechanism in this data set.
The proVISION system was configured to
transmit porosity, T2LM and FFV in real time to
allow use of measurements for geological characterization and to aid geosteering. Although further
evaluation will be required to completely understand the NMR T2 response in carbonate rocks,
the team working in the Al Shaheen field demonstrated that carefully interpreted LWD NMR data
can be used to help detect variation in carbonate
facies and their petrophysical characteristics.
Oilfield Review
Bound Fluid
200
Free Fluid
NMR–BVF
CMR–BVF
NMR T2LM
NMR Porosity
CMR T2LM
Lateral velocity, mm/s
150
CMR T2LM
ROP
ft/hr
500
0
100
NMR T2 Distribution
NMR T2 Distribution
CMR Porosity
0
29 0
29
XX250
50
0
0
75
150
T2 LM, ms
225
300
XX300
> Lack of motion-induced decay. The data acquired in this field show
no apparent reduction in T2 values associated with the lateral velocity
of the LWD NMR tool, implying that in this well, tool motion does not
affect T2 decay.
XX350
The Next Generation
The proVISION system has demonstrated its
ability to acquire real-time logs in both clastic
and carbonate reservoirs, potentially identifying
less obvious or otherwise undetected facies
changes. Even for longer T2 components in
carbonate formations drilled at elevated ROP,
the tool delivers sufficient data resolution for
facies determination and for permeability and
bound- to free-fluid volume calculations. The
LWD proVISION tool provides essential realtime reservoir information and data useful for
making geosteering decisions in complex
reservoir settings.
Severe stick-slip and BHA shock are often
associated with drilling long horizontal sections.
Bottomhole shock, combined with high ROP, may
increase noise in the data sets. However, field
data demonstrate that the proVISION tool is
sufficiently robust to handle these conditions
and provide reliable T2 data.
Future generations of NMR tools hold great
promise. The industry can look forward to the continued evolution of LWD NMR technology, which is
expected to provide drilling engineers and petrophysical teams with significant advancements in
real-time formation evaluation for geosteering and
productivity optimization.
—DW, SP
Summer 2003
XX400
> Agreement of wireline CMR and proVISION data. The wireline NMR porosity is seen to follow the same trend as the LWD NMR porosity with a small
systematic shift to lower porosity (Track 1). This difference in total porosity is
influenced by the differing depth of investigation of the tools and the
difference in mud-filtrate invasion related to the formation exposure time.
Computed bound-fluid volumes are in agreement (Track 1). The vertical, or
spatial, resolution of the LWD NMR tool is reduced because of the high level
of stacking utilized to increase the S/N. Likewise, the physics of measurement
imposes a temporal, or time, resolution limit on the LWD tool relative to that
seen with the wireline sensor. The overall effect is a smoothing of the T2 distribution over time and depth. The T2 LM of the LWD NMR is shown overlaid
on the CMR data (Track 2). Considering the difference in tool design, acquisition parameters, environmental conditions, and the time lapse between
drilling and drillpipe-conveyed wireline logging, the comparison is excellent.
51
Contributors
Anwar Husen Akbar Ali, who is based in Cairo, Egypt,
is Schlumberger advisor for Production Engineering,
and Oilfield Services Solutions and Technology
Integration manager for the East Africa and East
Mediterranean region. Prior to this he was
PowerSTIM* and Sand Management Solutions business development manager for the Middle East and
Asia. Since joining Schlumberger in 1988, he has
worked on projects in the Middle East and Asia, ranging from field engineer to operations manager and
technical advisor. He worked in Houston, Texas, USA,
for two years as senior technical engineer in the
Production Enhancement group and later managed
the Asia Technology Hub in Kuala Lumpur, Malaysia.
Anwar received his BS degree (Hons) in petroleum
and natural gas engineering from University
Technology of Malaysia and obtained an MS degree in
integrated reservoir management from Institut
Français du Pétrole in Rueil-Malmaison, France.
John Alvarado is Schlumberger Drilling &
Measurements (D&M) account manager in Houston,
Texas. There he is project coordinator for measurements-while-drilling (MWD) and logging-while-drilling
(LWD) operations and overall D&M business management including involvement with BP’s deepwater
exploration and development. He joined Schlumberger
in 1995 as a field engineer in Stafford, Texas, and subsequently became district engineer and field service
manager. John earned a BS degree in mechanical engineering at University of Houston in Texas.
