Oilfield Review
Winter 2011/2012
Reservoir Simulation
Digital Slickline
Wellbore Strengthening
Hybrid Rotary Steerable System
12-OR-0001
Slickline for the Information Age
Over time, but particularly in recent decades, the business
of finding and producing hydrocarbons has grown steadily
more challenging. Technology and technology applications
in nearly all segments of the E&P industry have kept pace
with the challenge. As a consequence, the industry’s equipment, tools, software and workforce skills have long been
and remain at the cutting edge of technology development.
Slickline technology, on the other hand, has defied this
trend and has changed little since the inception of slickline operations, testimony to its suitability for live well
intervention. Aside from the recent introduction of batterypowered devices and memory sensors, the tools deployed
and the information available to the operator during job
execution remain essentially what they have been for
decades. As measured by current standards, downhole
information from slickline technology has been limited in
nature, quantity and availability.
Only recently has there been a significant advance in
slickline technology, one that incorporates cutting-edge
benefits such as real-time visibility and interaction and
control, while maintaining the hallmark slickline advantage of simplicity.
Often, in our R&D efforts to improve or develop technology
applications, we overdesign and thus build complexity into a
technology solution. As a consequence, simplicity can elude us
and innovations can become overly complex and less effective
than the simple systems from which they originated.
A hybrid approach to innovation recognizes the value of
simplicity wherein developers deliver a tool that is simple to
use but relies on a high level of sophistication and complexity that remains in the background and does not require
users’ understanding. Perhaps Steve Jobs’s approach to
technology—creating usable tools that are not hindered by
their own complexity—is the most prominent example of
this concept. But appreciation for the value of simplicity in
science is not a recent phenomenon; Leonardo da Vinci
called simplicity “the ultimate sophistication.”
It is, in fact, the inherent simplicity of slickline that has
allowed it to survive relatively unchanged for these many
years. Early attempts to introduce significant change to
slickline met with mixed results. Scientists delivered a
slick wire that could act as a conductor, but the resulting
wire was unable to handle the tensile stresses or perform
slickline operations in the environment and mode typically
required of it. Ultimately, it could not execute the scope of
work for which it was intended.
The idea to build on simplicity rather than compromising
it, while not losing sight of the role and advantages of
slickline, turned out to be the right path. Using standard
slickline as its core, engineers developed LIVE* digital
slickline. In addition to performing traditional operations,
the enhanced slickline enables real-time digital telemetry.
This, coupled with other innovative components, provides a
plethora of capabilities, each of which can be applied with
considerable advantage to the mechanical, remedial and
measurement applications of slickline.
Mechanical applications are the most commonly used of
slickline services. The ability to deliver relevant, in situ
downhole measurement data to the surface in real time
promises to have significant impact on those mechanical
operations, ensuring operators a means by which to perform interventions in a more controlled, risk-managed
approach. In addition, digital slickline services provide a
digital record of all operations—information that is
increasingly in demand. Perhaps most importantly, these
well intervention advances may play a sizeable role in the
industry’s efforts to increase recovery factor.
The idea of insulating a standard slickline to allow digital telemetry is a simple one; achieving it has proved more
difficult. The barrier to success was creating an insulated
slickline—developing a method for bonding the wire and
the insulator so that they would remain intact and operational despite the rigors of repeated bending cycles, high
tension stresses and shocks imposed in the inherently hostile environments.
After years of attempts, however, engineers have succeeded in delivering a slickline that meets these demands,
while providing enhancements and advantages necessitated by today’s E&P industry (see “Slickline Signaling a
Change,” page 16).
Digital slickline provides many of the advantages of electric
line, retains the simplicity and the relatively smaller footprint
of traditional slickline and lends itself to well intervention
optimization with minimal risk. This remarkable technology is
certain to gain a secure place in the industry.
Stuart Murchie
Marketing and Technical Manager, Slickline
Schlumberger Oilfield Services
Roissy-en-France, France
Stuart Murchie began his Schlumberger career in well testing in Aberdeen
in 1984 after graduating from the University of Dundee, Scotland, with a BS
degree in mechanical engineering. In 1988, he transferred to Wireline, where he
held various field operation positions in Asia followed by a posting in Paris as
new technology manager for Wireline and Testing. In 1999, he was appointed
vice president of Data & Consulting Services, based in Houston. He next served
as QHSE manager for Oilfield Services North and South America, then moved
to Thailand as the managing director for Oilfield Services Central East Asia. He
returned to the UK in 2004 as managing director for Oilfield Services UK and
Ireland. In 2005, he became personnel manager for Schlumberger Integrated
Project Management, and then regional vice president for the Europe/Africa/
Caspian area. Now based in Roissy-en-France, Stuart assumed his current position as Marketing and Technology Manager for Slickline services in 2011.
An asterisk (*) indicates a mark of Schlumberger.
1
Schlumberger
Oilfield Review
www.slb.com/oilfieldreview
Executive Editor
Lisa Stewart
Senior Editors
Matt Varhaug
Rick von Flatern
1
Slickline for the Information Age
Editorial contributed by Stuart Murchie, Marketing and Technical Manager, Slickline,
Schlumberger Oilfield Services
Editor
Tony Smithson
Contributing Editors
David Allan
Ted Moon
Ginger Oppenheimer
Rana Rottenberg
Design/Production
Herring Design
Mike Messinger
Illustration Chris Lockwood
Tom McNeff
Mike Messinger
George Stewart
Printing
RR Donnelley—Wetmore Plant
Curtis Weeks
4
Reservoir Simulation: Keeping Pace with
Oilfield Complexity
The drive to get the most from each reservoir is spurring
developers to create increasingly sophisticated reservoir
simulators. Whereas the earliest reservoir simulators of the
1930s were physical models containing oil, sand and water,
today’s simulators use high-performance computing hardware and modern software engineering to handle fields of
great complexity, and at great speed. A next-generation simulator integrates several new technologies in one package,
including a new well model, advanced gridding, a scalable
parallel computing foundation, an efficient linear solver
and a field management module. These capabilities help
operators make better forecasts and, ultimately, better field
development decisions.
16 Slickline Signaling a Change
Slickline has remained essentially unchanged since its inception and, as a logical consequence, so have its uses. The recent
introduction of digital slickline promises to change that by
combining electric line capabilities with the strengths and
simplicity of traditional slickline. Case histories from both the
shallow and deep ends of the Gulf of Mexico demonstrate the
potential of the new system.
On the cover:
An engineer monitors a downhole tool
by interpreting signals delivered to the
surface in real time through telemetry
provided by digital slickline. The display
on the computer screen mounted on the
otherwise traditional slickline unit may
include data that can be used to confirm
a specific downhole action such as perforating or tool setting, or information
such as precise depth, downhole pressure and temperature, head tension or
other critical measurements.
2
About Oilfield Review
Oilfield Review, a Schlumberger journal,
communicates technical advances in
finding and producing hydrocarbons
to employees, clients and other oilfield
professionals. Contributors to articles
include industry professionals and experts
from around the world; those listed with
only geographic location are employees
of Schlumberger or its affiliates.
Oilfield Review is published quarterly and
printed in the USA.
Visit www.slb.com/oilfieldreview for
electronic copies of articles in multiple
languages.
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Winter 2011/2012
Volume 23
Number 4
ISSN 0923-1730
Advisory Panel
26 Stabilizing the Wellbore to Prevent
Lost Circlation
Gretchen M. Gillis
Aramco Services Company
Houston, Texas, USA
For drillers, lost circulation events, during which whole
drilling mud is lost to the formation, can range from nuisance
to nightmare. To minimize the risks and nonproductive time
associated with lost circulation, the industry has developed
a suite of wellbore strengthening materials that work to
inhibit fracture growth and keep drilling operations on course.
Roland Hamp
Woodside Energy Ltd.
Perth, Australia
Dilip M. Kale
ONGC Energy Centre
Delhi, India
George King
Apache Corporation
Houston, Texas
Richard Woodhouse
Independent consultant
Surrey, England
36 The Best of Both Worlds—A Hybrid Rotary
Steerable System
Rotary steerable systems provide a cost-effective, reliable
and efficient means for drilling complex wellbore trajectories.
However, slower positive displacement motors are still used
for drilling high-angle wellbores when build rates exceed
the capacity of rotary steerable systems. A hybrid rotary
steerable system has been developed that combines the
capabilities of drilling high build rates with high rates
of penetration.
Stabilizer blades
Alexander Zazovsky
Chevron
Houston, Texas
Internal geostationary
rotary valve
Lost Circulation
Figure 1_4
Control unit
45 Contributors
47 New Books and Coming in Oilfield Review
50 Defining Completion:
The Science of Oil and Gas Well Construction
This is the fourth in a series of introductory articles describing basic concepts of the E&P industry.
52 Annual Index
Editorial correspondence
Oilfield Review
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3
Reservoir Simulation: Keeping Pace with
Oilfield Complexity
David A. Edwards
Dayal Gunasekera
Jonathan Morris
Gareth Shaw
Kevin Shaw
Dominic Walsh
Abingdon, England
Paul A. Fjerstad
Jitendra Kikani
Chevron Energy Technology Company
Houston, Texas, USA
Jessica Franco
Total SA
Luanda, Angola
Geologic complexity and the high cost of resource development continue to push
reservoir simulation technology. Next-generation simulators employ multimillion cell
models with unstructured grids to handle geologies with high-permeability contrasts.
Through the use of more-realistic models, these new simulators will aid in increasing
ultimate recovery from both new and existing fields.
Viet Hoang
Chevron Energy Technology Company
San Ramon, California, USA
Lisette Quettier
Total SA
Pau, France
Oilfield Review Winter 2011/2012: 23, no. 4.
Copyright © 2012 Schlumberger.
ECLIPSE and INTERSECT are marks of Schlumberger.
Intel®, Intel386™, Intel486™, Itanium® and Pentium® are
registered trademarks of Intel Corporation.
Linux® is a registered trademark of Linus Torvalds.
Windows® is a registered trademark of Microsoft
Corporation.
1950
4
Interest in simulators is not new. People have
long used simulators to model complex activities.
Simulation can be categorized into three
periods—precomputer, formative and expansion.1 The Buffon needle experiment in 1777 was
the first recorded simulation in the precomputer
era (1777 to 1945). In this experiment, needles
were thrown onto a flat surface to estimate the
value of π.2 In the formative simulation period
(1945 to 1970), people used the first electronic
computers to solve problems for military applications. These ranged from artillery firing solutions
to the development of the hydrogen bomb. The
expansion simulation period (1970 to the present) is distinguished by a profusion of simulation
applications. These applications range from
2000
Oilfield Review
Surface Network Simulator
Process Simulator
Economic Simulator
Static and Dynamic Data
Reservoir Simulator
> Production simulation. A reservoir engineer takes static and dynamic data (bottom right ) and develops input for a reservoir simulator (bottom left ). The
reservoir simulator, whose primary task is to analyze flow through porous media, calculates production profiles as a function of time for the wells in the
reservoir. These data are passed to a production engineer to develop well models and a surface network simulator (top left ). A facilities engineer uses the
production and composition data to build a process plant model with the help of a process simulator (top right ). Finally, data from all the simulators are
passed to an economic simulator (right ).
games to disaster preparedness and simulation of
artificial life forms.3 Industry and government
interest in computer simulation is increasing in
areas that are computationally difficult, potentially dangerous or expensive. Oilfield simulations fit all of these criteria.
Oil and gas simulations model activities that
extend from deep within the reservoir to process
plants on the surface and ultimately include final
economic evaluation (above). Numerous factors
are driving current production simulation planning to produce accurate results in the shortest
possible time. These include remote locations,
geologic complexity, complex well trajectories,
enhanced recovery schemes, heavy-oil recovery
and unconventional gas. Today, operators must
make investment decisions quickly and can no lon-
ger base field development decisions solely on
data from early well performance. Operators now
want accurate simulation of the field from formation discovery through secondary recovery and
final abandonment. Nowhere do these factors
come into sharper focus than in the reservoir.
This article describes the tools and processes
involved in reservoir simulation and discusses
how a next-generation simulator is helping operators in Australia, Canada and Kazakhstan.
Visualizing the Reservoir
Oilfield Review
The earliest reservoir
date from the
WINTER simulators
11/12
1930s and were
physical
models;
the
interaction
Intersect Fig. 1
ORWNT11/12-INT
1 viewed—
of sand, oil and
water could be directly
often in vessels with clear sides.4 Early physical
simulators were employed when reservoir behav-
ior during waterfloods surprised operators. In
addition to physical simulators, scientists used
electrical simulators that relied on the analogy
between flow of electrical current and flow of reservoir fluids.
In the early 1950s, although physical simulators were still in use, researchers were starting
to think about how a reservoir might be described
analytically. Understanding what happens in a
reservoir during production is similar in some
respects to diagnosing a disease. Data from various laboratory tests are available but the complete disease process cannot be viewed directly.
Physicians must deduce what is happening from
laboratory results. Reservoir engineers are in a
similar position—they cannot actually view the
subject of their interest, but must rely on data to
1. Goldsman D, Nance RE and Wilson JR: “A Brief History
of Simulation,” in Rossetti MD, Hill RR, Johansson B,
Dunkin A and Ingalls RG (eds): Proceedings of the 2009
Winter Simulation Conference. Austin, Texas, USA
(December 13–16, 2009): 310–313.
2. Buffon’s needle experiment is one of the oldest known
problems in geometric probability. Needles are dropped
on a sheet of paper with grid lines, and the probability of
the needle crossing one of the lines is calculated. This
probability is related directly to the value of π. For more
information: Weisstein FW: “Buffon’s Needle Problem,”
WolframMathWorld, http://mathworld.wolfram.com/
BuffonsNeedleProblem.html (accessed July 25, 2011).
3. Freddolino PL, Arkhipov AS, Larson SB, McPherson A
and Schulten K: “Molecular Dynamics of the Complete
Satellite Tobacco Mosaic Virus,” Structure 14, no. 3
(March 2006): 437–449.
4. Peaceman DW: “A Personal Retrospection of Reservoir
Simulation,” in Proceedings of the First and Second
International Forum on Reservoir Simulation. Alpbach,
Austria (September 12–16, 1988 and September 4–8,
1989): 12–23.
Adamson G, Crick M, Gane B, Gurpinar O, Hardiman J
and Ponting D: “Simulation Throughout the Life of a
Reservoir,” Oilfield Review 8, no. 2 (Summer 1996): 16–27.
Winter 2011/2012
5
tell them what is happening deep below the
Earth’s surface. Production and other data are
used to build analytical models to describe flow
and other reservoir characteristics. In a reservoir model, the equations that describe fluid
behavior arise from fundamental principles that
have been understood for more than a hundred
years. These principles are the conservation of
mass, fluid dynamics and thermodynamic equilibrium between phases.5
When these principles are applied to a reservoir, the resulting partial differential equations
are complex, numerous and nonlinear. Early analytical derivations for describing flow behavior in
the reservoir were constrained to simple models,
whereas current formulations show a more complex picture (below).6 While formulation of the
equations for the reservoir has always been
straightforward, they cannot be solved exactly
and must be solved by finite-difference methods.7
In reservoir simulation, there is a trade-off
between model complexity and ability to converge to a solution. Advances in computing capability have helped enhance reservoir simulator
capability—especially when complex models and
large numbers of cells are involved (next page).8
Computing hardware advances over the past
decades have led to a steady progression in simulation capabilities.9 Between the early 1950s and
1970, reservoir simulators progressed from two
dimensions and simple geometry to three dimensions, realistic geometry and a black oil fluid
model.10 In the 1970s, researchers introduced
compositional models and placed a heavy emphasis on enhanced oil recovery. In the 1980s, simulator development emphasized complex well
management and fractured reservoirs; during the
1990s, graphical user interfaces brought enhanced
1951
1D flow of a
compressible fluid
∂ 2p
x
∂x
=
2
cφµ
∂p
k
∂t
.
2011
3D flow of n
components in a
complex reservoir
z
x
y
V
∆t
δ (φ
Np,c
Σρ S χ
p
p p
cp
W
) + qc
–
Faces
Np,c
ΣT Σ
k
k
p
ρp
k rp
χ ∆p – ∆Pc p – ρp g ∆h )
µp cp (
= Rc .
> Reservoir simulation evolution. One of the first attempts to analytically describe reservoir flow
occurred in the early 1950s. Researchers developed a partial differential equation to describe 1D flow
of a compressible fluid in a reservoir (top). This equation is derived from Darcy’s law for flow in porous
media plus the law of conservation of mass; it describes pressure as a function of time and position.
(For details: McCarty DG and Peaceman DW: “Application of Large Computers to Reservoir
Engineering Problems,” paper SPE 844, presented at a Joint Meeting of University of Texas and Texas
A&M Student Chapters of AIME, Austin, Texas, February 14–15, 1957.) Recent models developed for
reservoir simulation consider the flow of multiple components in a reservoir that is divided into a large
number of 3D components known as grid cells (bottom). Darcy’s law and conservation of mass, plus
thermodynamic equilibrium of components between phases, govern equations that describe flow in
and out of these cells. In addition to flow rates, the models describe other variables including
pressure, temperature and phase saturation. (For details: Cao et al, reference 6.)
6
ease of use. Nearing the end of the 20th century,
reservoir simulators added features such as local
grid refinement and the ability to handle complex
geometry as well as integration with surface facilities. Now, simulators can handle complex reservoirs while offering integrated full-field management. These models—known as next-generation
simulators—have taken advantage of several
recently developed technologies, including parallel computing.
Parallel Computing—Divide and Conquer
One of the hallmarks of current reservoir simulators is the use of parallel computing systems.
Parallel computing operates on the principle that
large problems like reservoir simulation can be
broken down into smaller ones that are then solved
concurrently—or in parallel. The shift from serial
processing to parallel systems is a direct result of
the drive for improved computational performance.
In the 1980s and 1990s, computer hardware
designers relied on increases in microprocessor
speed to improve computational performance.
This technique, called frequency scaling, became
the dominant force in processor performance for
personal computers until about 2004.11 Frequency
scaling came to an end because of the increasing
power consumption necessary to achieve higher
frequencies. Hardware designers for personal
computers then turned to multicore processors—
one form of parallel computing.
The kind of thinking that would eventually
lead to parallel processing for reservoir simulators, however, began around 1990. In an early
experiment, oilfield researchers demonstrated
that an Intel computer with 16 processors could
efficiently handle an oil-water simulation
model.12 Since then, the use of parallel computer
systems for reservoir simulation has become
more commonplace.
As prices for computing equipment have
decreased, it has become standard practice to
operate parallel computing systems as clusters
of single machines connected by a network.
These multiple machines, operating in parallel,
act as a single entity. The goal in parallel computing has always been to solve large problems
more quickly by going n times faster on n processors.13 For a host of reasons, this ideal performance is rarely achieved.
To understand the limitations in parallel networks, it is instructive to visualize a typical system used by a modern reservoir simulator. This
system might have several stand-alone computers networked through a hub and a switch to a
Oilfield Review
The Next Generation
Since 2000, a petroleum engineer could choose
from a number of reservoir simulators. Simulators
were numerous enough that the SPE supported
frequent projects to compare them.17 Although the
simulators differ from one another, their structures have common roots, which lie in serial computing and reliance on simple grids. An example of
this type of reservoir simulator is the ECLIPSE
simulator.18 The ECLIPSE simulator has been a
benchmark for 25 years and has been continually
updated to handle a variety of reservoir features.
Like microprocessors, however, reservoir simulators have reached a point at which the familiar
tools of the past may not be appropriate for some
current field development challenges.
Scientists have developed new reservoir tools—
the next-generation simulators—to broaden the
Winter 2011/2012
108
109
Intel Itanium 2 microprocessor
Reservoir cells
Intel microprocessor
108
Intel Pentium 4 microprocessor
Int
106
107
Intel Pentium II microprocessor
Intel Pentium microprocessor
Intel486 microprocessor
105
106
Intel386 microprocessor
104
Intel286 microprocessor
Number of transistors on microprocessor
107
Number of reservoir cells employed
controller computer and a network server.14 As
each of the individual computers works on its
portion of the reservoir, messages are passed
between them to the controller computer and
over the network to other systems. In parallel terminology, the individual processors are the parallel portions of the system, while the work of the
controllers is the serial part.15 The overall effect
of communications is the primary reason why
ideal performance in parallel systems can be only
approached but not realized. All computing systems, even parallel systems, have limitations.
The maximum expected improvement that a
parallel system can deliver is embodied in
Amdahl’s law.16 Consider a simulator that requires
10 hours on a single processor. The 10-hour total
time can be broken down into a 9-hour part that is
amenable to parallel processing and a 1-hour part
that is serial in nature. For this example, Amdahl’s
law states that no matter how many processors are
assigned to the parallel part of the calculation, the
minimum execution time cannot be less than
one hour.
Because of the effect of serial communications, in reservoir simulation there is often an optimal number of processors for a given problem.
Although the data management and housekeeping
parts of the system are the primary reasons for a
departure from the ideal state, there are others.
These include load balancing between processors,
bandwidth and issues related to congestion and
delays within various parts of the system. Reservoir
simulation problems destined for parallel solution
must use software and hardware that are designed
specifically for parallel operation.
105
Intel8086
microprocessor
103
1970
1980
1990
2000
2010
104
Year
> Computing capability and reservoir simulation. During the past four decades, computing capability
and reservoir simulation evolved along similar paths. From the 1970s until 2004, computer
microprocessors followed Moore’s law, which states that transistor density on a microprocessor
(red circles), doubles about every two years. Reservoir simulation paralleled this growth in computing
capability with the growth in number of grid cells (blue bars) that could be accommodated. In the last
decade, computing architecture has focused on parallel processing rather than simple increases to
transistor count or frequency. Similarly, reservoir simulation has moved toward parallel solution of the
reservoir equations.
5.Brown G: “Darcy’s Law Basics and More,” http://bioen.
white_papers/FromDeadEndToOpenRoad.pdf (accessed
okstate.edu/Darcy/LaLoi/ basics.htm (accessed
September 13, 2011).
August 23, 2011).
Flynn LJ: “Intel Halts Development of 2 New
Smith JM and Van Ness HC: Introduction to Chemical
Microprocessors,” The New York Times (May 8, 2004),
Engineering Thermodynamics, 7th Edition. New York
http://www.nytimes.com/2004/05/08/business/
City: McGraw Hill Company, 2005.
intel-halts-development-of-2-new-microprocessors.html
(accessed Sept 13, 2011).
6.Cao H, Crumpton PI and Schrader ML: “Efficient General
Formulation Approach for Modeling Complex Physics,”
12.Wheeler JA and Smith RA: “Reservoir Simulation on a
paper SPE 119165, presented at the SPE Reservoir
Hypercube,” SPE Reservoir Engineering 5, no. 4
Simulation Symposium, The Woodlands, Texas, February
(November 1, 1990): 544–548.
2–4, 2009.
13.Speedup, a common measure of parallel computing
7.Finite-difference equations are used to approximate
effectiveness, is defined as the time taken on one
solutions for differential equations. This method obtains
processor divided by the time taken on n processors.
Parallel effectiveness can also be stated in terms of
an approximation of a derivative by using small,
Oilfield
Review
efficiency—the speedup divided by the number of
incremental steps from a base value.
WINTER
8.Intel Corporation: “Moore’s Law: Raising the Bar,”
Santa 11/12processors.
Intersect
Fig.14.Baker
3
Clara, California, USA: Intel Corporation (2005),
ftp://
M: “Cluster Computer White Paper,” Portsmouth,
download.intel.com/museum/Moores_law/Printed_
England:
ORWNT11/12-INT
3 University of Portsmouth (December 28, 2000),
Materials/ Moores_Law_Backgrounder.pdf (accessed
http://arxiv.org/ftp/cs/00040004014.pdf (accessed
October 17, 2011).
July 16, 2011).
Fjerstad PA, Sikandar AS, Cao H, Liu J and Da Sie W:
Each of these computers in the parallel configuration
“Next Generation Parallel Computing for Large-Scale
may have either a single core or multiple core
Reservoir Simulation,” paper SPE 97358, presented at
microprocessors. Each individual core is termed a
the SPE International Improved Oil Recovery Conference
parallel processor and can act as an independent part
in Asia Pacific, Kuala Lumpur, December 5–6, 2005.
of the system.
9.Watts JW: “Reservoir Simulation: Past, Present, and
15.The serial portion is often called data management
Future,” paper SPE 38441, presented at the SPE
and housekeeping.
Reservoir Simulation Symposium, Dallas, June 8–11, 1997.
16.Barney B: “Introduction to Parallel Computing,”
10.In the black oil fluid model, composition does not
https//computing.llnl.gov/tutorials/parallel_comp/
change as fluids are produced. For more information
(accessed September 13, 2011).
see: Fevang Ø, Singh K and Whitsun CH: “Guidelines for
17.Christie MA and Blunt MJ: “Tenth SPE Comparative
Choosing Compositional and Black-Oil Models for
Solution Project: A Comparison of Upscaling
Volatile Oil and Gas-Condensate Reservoirs,” paper SPE
Techniques,” paper SPE 66599, presented at the
63087, presented at the SPE Annual Technical
SPE Reservoir Simulation Symposium, Houston,
Conference and Exhibition, Dallas, October 1–4, 2000.
February 11–14, 2001.
11.Scaling, or scalability, is the characteristic of a system
18.Pettersen Ø: “Basics of Reservoir Simulation with the
or process to handle greater or growing amounts of
Eclipse Reservoir Simulator,” Bergen, Norway:
work without difficulty. For more information: Shalom N:
University of Bergen, Department of Mathematics,
“The Scalability Revolution: From Dead End to Open
Lecture Notes (2006), http://www.scribd.com/
Road,” GigaSpaces (February 2007), http://www.
doc/36455888/Basics-of-Reservoir-Simulation
gigaspaces.com/files /main/Presentations/ByCustomers/
(accessed September 13, 2011).
7
Wellbore
Segment
Node
Nodes at branch junction
Reservoir
Σ
FIN
Σ
FOUT
ΣF
OUT
ΣF
IN
Nodes at well connections
with grid cells
> Multisegment well model. For each segment node in a wellbore, the new well model calculates the
total flow in (ΣFIN) and total flow out (ΣFOUT), including any flow between the wellbore and the
connected grid cell in the reservoir. Assuming a three-phase black oil simulation, there are three mass
conservation equations and a pressure drop equation associated with each well segment. During the
simulation, the well equations are solved, along with the other reservoir equations, to give pressure,
flow rates and composition in each segment.
One of the next-generation tools available
technology to handle the greater complexity now
present in the oil field. These simulators take now, the INTERSECT reservoir simulator, is
advantage of several new technologies that include the result of a collaborative effort between
parallel computing, advanced gridding techniques, Schlumberger and Chevron that was initiated in
modern software engineering and high-perfor- late 2000.19 Total, which also collaborated on the
mance computing hardware. The choice between project from 2004 to 2011, assisted researchers in
the next-generation simulators and the older ver- developing the thermal capabilities of the softsions is determined by field complexity and busi- ware. Following the research phase and a subseness needs. Next-generation tools should be quent development phase, Schlumberger released
considered if the reservoir needs a high cell count the INTERSECT simulator in late 2009. This systo capture complex geologic features, has exten- tem integrates several new technologies in one
sive local grid refinements or has a high permea- package. These include a new well model,
bility contrast.
advanced gridding, a scalable parallel computing
In addition to handling fields of greater com- foundation, an efficient linear solver and effective
plexity, the next-generation simulator gives the field management. To fully understand this simuoperator an important advantage—speed. Many lator, it is instructive to examine each of these
reservoir simulations involve difficult calcula- parts, starting with the new model for wells.
Oilfield
tions that can take hours or days to reach
com- Review
WINTER 11/12
pletion using older tools. The next-generation
Multisegment Well Model
Intersect Fig. 4_2
simulators can reduce calculation times on com- The INTERSECT simulator uses a new multisegORWNT11/12-INT 4
plex reservoirs by an order of magnitude or ment well model to describe fluid flow in the wellgreater. This allows operators to make field devel- bore.20 Wells have become more complex through
opment decisions in time and with confidence, the years, and models that describe them must
thus maximizing value and reducing risk. Shorter reflect their actual design and be able to handle a
runs lead to more runs, which in turn leads to variety of different situations and equipment. These
operators having a better understanding of the include multilateral wells, inflow control devices,
reservoir and the impact of geologic uncertain- horizontal sections, deviated wells and annular
ties. Shorter run times also allow the simulator to flow. Older, conventional well models treated the
be used more dynamically—it can evaluate well as a mixing tank that had a uniform fluid comdevelopment scenarios and optimize designs as position, and the models thus reflected total inflow
new data and information become available.
to the well. The new multisegment model overcomes this method of approximation, allowing each
branch to produce a different mix of fluids.
8
This well model provides a detailed description of wellbore fluid conditions by discretizing
the well into a number of 1D segments. Each segment consists of a segment node and a segment
pipe and may have zero, one or more connections
with the reservoir grid cells (left). A segment’s
node is positioned at the end farthest away from
the wellhead, and its pipe represents the flow
path from the segment’s node to the node of the
next segment toward the wellhead. The number
of segment pipes and nodes defined for a given
well is limited only by the complexity of the particular well being modeled. It is possible to position segment nodes at intermediate points along
the wellbore where tubing geometry or inclination angle changes. Additional segments can be
defined to represent valves or inflow control
devices. The optimal number of segments for a
given well depends on a compromise between
speed and accuracy in the numerical simulation.
An advantage of the multisegment model is
its flexibility in handling a variety of well configurations, including laterals and extended-reach
wells. The model also handles different types of
inflow control devices, packers and annular flow.
The new multisegment well model is, however,
only the beginning of the story on the INTERSECT
simulator and others like it. The next step splits
the reservoir into smaller areas, called domains.
19.DeBaun D, Byer T, Childs P, Chen J, Saaf F, Wells M,
Liu J, Cao H, Pianelo L, Tilakraj V, Crumpton P, Walsh D,
Yardumian H, Zorzynski R, Lim K-T, Schrader M,
Zapata V, Nolen J and Tchelepi H: “An Extensible
Architecture for Next Generation Scalable Parallel
Reservoir Simulation,” paper SPE 93274, presented at
the SPE Reservation Simulation Symposium, Houston,
January 31–February 2, 2005.
For another example of a next-generation simulator:
Dogru AH, Fung LSK, Middya U, Al-Shaalan TM, Pita JA,
HemanthKumar K, Su HJ, Tan JCT, Hoy H, Dreiman WT,
Hahn WA, Al-Harbi R, Al-Youbi A, Al-Zamel NM,
Mezghani M and Al-Mani T: “A Next-Generation Parallel
Reservoir Simulator for Giant Reservoirs,” paper SPE
119272, presented at the SPE Reservoir Simulation
Symposium, The Woodlands, Texas, February 2–4, 2009.
20.Youngs B, Neylon K and Holmes J: “Multisegment
Well Modeling Optimizes Inflow Control Devices,”
World Oil 231, no. 5 (May 1, 2010): 37–42.
Holmes JA, Byer T, Edwards DA, Stone TW, Pallister I,
Shaw G and Walsh D: “A Unified Wellbore Model for
Reservoir Simulation,” paper SPE 134928, presented at
the SPE Annual Technical Conference and Exhibition,
Florence, Italy, September 19–22, 2010.
21.DeBaun et al, reference 19.
22.Weisstein FW: “Traveling Salesman Problem,” Wolfram
MathWorld, http://mathworld.wolfram.com/Traveling
SalesmanProblem.html (accessed October 12, 2011).
23.Karypis G, Schloegel K and Kumar V: “ParMETIS—
Parallel Graph Partitioning and Sparse Matrix Ordering
Library,” http://mpc.uci.edu/ParMetis/manual.pdf
(accessed July 7, 2011).
Karypis G and Kumar V: “Parallel Multilevel k-way
Partitioning Scheme for Irregular Graphs,” SIAM
Review 41, no. 2 (June 1999): 278–300.
24.Fjerstad et al, reference 8.
25.Hesjedal A: “Introduction to the Gullfaks Field,” http://
www.ipt.ntnu.no/~tpg5200/intro/gullfaks_introduksjon.
html (accessed September 26, 2011).
Oilfield Review
Domains and a Parallel, Scalable Solver
The calculation of flow within the reservoir is the
most difficult part of the simulation—even for
simulators using parallel computing hardware. The
number of potential reservoir cells is many times
larger than the number of processors available. It
is natural to parallelize this calculation by dividing
the reservoir grid into areas called domains and
assigning each one to a separate processor.
Partitioning a structured Cartesian grid into segments containing equal numbers of cells while
minimizing their surface area may be a straightforward process; partitioning realistic unstructured
grids, however, is more difficult (right). Realistic
grids must be used to model the heterogeneous
nature of a reservoir that has complex faults and
horizons. The grids must also have sufficient detail
to delineate irregularities such as water fronts, gas
breakthroughs, thermal fronts and coning near
wells. These irregularities are usually captured by
the use of local grid refinements. Partitioning
unstructured grids with these complex features
and numerous local refinements is challenging; to
address this, next-generation simulators typically
use partitioning algorithms.21
The objective of partitioning the unstructured
grid is to divide the grid into a number of segments, or domains, that represent equal computational loads on each of the parallel processors.
Calculating the optimal partitioning for unstructured grids is difficult, and the solution is far
from intuitive. Reservoir partitioning is similar to
the “traveling salesman problem” in combinatorial mathematics that seeks to determine the
shortest route that permits only one visit to each
of a set of cities.22 Unlike the traveling salesman
who is concerned only about minimizing his time
in transit, partitioning of the reservoir must be
guided by the physics of the problem. To this end,
the INTERSECT simulator employs the ParMETIS
reservoir partitioning algorithm.23 The advantages of partitioning a complex reservoir grid to
balance the parallel workload become obvious by
considering simulation of the Gullfaks field in the
Norwegian sector of the North Sea.24
Gullfaks, discovered in 1979 and operated
by Statoil, is a complex offshore field that
has 106 wells producing about 30,000 m3/d
[189,000 bbl/d] of oil.25 This field is highly faulted
with deviated and horizontal wells crossing the
faults. An INTERSECT simulation of this field
developed several domain splits so that different
numbers of parallel processors could be evaluated for load balancing (right). When compared
Winter 2011/2012
Structured Reservoir Grid
Well
Unstructured Reservoir Grid
> Reservoir grids. Reservoir simulators may lay out the grid in either a structured pattern (upper left )
or as an unstructured pattern (lower right ). Structured grids have hexahedral (cubic) cells laid out in
a uniform, repeatable order. Unstructured grids consist of polyhedral cells having any number of
faces and may have no discernable ordering. Both grid types partition the reservoir space without
gaps or overlaps. Structured grids with many local grid refinements around wells are usually treated
as unstructured. Similarly, when a large number of faults are present in a structured grid, it becomes
unstructured as a result of the nonneighbor connections created.
Gullfaks Field Unstructured Grid
Gullfaks Field Domain Split
Oilfield Review
WINTER 11/12
Intersect Fig. 5
ORWNT11/12-INT 5
> Gullfaks domain decomposition. The highly faulted nature of the Gullfaks field and the number of
wells and their complexity result in complicated reservoir communication and drainage patterns. The
simulator takes these factors into account and develops a complex, unstructured grid in preparation
for partitioning (left ). Fine black lines define individual cell boundaries; vertical lines (magenta)
represent wells. Different colors denote varying levels of oil saturation from high (red) to low (blue).
This unstructured grid is split into eight domains using a partitioning algorithm for an eight-processor
simulation (right ). In the partitioned reservoir, different colors denote the individual domains. Only
seven colors appear in the figure—one domain is on the underside of the reservoir and cannot be
viewed from this angle. The primary criterion for the domain partition is an equal computational load
on each of the parallel processors.
9
0
Equations for cellnearest neighbors
2,550
Row number
2,000
Row number
4,000
6,000
2,560
2,570
2,580
2,590
Equations for other
reservoir connections
2,550
2,570
2,590
Column number
8,000
Equations for wells
10,000
0
2,000
4,000
6,000
8,000
10,000
Column number
> Matrix structure. A matrix of the linearized reservoir simulation equations is typically sparse and
asymmetrical (left ). The unmarked spaces represent matrix positions with no equation, while each dot
represents the derivative of one equation with respect to one variable (right ). The nine points inside
the red square (right ) represent mass conservation equations for gas, water and oil phases. The
points on the off-diagonal (left ) represent equations for connections between cells and their
neighboring cells in adjacent layers. Points near the vertical and horizontal axes (left ) represent the
well equations.