Kevin Bellman is international operations geologist
for EnCana Corporation. He is based in Calgary,
Alberta, Canada, where his main areas of operations
are the Middle East and Ecuador. Previously he was
with AEC International for three years.
Scott Bittner, Schlumberger Product Champion for
ABC* Analysis Behind Casing services, is based in
Sugar Land, Texas. He is responsible for business
development of cased hole formation evaluation
including product development and marketing of new
technologies. He began his career with Schlumberger
in 1987 as a junior field engineer in Brooks, Alberta,
Canada, performing production and evaluation services. After 10 years in various field locations throughout North America, he became alliance coordinator,
Chevron Canada Inc. in Calgary, Alberta, Canada, and
then North America staff technical engineer for formation evaluation in Sugar Land, Texas. He has also
served as Reservoir Evaluation–Wireline (REW) operations manager in Alaska (USA), northern Canada and
Oman. Scott holds a BS degree in mechanical engineering from Carleton University in Ottawa, Ontario,
Canada.
52
Tim Brown, Marathon Oil Company Asset Team
Manager for northern Oklahoma, is based in Oklahoma
City, Oklahoma, USA. Since he joined Marathon in
1982, he has had various domestic and international
positions in production and operations, both onshore
and offshore. Tim earned a BS degree in mechanical
engineering at Rose-Hulman Institute of Technology in
Terre Haute, Indiana, USA.
David Cameron, Schlumberger Account Manager for
Reservoir Evaluation–Wireline, is based in Stavanger,
Norway. There he manages accounts in Scandinavia for
ConocoPhillips, Agip, Shell, Total, Marathon,
ExxonMobil, Mærsk, Amerada Hess and DONG. He
began his career in 1988 as a field engineer for
Western Atlas Logging Services and had assignments
in Scotland, Saudi Arabia, Norway and Indonesia.
From 1998 to 2000, he was a senior consultant with
Independent Project Analysis in The Hague, The
Netherlands. He assumed his current position with
Schlumberger in 2000. David received a BS degree in
mechanical engineering at Brunel University in
London, England, and also received an MBA degree
after studying at Erasmus University in Rotterdam,
The Netherlands, and at the Stern School of Business
at New York University, New York, USA.
Edwin Cervantes is a sales and support engineer for
Schlumberger Reservoir Evaluation–Wireline in Quito,
Ecuador. There he provides technical support for field
operations and for all clients in Ecuador, primarily
Petroproducción. He joined Schlumberger in 1994 and
subsequently had field engineering positions in
Colombia and Ecuador. Edwin obtained a degree in
mechanical engineering from Escuela Politecnica
Nacional in Quito.
Anders Damgaard is petroleum engineering manager
with Maersk Oil in Doha, Qatar. He joined Maersk Oil
in 1981 and has held various petroleum and drilling
engineering positions in Denmark and abroad. Anders
has a degree in electronic engineering from Technical
University of Denmark in Copenhagen.
Roger Delgado, a senior drilling engineer with
Pluspetrol Peru Corporation in Lima, Peru, is responsible for planning and design of wells in the Camisea gas
field. He began his career in 1990 as a drilling engineer with Petróleos del Perú S.A. From 1996 to 1999,
he was with Pluspetrol Peru Corporation, planning and
designing wells in the Peruvian jungle. Before taking
his current position, he was a drilling engineer with
Pluspetrol Bolivia Corporation, designing high-pressure, high-temperature wells in Bolivia. Roger has a
degree in petroleum engineering from Universidad
Nacional Ingeniería, and a degree in accounting and
finance from Escuela de Administración Negocios para
Graduados, both in Lima, Peru.
Jim Farnsworth is BP Technology vice president
responsible for worldwide exploration and is also the
senior manager for the BP Global Initiative for Seismic
Services. Prior to this he was vice president of North
America Exploration. His other positions with BP have
included vice president of deepwater exploration for
BP in Houston, Texas; Alaska exploration manager;
and Central North Sea subsurface manager. Jim
received BS and MS degrees in geophysics and geology
from University of Western Michigan and Indiana
University, respectively.
Anthony Fondyga is Schlumberger Data & Consulting
Services manager for Ecuador. He joined
Schlumberger Canada as an openhole logging engineer
in 1980 after earning a degree in electrical engineering from the University of Toronto, Ontario, Canada.