V
Δ φ ( ρo So xi + ρg Sgyi + ρw SwWi ( = _ (qo + qg + qw ) +
Δt r
kr
Δxyz T ρo xi μo (Δp _ ΔPcgo _ γo ΔZ ( +
o
krg
Δxyz T ρgyi μ (Δp _ γg ΔZ ( +
g
Residual, R(x)
krw
Δxyz T ρwwi μ (Δp _ ΔPcgo _ ΔPcwo _ γw ΔZ (
w
Tolerance
0
xn
x2
Oilfield Review
WINTER 11/12
Intersect Fig. 7
ORWNT11/12-INT
7
x1
x0
Solution variable x
> Numerical solution. The complete set of fundamental reservoir equations can be written in finitedifference form (top). These equations describe how the values of the dependent variables in each
grid cell—pressure, temperature, saturation and mole fractions—change with time. The equations
also include a number of property-related terms including porosity, pore volume, viscosity, density and
permeability (see DeBaun et al, reference 19). Numerical solution of this large set of equations is
carried out by the Newton-Raphson method illustrated on the graph. A residual function R(x) that is
some function of the dependent variables is calculated at x0 (dashed black line marks coordinate
position) and x 0 plus a small increment (not shown). This allows a derivative or tangent line (black) to
be calculated, that when extrapolated, predicts the residual going to zero at x1. Another derivative is
calculated at x1 that predicts the residual going to zero at x2. This procedure is carried out iteratively
until successive calculated values of R(x) agree within some specified tolerance. The locus of points
at the intersection of the derivative line and its corresponding value of x describe the path of the
residual as it changes with each successive iteration (red).
10
with an ECLIPSE simulation on Gullfaks using
eight processors, the INTERSECT approach
decreased computational time by more than a
factor of five. Runs with higher numbers of processors showed similar improvements and confirmed the scalability of the simulation.
Proper domain partitioning is only part of the
next-generation simulation story. Once the reservoir cells are split to balance the workload on the
parallel processors, the model must numerically
solve a large set of reservoir and well equations.
These equations for the reservoir and wells form
a large, sparsely populated matrix (left).
Although the equations generated in the simulator are amenable to parallel computation,
they are often difficult to solve. Several factors
contribute to this difficulty, including large system sizes, discontinuous anisotropic coefficients,
nonsymmetry, coupled wells and unstructured
grids. The resultant simulation equations exhibit
mixed characteristics. The pressure field equations have long-range coupling and tend to be
elliptic, while the saturation or mass balance
equations tend to have more local dependency
and are hyperbolic. The INTERSECT simulator
uses a computationally efficient solver to achieve
scalable solution of these equation systems.26 It is
based on preconditioning the equations to make
them easier to solve numerically. Preconditioning
algebraically decomposes the system into subsystems that are then manipulated based on their
particular characteristics to facilitate solution.
The resulting reservoir equations are solved
numerically by iterative techniques until convergence is reached for the entire system including
wells and surface facilities (left).27
The solver provides significant improvements
in scalability and performance when compared
with current simulators. A major advantage of
this highly scalable solver is its ability to handle
both structured and unstructured grids in a general framework for a variety of field situations
(next page, top).
26.Cao H, Tchelepi HA, Wallis J and Yardumian H: “Parallel
Scalable Unstructured CPR-Type Linear Solver for
Reservoir Simulation,” paper SPE 96809, presented at
the SPE Annual Technical Conference and Exhibition,
Dallas, October 9–12, 2005.
27.The linear solver consumes a significant share of system
resources. In a typical INTERSECT case, the solver may
use 60% of the central processing unit (CPU) time.
28.Güyagüler B, Zapata VJ, Cao H, Stamati HF and
Holmes JA: “Near-Well Subdomain Simulations for
Accurate Inflow Performance Relationship Calculation
to Improve Stability of Reservoir-Network Coupling,”
paper SPE 141207, presented at the SPE Reservoir
Simulation Symposium, The Woodlands, Texas,
February 21–23, 2011.
Oilfield Review
Winter 2011/2012
Ideal scaling
Fractured carbonate oil field
Highly faulted supergiant field
Offshore supergiant field
Massive gas condensate field
Large onshore oil field
Highly faulted oil field
18
16
14
Run time on 16 processors
Run time on n processors
Field Management Workflow
An improved field management workflow is one of
the components of the INTERSECT simulator
package. Field management tasks include design
of and modifications to surface facilities, sen­
sitivity analyses and economic evaluations.
Traditionally, field management tasks have been
distributed among the various simulators—includ­
ing a reservoir simulator, process facilities simula­
tor and economic simulator. The isolation of the
simulators in the traditional workflow tends to
produce suboptimal field management plans.
The field management (FM) module in the
INTERSECT simulator addresses the weaknesses
of traditional methods with a collection of tools,
algorithms, logic and workflows that allow all of
the different simulators to be coupled and run in
concert. This provides a great deal of flexibility;
for example, the module would allow two iso­
lated, offshore gas reservoirs to be linked to a
single surface processing facility for modeling
and evaluation.28
At the top level, the module executes one or
more strategies that are the focal point of the
whole framework. Strategies, which consist of a
list of instructions and an optional balancing
action, can encompass a wide variety of scenarios
that might affect production. These strategies
may include factors that affect subsurface deliv­
erability such as reservoir performance, well per­
formance and recovery methods. Other strategies
affecting production may include surface capa­
bility and economic viability. After the strategy is
selected, the FM module employs tools to create
a complete topological representation of the field
including wells, completions and inflow control
devices. Once the strategy has been set and the
field topology is defined, the module uses operat­
ing targets and limits to set well balancing
actions and potential field topology changes. An
important feature of the FM workflow is the abil­
ity to control multiple simulators running on dif­
ferent machines and operating systems and in
different locations (right).
Chevron and its partners used the INTERSECT
simulator in their field development of a major
gas project off the coast of Australia. The large
capital outlays envisioned for this project
required a next-generation simulator that could
run cases quickly on large, unstructured grids
characterized by highly heterogeneous geology.
12
10
8
6
4
2
16
50
100
150
200
250
300
Number of processors, n
> INTERSECT simulation scalability. This simulation system has been used in
a variety of offshore and onshore field scenarios including large gas
condensate fields and fields with significant faulting. Scalability—measured
as the run time on 16 processors divided by the run time on n processors, or
speedup—is calculated as a function of the number of processors. The
diagonal straight line (dashed) represents ideal scaling.
INTERSECT
field management
Surface network
simulator
Reservoir A, using
the ECLIPSE reservoir
simulator
Oilfield Review
WINTER 11/12
Intersect Fig. 9
ORWNT11/12-INT 9
Reservoir B, using the
INTERSECT reservoir
simulator
>Multiple reservoir coupling. The field management module can link independent Reservoirs A
and B and surface facilities (center ) via network links. In this example, Reservoir A (lower left ) is
using the ECLIPSE simulator on a Microsoft Windows desktop computer while Reservoir B (lower
right ) is using the INTERSECT system on a Linux parallel cluster. The surface network simulator,
running on a Microsoft Windows desktop, is handling surface facilities for this network (upper
right ). The FM module (top) that controls all of these simulators may be a desktop or local
mainframe computer.
11
AUSTRALIA
IO/Jansz field
Gorgon field
Barrow
Island
Dampier to Bunbury
natural gas pipeline
Pipeline junction
LNG plant
Gorgon pipeline
Existing pipeline
0
0
km
50
mi
50
> Gorgon project, offshore Australia. The Gorgon project includes the Gorgon and IO/Jansz subsea gas
fields that lie 150 to 220 km [93 to 137 mi] off the mainland. Gas is moved from the fields by deep
underwater pipelines (black) to Barrow Island, about 50 km off the coast. There, the raw gas is stripped
to remove CO2 and then either liquefied to LNG for export by tanker or moved to the mainland by
pipeline for domestic use. On the mainland, gas from Barrow Island is transported through an existing
pipeline (blue) that gathers gas from other producing areas nearby.
Better Decisions—Reduced Uncertainty
The Gorgon project—a joint venture of Chevron,
Royal Dutch Shell and ExxonMobil—will produce LNG for export from large fields off the
coast of northwest Australia.29 This project will
take subsea gas from the Gorgon and IO/Jansz
fields and move it by underwater pipeline to
Barrow Island about 50 km [31 mi] off the oast
(above). Chevron—the operator—is building a
15 million–tonUK [15.2 million–metric ton] LNG
plant on Barrow Island to prepare the gas for
export to customers in Japan and Korea.
Engineers at Chevron knew that one of the challenges would be to dispose of the high levels of
CO2 separated from the raw gas.30 Chevron will
meet this challenge by removing the CO2 at the
LNG plant and burying it deep beneath the surface of Barrow Island (below). Gorgon will be
capable of injecting 6.2 million m3/d [220 MMcf/d]
of CO2 using nine injection wells spread over
three drill centers on Barrow Island.
Oilfield Review
WINTER 11/12
Intersect Fig. 11
ORWNT11/12-INT
11
CO2 stripping
Gorgon project
gas fields
LNG plant
With billions of dollars of capital and LNG revenues at stake, Chevron and its partners understood from the start that the engineers developing
the business case would need to know how much
the project would yield and for how long.
Extensive reservoir modeling and simulation
were the solutions to this challenge. Some of
Chevron’s simulations on an internal serial simulator with fine grid models of individual Gorgon
formations were taking 13 to 17 hours per run.
Early in the project, Chevron decided that migration to the INTERSECT simulator would be
required for timely project development.
Although some computer models require a
minimal amount of input data, that cannot be
said for reservoir simulators. These simulators
employ large datasets and typically use purposebuilt migrators to move the data from one simulator to another. For Gorgon, Chevron used internal
migrating software to transform input from
their internal simulator to the corresponding
INTERSECT input dataset. These data were used
to develop history-matching cases at data centers
in Houston and in San Ramon, California, USA.31
The results from these cases showed that both
simulators were producing equivalent results—
although taking very different amounts of CPU
time to do it. This process was repeated on highperformance, parallel computing clusters at the
Chevron operations center in Perth, Western
Australia, Australia.
As Chevron project teams in Australia began
advanced project planning, the INTERSECT simulator reduced simulation times by more than an
order of magnitude. In one Gorgon gas field simulation with 15 wells and 287,000 grid cells, serial
run times with the internal simulator were six to
eight hours, while the INTERSECT system
reduced run times to under 10 minutes with
LNG product
Seismic
surveys
Surveillance
wells
CO2
CO2 disposal
> CO2 disposal. As natural gas is produced from the various reservoirs in the Gorgon project (left ), it is fed to a CO2 stripping facility located near the LNG
plant (middle). Stripped natural gas (orange) flows to liquefaction and an associated domestic gas plant (not shown), while the extracted CO2 (blue) is
compressed and injected into an unused saline aquifer 2.5 km [1.6 mi] beneath the surface for disposal. Conditions in the CO2 storage formation are
monitored by seismic surveys and surveillance wells (right ).
12
Oilfield Review
excellent scalability. In addition to this simulation, Chevron has used the INTERSECT simulator
on other fields in the Gorgon area including
Wheatstone, IO/Jansz and West Tryal Rocks. Both
black oil and compositional models have been
used with grids ranging from 45,000 to 1.4 million
cells. INTERSECT simulation times on these
cases using the Perth cluster ranged from 2 minutes to 20 minutes depending on the case.
Next-generation reservoir simulation on geologic scale models with fast run times has
enhanced decision analysis and uncertainty
management at Gorgon.
Reducing Simulation Time
Reduction of reservoir simulation execution
time was also a key factor for Total at their
Surmont oil sands project in Canada. Surmont,
located in the Athabasca oil sands area about
60 km [37 mi] southeast of Fort McMurray,
Alberta, Canada, is a joint venture between
ConocoPhillips Canada and Total E&P Canada
(right).32 The project was initiated in 2007 with
a production of 4,293 m3/d [27,000 bbl/d] of
heavy oil; it is expected to reach full capacity of
16,536 m3/d [104,000 bbl/d] in 2012.
At Surmont, the highly viscous bitumen in the
unconsolidated reservoir is produced by steamassisted gravity drainage (SAGD). In this process, steam is injected through a horizontal well,
and heated bitumen is produced by gravity from a
parallel, horizontal producing well below the
injector. Typically, one steam chamber is associated with each injector and producing well, and a
SAGD development consists of several adjacent
well pairs.
From a simulations point of view, at the start
of SAGD operations, the individual steam chambers are independent of each other and simulations can be performed on individual SAGD pairs.
As the heating and drainage proceed, this independence between well pairs ceases because of
pressure communications, gas channeling and
aquifer interactions. Including all well pairs in a
typical SAGD development quickly leads to multimillion-cell models that could not be run in a reasonable time frame with commercial thermal
simulators.33 Total turned to the INTERSECT
new-generation simulator to model the full-field,
nine-pair SAGD operation at Surmont.
The model describes an oil sands reservoir with
an oil viscosity of 1.5 million mPa.s [1.5 million cp]
and 1.7 million grid blocks with heterogeneous cell
properties.34 The model includes external heat
sources and sinks to describe the interaction with
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C A N A D A
0
0
km
U N I T E D
S T A T E S
200
mi
200
Fort McMurray
Surmont
Athabasca
oil sands
A l b e r t a
Edmonton
Calgary
> Surmont project. The Surmont oil sands project is located
southeast of Fort McMurray, Alberta, Canada, within the greater
Athabasca oil sands area. Depending on the topography and the
depth of the overburden, oil sands at Athabasca may be produced
by surface mining or steam-assisted processes such as SAGD.
over- and underburden material. The producers are on a parallel computer cluster. To test its speed
controlled by maximum steam rate, maximum liq- and scalability, the software was used on different
uid rate and minimum bottomhole pressure (BHP). parallel hardware configurations ranging from 1
The injectors are controlled by maximum injection to 32 processors. These tests proved the ability of
this application to handle this large heterogerate and maximum BHP.
The INTERSECT system was used to model the neous model quickly enough to support operational decisions. For example, using 16 processors,
first three years of SAGD operations atOilfield
SurmontReview
WINTER 11/12
29.Flett M, Beacher G, Brantjes J, Burt A, Dauth Intersect
C,
TC, Nations T and Noonan SG: “SAGD Gas Lift
Fig.32.Handfield
13Completions
Koelmeyer F, Lawrence R, Leigh S, McKenna J, Gurton R,
and Optimization: A Field Case Study at
ORWNT11/12-INT
13 paper SPE/PS/CHOA 117489, presented at the
Robinson WF and Tankersley T: “Gorgon Project:
Surmont,”
Subsurface Evaluation of Carbon Dioxide Disposal Under
SPE International Thermal Operations and Heavy Oil
Barrow Island,” paper SPE 116372, presented at the
Symposium, Calgary, October 20–23, 2008.
SPE Asia Pacific Oil and Gas Conference and Exhibition,
33.Total initially tried a commercial, thermal simulator to
Perth, Western Australia, Australia, October 20–22, 2008.
model operations at Surmont. Case run times were very
30.Raw gas from the Gorgon fields has about 14% CO2.
long—45 hours—making this approach impractical.
31.To ensure that two reservoir simulators are producing
34.The oil is modeled using two pseudocomponents—
equivalent results, a user may employ a technique called
one light and one heavy.
history-matching. Each simulator will run the same case,
and the oil or gas production rates, as a function of time,
will be compared. If they match, the two cases are
deemed equivalent. This technique can also be used to
calibrate a simulator to a field where long-term
production data are available.
13
Conserving Resources
As operators continue to push into remote areas
in search of resources, next-generation simulators will be there to aid in planning and development. A case in point is the new Chevron Tengiz
field in the Republic of Kazakhstan, at the shore
of the Caspian Sea. Tengiz is a deep, supergiant,
naturally fractured carbonate oil and gas field
with an oil column of about 1,600 m [5,250 ft] and
a production rate of 79,500 m3/d [500,000 bbl/d].36
The Tengiz field is expansive, covering an area of
the INTERSECT simulator executed the Surmont
case in 2.6 hours.35 Parallel scalability is also
good—10 times faster on 16 processors compared
with a serial run. In addition to predicting flow
performance from SAGD operations, the system
can also give information on profiles of important
variables such as pressure and temperature in the
steam chambers (below). In preparation for fully
deploying the INTERSECT technology at Surmont,
Total is confirming these results on the most current version of the simulator.
Temperature, °C
10
66
122
178
234
> Steam chambers. The nine steam chambers at Surmont are located at a depth of 300 m [984 ft] near
the bottom of the oil sands reservoir. These chambers have a lateral spacing of about 100 m [328 ft] and
a length of nearly 1,000 m [3,281 ft]. Each chamber has a pair of wells—one steam injector (magenta)
and a parallel producing well (not shown). INTERSECT simulation of a thermal process such as SAGD
also yields information on temperature profiles in the steam chambers. At Surmont, the temperature
varies from more than 230°C [446°F] (red areas) at the core of the chamber to ambient temperature at
the periphery (blue areas). Gaps along the length of the chambers reflect permeability differences in
the oil sands. The operator monitors temperature in the steam chambers during production. While the
steam chambers are relatively small, the SAGD process is efficient. Once the chamber growth reaches
the rock at the top of the reservoir, thermal efficiency drops because of heat transfer to the overburden.
35.This case used 16 processors—four multicore
Lim K-T and Hoang V: “A Next-Generation Reservoir
processors each having four cores built into the chip.
Simulator as an Enabling Tool for Routine Analyses of
Heavy Oil and Thermal Recovery Process,” WHOC paper
36.Tankersley T, Narr W, King, G, Camerlo R,
2009-403, presented at the World Heavy Oil Congress,
Zhumagulova A, Skalinski M and Pan Y: “Reservoir
Puerto La Cruz, Venezuela, November 3–5, 2009.
Modeling to Characterize Dual Porosity, Tengiz Field,
Republic of Kazakhstan,” paper SPE 139836, presented
39.Afifi AM: “Ghawar: The Anatomy of the World’s Largest
at the SPE Caspian Carbonates Technology Conference,
Oil Field,” Search and Discovery (January 25, 2005),
Atyrau, Kazakhstan, November 8–10, 2010.
http://searchanddiscovery.com/documents/2004/afifi01/
(accessed September 29, 2011).
37.The Tengiz simulation also couples the reservoir and
well models to surface separation facilities to maximize
40.Dogru et al, reference 19.
plant capacities as part of development planning.
41.Dogru AH, Fung LS, Middya U, Al-Shaalan TM, Byer T,
Oilfield Review
38.Chevron Corporation: “Envisioning Perfect Oil Fields,
Hoy H, Hahn WA, Al-Zamel N, Pita J, Hemanthkumar K,
WINTER
11/12
Growing Future Energy Streams,” Next*, no. 4
Mezghani M, Al-Mana A, Tan J, Dreiman W, Fugl A and
(November 2010): 2–3.
Al-Baiz A: “New Frontiers in Large Scale Reservoir
Intersect Fig. 14
Simulation,”
Chevron is also using the INTERSECT system to
reduce
ORWNT11/12-INT
14 paper SPE 142297, presented at the SPE
Reservoir Simulation Symposium, The Woodlands,
run time in field scale models for thermal recovery
Texas, February 21–23, 2011.
processes. For more information, see:
14
about 440 km2 [170 mi2], and contains an estimated 4.1 billion m3 [26 billion bbl] in place.
The challenge for Chevron in modeling Tengiz
was the field’s geologic complexity coupled with
the need to reinject large quantities of H2S recovered from the production stream. This required
combining detailed geologic information with
information on the distinctly different flow
behaviors between fractured and nonfractured
areas of the field. To assist in current field management and support future growth, Chevron
developed an INTERSECT case that encompassed the 116 producing wells. The model contained 3.7 million grid blocks in an unstructured
grid that included more than 12,000 fractures.37
Chevron has experienced improved efficiency
using the new simulator at Tengiz; simulations
that once took eight days now take eight hours.38
More-realistic geologic input leads to more-accurate production forecasts that allow engineers to
make better field development decisions. In addition to their use in the development of new fields,
next-generation simulators may also aid recovery
of additional oil and gas from older fields.
The world energy markets rely heavily on the
giant reservoirs of the Middle East. The largest of
these reservoirs—Ghawar—was discovered in
1948 and has been producing for 60 years.39
Ghawar is a large field, measuring 250 km
[155 mi] long by 30 km [19 mi] wide. Simulation
of a reservoir the size of Ghawar is challenging
because of the fine grid size that must be
employed to capture the heterogeneities seen in
high-resolution seismic data. Using fine grid sizes
can reduce errors in upscaling (next page).
To handle reservoirs the size of Ghawar and
the other giant fields that it owns, Saudi Aramco
has developed a next-generation reservoir simulator.40 In one Ghawar black oil simulation, the
model used more than a billion cells with a 42-m
[138-ft] grid and 51 layers with 1.5-m [5-ft] spacing.41 Using a large parallel computing system,
42.Dogru AH: “Giga-Cell Simulation,” The Saudi Aramco
Journal of Technology (Spring 2011): 2–7.
43.Farber D: “Microsoft’s Mundie Outlines the Future of
Computing,” CNET News (September 25, 2008) http://
news.cnet.com/830113953_3-10050826-80.html
(accessed August 4, 2011).
44.Dogru et al, reference 41.
45.Bridger T: “Cloud Computing Can Be Applied for
Reservoir Modeling,” Hart Energy E&P (March 1, 2011),
http://www.epmag.com/Production-Drilling/CloudComputing-Be-Applied-Reservoir-Modeling_78380
(accessed August 11, 2011).
Oilfield Review
50 m
250 m
© 2011 Google-Imagery © 2011 Digital Globe, GOIEYE
© 2011 Google-Imagery © 2011 Digital Globe, GOIEYE
> Grid resolution. Areal grid size plays an important role in capturing reservoir heterogeneity and eliminating errors caused by upscaling. Overhead photos
of the Colosseum in Rome illustrate this concept. If the area of interest is the Colosseum floor (dashed box, upper left), then a 50 m x 50 m [164 ft x 164 ft]
grid is appropriate to capture what is required. Choice of a larger 250 m x 250 m [820 ft x 820 ft] grid (dashed box, right) includes driveways, streets,
landscaping and other features not associated with the focal point of interest. In the case of the Colosseum, use of the larger grid to capture properties
associated with the floor would introduce errors.
this model simulated 60 years of production history in 21 hours.42 The results were compared
with an older simulation run using a 250-m [820ft] grid and a given production plan. The older
simulator predicted no oil left behind after secondary recovery; the new simulator revealed oil
pockets that could be produced using infill drilling or other methods. This example shows how
next-generation simulators may facilitate additional resource recovery.
Although a primary goal of next-generation
simulators has been to more completely
describe reservoirs through reduced grid size
and upscaling, scientists are also pursuing other
technology innovations. Improved user interfaces and new hardware options for reservoir
simulation are imminent.
These improved user interfaces embody a concept known as spatial computing. Spatial computing relies on multiple core processors, parallel
programming and cloud services to produce a virtual world controlled by speech and gestures.43
This concept is being tested for controlling large
Winter 2011/2012
reservoir simulations with hand gestures and verbal commands rather than with a computer
mouse.44 To test this concept, a room is equipped
with cameras and sensors connected to large
screens on the walls and a visual display on a table.
Using hand gestures and speech, engineers manage the simulator input and output. If needed, the
system can be used in a collaborative manner via a
network with engineers and scientists at other
locations. This kind of system has vast possibilities—it tends to mask computing system complexOilfield Review
ity and allows the
engineers
and scientists to freely
WINTER
11/12
interact with the
reservoir
simulation.
Intersect Fig. 15
ORWNT11/12-INT
15
Just as ideas
such as spatial computing
will
enhance the user interface, new hardware utilization concepts that go beyond onsite parallel
computing clusters will add to reservoir simulation capability. Clusters of parallel computers are
expensive and the associated infrastructure is
complex and difficult to maintain. Some operators are discovering that it may be useful to use
cloud computing to communicate with multiple
clusters in many locations.45 Using this approach,
the operator can add system capacity as the
situation dictates rather than depending on a
fixed set of hardware. This approach allows the
user to communicate with the cloud system via a
“thin client” such as a laptop or a tablet. Reservoir
modeling tools using this technology have already
been developed, and more will follow.
New technology for reservoir simulation is
emerging on several fronts. Foremost are nextgeneration reservoir simulators that produce
more-accurate simulations on complex fields
with reduced execution time. Other technologies
such as spatial and cloud computing are on the
near horizon and will allow scientists and engineers to interact more naturally with the simulations and potentially add hardware capability at
will. These developments will give operators
more-accurate forecasts, and those improved
forecasts will lead to better field development
decisions. —DA
15
Slickline Signaling a Change
Well intervention techniques have long been dependent on mechanical and
hydraulic systems for actuation and measurement. As a consequence, the outcomes
of many downhole operations—for which depths were often approximate—
depended as much on the skill of the operators as on the design of the tools.
For one intervention method, these limitations were eliminated when engineers
developed digital slickline.
Matthew Billingham
Vincent Chatelet
Stuart Murchie
Roissy-en-France, France
Morris Cox
Nexen Petroleum USA Inc.
Houston, Texas, USA
William B. Paulsen
ATP Oil & Gas Corporation
Houston, Texas
Oilfield Review Winter 2011/2012: 23, no. 4.
Copyright © 2012 Schlumberger.
For help in preparation of this article, thanks to Blaine
Hoover, Buddy Dearborn, Chuck Esponge, Douglas Guillot
and Scott Milner, Broussard, Louisiana, USA; Farid Hamida,
Rosharon, Texas; and Fabio Cecconi, Pierre-arnaud Foucher
and Keith Ross, Roissy-en-France, France.
D-Jar, D-Set, DSL, D-Trig, FloView, GHOST, Gradiomanometer,
LIVE, LIVE Act, LIVE Perf, LIVE PL, LIVE Seal, LIVE Set,
PS Platform, Secure and UNIGAGE are marks of Schlumberger.
16
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Oilfield Review
Slickline operations in oil and gas wells have
been performed for more than 75 years, and
until recently, practices have changed little.
Technicians and engineers in the field perform
basic downhole operations through manipulation
of downhole tools attached to the end of a singlestrand thin wire called a slickline; the name distinguishes it from a conducting cable used in
electric line or a braided cable used for heavier
mechanical work. These downhole operations
may be as simple as running a gauge ring to TD or
more complex wellbore maintenance and production optimization procedures such as setting
or pulling valves and plugs. Operations also
include removing production-hindering debris
such as sand or paraffin from the well. More
recently, devices with electronic memory have
been run on slickline to gather data for pressure
transient surveys or production logging.
Slickline has remained a staple of well intervention because it is cost-effective, reliable, efficient and logistically uncomplicated. It is
deployed with relative ease using compact equipment that may be moved to and situated at a wellsite of nearly any size located anywhere in the
world. It may be used in all types of wells, including HPHT, sour gas, high-angle and flowing. On
locations with space or weight limitations, slickline is often the only feasible intervention option.
But the simplicity of slickline is also the
source of its drawbacks. Engineers designed
slickline initially to perform rudimentary
mechanical operations. At that time, absolute
depth was not an essential consideration for such
operations. Drillers could not place tools precisely, and as a consequence, it was difficult to
verify a tool’s precise downhole location. For
some operations, particularly perforating or the
setting of isolation tools, knowledge of exact tool
depth is critical. Similarly, to ensure sensitive
instruments and other tools are not damaged
during setting or pulling operations, or to confirm
the intended downhole action, it is sometimes
imperative that a force—which must fall within a
narrow range—be delivered downhole. Using
slickline, it is impossible to determine with any
certainty exact tool depth or amount of force
delivered downhole.
All tubulars, wires and cables stretch to some
extent as they are moved into and out of a well.
Stretch in slickline wire, however, is significantly
greater than that of other conveyance methods.
Therefore, depth measurements taken using a
mechanical device and displayed at the surface
may not accurately represent the tool location.
Indeed, displayed information is not a measurement of tool depth but of how much wire has been
Winter 2011/2012
Sheave
Stuffing box
Lubricator
Wireline
valve
Sheave
Slickline drum
Christmas
tree
Load cell
> Basic slickline rig-up. A load cell, which is attached to a sheave, is activated
by tension in the wire running through the sheave. The wire runs from the
slickline drum to the sheave, which redirects it upward at an acute angle. It is
turned 180° by a second sheave and fed into the stuffing box where it enters the
well through the lubricator. The wireline valve above the Christmas tree contains
opposing rams (not shown) that may be closed to seal against each other
without removing the wire, thus providing a pressure barrier alternative in the
event the stuffing box sealing mechanism fails.
spooled on or off the drum. As a consequence, the tor readings at the surface; these readings are
standard accuracy for slickline depth measuring the only indicator of forces being applied downsystems is about 30 cm/300 m [1 ft/1,000 ft].1 This hole. Typically, the weight downhole is measured
degree of accuracy is often sufficient for slickline using a load cell attached to a wellhead and then
Oilfield Review
to a pulley through which the slickline is directed
operations for which depth is reckonedWINTER
to within11/12
a few feet of some fixed point in the completion
Slickline Fig. 1from the drum to the top of the lubricator
string. In wells that have no downhole marker,
the (above). 1As the angle of deviated wells has
ORWNT11/12-SLKLN
margin of error may be unacceptable. Engineers increased, along with the number of such wells,
have devised systems to correct for stretch as well there has been a corresponding increase in the
as other variables, but such corrective measures frequency and degree of inaccurate weight readare based on data estimates only, and sophisti- ings. Such depth and weight inaccuracies may
cated operations typically require more accuracy
1. King J, Beagrie B and Billingham M: “An Improved
than these systems could deliver.
Method of Slickline Perforating,” paper SPE 81536,
presented at the SPE 13th Middle East Oil Show and
In addition, wellbore deviation can cause
Conference, Bahrain, April 5–8, 2003.
considerable inaccuracies in the weight indica-
17
7.1 ft
[2.2 m]
4.8 ft
[1.5 m]
GHOST Tool
Gradiomanometer
Tool
Density, deviation
Gas holdup, gas and
liquid bubble count,
average caliper, bearing
6.8 ft
[2.1 m]
4.2 ft
[1.3 m]
3.1 ft
[0.94 m]
FloView Tool
UNIGAGE
Carrier
Quartz pressure
gauge
Bidirectional
Inline Spinner
Flowmeter
Water holdup, bubble
count, centralizer,
average caliper
13.5 ft
[4.11 m]
Basic Measurement Sonde
Batteries and recorder, gamma ray,
casing collar locator,
temperature, pressure
Flow-Caliper
Imaging Tool
Flowmeter, X-Y caliper,
water holdup, bubble count,
relative bearing, centralizer
> Battery-powered tools. The PS Platform service is a suite of battery-powered tools that can perform both memory and
surface readout operations. The GHOST gas holdup optical sensor tool (top left) uses four sapphire optical probes to
measure gas and liquid holdups, bubble count, average hole caliper measurements and bearing. The Gradiomanometer
specific gravity profile tool (top second from left) measures the average density of the wellbore fluid and wellbore deviation,
from which water, oil and gas holdups can be derived. The bubble count from the FloView holdup measurement tool (top
center) identifies first fluid entry, water holdup and bubble count and includes a centralizer and average hole caliper
measurements. The UNIGAGE pressure gauge system carrier (top second from right) contains a crystal quartz gauge that
offers the option of a high-resolution pressure measurement. The optional inline spinner (top right) provides a bidirectional
fluid velocity measurement inside the tubing. The basic measurement sonde (bottom left) provides gamma ray (GR) and
casing collar locator (CCL) data for correlation, plus pressure and temperature measurements. The flow-caliper imaging tool
(bottom right) measures the average fluid velocity, water and hydrocarbon holdups and bubble count from four independent
probes. It also provides dual-axis X-Y caliper measurements and relative bearing measurements. Well deviation and
accelerometer measurements provide the deviation correction for the measured fluid density.
lead to extended operation times or, in more
complex well completions, to operational issues.
In slickline perforating, for example, placing a
gun a few feet above or below target depth may
mean the difference between producing water,
oil or gas—or nothing at all.
In recent years, engineers have developed
numerous improvements to traditional slickline
equipment. Most of these are incremental
changes applied to tools run on slickline rather
than to the wire itself. Battery-powered electronic tools, which acquire and store data in
memory, have overcome some slickline shortcomings pertaining to actuation and confirmation of
downhole actions. But once these tools have been
deployed, they do not provide real-time downhole
data or give the operator the ability to change
settings, such as the depth or temperature at
which triggers are activated. As a result, batteryoperated tools cannot address the time and efficiency shortcomings that characterize many
traditional slickline operations.
The most ambitious attempt to overcome these
hurdles—using the slickline itself to deliver twoway signals between the tool and the surface—has
been pursued for decades. Such a solution could
be used to provide operators with precise tool
18
depth, tool status, downhole weight, wire tension
and wellbore data such as pressure and temperature measurements in real time.
Despite many years of effort, manufacturers
had been unable to develop an acceptable solution using a slickline wire and equipment. That
Oilfield
Review at Geoservices, a
changed when
engineers
WINTER 11/12
Schlumberger company, developed DSL digital
Slickline Fig. 2
slickline services.
ORWNT11/12-SLKLN 2
This article describes enhancements made to
slickline in the form of battery-powered and
memory tools that allow engineers to expand
slickline applications to include accurate depth
measurements for perforating and production
logging. Also discussed is DSL technology, which
is an engineering breakthrough, rather than a
slickline enhancement. Using telemetry over
slickline, coupled with battery-powered electronic tools that incorporate a memory and
telemetry interface, DSL services allow commands and data communication between the surface and downhole without compromising the
mechanical integrity of the wire. These features
expand slickline capabilities significantly by
offering accurate depth correlation, tool status
information and tool control to the operator in
real time; this is critical to delivering precise,
efficient and low-risk operations on slickline-
conveyed mechanical, remedial and measurement operations.
Upgrading Slickline
Historically, depth accuracy has critically limited
the scope of slickline operations that use conventional measuring devices. The primary factors
affecting depth accuracy are elastic stretch, temperature, buoyancy, slickline and toolstring friction against the wellbore wall, lift and measuring
wheel precision. The variety of sizes and materials used for slickline wire may also impact measurement readings. The most common slickline
wire diameters are 0.092, 0.108 and 0.125 in.
[2.34, 2.74 and 3.18 mm]. The materials from
which they are manufactured—depending on
their application—include carbon steel, stainless
steel alloys and nickel- and cobalt-based alloys.2
Elastic stretch—the factor that causes the most
variability in slickline depth accuracy—is a function
of line tension and the modulus of elasticity of the
wire.3 Length measurements may be increased or
decreased by out-of-tolerance or poorly calibrated
measuring wheel diameters. Changes in measuring
wheel diameters can result from wheel wear, debris
buildup or the disparity in the temperatures at
which the measuring wheel was manufactured or
Oilfield Review
calibrated and the temperature at which it operates.
Measurement errors can be in excess of 0.6 m [2.0 ft]
at well depths of 3,000 m [10,000 ft].4 Temperature
differences in the hole also affect wire length as the
wire is lowered into the well. Unless wellbore temperature gradients remain constant, or temperature
and measurement variations are included in depth
corrections, it is difficult to compensate for this variable. In addition, buoyancy, friction and lift—which
are functions of wellbore parameters such as fluid
viscosity, flow rate, fluid type, deviation, tortuosity
and wellbore geometry—affect tension measurements at the surface.
Although minimal differences in measurement occur at shallow depths, discrepancies
may increase and become more significant with
increasing depth. In recent years, engineers
have addressed the depth accuracy issue through
the development of electronic measurement
devices that attempt to automatically correct for
wire stretch.
Another slickline limitation has been the
mechanical means by which tools are activated.
Engineers addressed this issue through development of battery-powered tools. These tools, which
store downhole data in memory that is accessed
once the tool returns to the surface, may perform
downhole slickline operations when activated by
a timer or a when a signal is generated through a
predefined cable movement sequence. Memory
devices have been used in remedial services,
such as perforating and device setting, and have
been used in measurement services such as production logging, while offering a cost or access
advantage over electric line.
Battery-powered electronic triggering can
enable safe detonation of explosives used for tubing and casing cutting and perforating, and electromechanical setting tools can replace explosive
devices. The industry has welcomed electronic firing heads because they can be programmed to disarm automatically on retrieval to the surface if the
pressure window that is a condition of their arming has been selected correctly.5 These concerns
were formerly met using mechanically or hydraulically actuated firing heads.
The industry has also embraced the use of
nonexplosive, electronically actuated setting tools
in environments where logistics associated with
explosives are restrictive or complex. Firing
delays or pressure windows are two examples of
safety measures added to traditional devices. But
these add complexity and compromise precision
because of variations in downhole conditions
such as temperature and pressure and because of
the time the tool has spent downhole. Electronic
firing heads are immune to these variations and
provide improved accuracy and control.6
Many services that were performed using electric line or coiled tubing are now possible as slickline services because of battery-operated tools.