After many operations and sales assignments in open
hole, cased hole, and production logging and drillstem
testing, he was seconded to the Petrophysics department of PanCanadian Petroleum in 1994. Tony
returned to the Schlumberger Interpretation
Development group in Calgary, where he worked on
developing new applications and technologies in logging services. Before his current assignment, he spent
two years as senior petrophysicist for the Hibernia
Asset team in Saint John’s, Newfoundland, Canada.
David Gibson is the WesternGeco global EcoSeis†
champion for land operations worldwide and is responsible for integration of an environmental inspection
tool into the company’s quality, health, safety and environment (QHSE) and knowledge management
processes. He previously served as manager of South
Texas operations. He joined Western Geophysical in
1980. David holds a BS degree in geology from Victoria
University at Wellington, New Zealand.
Ankur Gupta joined Schlumberger in 1988 as a wireline field engineer and spent the next three years in
field operations in offshore Great Yarmouth, England.
His subsequent positions were in India and Kuwait
where he was general field engineer, engineer in
charge and field service manager. In 1998, he joined
the Evaluation Services Technique staff in Montrouge,
France. From 1999 to 2000, he was the Wireline &
Testing (W&T) asset manager at Schlumberger
Wireline headquarters in Clamart, France. Before
becoming ABC product champion in Sugar Land,
Texas, in 2001, he was W&T operations manager, India,
and then Oilfield Services manager, Mumbai, India.
Ankur earned a BS degree in electrical engineering at
the Indian Institute of Technology in New Delhi, India.
Pia Hansen is currently a senior petrophysicist with
Maersk Oil Qatar. She joined Maersk Oil in 1980 and
has been working in various petroleum and drilling
engineering positions both in Denmark and abroad.
Oilfield Review
Ralf Heidler is the section manager for the
proVISION* engineering project at the Schlumberger
Sugar Land Product Center in Texas. There he oversees ongoing tool development and new answer products. He joined Schlumberger in 1997. Since then, he
has been associated with various aspects of proVISION
development including data processing and software
development. Ralf received a PhD degree in physics
from University of Leipzig in Germany.
Robert Hoshun is Schlumberger field operations coordinator for the proVISION tool. Since joining
Schlumberger in 1996, he has worked in various locations including Saudi Arabia, Australia, Papua New
Guinea and Qatar. Before taking his current assignment in Sugar Land, Texas, he was an LWD geosteering
specialist in Qatar. Robert holds a BE degree (Hons) in
aerospace engineering from the Royal Melbourne
Institute of Technology, Australia.
Trent Hunter is Schlumberger Oilfield Services manager, Lloydminster, Alberta, Canada. He joined the
company in 1992 and had many field engineering positions in Canada, Alaska and Texas. From 1997 to 2000,
he worked in technical sales for Hercules Canada Inc.
Before taking his current position, he was
Schlumberger Reservoir Evaluation–Wireline account
manager in Calgary, Canada. Trent has a BE degree in
engineering from the University of Saskatchewan,
Saskatoon, Canada.
Diego Jaramillo is a Schlumberger petrophysicist for
Data & Consulting Services in Quito, Ecuador. His
work mainly involves processing and interpretation of
openhole and ABC logs. He joined Schlumberger in
1999 after receiving a degree as a geologist engineer
from Universidad Central del Ecuador in Quito.
Oscar Kelder, who is based in Stavanger, Norway, has
been working as a consultant for Statoil on the Snorre
field. He joined the Snorre Team in January 2002. Prior
to this assignment, he was a petrophysicist with Statoil
in Bergen and Stavanger. Oscar earned an MS degree
in petroleum engineering and a PhD degree in petrophysics at Delft University of Technology in The
Netherlands. He recently accepted a position with
Saudi Aramco.
James Kovats, Nuclear Magnetic Resonance (NMR)
Product Champion at the Sugar Land Product Center
in Texas, is responsible for overseeing development
and introduction of wireline and logging-while-drilling
NMR technology. He began his career as a hydrologist
working on the Yucca Mountain project with the US
Geological Survey in Denver, Colorado, in 1989. He
joined Schlumberger as a field engineer in 1991 and
worked in various locations in the North Sea and the
United Arab Emirates (UAE). Before taking his current position, he was field service manager for UAE
Offshore Operations, involved in coordinating all
aspects of wireline formation evaluation, workover and
completion activities. James earned BS and MS
degrees in geophysical engineering from the Colorado
School of Mines in Golden, USA.