These include sensors for pressure, temperature,
gamma ray (GR), casing collar locator (CCL), flowmeter, caliper, bubble count, tool orientation,
water holdup and gas holdup (previous page).
Despite these improvements, engineers continued to seek the next major advance in slickline
capabilities—a method by which they could send
signals to, and receive data from, downhole tools
in real time. Their objective was to gain the
versatility and accuracy of electric line telemetry
communication without sacrificing the advantages of slickline.
For example, because slickline is a single
component it is naturally balanced and so lends
itself to operations such as jarring. In contrast,
jarring with electric line may lead to destruction
of the insulator between the conductor and the
cable’s armor.7 Electric line includes an outer
and inner set of protective armor wires wound in
opposite directions around the central conductors (above right). This creates an inherent
torque level within the cable that must be managed to avoid wire damage, particularly in deep
or highly deviated wells. This damage may take
the form of overlapping outer armor, or wires,
that quickly wear and break and then hang up in
pressure control equipment. When an overlapping wire breaks, it unravels as it enters wellhead
pressure control equipment, which results in an
extensive operation to remove the stranded
armor wire.
The sealing mechanism at the top of the
slickline lubricator also offers an advantage
over that used for braided or electric line. A
slickline stuffing box is far less complex than
2. Larimore DR and Kerr WL: “Improved Depth Control for
Slickline Increases Efficiency in Wireline Services,”
Journal of Canadian Petroleum Technology 36, no. 8
(August 1997): 36–42.
3. Modulus of elasticity is the ratio of longitudinal stress to
longitudinal strain.
4. Larimore and Kerr, reference 2.
5. A pressure window is a preset condition that allows the
tool to arm only when it is at a pressure greater than
surface pressure.
6. Goodman KR, Bertoja MJ and Staats RJ: “Intelligent
Electronic Firing Heads: Advancements in Efficiency,
Flexibility, and Safety,” paper SPE 103085, presented at
the SPE Annual Technical Conference and Exhibition,
San Antonio, Texas, USA, September 24–27, 2006.
7. Slickline jarring uses a downhole mechanical device
called a jar to deliver an impact load to another downhole
component. Jars include a lower section attached to a
tool or other component, and an upper section that can
travel freely. The jar may be opened upward and then
quickly lowered to use the weight of the toolstring to
deliver a downward blow to the lower section. In reverse,
the slickline is reeled in at high speed to deliver an
upward force to the lower section of the jar.
Winter 2011/2012
Outer armor
Inner armor
Semiconductive
jacket
Insulated
conductors
> Armored electric cable. Cables used for electric
line, or wireline, operations include multiple
armored and insulated conductors. In this case,
seven insulated wire conductors are packaged
within a semiconductive jacket. The wires and
insulators are wrapped in inner and outer sets of
armor wound onto the bundle in opposite directions.
the grease tube assembly used for braided or
electric line. A rubber packing element maintains a pressure seal even when a wire passes
through it (below). It is thus easier to rig up
than a braided cable grease-control flow-tube
Sheave
Oilfield Review
WINTER 11/12
Slickline Fig. 3
ORWNT11/12-SLKLN 3
> Simple pressure control. A slickline stuffing box
(orange) is a relatively simple sleeve lined with
sections of polymer packing (black) that act as a
pressure seal against the wire as it moves out of
the wellbore, through the pressurized lubricator
and the stuffing box, into the atmosphere and up
and over the sheave. When tightened, a packing
nut (red) compresses the packing against the
wire, increasing the sealing force. The same
sealing mechanism holds pressure as the slickline
is going into the well.
19
assembly, which requires grease to be injected
across flow tubes at a pressure greater than that
of the wellhead during the entire operation.
Electric line operations performed under pressure require additional equipment, including a
grease pump and a grease supply, which have
implications for logistics and the environment.
In addition, because moving the line through
the grease tubes may break the grease seal,
braided cable is restricted to running speeds of
about 1,200 to 3,000 m/h [4,000 to 10,000 ft/h] in
and out of the well. The mechanical slickline
tools can be run at a faster rate without losing
the pressure seal, saving valuable rig time.
A Matter of Live and Depth
While a true slickline telemetry system eluded
engineers for decades, they were able to develop
a power–telemetry slickline link using coaxial
cable. However, because the cable sacrifices the
tensile strength and inherent robustness that are
essential to slickline applications, the technology
has been abandoned.
Developing an insulator was the stumbling
block to slickline telemetry, and engineers were
further challenged to find a method to bond the
insulating material to the wire. In 2002, engineers at Geoservices began work on a telemetry
system based on previously developed MWD
electromagnetic technology. However, telemetry
1,000
70.5
800
0
69.5
200
120
1,350
1,300
Head tension, lbf
400
Temperature, °F
50
70.0
600
CCL, mV
Acceleration, gn
150
140
1,400
Tubing pressure, psi
200
about transmission reliability through an electric
line, associated accessories such as sinker
weights and the point at which the wire is connected to the toolstring. But the mechanical
demands on the insulation-wire bond remain significant; the wire deployed using standard slickline equipment must withstand the rigors of
spooling on and off the drum, running around
sheaves and through pressure-control equipment. It must also endure an often punishing
downhole environment, and when it emerges
from the well through the stuffing box, it is
exposed to instantaneous decompression from
wellhead to atmospheric pressure.
In 2009, those hurdles had been overcome
and the first commercial jobs were performed
successfully in Africa, France, Italy and
Indonesia. Since that time, various applications
within digital slickline services have been performed in France, Indonesia, China, the US and
Saudi Arabia.
The core of the LIVE toolstring includes the
computer baseboard management controller
(BMC) that handles the telemetry downhole;
delivers surface readouts of shock, line tension,
deviation and movement in real time; and confirms the success of operations such as perforating (below). Surface equipment includes a
slickline unit furnished with a computer and
transceiver, pressure control equipment and the
160
1,450
250
100
was not the issue; the challenge was finding an
insulating material and a method by which it
could be bonded to wire that would allow it to
survive the rigors of slickline operations. Initially,
the team tested seven polymers, based on their
resistance properties, as insulation material candidates. Under well conditions, however, these
coatings did not adhere to the wire.
After years of effort, researchers developed a
complex wire-coating material and an exacting
bonding procedure. The finished product is made
continuous, uniform and with a precise diameter
to within 0.002 in. [0.05 mm] throughout its
length.8 Applied to standard 0.108- and 0.125-in.
[2.74- and 3.25-mm] stainless steel alloy line, the
outside diameter of the coated slickline is 0.138
and 0.153 in. [3.51 and 3.89 mm], respectively.
The resulting LIVE digital slickline retains all
the strengths of the original wire upon which it is
built. The system maintains tool power requirements delivered from batteries and uses the slick
wire as a telemetry conduit rather than as an
electrical conduit. Because engineers designed
the service to be a digital telemetry system rather
than an electrical conduit, they were able to
reduce insulation performance requirements and
so hasten development. Engineers created
another advantage by not sending power through
the slickline. This feature eliminates concerns
100
80
1,250
60
1,200
40
69.0
–50
0
–100
03:28:15
03:28:30
03:28:45
03:29:00
03:29:15
03:29:30
03:29:45
03:30:00
Time, h:min:s
> Surface confirmation of detonation. Multiple measurements displayed at the surface show the instantaneous effects of the firing
of perforating guns just before 03:29:00. The shock curve (red) indicates a negative acceleration of more than 100 gn. At the same
time, head tension (purple) increases from approximately 80 lbf [356 N] to more than 120 lbf [534 N] and pressure (blue) drops from
1,364 psi [9.4 MPa] to about 1,220 psi [8.4 MPa]. Tool movement is apparent on the CCL curve (green) immediately after gun detonation
as the tool moves in the tubing, creating voltage across the CCL coil. Oscillation of the cable and gun after detonation is reflected
in both the head tension and pressure curves. After the guns are fired, a decrease in temperature (orange) indicates cooler fluid is
entering the tubing from the annulus. These indicators are independent verifications that the gun has been detonated on command.
20
Oilfield Review
digital line. Optional core downhole equipment
includes a depth correlation cartridge, which
delivers real-time CCL and GR measurements to
provide depth accuracy during any slickline service; a digital pressure-temperature gauge may
also be added for downhole measurements.
LIVE digital slickline services are divided
into the typical intervention service classifications: mechanical, remedial and measurement.
The mechanical LIVE Act digital slickline services include conventional tools deployed as they
would be on a standard slickline. Remedial services include LIVE Set setting services, which are
nonexplosive, hydraulically set plug and retainer
services; LIVE Seal sealing services, which use
nonelastomeric sealing for monobore completions; and LIVE Perf perforating, punch and pipe
cutting services.9 The measurement segment of
the service is the LIVE PL comprehensive suite of
production logging tools. These services are run
in conjunction with the core and optional tools
and with real-time measurement and control.
In addition, LIVE services expand on traditional capabilities and requirements by adding
the digital D-Jar downhole adjustable jar, which
can be commanded to repeatedly activate and
deliver a specific force downhole. When using traditional hydraulic or mechanical jars, operators
rely on their experience and a weight indicator to
determine jar action downhole. The D-Jar tool, in
contrast, provides control and efficiency to jarring operations without requiring trips to the surface to adjust the impact force. It does so through
repeated upward jarring using elasticity of the
cable to store energy while the jarring action is
delivered via the electrically triggered mechanical firing function. Downhole tension and shock
are measured and monitored at the surface during operation, which allows an optimized jarring
force without unnecessary stress on the toolstring or jarring of components. Engineers set
jarring force by adjusting cable tension, which
can be reset when and as often as necessary.
The digital controlled release (DCR) tool is
another LIVE tool that may be added to any digital slickline operation. In the event the toolstring
becomes stuck downhole and cannot be freed,
conventional slickline options include using a
cutter bar to sever the wire as close to the toolstring as possible. The resulting fishing job may
require numerous runs to gather, cut and retrieve
any wire that remains in the well, sometimes followed by attempts using a braided wireline to
latch onto and retrieve the stuck tool. This can be
problematic if wire remains on top of the object
Collet
Collets
Internal
fishing
neck
External
fishing
neck
> Digital controlled release. In the event a slickline tool becomes stuck, a
signal from the surface decouples the DCR tool, allowing the operator to pull
the top portion of the tool and all the wire from the hole, leaving clean internal
and external fishing neck profiles facing upward (bottom). Depending on the
DCR tool’s position in the well, or other factors affecting access, the operator
may then use a cable wire or coiled tubing and either a fishing tool with
collets that latch an internal profile (left) or an overshot-type tool (right) with
collets that latch an external profile to retrieve the stuck tool.
LIVE Set digital slickline setting services probeing retrieved or the fishing neck has been damaged. Often, it requires numerous attempts to vide a means for setting devices such as casing
determine the nature and amount of the debris and tubing plugs and cement retainers without
that is on top of the stuck tool and to then remove using traditional explosives-based systems. Using
it before the stuck tool can be latched onto and
8. “GEM-Line Goes LIVE,” GeoWorld—The Geoservices
retrieved. In contrast, the DCR tool provides a
Group Magazine 54 (December 2010): 4–7.
controlled separation of the toolstring assembly 9. Punchers are perforating devices designed to penetrate
the inner tubing string without damaging the surrounding
at or near the tool head, which instead of leaving
casing.
Oilfield and
Review
wire behind, leaves only a defined internal
external fishing neck profile (above).WINTER 11/12
Slickline Fig. 6
ORWNT11/12-SLKLN 6
Winter 2011/2012
21
Hydraulic power unit
Solenoid
valve
Electric
motor
Pressure
barrier
Electronics
package
Lithium battery
Microhydraulic
pump
>D-Set electrohydraulic setting tool. The D-Set electrohydraulic unit contains three principal
components: a high-temperature lithium battery, an electronics package and a hydraulic power unit
(HPU). The lithium battery provides power. The electronics package converts the DC battery output to
three-phase alternating current for the HPU’s electric motor and commands the hydraulic circuit. The
battery and electronics package are isolated by means of a pressure barrier from the HPU. The HPU,
which consists of the electric motor, microhydraulic pump and a solenoid valve is 54 mm [2.1 in.] in
diameter by 510 mm [20.1 in.] in length. A smaller 43-mm [1.7-in.] diameter pump can generate nearly
6 tons [60 kN] of force. Within the HPU, the brushless electric motor is coupled to a fixed-displacement,
microhydraulic axial piston pump (not shown). The motor is run at high speed for low-torque
requirements, such as tool stroke, and switches to low speed for high-torque needs such as setting a
tool or shearing a setting stud. Hydraulic pump output is routed to the tool’s mechanical section (not
shown) through surface-controlled solenoids.
Seal
elements
set
Cone
Oilfield Review
WINTER 11/12
Slickline Fig. 7
ORWNT11/12-SLKLN 7
Slips
Seal
elements
retracted
> Setting without profiles. With a GeoLock mandrel, tools may be set in
smooth tubulars having no internal setting profiles. When the tool is in the
running position, the slips and seal elements (inset, bottom) are retracted,
which minimizes the mandrel’s outside diameter and allows it to pass through
tubing. Once the tool has been run to the desired depth, it is set using a
LIVE D-Set digital setting tool or explosive setting tool to compress the tool,
forcing cones to travel beneath the slips and seals. This expands the seals
(inset, top) against the tubing wall. The mandrel may be retrieved using an
electric or hydraulic tool that latches and returns the cones, seals and slips to
their original positions.
22
the surface-controlled D-Set digital electrohydraulic setting tool, this service allows placement
of downhole components on depth (left). This tool
is a battery-powered electrohydraulic power unit
that can generate up to 25 tons [249 kN] of
force—sufficient to set permanent plugs, packers
and other devices. Microhydraulics—miniaturized hydraulic pumps—can generate this force
with limited power in a small package. Engineers
control the depth of the tool accurately using a
downhole GR and CCL. The D-Set tool uses a
battery-powered electrohydraulic pump to generate the power to create pull or movement, or
stroke, necessary to set the device. During the
setting sequence, diagnostic motor current, toolstring shock and head tension information is sent
to the surface to confirm each step of the process.
The retrievable locking mandrel, one of the
most versatile tools in the slickline toolbox,
allows well intervention in monobore wells
or completions with damaged landing nipples.
Traditional slickline locking mandrels feature
rubber seals that are extruded outward against
the tubing wall for pressure containment. They
are activated by an inner mandrel that moves
downward behind them at the same time it forces
slips to move out and grip the tubing. Engineers
use these locking mandrels to carry plugs, pressure and temperature sensors and other tools to
points in the tubing or casing that do not have
landing nipples.
Unlike traditional locking mandrels, the LIVE
Seal GeoLock digital sealing service uses a nonrubber kinematic sealing mechanism that does
not deform when the tool is set (left). It can thus
be used in the presence of gas and at high temperatures and pressures for prolonged periods—
circumstances that often lead to failure of
extruded rubber seals—and can be easily
retrieved with standard slickline pulling tools.
The anchoring and sealing devices maximize the
mandrel’s internal flow area and, when retracted,
reduce the mandrel OD while running in and out
of the hole.
The GeoLock mandrel is run with the D-Set
setting tool and a sequence consisting of centralizing, anchoring and sealing. Engineers can monitor the procedure from surface using a time plot
of the complete sealing sequence. The tool and
mandrel use a calibrated shear disk instead of a
shear pin, which ensures a fully open flush tube
with no internal restrictions once the tool is set.
Digital slickline also includes LIVE Perf perforating services. With these services, operators can
confidently and safely cut pipe for recovery, punch
tubing and perforate at specified depths. The service employs the D-Trig digital activation device,
Oilfield Review
which allows surface-controlled activation of both
explosive and nonexplosive devices. Like other
DSL equipment, the D-Trig device uses the depth
correlation cartridge real-time GR or CCL data to
achieve accurate depth control. It is equipped
with multiple fail-safe systems and is compatible
with most industry perforating, punching and setting technologies.
The D-Trig activation device represents a significant advance in slickline triggers because it
can be correlated in real time with surface readout GR and CCL when deployed in combination
with the depth correlation cartridge tool (right).
This tool can fire all Schlumberger throughtubing perforating guns, hollow carrier guns,
casing and tubing cutters and some third-party
systems. The D-Trig system can also be used to
initiate explosive setting tools.
The combination of the D-Trig system and the
baseboard management controller (BMC), and
other devices such as a quartz pressure gauge,
enhances downhole shot detection. Crews can
confidently identify misruns prior to retrieving
the tools to surface. Within the BMC, shock
detection and head tension changes give conclusive evidence that a device has fired. This can
also be confirmed with downhole pressure and
temperature measurements.
Another safety feature of the D-Trig service is
a fuse that can be blown to disarm the trigger
under certain conditions including disagreement between the microprocessors, drift in
clock frequency within electronics, low BMC
battery voltage and excessive time gaps in communication; the fuse can also be blown by operator command.
When engineers replace high explosives with
exploding bridgewire detonators or exploding foil
detonators, the system becomes immune to early
detonation caused by a number of factors:
•radio frequency radiation
•impressed current cathodic protection
•electric welding
•high-tension power lines.
The introduction of LIVE PL production logging services changed the industry’s dependence
for these surveys on battery-operated memory
tools or electric line. Arguably the most powerful
tool for diagnosing the health of a well, production logs provide in situ measurements that
describe the nature and behavior of fluids in the
borehole during production or injection; production logs also help engineers determine which
zones are contributing to fluid flow. But at wells
with surface locations where space, weight or
accessibility limits exclude use of large electric
line units, the only option for obtaining a production log has been a battery-powered memory
Winter 2011/2012
Battery
Electronics cartridge
Safety fuse
Safety pressure switch
Spring monopin box connection
> Digital trigger. The D-Trig device is controlled by redundant dual microprocessors and incorporates
multiple fail-safe systems. A signal sent from surface is received by the tool, which generates a pulse
to fire the detonator of the cutter or explosive tool (not shown). The device includes a battery that can
fire either third-party exploding bridgewire detonators or Schlumberger Secure detonators. A separate
smaller battery is mounted in the baseboard management controller (not shown) to power the
electronics within the electronics cartridge. This design allows for a safety fuse to be placed between
the firing battery and detonator (not shown) and adds a level of security to operations. In addition, a
safety sub is placed between the detonator and the D-Trig tool and includes a safety pressure switch
that automatically grounds the detonator when the device is at atmospheric pressure. The D-Trig
device shown is electrically plugged into the detonator using a single spring monopin box connection.
slickline tool. The LIVE PL service offers an Two for One
alternative to the larger electric line unit and Combining real-time downhole measurements
delivers more accurate depth correlation than is with traditional slickline creates numerous benpossible with memory tools; in addition, the ser- efits. For example, one operator discovered
Review
inherited wellbore schematics were in error. Had
vice sends logging data to the surface inOilfield
real time
WINTER 11/12
engineers chosen to shoot tubing perforations as
while simultaneously storing it in memory.
Slickline Fig. 9
originally 9planned, based on depths displayed on
Additionally, when engineers perform
tranORWNT11/12-SLKLN
sient buildup tests with digital slickline, they can the schematic and without a CCL and GR for cormonitor downhole pressure and temperature in relation, they would have tried and failed to
real time and detect when the well has reached puncture a blast joint located where the well
maximum bottomhole pressure (BHP). Obtaining schematic showed the target tubing joint. In this
this information in real time can reduce shut-in case, changes were made immediately as the job
times. Data can therefore be used efficiently for was progressing based on real-time GR and CCL
reservoir monitoring, updating models and diag- data seen on the surface, allowing engineers to
nosing certain individual well conditions such as carry out the operation without additional time
and, more importantly, without error.
the existence and location of water sources.
23
Day
Digital Slickline
Slickline Plus Electric Line
Rig up and run
first gauge ring.
1
Perform
static gradient
survey and
first shut-in.
2
Run second gauge ring.
Perform
static gradient
survey and
flow well.
3
Run third gauge ring.
4
5
6
7
Perform
static gradient
survey, flow well
and perform buildup.
Install plugs,
shift sliding sleeves and
run fourth gauge ring.
Install plugs, shift
sliding sleeves and
run fourth gauge ring.
Perform buildup
survey and rig down.
10 hours saved
Close sliding sleeve,
install SSV and rig down.
> Single-unit logging operation. Typically, operators use a slickline unit to
prepare a well for logging by first performing gauge ring runs, installing
plugs and locking out the surface-controlled subsurface safety valve (SSV).
They then use an electric line unit to acquire production log data. For one
typical operation requiring a static pressure gradient, drawdown and shut-in
pressure and temperature survey for each producing zone, the operator
scheduled the program to take 168 hours using slickline and electric line
independently. By using DSL services to perform both conventional slickline
and electric line surface readout operations, the operator saved more than
10 hours and eliminated an extra crew and logging unit.
Oilfield Review
WINTER 11/12
In addition to risk management,
efficiency
Slickline
Fig. 10potential risks and lengthy operating time.
Because10LIVE digital slickline services can perand precision advantages, LIVE digital
slickline
ORWNT11/12-SLKLN
services also enable engineers to perform certain
types of jobs—operations that once required use
of traditional slickline and electric line with a
unit and a crew for each—with a single digital
slickline unit and crew. For example, engineers
often use both conventional electric line units
with surface readouts to gather real-time measurements, and a slickline unit to perform
mechanical operations on the same well. When
performing such interventions in each of four
producing zones, engineers traditionally first use
a slickline unit to prepare the well for logging by
running gauge rings, installing plugs and shifting
sliding sleeves. They then run production logs
using a separate electric line unit. This movement of equipment and personnel can lead to
complicated logistics, high costs, increased
24
form the full scope of work, the single unit and
crew cuts logistics and manpower requirements
by half and reduces risks while saving significant
overall rig time (above).
ATP Oil & Gas Corporation engineers seeking
to capitalize on these efficiencies selected DSL
services for a recompletion operation at Eugene
Island Block 71, offshore Louisiana, USA. The
zone isolation and recompletion operation was
performed from the deck of a jackup vessel by
first setting a through-tubing cast iron bridge
plug and dumping 50 ft [15 m] of cement in 27/8-in.
tubing to shut off a depleted lower zone at
12,790 to 12,875 ft [3,898 to 3,924 m].
Once the lower zone was plugged, the operator planned to perforate a shallower interval at
12,668 to 12,678 ft [3,861 to 3,864 m] using six
shots-per-foot perforating guns (next page).
Because the shallower target sand was thin,
depth precision and accuracy were critical and
could be achieved efficiently and in real time
through the use of CCL and GR, an option formerly available only with electric line. Because
other parts of the operation, such as dump bailing the cement, required slickline tools, two
crews would have been required to perform
numerous rigging operations and equipment
moves on the deck of the vessel. Using the LIVE
depth correlation package with the LIVE Perf
services, a single unit and crew accomplished the
plug back and perforation operations. Total cost
as a result of time saved was US$ 80,000 below
the original authorization for expenditure.
In this instance, the operator realized savings
by reducing the time required to mobilize and
move electric line and slickline units on and off
the well and around the deck and by eliminating
the standby costs associated with a second crew.
In other cases, there may be additional savings
because space and weight requirements are
reduced when only one unit is deployed, allowing
the operator to hire a less expensive lift vessel
with reduced deck capacity. In some instances,
because of the slickline equipment’s relatively
small footprint and light weight, an operator may
be able to place the unit directly on the deck of a
platform too small to accommodate larger,
heavier electric line equipment. This may eliminate the cost of a service vessel entirely, resulting
in significant savings.
Cost reduction as a function of time can
quickly multiply depending on environment. For
example, in relatively shallow waters, interventions may be performed from the deck of lift
boats for which the day rate ranges from about
US$ 4,000 to as much US$ 40,000 as a function of
water-depth capabilities and deck space.
However, savings can skyrocket when work is
slated for water beyond lift boat depth capabilities, which is about 60 m [200 ft], in relatively
calm waters such as offshore West Africa and in
the Gulf of Mexico. The cutoff depth is even shallower in areas of typically rougher waters such as
the North Sea.
In deeper waters, an operator may use a semisubmersible or dynamically positioned drilling
unit whose costs are much higher than jackup
vessels. And in deep and ultradeep water, operators must use specially designed deepwater drilling units. The day rate for these giant units is
around US$ 1 million. Saving a few days or even a
few hours to perform slickline and electric line
work can quickly yield significant savings.
Oilfield Review
In the deepwater Green Canyon area of the
Gulf of Mexico, Nexen Petroleum USA leased the
deepwater rig Ocean Saratoga to plug and abandon (P&A) a well in about 900 ft [275 m] of water,
about 100 mi [160 km] off the Louisiana coast.
Typically, this phase of the P&A operation would
have required preparatory work on slickline, followed by tubing punching and tubing cutting,
which require accurate depth correlation using
electric line. Nexen engineers turned to digital
slickline to perform all P&A operations using a
single slickline unit. Their objective for this highcost environment was considerable savings
through operational efficiencies—such as fewer
rig-up and rig-down operations.
Digital slickline was used successfully for
depth correlation and the subsequent tubing
punching operation at 10,030 ft [3,057 m]. Tool
shock measurements displayed at the surface in
real time clearly indicated the successful firing of
the puncher. The operator benefited from the
value of a smooth, depth-correlated puncher operation, and as a result, realized significant savings
in this high-cost environment. Some of these savings were achieved because the operator was not
forced to pay standby costs for two crews when
unforseen delays idled the rig for several days.
Executing such interventions with digital
slickline instead of electric line also reduces risk
because its pressure control equipment is less
complex. During pressure control events, if it
becomes necessary to cut the line, it is easier to
cut slickline than thicker electric line that may
be across the wellhead.
A Very Large Niche
As operating environments become increasingly
more challenging in places such as the Gulf of
Mexico and the North Sea, operators are actively
seeking ways to control costs. Digital slickline,
which offers the robust simplicity of slickline while
maintaining the versatility of electric line, is
poised to play a significant role in that quest. Its
suitability for P&A operations will no doubt draw
particular attention as aging wells in the North Sea
and the Gulf of Mexico drive a push by regulators
for large-scale platform decommissioning.
Engineers are likely to adopt digital slickline
technology as part of a well’s completion strategy. It maintains the basic simplicity and familiarity of slickline and is thus far less intrusive
than other recent innovations such as intelligent
completions or monobore wells, whose complexity sparked years of resistance from an industry
as concerned with the cost of failure as with
potential benefits. A failure of an intelligent well
or a monobore installation may result in loss of
Winter 2011/2012
60-in. by 48-in. casing at 224 ft
16-in. casing at 810 ft
10 3/4-in. casing at 3,970 ft
7 5/8 -in. casing at 12,032 ft
5 1/2-in. packer at 12,487 ft
B sand perforations
12,668 ft to 12,678 ft MD
12,070 ft to 12,080 ft TVD
5 1/2-in. packer at 12,700 ft
50 ft of cement
Cast-iron bridge plug
C sand perforations
12,790 ft to 12,875 ft MD
12,144 ft to 12,200 ft TVD
Sliding sleeve at 12,870 ft
Isolation packer at 12,886 ft
Isolation packer at 13,311 ft
D upper sand perforations
13,448 ft to 13,472 ft MD
12,588 ft to 12,604 ft TVD
Sliding sleeve at 13,449 ft
Sump packer at 13,482 ft
5 1/2-in. casing at 13,802 ft
13,802 ft MD
12,817 ft TVD
> Wellbore schematic. Operator ATP Oil & Gas decided to plug the reservoir
C sand at its Eugene Island Block 71 field and move uphole to perforate the
B sand. Because the B sand is just 10 ft [3 m] thick, depth accuracy was
critical. Obtaining that level of accuracy traditionally required the use of an
electric logging unit for perforating. For this operation, the crew used only a
LIVE digital slickline unit to first set a cast-iron bridge plug in the lower tubing
string, dump 50 ft of cement on top of it and perforate the casing across the
thin B sand precisely on depth. Unless otherwise marked, all depths are
measured depth (MD).
There are also some simple but important and
an entire wellbore and almost certainly in the
loss of many thousands of dollars spent in repair practical advantages to choosing digital slickline
costs and delayed production. In contrast, the over electric line for certain offshore operations.
worst-case scenario of a digital slickline
operaOilfield
ReviewFor example, several industry efforts to develop
WINTER
11/12riserless intervention techniques on subsea wells
tion failure is lost time while an electric
line unit
Slickline Fig. 11are ongoing. Slickline may have an edge over
is brought in to finish the job.
ORWNT11/12-SLKLN 11
In a post-Macondo world, operators are eager wireline in this application because it is very difto seize any safety advantage, which means the ficult to manage a grease seal during subsea
benefits of digital slickline may be more than cost riserless operations. In this environment, the
and time savings. Because digital slickline often slickline-style stuffing box used in conjunction
allows a single crew with a single unit to provide with digital slickline could prove to be one of the
services that once required two units and crews, critical components that brings deepwater riserit can significantly ease personnel and equip- less intervention into the mainstream. This techment movement logistics and thereby enhance nology upgrade is long overdue for a service that
safety and reduce environmental risk. This may has been used since the turn of the last century;
be especially important in remote locations digital slickline services may soon move from
where transportation is difficult and offshore, technology trial status to best practice. —RvF
where space, weight and environmental considerations are paramount.
25
Stabilizing the Wellbore to Prevent
Lost Circulation
wide
hes wide
wide
wide
Lost circulation—the loss of whole drilling mud to the formation—raises significant
costs and risks to drillers around the world and threatens to pose greater challenges
in the future. The industry is meeting this threat with diverse wellbore strengthening
materials that work by different mechanisms but share a common goal: to stop
fracture growth and keep drilling mud in the wellbore.
John Cook
Cambridge, England
Fred Growcock
Occidental Oil and Gas Corporation
Houston, Texas, USA
Quan Guo
Houston, Texas
Mike Hodder
M-I SWACO
Aberdeen, Scotland
Eric van Oort
Shell Upstream Americas
Houston, Texas
Oilfield Review Winter 2011/2012: 23, no. 4.
Copyright © 2012 Schlumberger.
For help in preparation of this article, thanks to Raul
Bermudez, Clamart, France; Jim Friedheim, Houston; Guido
Leoni, Ravenna, Italy; and Mark Sanders, Aberdeen.
Losseal is a mark of Schlumberger.
MPSRS is a mark of M-I, l.l.c.
1. Dodson T: “Identifying NPT Risk,” Keynote presentation
at the Atlantic Communications Drilling and Completing
Trouble Zones Forum, Galveston, Texas, USA,
October 20, 2010.
2. Redden J: “Advanced Fluid Systems Aim to Stabilize Well
Bores, Minimize Nonproductive Time,” The American Oil
& Gas Reporter 52, no. 8 (August 2009): 58–65.
3. Growcock F: “Lost Circulation Solutions for Permeable
and Fractured Formations,” Proceedings, Southwestern
Petroleum Short Course 54 (2007): 175–181.
4. ECD is a function of the hydrostatic head generated by
the mud density and the frictional pressure losses that
the mud pump must overcome to move fluid and cuttings
up the wellbore.
26
Over the past century, the oil and gas industry has
made great strides in developing drilling technologies and techniques that make well construction a cost-effective and safe enterprise. However,
as new hydrocarbon sources are found in increas-
ingly remote and geologically complex reservoirs,
the industry continues to develop technologies to
meet wellbore integrity challenges that present
safety hazards and economic risks to the longterm viability of a well.
Remediation
Lost circulation materials
Prevention
Wellbore strengthening materials
Drilling fluid selection
Best drilling practices
> Comprehensive lost circulation management program. The bottom three
tiers of the pyramid focus on lost circulation prevention. Best drilling practices
may encompass implementing accurate geomechanical models to calculate
the risk of hole collapse or lost circulation and may also make use of
expandable casing, managed pressure drilling or casing-while-drilling
techniques. Drilling fluid selection includes the implementation of drilling fluid
with the proper rheological properties to minimize or cure lost circulation.
Wellbore strengthening materials consist of specially formulated and sized
particulate materials that enter a fracture and arrest its propagation by
isolating it from the wellbore. The top tier is devoted to remediating losses
though the use of lost circulation materials such as cure or stop-loss pills.
Oilfield Review
In the Gulf of Mexico alone, wellbore integrity
issues in the form of stuck pipe, wellbore collapse,
sloughing shales and lost circulation account for
as much as 44% of nonproductive time (NPT) that
prevents progress of the drill bit toward its target.1
The financial ramifications of wellbore integrity–
related NPT are so great that operators may add
10% to 20% to authorizations for expenditures to
cover the anticipated downtime.2
Lost circulation, in which drilling fluid, or
mud, flows partially or completely into a formation through areas known as thief zones, is a common contributor to NPT (right). These zones
effectively steal drilling fluid from the wellbore.
Although the fluid has several purposes, those
most affected by lost circulation are the needs to
maintain hydrostatic pressure in the annulus and
prevent formation fluids from entering the borehole during the drilling process.
To counter this phenomenon, a comprehensive lost circulation management program provides a staged approach to mitigating fluid losses,
depending on the severity of the problem. One
such approach is a four-tiered strategy consisting
of both prevention and remediation measures
(previous page). Industry experience has proved
that it is often easier and more effective to prevent the occurrence of losses than to attempt to
stop or reduce them once they have started.
Fluid losses occur typically through fractures
induced by the drilling process. These fractures
tend to propagate easily because the pressure
required to lengthen a fracture is often lower
than that required to initiate it.3 Therefore,
remediation is commonly considered a contingency to be used only after preventive measures
have failed.
This article reviews the drilling conditions
that contribute to lost circulation events and
explains why lost circulation threatens to become
a greater contributor to NPT than it has been in
the past. The article also discusses lost circulation prevention through the use of wellbore
strengthening materials and describes various
schools of thought within the industry on mechanisms for stabilizing the wellbore and preventing
fracture propagation.
Lost Circulation Fundamentals
Lost circulation events arise most commonly as a
consequence of the method used to drill a well.
Traditionally, wells are drilled in an overbalanced
condition in which drilling fluid, or mud, is circulated down the drillstring, through the bit and up
the annulus.
Winter 2011/2012
Wellbore cross section
Filtercake
Fracture
Drillpipe
Formation
Wellbore
Filtercake
Drilling
fluid
flow
Fluid losses
Fracture
Thief zone
Fluid leakoff
> Mechanisms for drilling fluid egress from the wellbore. During circulation of drilling mud back to the
surface (green arrows), the fluid comes into contact with the wellbore. In traditional drilling practices,
the pressure in the wellbore exceeds that of the formation, which prevents formation fluids from
entering the wellbore. In one method of fluid loss from the wellbore, a filtration process takes place in
the permeable rock, whereby the liquid component of the drilling mud moves into the rock, leaving the
solid particulates and emulsion droplets to collect on the wellbore wall and form a filtercake. The low
permeability of this cake keeps the volume of fluid lost by leakoff very low, and this is not considered a
lost circulation event. Lost circulation occurs if the rock is naturally fractured, vugular or highly porous.
If the wellbore pressure is higher than the rock’s tensile strength, fractures will form. Each of these
cases results in the loss of large volumes of drilling fluid (white arrows) into thief zones. In severe
cases, an appreciable quantity, or even all, of the drilling fluid enters the formation, propagating further
fracture growth (inset).
Mud weight, or density, is the primary source risks to wellhead equipment and potential injury
of hydrostatic pressure in a well. When circulat- to rig personnel.
Lost Circulation
ing through the wellbore, the mud contributes to
Other obstacles to the safety and economic
Figure 1_4
a pressure in the wellbore that can be expressed
viability of the well may arise if the hydrostatic
in terms of the equivalent circulating density pressure is too low to support the rock face at
(ECD).4 In an overbalanced state, this ECD helps the wellbore. Drilling mud must be heavy enough
create a hydrostatic pressure in the wellbore that to counter the instability in the borehole that
is greater than the pore pressure of the exposed is created when rock is removed through the
formation. A drilling fluid of insufficient density drilling process. If the driller selects a drilling
may yield a hydrostatic pressure that is lower mud of insufficient density, the result may be
than the pore pressure. This may lead to a wellbore instability and, in extreme cases, wellkick: an unplanned influx of formation fluids into bore collapse.
Conversely, a drilling fluid with an excessively
the wellbore. Most kicks are managed using
established well kill operations, but in rare high mud weight exerts a hydrostatic pressure
instances an uncontrolled kick may manifest that may exceed the formation’s mechanical
itself in the form of a blowout, with associated
27
Wellbore
> Types of lost circulation events. The upper formation experiences loss of
drilling mud (white arrows) into natural fractures that were intersected by the
wellbore. The middle formation exhibits the propagation of a fracture that was
hydraulically induced by the drilling process. The lower formation highlights
losses caused by seepage.
integrity, forcing drilling fluid into natural fractures (above). Naturally occurring fractures may
be present in any type of formation, but they
occur most commonly in geologic settings with
ongoing tectonic activity.