Summer 2003
Don Lee is a principal geoscientist with Schlumberger
Data & Consulting Services in Houston, Texas. His
work involves processing and interpreting information
relating to formation mechanical properties, pore
pressure prediction and petrophysics for projects
worldwide. After earning a BS degree in electrical
engineering from Tennessee Technological University
in Cookeville, USA, he joined Schlumberger in 1980 as
a field engineer in Texas. His subsequent positions
included special services engineer, log analyst, senior
log analyst, application development engineer, senior
interpretation application engineer and data center
manager.
Venkat Pacha is operations manager, Schlumberger
Reservoir Evaluation–Wireline (REW) in Quito,
Ecuador. He joined Schlumberger in 1996 and had several engineering assignments in India and Indonesia.
In 2000, he became REW field service manager in Duri,
Indonesia. Before taking his current position in 2002,
he was REW location manager in South Sumatra,
Indonesia. Venkat holds a BS degree in chemical engineering from the Indian Institute of Technology in
Kharagpur, India, and is currently enrolled in the MBA
program at Erasmus University in Rotterdam, The
Netherlands, and in an MS degree program at HeriotWatt University, Edinburgh, Scotland.
Rob Marsden, who is based in Abu Dhabi, UAE, manages Schlumberger geomechanics and No Drilling
Surprises projects in the Middle East. He joined
Schlumberger in 2000, after spending 10 years as
senior lecturer and head of the Rock Mechanics
Laboratories and Wellbore Mechanics Research Group
at Imperial College in London, England. Since graduating with a degree in civil engineering from
Sunderland Polytechnic in England, and with MS and
DIC degrees in engineering rock mechanics from
Imperial College, Rob has had about 19 years of consulting, field, research and teaching experience in
petroleum rock mechanics. A chartered engineer, he
has published more than 40 papers, and has served on
numerous international and industry committees.
Richard Plumb, Geomechanics Metier, Schlumberger
Oilfield Services, is based in Houston, Texas.
Previously, he was principal consultant and manager
of Geomechanics for Schlumberger Data & Consulting
Services and Holditch-Reservoir Technologies, team
leader of Geomechanics for Integrated Project
Management (IPM) Engineering, and Geosciences
coordinator for the IPM Support Center in Houston.
Prior to joining IPM, he was responsible for case studies in the Interpretation and Geomechanics department at Schlumberger Cambridge Research in
England. He also worked at Schlumberger-Doll
Research, Ridgefield, Connecticut, USA, where he
developed log interpretation techniques for fracture
characterization, in-situ stress measurement and
hydraulic fracture containment. Dick has a BA degree
in physics and geology from Wesleyan University,
Middletown, Connecticut; an MA degree in geology
from Dartmouth College, Hanover, New Hampshire,
USA; and a PhD degree in geophysics from Columbia
University, New York, New York.
Bruce Miller, Schlumberger Formation Evaluation
Sales and Marketing Manager for Scandinavia, is based
in Stavanger, Norway. There he is responsible for marketing and sales of Wireline, LWD and Data &
Consulting Services products. He joined Schlumberger
in 1995 as a general field engineer in Opelousas,
Louisiana. In 1998, he led the Schlumberger-Texaco
Alliance Process Improvement team to streamline
openhole operations between the two companies in
the Gulf Coast area. Before taking his current position,
he was wireline field service manager in Houma,
Louisiana. Bruce obtained BS and MS degrees in geology
from the University of Illinois, Champaign-Urbana, USA.
Chris Morriss joined Schlumberger in 1978 and has
worked as a field engineer, log analyst and petrophysicist at various locations. He is currently principal engineer for the proVISION group at the Schlumberger
Sugar Land Product Center in Texas. Chris received an
engineering degree in 1975 from Aston University,
Birmingham, England.
Ruperto Orozco is an operations geologist with AEC
Ecuador Ltd. (EncanEcuador) in Quito, Ecuador. He
began his career in 1992 with Baker Hughes Inteq,
working in the Oriente and Neuquen basins. He joined
Tripetrol Company in Ecuador as chief geologist in
1995. Prior to joining AEC he worked for Petrokem
Logging Services doing mud logging in the Oriente
basin. Ruperto earned a degree as a geologist engineer
at Universidad Central del Ecuador in Quito.