Lost circulation management can also be
quite challenging when fractures are induced
during the drilling process.5 Fracture creation
results from tensile failure, which occurs when
the stress exerted on the formation exceeds the
Pbreakdown
Ppropagation
Pressure
Pleakoff
Pumps off
Pclosure
Preopening
Lost Circulation
Pumps on
Figure 3_3
Time
> Pressure thresholds. During the initial stages of an extended leakoff test
(XLOT), pressure increases linearly with the volume of fluid pumped. As more
fluid is pumped into the wellbore, the pressure increase eventually departs
from linearity at the leakoff pressure (Pleakoff) point, which also leads to
initiation of a fracture. The fracture propagates until the formation breakdown
pressure (Pbreakdown) is reached. The pressure curve falls off quickly at this
point, and fractures propagate in a more controlled fashion at a lower and
somewhat steady pressure called the fracture propagation pressure
(Ppropagation). If pumping is stopped, pressure in the fracture will bleed off to the
formation, which lowers pressure in the fracture and causes the fracture to
close at the fracture closure pressure (Pclosure). When pumping resumes,
pressure builds again and the fracture can reopen at the reopening pressure,
(Preopening), which is similar to Pclosure. The fracture will then resume
propagating at a pressure similar to Ppropagation. An XLOT curve may not exhibit
this shape or possess a peak or plateau. The shape is driven by a host of
factors, including in situ stresses in the rock, pore pressure, inherent rock
strength and wellbore orientation.
28
hoop stress around the wellbore and the tensile
strength of the rock, most commonly because of
excessive mud density or wellbore pressure.6
Typically, a pressure-integrity or extended
leakoff test (XLOT) measures the ability of the formation and wellbore to sustain pressure. Engineers
conduct the test after a new casing string has been
run and cemented, immediately after drilling out
beneath the casing shoe. To initiate the test, the
rig crew shuts in the well and pumps fluid into
the wellbore to gradually increase the pressure
exerted on the formation (below left).
The driller must stay within a pressure regime
that avoids a kick or a lost circulation event; an
XLOT can provide insight into that pressure
regime. The upper limit on ECD is typically represented by the fracture gradient (FG), the pressure in the well that would cause the surrounding
formation to fracture, creating potential loss of
fluid from the well. FG is not defined precisely;
some drillers identify FG as the pressure at which
a fracture is initiated (Pleakoff), others may select
the more conservative value of the fracture closure pressure (Pclosure), and some select a pressure for FG between these two parameters.
The lower limit on ECD is normally determined by either the pore pressure (Ppore) or the
wellbore collapse pressure (Pcollapse), below
which the flow of formation fluids into the
wellbore causes causes such severe mechanical
instability problems that operations must be
modified or halted. The range between the upper
and lower limits is the mud weight window or
drilling margin. These upper and lower limits are
influenced by in situ rock stress orientations and
magnitudes, pore pressure, rock strength and
wellbore orientation. These parameters vary
with wellbore depth and act to significantly
change the size of the mud weight window (next
page, left).
To avoid lost circulation or wellbore instability
events, drillers pay close attention to maintaining
the ECD within the confines of the mud weight
window. Failure to do so causes the wellbore’s
physical stability to change along a continuum of
possible profiles, ranging from formation fluid
influx to severe or total drilling fluid losses and
even wellbore collapse (next page, right).
Whether lost circulation occurs while drilling,
running casing, or completing and cementing the
well, its impact on well construction costs is significant, representing an estimated US$ 2 to 4 billion annually in lost time, lost drilling fluid and
materials used to stem the losses. The US
Department of Energy reports that on average 10%
to 20% of the cost of drilling high-pressure, hightemperature wells is expended on mud losses.7
Oilfield Review
Circulation Risks in Complex Reservoirs
Worldwide, the portion of NPT attributable to lost
circulation is increasing as drillers pursue more
complex and technically challenging prospects
than have been attempted in the past. For example, to reach isolated reservoirs located at a significant horizontal distance from the surface well
pad, operators are increasingly implementing
extended-reach drilling (ERD) techniques.8
These wells present unique fluid management
challenges because drilling margins change dramatically, depending on location in the wellbore.
In the vertical section of the wellbore, while
the section is being drilled to the next casing
shoe, the mud weight may safely reside in a wide
envelope with no danger of wellbore instability,
Wellbore
Wellbore
Wellbore
Wellbore
Wellbore
Wellbore
Uncontrolled
fluid influx
Wellbore
deformation
In-gauge
hole
Fluid flow into
fractures
Severe fluid
losses
Stable ECD window
Safe window
Ppore
Low
Pbreakdown
ECD
High
A
> Wellbore profiles as functions of mud weight. If the drilling mud weight, or ECD, is closely monitored
and maintained within the wellbore’s stable ECD window (green line), an in-gauge hole is ensured,
with no fluids entering or exiting the wellbore (top center). If the ECD drops below this stable window,
the wellbore enters an instability regime, in which reservoir fluid begins to exert pressure on the hole
to begin hole deformation (top, second from left). The ECD continues to drop and reaches the pore
pressure (Ppore). Below this pressure, the formation fluid (red arrows, top left) enters the wellbore
unabated and may cause wellbore collapse and the uncontrolled release of production fluids to
surface via the wellbore. The other end of the ECD continuum (orange line, right) begins with a mud
weight that is too high, which causes the drilling mud to induce fracture formation or enter existing
fractures (top, second from right). If the ECD is too high, the formation breakdown pressure (Pbreakdown)
is reached; above this pressure, severe fluid losses occur (top right).
Depth
B
C
ECD
window
D
Pressure
Overburden
pressure
Fracture gradient
Pore pressure
Wellbore collapse
pressure
>Pressure gradient regimes in a wellbore. In
Interval A, the ECD window, or mud weight
window (purple shading) is bordered by the pore
pressure (blue) and the fracture gradient (FG)
(red). In a depleted interval (B), in which
production from the interval leads to a reduction in
pore pressure, the mud weight window narrows
and both pore pressure and FG shift to lower
pressures. In an interval with a mechanically weak
formation (C), the lower limit of the mud weight
window is defined by wellbore collapse pressure
(green) and not pore pressure. In Interval D, pore
pressure is high and FG is low, resulting in a very
narrow mud weight window, which would present
a challenge to controlling the ECD.
Winter 2011/2012
Lost Circulation
Figure 5_3
formation fluid ingress to the wellbore or drilling
Deepwater drilling in the Gulf of Mexico and
fluid egress to the formation. However, as the well offshore Brazil and West Africa has introduced
becomes more inclined, the minimum required lost circulation challenges beyond narrow drillECD increases because friction losses increase. ing margins. These challenges include high ECDs
In addition, the influence of drilling parameters and drilling fluid that is cooled by the nearon ECD may increase because of the great length freezing seawater surrounding the drilling riser.
of the ERD well. These factors can decrease the Additionally, the cost of lost circulation and NPT
drilling margin significantly—in some cases to as is exacerbated by the use of synthetic-base muds
Lost Circulation
low as 60 kg/m3 [0.5 lbm/galUS] or less—which (SBMs) that range from US$ 100 to US$ 200 per
Figure barrel
6_4 and by high rig time costs.9
elevates the risk of lost circulation. This is especially true in ERD wells drilled into unconsolidated formations with relatively low FGs.
5. M-I SWACO Technical Service Group: “Chapter 1:
Fundamentals of Lost Circulation,” Houston: M-I SWACO,
Prevention and Control of Lost Circulation (March 17,
2011): 1:1–7.
6. Hoop stress refers to the stress acting circumferentially
around a wellbore, which is generated as a result of
removing the rock volume when the wellbore is created.
For more information: Fjaer E, Holt RM, Horsrud P,
Raaen AM and Risnes R: Petroleum Related Rock
Mechanics, 2nd ed. Amsterdam: Elsevier (2008): 139–140.
7. Growcock F: “How to Stabilize and Strengthen the
Wellbore During Drilling Operations,” SPE Distinguished
Lecturer Program (2009/2010), http://www.spe.org/
dl/docs/2010/FredGrowcock.pdf (accessed
September 21, 2011).
8. For more on extended-reach wells: Bennetzen B,
Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N,
Poupeau J-F and Sonowal K: “Extended-Reach Wells,”
Oilfield Review 22, no. 3 (Autumn 2010): 4–15.
9. Synthetic-base muds are nonaqueous, water-internal
emulsion drilling fluids in which the external phase is a
synthetic fluid rather than oil.
29
circulation materials
Lost
Most salts
Flakes
Reactive materials
Most fibers
Laminates
Plates
Soft granules
Marble
We
Synthetic graphite
Hard, granular fibers
ll b o
re s tr e
n gt h e ni n g m
ater
ial s
> Lost circulation materials. While wellbore
strengthening materials (WSMs) are considered
a preventive measure for lost circulation
challenges, they may be categorized as a
specialized subset of lost circulation materials
(LCMs). Most LCMs are added to the drilling fluid
once a lost circulation event has begun.
The risks of lost circulation events are even
greater for deepwater fields that experience
depletion-related stress changes, which increase
the risk of fault activation and leads to the creation of new lost circulation zones. ERD wells of
more than 10-km [6.2-mi] total depth also present challenges for managing ECD.10
Lost circulation challenges arise when drillers target depleted zones within maturing fields.
Production from these fields leads to reduced
pore pressure in some of the formation layers,
which in turn leads to a reduced FG and a
requirement for reduced mud densities. Where
overlying and interbedded shales are also present, a high mud density is required to prevent
wellbore collapse
possible fluid influx. In
Lostand
Circulation
such scenarios, the depleted layers must be
Figure 7_3
drilled with a high overbalance, and drillers must
take measures to prevent lost circulation. While
overbalances as high as 90 MPa [13,000 psi] have
been recorded in some Gulf of Mexico formations, more typical values are in the range of 20
to 30 MPa [2,900 to 4,300 psi], such as those
observed in the North Sea.11
Framing the Challenge
The industry has developed a range of technologies and services designed to prevent or mitigate
lost circulation. Selecting the proper solution typically begins with classifying the rate or magnitude
of fluid loss. These fall into three categories: seepage, partial fluid losses and severe losses.
30
The least severe loss, seepage, takes the
form of whole mud loss at a rate lower than
1.6 m3/h [10 bbl/h]. Typically these losses arise
from flow of fluid into formation pores and not
fractures. Seepage losses are usually associated
with loss of whole mud into the pore network system in which filtercake has not yet developed.12
The seepage rate is strictly a function of the overbalance and the permeability of the rock.
To accurately track seepage losses, engineers
must account for other volume changes to the
drilling mud. These include removal of cuttings—rock pieces dislodged by the drill bit as it
cuts rock to form the wellbore—and evaporation
of the fluid portion of the drilling mud at the surface. Engineers must accurately determine the
drop in drilling mud volume, which is caused by
the removal of cuttings and any residual mud on
them. Evaporation of the water phase of a waterbase mud was a greater problem in the past,
when open mud pits—large holes dug into the
ground to hold drilling fluid—were used.
Environmental concerns have prompted the
industry to exchange these pits for closed steel
vessels that hold from 160 to 320 m3 [1,000 to
2,000 bbl] of drilling mud.
Drillers verify seepage losses by pulling the
drill bit off-bottom, turning off all mixing and
nonessential solids removal equipment and then
checking mud volumes with and without circulation. Once it is established that a volume of drilling mud is being lost due to seepage, the operator
must decide whether to cure the losses or drill
ahead. This decision often depends on the costs
of drilling fluid and rig time, the narrowness of
the drilling margin and the likelihood of NPT
resulting from events such as formation damage
or stuck pipe.13
Partial fluid losses—1.6 to 16 m3/h
[10 to 100 bbl/h]—represent the next rung of the
lost circulation ladder. Drillers face the same
decisions for partial losses as they do for seepage
losses, but because greater volumes of drilling
fluid are lost, the driller more carefully considers
remedial measures. The cost of the drilling fluid
plays an important role: If the fluid is relatively
inexpensive and the mud weight can be reasonably managed within the drilling margin, drilling
ahead without remediation may be considered.
The point at which the cost of lost drilling fluids
becomes too high to ignore varies from well to
well and operator to operator.
When drilling fluids enter the formation
through fractures, vugs or caverns at a rate
greater than 16 m3/h, the losses are classified as
severe. These include total losses, in which no
volume of drilling fluid makes the return trip to
the surface. The consequences of such events
may include well control events and dry drilling
events, in which continued drilling after a total
loss leads to damage to the drill bit, drillstring
or wellbore.
Wellbore Strengthening
Fluids experts have developed a variety of methods to enhance the integrity of the wellbore and
prevent lost circulation. Collectively, these practices are called wellbore strengthening methods,
and include strategies that both alter stresses
around the wellbore and minimize fluid losses.
Operators employ a number of techniques to prevent lost circulation by physical or mechanical
means, which are theorized to work in fundamentally different ways:
•Fracture propagation resistance isolates the
tip of the existing fractures and mechanically
increases the fracture reopening pressure,
which increases the resistance to fracture
propagation.14
•Hoop stress enhancement mechanically
increases the near-wellbore stresses and the
Pleakoff or, more likely, the Pbreakdown.15
•The fracture closure stress technique fills and
enlarges fractures while isolating the fracture
tip and increasing near-wellbore stresses.16
•Wellbore isolation physically isolates the formation from the wellbore pressure.17
While there is no industrywide consensus for
which underlying technique is at work, there is
agreement that wellbore strengthening is a
real phenomenon. The overall effects of these
mechanisms is to elevate the pressure at which
uncontrolled losses occur and thereby widen the
drilling margin. The borehole is then able to
withstand greater pressures and, as measurement data illustrate, appears stronger, although
no actual change in rock strength has occurred.
For this reason, some have proposed calling the
phenomenon wellbore stabilization or drilling
margin extension, but the historical precedent
and industry’s long-standing use of the term wellbore strengthening contribute to its continued
widespread use.18
These theoretical wellbore strengthening
mechanisms share a common component: specifically sized and specially designed particulates, which are added to the drilling fluid. Any
Oilfield Review
particulate material that acts to stop or slow
mud loss is called a lost circulation material
(LCM), and may include soft granules, insoluble
salts, flakes or fibers (previous page). Most of
these may prove useful to mitigate, or cure, loss
of whole mud. Wellbore strengthening materials
(WSMs), a category of LCMs, have proved effective not only for mitigating losses but also for
preventing them.
Operators choose a WSM based on the desired
wellbore strengthening mechanism. A description of the principal mechanisms follows.
Fracture propagation resistance (FPR)—
The FPR theory of lost circulation prevention
posits that LCM is pushed into an incipient or
existing fracture to bridge, seal and isolate the
fracture tip, thereby increasing the formation’s
resistance to fracture propagation. Halting this
propagation also stops the lost circulation event.
The mechanism for FPR has its origins in a
joint industry project (JIP) known as the Drilling
Engineering Association (DEA)-13, which was
conducted in the mid-1980s to determine why oilbase mud (OBM) seemed to yield a lower FG than
water-base mud (WBM).19 The project found no
difference in fracture initiation pressure for different fluid types and formulations in intact boreholes, but noted significant differences for
fracture propagation behavior, which was influenced by fluid type and composition.
This difference was explained through a phenomenon known as fracture tip screenout.20
When fracture growth begins, the wellbore
instantaneously loses a volume of drilling fluid
into the new void space of the fracture. If the
fluid contains LCM, the introduction of fluid into
the fracture causes a buildup of LCM that isolates, or screens, the fracture tip from the full
pressure of the invading mud. The means by
which this LCM buildup occurs varies with the
type of fluid used (right).
Rfluid
Rcake
Rtip
Fracture
External filtercake
Rfluid
Rtip
Fracture
Internal filtercake
> Mud type, filtercake and fracture propagation. In a system using a WBM
(top), the fracture tip is sealed by an external filtercake that builds to prevent
effective pressure communication between the drilling fluid and the tip, thus
preventing fracture extension. The radial distance from the wellbore that the
drilling fluid occupies in the fracture is defined as Rfluid. The thickness of the
filtercake that builds up between the drilling fluid and the beginning of the
fracture tip is defined as Rcake. The length of the filter tip, Rtip, is measured
from the end of Rcake to the outer edge of where the drilling fluid solids (black
particles) meet the formation. In a system using an OBM or SBM (bottom), an
internal filtercake allows for full pressure communication to the tip, which
facilitates fracture extension at lower propagation pressures than with a
WBM. Rfluid is defined in the same manner as in a WBM technique.
Rtip is the distance between Rfluid and the length of the filter tip, which
also incorporates the drilling fluid solids. (Adapted from van Oort et al,
reference 10.)
Lost Circulation
Figure 8_3
10.van Oort E, Friedheim J, Pierce T and Lee J: “Avoiding
Losses in Depleted and Weak Zones by Constantly
Strengthening Wellbores,” paper SPE 125093, presented
at the SPE Annual Technical Conference and Exhibition,
New Orleans, October 4–7, 2009.
11.Growcock F, Kaageson-Loe N, Friedheim J, Sanders M
and Bruton J: “Wellbore Stability, Stabilization and
Strengthening,” presented at the Offshore
Mediterranean Conference and Exhibition, Ravenna,
Italy, March 25–27, 2009.
12.Filtercake is the solid residue deposited on the
wellbore when the drilling mud slurry is forced against
it under pressure, which occurs during an
overbalanced drilling condition.
Winter 2011/2012
13.Stuck pipe occurs when the drillpipe is not free to move
up, to move down or rotate as needed in the wellbore.
Seepage losses increase the risk of differential sticking
by generating thicker filtercakes on the wellbore wall,
which increases the contact area between the drillpipe
and wellbore.
14.Morita N, Black AD and Fuh G-F: “Theory of Lost
Circulation Pressure,” paper SPE 20409, presented at
the SPE Annual Technical Conference and Exhibition,
New Orleans, September 23–26, 1990.
van Oort et al, reference 10.
15.Aston MS, Alberty MW, McLean MR, de Jong HJ and
Armagost K: “Drilling Fluids for Wellbore Strengthening,”
paper IADC/SPE 87130, presented at the IADC/SPE
Drilling Conference, Dallas, March 2–4, 2004.
16.Dupriest F: “Fracture Closure Stress (FCS) and Lost
Returns Practices,” paper SPE/IADC 92192, presented
at the SPE/IADC Drilling Conference, Amsterdam,
February 23–25, 2005.