Erling Prado-Velarde, who is based in Al-Khobar,
Saudi Arabia, is the Schlumberger coordinator for
PowerSTIM activities in Saudi Arabia, Kuwait, Bahrain
and Pakistan. He joined Schlumberger in 1980 as a
well cementing services engineer in Peru. After an
assignment at the UK training center, he became a
technical engineer in Macae, Brazil, providing training
to young engineers. From 1990 to 1993, he was district
technical engineer, overseeing cementing and stimulation in south Argentina. After a two-year assignment at
the Kellyville Training Center in Oklahoma, he became
district technical engineer in Mexico. In 1999, he
became fracture design manager for the
Schlumberger- Nefteyugansk Yukos alliance in western
Siberia. Erling obtained a degree in chemical engineering from Universidad Nacional de San Agustin,
Arequipa, Peru.
Lee Ramsey is global PowerSTIM training and support
manager based in Sugar Land, Texas. His main role is
to help organize new production optimization teams to
develop solutions in areas where past stimulations or
completions have not met client expectations. He
began his career with Dowell as a field engineer in
1974 in Williston, North Dakota, USA, and has held various positions in operations, engineering and marketing in the United States and Canada. He recently
headed the PowerSTIM initiative in North America as
product champion. The PowerSTIM team was nominated for several “Performed by Schlumberger”
awards. Lee attended Kansas State University in
Manhattan, Kansas, USA, where he received a BS
degree in geology.
53
Madeleine Raven is a lead geologist with Maersk Oil
Qatar. She joined the company in 1998 and has been
involved in geological interpretation, modeling and
development operations. Prior to joining Maersk, she
was projects manager for IEDS, and also a senior
reservoir geologist with Robertson Research
International. Madeleine holds a BS degree in earth
sciences from University of Leeds and a PhD degree
from University of Nottingham, both in England.
production, operations, reservoir engineering and
completions. From 1993 to 1996, he worked with the
company’s deep-gas exploration and risk-assessment
team in Calgary. The following year he was engineering manager at Truax Resources. Before joining
Enterra in 2001, he was vice president of operations
for Big Horn Resources Ltd. Trevor received a BS
degree in mechanical engineering from the University
of Saskatchewan in Saskatoon.
Shawn Rice is quality, health, safety and environment
(QHSE) manager for WesternGeco worldwide operations and serves on the executive board of the
International Association of Geophysical Contractors.
He previously was the business services manager for
Western Geophysical Company, responsible for QHSE,
human resources and training. He has held numerous
other positions since joining the company in 1984.
Shawn holds a BS degree in geophysical engineering
from Colorado School of Mines in Golden, USA.
David Spooner is a senior drilling engineer with BP
in Aberdeen, Scotland. He joined BP Exploration in
1988 and three years later, moved to Amoco UK as
lead drilling engineer on various projects including
the Everest development. From 1998 to 1999, he was a
senior drilling engineer with Global Marine
Integrated Services. He returned to BP in 2000 as
senior drilling engineer on the South Everest, Mirren
and South Magnus subsea developments. David has a
BS degree (Hons) in naval architecture and offshore
engineering, and an MS degree in marine technology,
both from the University of Strathclyde in Scotland.
David Rose is a Schlumberger interpretation development petrophysicist in Doha, Qatar. He joined
Schlumberger in 1989 as a field engineer and had various assignments in Norway, Denmark and Indonesia.
From 1995 to 1997, he was a log analyst in
Bakersfield, California, USA. Before taking his current
post in 2000, he was interpretation and computing
center manager in Midland, Texas. David has a BS
degree in geophysical engineering from the Colorado
School of Mines in Golden.
Al Salsman is Schlumberger cased hole wireline business development manager in Canada. After completing two years of training for a BS degree in business
administration at Acadia University in Wolfville, Nova
Scotia, Canada, he joined Schlumberger in 1977 as a
field engineer in Canada. After postings in Aberdeen,
Scotland, and Ras Shukeir, Egypt, he became a tubingconveyed perforating (TCP) coordinator in the Middle
East. He served as wireline country manager in Qatar,
manager of TCP and drillstem testing operations in
Indonesia, and technical staff engineer for Southeast
Asia. From 1993 to 1996, he was marketing manager
for the Schlumberger Perforating and Testing Center
in Rosharon, Texas. Before assuming his current position in 2000, he was Oilfield Services account manager for deepwater services in Nigeria.
Nikolay Smirnov is a Schlumberger geomechanics
scientist assigned to Integrated Project Management
and Data & Consulting Services in Houston, Texas. He
is currently working on No Drilling Surprises projects
involving pore pressure prediction, stress and drillingrisk analysis, and completion design. He joined
Schlumberger in 1997 as a field engineer in Moscow,
Russia. The following year he became a drilling engineer in Port Gentil, Gabon. Before taking his current
assignment in 1999, he was a drilling engineer in
Angola. Nikolay obtained BS and MS degrees in geophysics from Novosibirsk State University in Russia.
Trevor Spagrud, Vice President of Engineering at
Enterra Energy Corp. in Calgary, Alberta, Canada, is
responsible for technical and economic evaluation of
oil and gas assets as well as technical support in completions and operations. He began his career in 1990
at Wascana Energy Inc. (Saskoil) in Regina,
Saskatchewan, and subsequently had assignments in
54
Terry Stone is principal software consultant with
Schlumberger Information Solutions in the Abingdon
Technology Centre in England. A developer of the
ECLIPSE* reservoir simulator, he has worked on various technical options in the simulator including geomechanical stress equations, thermal simulation and
processes, and advanced well modeling. Previously he
worked for Scientific Software Intercomp in Denver,
Colorado; Mobil Oil in Dallas, Texas; and the Alberta
Research Council in Canada. In 1995, he joined
INTERA, which was subsequently bought by
Schlumberger GeoQuest. Terry earned an undergraduate degree in mathematics at University of Windsor,
and a PhD degree in nuclear engineering at McMaster
University in Hamilton, both in Ontario, Canada.
Tim Stouffer is first deputy general director,
Technical Support, Khanty Mansiyshk Oil Corporation
(recently acquired by Marathon Oil Company) in
Moscow, Russia. In his 25 years with Marathon he has
had various positions around the world in production
operations, reservoir engineering, liquid natural gas
operations, and evaluation of prospective acquisitions.
He also served as the reservoir engineer for the
Sakhalin II project, Piltun-Astokhskoye field, Sakhalin
Island, Russia. Tim obtained a BS degree in petroleum
engineering from Colorado School of Mines in Golden.
Wayne A. Wendt is a petrophysicist at BP Deepwater
Projects Business Unit in Houston, Texas. There he
works in field development, specializing in well planning and operations, seismic rock properties, and
pressure prediction and detection. He began his
career in 1978 as a geophysicist with Natural Gas
Corporation in San Francisco, California. He joined
BP (Sohio) in 1983 and worked on reservoir description of the Prudhoe Bay field, and next moved to
Anchorage, Alaska, to work in reservoir surveillance
and field operations. In 1987, he moved to Houston to
work on various exploration projects. Wayne has a BS
degree in mathematics from Indiana University of
Pennsylvania, USA, and an MS degree in engineering
geoscience from University of California, Berkeley.
An asterisk (*) is used to denote a mark of Schlumberger.
† EcoSeis is a mark of WesternGeco.
Oilfield Review
Coming in Oilfield Review
Coalbed-Methane Reservoirs.
Exploitation of coalbed-methane
reservoirs is becoming more economical as energy markets change
and new technologies take hold.
Coalbed-methane reservoirs do not
behave like ordinary gas reservoirs,
prompting operators and service
companies to reexamine traditional
well-construction, formation-evaluation, completion and production
techniques. In this article, we investigate this unconventional resource
and the industry’s efforts to unlock
the enormous potential of coalbedmethane reservoirs.
Refracturing. Hydraulically fracturing the same interval after initial
treatment can restore production to
near original rates. Research indicates that stress changes around
existing wells allow new fractures
to reorient and contact undepleted
areas. Restimulations are particularly effective in low-permeability,
highly anisotropic, naturally fractured or laminated gas reservoirs.
This article presents candidate
selection criteria and design considerations. US and Canada examples
illustrate field implementation
and results.
Gas-Well Construction. The world
energy market is becoming increasingly reliant on natural gas. Operators
are challenged to drill highly productive and durable gas wells in difficult
environments. This article reviews
the state of existing gas wells and
explores wide-ranging aspects of
modern gas-well construction from
well planning to completion.
Summer 2003
NEW BOOKS
•
•
•
•
•
•
Nontechnical Guide to
Petroleum Geology, Exploration,
Drilling and Production
Norman J. Hyne
PennWell Books
1421 South Sheridan Road
P.O. Box 1260
Tulsa, Oklahoma 74112 USA
2001. 575 pages. $64.95
Workover
Reservoir Mechanics
Petroleum Production
Reserves
Improved Oil Recovery
Glossary, References, Index
I highly recommend this book for
geology students and professionals in
the field of petroleum geology…nongeoscientists who would like to learn
about the oil and gas industry would
benefit from this book.
Hyne presents the material in an
easy-to-read format with many illustrations to aid the reader in visualizing subsurface geologic conditions.
Bednar DM Jr: Geotimes 47, no. 9
(September 2002): 36.
Shmuel Yariv and Harold Cross (eds)
Marcel Dekker, Inc.
270 Madison Avenue
New York, New York 10016 USA
2002. 688 pages. $195.00
ISBN 0-8247-0586-6
This reference provides comprehensive
coverage of the structures, properties
and interactions of organo-clay complexes as well as their role in the origin
of life.
ISBN 0-87814-823-X
The book contains 27 chapters with an
extensive glossary, index and color
plates that show common minerals and
3D seismic views of the subsurface.
While explaining basic geologic concepts and terms, it follows the process
of petroleum exploration from identifying its features within the Earth’s crust,
to its extraction from production wells.
Contents:
• The Nature of Gas and Oil
• The Earth’s Crust—Where We
Find It
• Identification of Common Rocks
and Minerals
• Geological Time
• Deformation of Sedimentary Rocks
• Sandstone Reservoir Rocks
• Carbonate Reservoir Rocks
• Sedimentary Rock Distribution
• Mapping
• Ocean Environment and
Plate Tectonics
• Source Rocks, Generation,
Migration, and Accumulation
of Petroleum
• Petroleum Traps
• Petroleum Exploration—Geological
and Geochemical
• Petroleum Exploration—
Geophysical
• Drilling Preliminaries
• Drilling a Well—The Mechanics
• Drilling Problems
• Drilling Techniques
• Testing a Well
• Completing a Well
• Surface Treatment and Storage
• Offshore Drilling and Production
Organo-Clay Complexes
and Interactions
Death Assemblage
Susan Cummins Miller
Texas Tech University Press
Box 41037
Lubbock, Texas 79409 USA
2002. 200 pages. $23.95
ISBN 0-8967-2481-6
In this work of mystery fiction, stratigrapher Frankie MacFarlane is unraveling a fossil puzzle that could bring her a
professorship. Frankie dodges death
three times before she unravels the puzzle that links the fossils, a murder and a
missing manuscript. Set in Nevada, this
fast-paced book combines a suspenseful
plot and well-drawn characters. In
Death Assemblage, the paleontological
term for fossils brought together after
death, the author vividly describes
mountain and desert life, and offers
insights into western history and the
lives of ranchers.
Miller turns a phrase. Her prose is
a pleasure to read.
I hope to see more of Frankie
MacFarlane. As the story ends, she’s
off to a teaching post, which, I trust,
cannot fail to serve up another ample
ration of murder and mayhem.
Contents:
• Structure and Surface Acidity of
Clay Minerals
• Introduction to Organo-Clay
Complexes and Interactions
• Interactions of Vermiculites with
Organic Compounds
• Organophilicity and Hydrophobicity
of Organo-Clays
• Adsorption of Organic Cations on
Clays: Experimental Results and
Modeling
• Nuclear Magnetic Resonance
Spectroscopy of Organo-Clay
Complexes
• Thermal Analysis of Organo-Clay
Complexes
• IR Spectroscopy and Thermo-IR
Spectroscopy in the Study of the
Fine Structure of Organo-Clay
Complexes
• Staining of Clay Minerals and
Visible Absorption Spectroscopy
of Dye-Clay Complexes
• Clay Catalysis in Reactions of
Organic Matter
• Organo-Minerals and Organo-Clay
Interactions and the Origin of Life
on Earth
• Indexes
Overall, I felt that the volume
was a useful resource that covered
selected areas well. It contains a mineral, organic compound and author
index and…the references are supplied complete with titles....
Andrews S: Geotimes 47, no. 9
(September 2002): 36.
55
The quality of a number of the
figures is disappointing and I felt that
occasionally some authors paid too
much attention to well-established
studies with which they were familiar,
rather than presenting new and
emerging work.
Rifkin is certainly right to say that
we will soon start running out of oil,
that continued burning of fossil fuels is
a grave threat to the Earth’s climate,
and that hydrogen, either in fuel cells
or by combustion, is the best bet for the
future of transportation. He has correctly identified the biggest problem we
have. But this book is not part of the
solution.
Breen C: Clays and Clay Minerals 50,
no. 4 (2002): 533-534.
Goodstein D: American Scientist 91, no. 2 (MarchApril 2003): 183-184.
The Hydrogen Economy:
The Creation of the Worldwide
Energy Web and the
Redistribution of Power
on Earth
This is a very readable “personalized” history of applied geophysics,
from three eminently qualified authors.
Jeremy Rifkin
Penguin Putnam Inc.
375 Hudson Street
New York, New York 10014 USA
2002. 294 pages. $24.95
ISBN 1-58542-193-6
An Introduction to
Seismology, Earthquakes,
and Earth Structure
Seth Stein and Michael Wysession
Blackwell Publishing
350 Main Street
Malden, Massachusetts 02148 USA
2003. 498 pages. $79.95
ISBN 0-86542-078-5
This classic textbook targets upper-level
undergraduate or first-year graduate
students. Although it deals mainly with
seismology, the presentation and
coverage should be of interest to those
studying earth sciences. The text is
supported by plots, graphs, illustrations
and maps, and each chapter contains
problem sets, with answers given at the
end of the book. Appendix material
provides the bulk of the mathematical
support discussions.
Contents:
• Introduction
• Basic Seismological Theory
• Seismology and Earth Structure
• Earthquakes
• Seismology and Plate Tectonics
• Seismograms as Signals
• Inverse Problems
• Appendix, References, Index
Along with all the classical stuff,
[the authors] explain the recent
advances from tracking plates right
down to the core-mantle boundary to
describing large-scale deformation of
the continents. This book should
become a mainstay of many undergraduate courses.
Depletion of world oil reserves is
compounded by the rise of Islamic
fundamentalism in oil-rich regions.
The author believes the answer is to
embrace a new energy source: hydrogen
fuel cells. The book outlines the merits
of hydrogen as a “forever fuel” and
offers a vision of a worldwide hydrogen
energy web, much like today’s World
Wide Web.
Contents:
• Between Realities
• Sliding Down Hubbert’s Bell Curve
• Energy and the Rise and Fall of
Civilizations
• The Fossil-Fuel Era
• The Islamist Wild Card
• A Global Meltdown
• Vulnerabilities Along the Seams
• The Dawn of the Hydrogen Economy
• Reglobalization from the Bottom Up
• Notes, Bibliography, Index
Is Rifkin’s proposed solution physically possible? Well, yes, sort of, but
it’s extremely implausible that all the
power generated today by fossil fuels,
about 10 terawatts world wide, could
ever be replaced from those sources
[renewable resources including photovoltaic, wind, hydroelectric, geothermal, and biomass].
• An Industry in Turmoil—The
Mid-to-Late 1980s
• Geophysical Advances in the Midst
of Uncertainty—The 1990s
• Geophysics as a Business—Then
and Now
• Corporate Profiles of Yesteryear
• Today’s Geophysical Industry:
The Full-Service Companies
• Some Niche Firms
• The Geophysical
Professional—Worldwide
• Appendices
• References, Index
Geophysics in the Affairs
of Mankind
L.C. Lawyer, Charles C. Bates and
Robert B. Rice
Society of Exploration Geophysicists
P.O. Box 702740
Tulsa, Oklahoma 74170 USA
2001. 429 pages. $25.00
ISBN 1-56080-087-9
Since World War I, major changes have
occurred within the interrelated fields
of exploration geophysics, seismology
and oceanography in the search for new
oil and natural gas reserves. This book
focuses on the people and organizations
that led the technical improvements in
the field, including advances in computer hardware and software, and in
marine geophysical techniques.
Minor quibbles aside, this book
will be an excellent addition to any
geophysicists’s library. It is loaded
with useful information and interesting anecdotes and does a fine job of
showing how the business of geophysics relates to global economics
and politics.
There are a few minor problems
in production that could have been
improved. Some sections appear to
have been repeated directly from the
book’s 1982 predecessor…a few
spelling mistakes, errors in
names…missing references, and
occasional repetitions.
My only significant complaint is
the almost complete lack of attention
to geophysics in mining and other
nonpetroleum industries.
Green WR: The Leading Edge 21, no. 9
(September 2002): 936-938.
Contents:
• Some Antecedents to the ModernDay Profession of Geophysics
Through World War I
• Geophysics Comes of Age—
The Roaring Twenties and the
Depressing Thirties
• Geophysicists at War—1939-45
• Reversion to Peacetime, 1945-50
• The 1950s—A Burgeoning Era of
Geophysics
• Science in Government and
Government in Science—The 1960s
• Geophysics Interacts with the
Environmentalists and OPEC—The
1970s and the Early 1980s
Butler R: New Scientist 177, no. 2387
(March 22, 2003): 52.
56
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