17.Benaissa S, Bachelot A and Ong S: “Preventing Mud
Losses and Differential Sticking by Altering Effective
Stress of Depleted Sands,” paper IADC/SPE 103816,
presented at the IADC/SPE Asia Pacific Drilling
Technology Conference and Exhibition, Bangkok,
Thailand, November 13–15, 2006.
18.van Oort et al, reference 10.
19.Morita et al, reference 14.
20.van Oort et al, reference 10.
31
If a WBM is used, the growth of the fracture
leads to a dehydrated cake, or plug, of LCM that
isolates the fracture tip and curtails further
growth. The use of LCM in a WBM generally
causes elevated fracture propagation pressures;
the fracture continues to grow only if the mud
pressure is high enough to puncture the LCM barrier and reach the fracture tip again. However,
once this occurs and fracture propagation begins
anew, additional LCM begins collecting at the tip
until it is sealed again.
Nonaqueous fluids (NAFs), a collective term
for OBMs and SBMs, use the emulsified aqueous
fluid to penetrate the permeable rock and create
a very tight and ultrathin filtercake that is internal to the fracture wall. When a fracture propagates in the presence of an NAF, the invert
emulsion quickly seals off fracture faces, which
limits fluid loss into the formation. Consequently,
very little solid material is deposited in the fracture, and a coherent barrier of LCM or mudcake
is not built. For NAFs, the result is that the pressure near the fracture tip is close to that in the
wellbore, whereas for WBMs, the pressure near
the fracture tip drops significantly. As a consequence, fracture propagation occurs less readily
for WBMs than for NAFs, so that the effective
FG for WBMs is greater than for NAFs. This
translates to narrower drilling margins for an
NAF than for a WBM, which may present significant challenges when constructing wells with
low drilling margins.
The DEA-13 project also revealed that the
composition and size distribution of particulates
in the fluid were critically important to the success of FPR. Laboratory research conducted outside of the DEA-13 project resulted in the
development of a specialized WSM known as a
loss prevention material (LPM) that inhibited
fracture tip growth.21
This research showed that the LPM must be
present in the mud at all times during drilling
because FPR is a continuous, preventive treatment method. The findings also suggested that
LPM should be present at a size distribution of
between 250 and 600 microns [60 to 30 mesh],
although subsequent work by Shell—a proponent of the FPR method—suggests that size distribution should be a function of the type of
formation to be strengthened.22
Shale shakers
Flow
line
Screw conveyor
Effl
uen
t
To a
ctiv
ent
fflu
E
ove
Rec
MPSRS
unit
Coarse cuttings
disposal
ste
m
ry
Effl
Cuttings dryer
e sy
uen
t
Centrifuge
Fine cuttings
disposal
> WSM recovery. The process to recover WSM for subsequent reuse begins with a flowline that collects drilling fluid solids (including cuttings and WSMs
originally pumped downhole for wellbore strengthening) from the wellbore and passes them through shale shakers, which remove very large particles. The
remaining fluid and particles (red arrows) are then passed through a screw conveyor and cuttings dryer to remove residual cuttings from the drilling fluid.
The fluid then passes through the MPSRS Managed Particle Size Recovery System unit, which further separates the WSM from smaller drill cuttings. A
centrifuge conducts the last separation process, removing the very smallest drill cuttings from the WSM (blue arrow). The effluent, or WSM, from the shale
shakers, MPSRS unit and centrifuge are sent back to the active system for reintroduction into the wellbore.
32
Oilfield Review
The types of WSM deemed most effective in
consistently sealing a fracture and minimizing
leakoff through the fracture tip include synthetic
graphite, ground nut hulls and oil-dispersible
cellulose particles. Blends of these materials in
various ratios have demonstrated synergistic
performance benefits in both laboratory and field
trials. These materials must be present in the mud
at concentrations ranging from 43 to 57 kg/m3
[15 to 20 lbm/bbl] and are continuously recycled
and reintroduced to the wellbore to ensure continuous protection as new sections are drilled.
Field trials have demonstrated the importance of maintaining both the concentration
and size distribution of WSM in the mud.23 This
need led to the development of in-field WSM
recycling equipment, such as the MPSRS
Managed Particle Size Recovery System technology. The system removes drill cuttings and
low-gravity solids that may negatively impact
mud rheology and ECD while recovering WSM in
the appropriate size ranges for raising the FPR
(previous page).24
Shell introduced the FPR concept with the
MPSRS technology in 2006 in Gulf of Mexico subsea wells. Lost circulation’s contribution to NPT
diminished significantly in these wells over a
four-year period (right). This is in contrast to
alternative drill cuttings removal systems that
are composed of shakers with three levels that
are configured in series. Cuttings are removed
from the top level (fitted with the coarsest
screens), fines are removed from the bottom
level (with the finest screens) and most of the
coarse, relatively undegraded WSM is trapped on
the middle level and shunted back into the
active system.25
Hoop stress enhancement: The stress cage
concept—A second wellbore strengthening
model, the stress cage theory, proposes that the
hoop stresses at the edge of the wellbore may be
increased by adding a suitable WSM to the drilling fluid. A drilling mud pretreated with WSM
circulates in an overbalanced state to induce
shallow fractures in the near-wellbore region.
These newly created fractures act to compress the wellbore, generating an additional hoop
stress, or stress cage. The WSM-laden mud enters
these shallow fractures, and the sized WSM particles begin to collect and bridge close to the
wellbore face. Additional buildup of WSM forms a
hydraulic seal near each fracture mouth; as a
result, no additional mud can enter from the
wellbore, and the fluid within the fracture leaks
off into the formation.
Winter 2011/2012
2006
NPT rank 3
2007
4%
12%
88%
96%
2008
2009
NPT rank 18
1%
99%
1%
99%
Lost circulation NPT
Other NPT
> NPT attributed to lost circulation. After Shell introduced the FPR mechanism
and MPSRS equipment in the third quarter of 2006, lost circulation’s
contribution to NPT dropped significantly, from 12% at the onset of the
wellbore strengthening strategy to 1% in 2009. Lost circulation fell significantly
as a major trouble category in a Shell NPT ranking, from rank 3 to rank 18.
(Adapted from van Oort et al, reference 10.)
Tehrani A, Friedheim J, Cameron J and Reid B:
Lost Circulation
“Designing Fluids for Wellbore Strengthening—Is It an
Figure 10_2
Art?” paper AADE-07-NTCE-75, presented at the AADE
21.Fuh G-F, Morita N, Boyd PA and McGoffin SJ: “A New
Approach to Preventing Lost Circulation While Drilling,”
paper SPE 24599, presented at the SPE Annual Technical
Conference and Exhibition, Washington, DC,
October 4–7, 1992.
22.van Oort et al, reference 10.
23.Sanders MW, Young S and Friedheim J: “Development
and Testing of Novel Additives for Improved Wellbore
Stability and Reduced Losses,” paper AADE-08-DFHO-19, presented at the AADE Fluids Technical
Conference and Exhibition, Houston, April 8–9, 2008.
Friedheim J, Sanders MW and Roberts N: “Unique
Drilling Fluids Additives for Improved Wellbore Stability
and Reduced Losses,” presented at the Seminario
Internacional de Fluidos de Perforación, Completación y
Cementación de Pozos (SEFLU CEMPO) Conference,
Margarita Island, Venezuela, May 19–23, 2008.
National Technical Conference and Exhibition, Houston,
April 10–12, 2007.
24.van Oort E, Browning T, Butler F, Lee J and Friedheim J:
“Enhanced Lost Circulation Control Through Continuous
Graphite Recovery,” paper AADE-07-NTCE-24, presented
at the AADE National Technical Conference and
Exhibition, Houston, April 10–12, 2007.
Butler F and Browning T: “Recovery System,” US Patent
No. 7,438,142 (October 21, 2008).
25.Growcock F, Alba A, Miller M, Asko A and White K:
“Drilling Fluid Maintenance During Continuous Wellbore
Strengthening Treatment,” paper AADE-10-DF-HO-44,
presented at the AADE Fluids Conference and Exhibition,
Houston, April 6–7, 2010.
33
This leakoff lowers the hydraulic pressure
within the fracture, causing it to begin to close.
However, the presence of the WSM bridge,
wedged at the fracture mouth, prevents total closure and maintains a degree of additional hoop
stress. The presence of one or more of these
propped fractures increases the hoop stress, and
thus a higher wellbore pressure is needed to
extend or create additional fractures (below).
Industry research suggests that for this mechanism to be successful, high concentrations of
bridging additives are required; they must be
strong enough to resist closure stresses and they
have to be appropriately sized to bridge near the
fracture mouth rather than deeper into the fracture. They must also create an impermeable
bridge so that leakoff through the bridge is minimized, allowing the pressure within the fracture
to drop. Materials such as graphitic blends, marble, nut husks and ground petroleum coke work
Wellbore
Ppore
Ptip
well, just as with the FPR mechanism. For a fracture opening of 1 mm [0.04 in.], a particle size
distribution ranging from colloidal clays up to
values approaching 1 mm has been suggested.26
Historically, the WSM was applied as a dedicated squeeze in pill form—a relatively small
volume (less than 32 m3 [200 bbl]) of fluid added
to the wellbore at one time. However, the WSM
has been continuously applied to the whole mud
when field engineering and logistics permitted it.
Stress cage treatments typically require at least
25 kg/m3 [9 lbm/bbl] of WSM in the mud. A solidsrecovery system, such as a three-level shaker system configured in series, may be used to scalp the
cuttings and remove the fines while capturing
WSM-sized particulates for routing back to the
active system. Shakers fitted with coarse (10- to
20-mesh) screens alone may suffice, although
these would remove only cuttings and leave WSM
and drilled fines in the mud. The buildup of fines
Pmud
Fracture
Pmud = Mud pressure
Ptip = Pressure at fracture tip
Ppore = Pore pressure
For stability, Ptip ~ Ppore < Pmud
> Stress cage concept. In this wellbore strengthening strategy, a fracture is
formed and quickly sealed by WSMs (small brown circles) that bridge and
seal the fracture mouth. This seal forms a compressive stress, or stress cage,
in the adjacent rock, which effectively strengthens the wellbore. For fracture
stability to be realized, Ptip—which is, in practical terms, equivalent to Ppore—
must be less than Pmud, which is isolated behind the WSM seal.
26.Aston et al, reference 15.
27.Dupriest, reference 16.
28.M-I SWACO Technical Service Group: “Chapter 7:
Wellbore Strengthening Solutions,” Houston:
M-I SWACO, Prevention and Control of Lost Circulation
(March 17, 2011): 7:1–7.
29.Benaissa et al, reference 17.
30.Karimi M, Moellendick E and Holt C: “Plastering Effect
of Casing Drilling; a Qualitative Analysis of Pipe Size
Contribution,” paper SPE 147102, presented at the
SPE Annual Technical Conference and Exhibition,
Denver, October 30–November 2, 2011.
34
31.For more information: Lund JW: “Characteristics,
Development and Utilization of Geothermal Resources,”
Geo-Heat Center Quarterly Bulletin 28, no. 2 (June 2007),
http://geoheat.oit.edu/bulletin/bull28-2/bull28-2-all.pdf
(accessed October 15, 2011).
Beasley C, du Castel B, Zimmerman T, Lestz R,
Yoshioka K, Long A, Lutz SJ, Riedel K, Sheppard M
and Sood S: “Mining Heat,” Oilfield Review 21, no. 4
(Winter 2009/2010): 4–13.
32.For more information: Oliver JE: “New Completion
System Eliminates Remedial Squeeze Cementing for
Zone Isolation,” paper SPE 9709, presented at the SPE
Permian Basin Oil and Gas Recovery Symposium of the
SPE of the AIME, Midland, Texas, March 12–13, 1981.
might be tolerable, particularly for strengthening
short intervals drilled with solids-tolerant NAF,
but removing all unnecessary solids is considered
best practice.
Fracture closure stress—A third wellbore
strengthening model, fracture closure stress
(FCS), was developed in the mid-1990s and is still
widely applied in the industry.27 This method has
some similarities to the stress cage concept, particularly in how WSM is theorized to plug and
wedge open fractures to increase hoop stress near
the wellbore and arrest fracture propagation.
However, unlike stress caging—which initiates fractures before quickly stopping their
growth—FCS is a high-fluid-loss treatment for
existing fractures. While the WSM in this method
may be applied as a whole mud treatment, it is
commonly applied via high-fluid-loss pills.
FCS theory holds that an effective treatment
must isolate the fracture tip. Scientists believe
this occurs because of rapid drainage of carrier
fluid from the mud mixture as the particles are
compressed and agglomerate during the squeeze
phase and then form a plug in the fracture. The
plug quickly becomes immobile and cuts off communication between the fracture tip and the
wellbore, thus preventing transmission of pressure to the tip and halting fracture propagation,
allowing an increase in the wellbore pressure and
a consequent increase in fracture width.
As a result, it is important that the particles
are able to deform, or be crushed, during the
application of a squeeze treatment. The ideal
WSM should be composed of relatively large particles of similar size and considerable roughness
that do not pack well; examples include diatomaceous earth and barite.28 Often, more than one
FCS treatment is required.
The FCS theory holds that the particulate
plug can manifest anywhere in the fracture, not
only near the mouth as in stress caging. For this
mechanism, although compressive strength of
the WSM is not important, high fluid loss is critical because it accelerates formation of the immobilized plug. Alternatively, leakoff of filtrate may
occur through generation of microfractures or
extension of the existing fracture, thus permitting deliquefication of the WSM and formation of
a plug before the onset of whole mud loss.
Wellbore isolation—As a fourth wellbore
strengthening strategy, various methods have
been proposed to isolate a wellbore while drilling
to seal off the formation in a manner similar
to protecting a wellbore with casing.29 In
some cases, the WSMs for this application are
flexible fluid-loss control materials that have the
Oilfield Review
capability of penetrating or sealing the rock. The
concept involves reducing the permeability of the
rock to near zero by plastering the rock with a
material of equal or greater tensile strength.
Various low-fluid-loss materials have been
implemented to achieve this effect, which essentially attempts to build a cement-like sheath on
the wellbore surface. Such a barrier serves to isolate the wellbore from both fluid invasion and
wellbore pressure. Advances in mud chemistry
have developed micro- and nanoparticulates that
may reduce permeability to a negligible level, but
isolation of wellbore pressure remains an elusive
goal. The smear effect, which is thought to occur
during casing or liner drilling operations, may be
considered an example of wellbore isolation
because fines are thought to be plastered onto
the wellbore walls to create a tight barrier to
fluid invasion.30
Some wellbore strengthening techniques defy
easy classification. An example is the Losseal lost
circulation treatment, an engineered pill that
blends a flexible fiber with a firm fiber to synergistically bridge fractures and stop fluid loss.
Theoretically, the treatment creates an
impermeable grid that prevents fluid from entering the fracture; it is strong enough to withstand
additional pressure buildup caused by increasing
mud density. The pill can be pumped through a
bottomhole assembly or open-ended drillpipe
and is applicable in wellbores affected by natural
fractures, depleted reservoirs and drillinginduced lost circulation zones. The Losseal solution has also been applied to
lost circulation scenarios outside of the oil and
gas industry. Enel Green Power recently used the
system to solve a lost circulation problem while
drilling a geothermal well in Italy. To extract
energy from a geothermal well, the operator drills
into high-temperature subsurface zones and
injects water, which is heated and pumped back
to surface, where it is used to provide a source for
home heating or, at higher temperatures, electricity generation for industrial applications.31
Geothermal wells drilled previously in the
same area passed through a shale section at shallow depths, followed by a limestone formation
where fluid losses ranged from 10 m3/h [63 bbl/h]
to total loss of fluid.
Historically, lost circulation solutions in these
wells included a remedial squeeze cement job to
achieve vertical isolation of a completion interval. For the newest well, the operator wished to
avoid the additional cost and time associated
with a squeeze job. Additionally, in some
instances, squeeze jobs had created formation
damage that impaired productivity.32
Winter 2011/2012
Category
Fracture Propagation
Resistance
Stress Cage
Fracture Closure
Stress
Continuous in mud
Continuous in mud or
pill squeeze
Continuous in mud
or pill squeeze
Formation or closure stress applied?
No
No
Yes
Fracture tip isolation required?
Yes
No
Yes
High fluid loss required?
No
No
Yes
WSM particle strength
Unimportant
Somewhat important
Unimportant
WSM particle size
Important
Important
Unimportant
WSM particle type
Important
Important
Unimportant
Application technique
> Differences among wellbore strengthening techniques. A comparison of the tenets of wellbore
strengthening techniques reveals some fundamental differences.
The operator pumped a 32-m3 [200-bbl]
Losseal pill to the lost circulation zone and monitored the pressure in the wellbore as a function
of time. While the pressure initially increased by
as much as 200 psi [1.4 MPa] during the pill’s
movement through the wellbore, a sudden drop
in pressure indicated that the Losseal pill
reached the fractures and plugged them. The
liner was then run to total depth and cemented in
one stage using conventional completion techniques. No fluid losses were recorded during this
operation, and the pressure reached closely
matched what modeling had predicted.
By implementing the single-stage cement job
and improving well integrity, the company was
able to avoid a cement squeeze job, thus saving
three days of rig time. The improved zonal isolation and casing protection afforded by having the
entire string encased in cement are expected to
increase the productive life of the well.
the best laboratory-based fracture modeling
method that would yield reproducible data. The
resulting fracture model was tested with a device
used to screen LCM candidates for wellbore
strengthening. Acceptable WSMs identified by
this method included marble, graphite, ground
petroleum coke, nut husks and proprietary cellulosic blends.
A second JIP, conducted from 2007 to 2010,
included several additional operators and
focused on clarifying, through laboratory testing,
the fundamental differences among the various
wellbore strengthening theories. Research priorities included comparing sealing at the fracture
mouth—hoop stress enhancement—versus sealing throughout the fracture (FPR), matching
LCM size distribution in relation to fracture
width and investigating LCM performance as a
function of material type and concentration.
A third industry project, the Research
Cooperative Agreement III, began in December
2010 with a focus on developing lost circulation
Investigating Mechanisms
Lost Circulation
Fundamental differences exist among the proTablesolutions
1_3 for extreme downhole conditions and
posed wellbore strengthening mechanisms for wells in high-value plays.
Numerous operators working in concert have
(above). Because it is impossible to see what
takes place in a fracture during a wellbore committed resources to research projects
strengthening treatment, the industry has not dedicated to finding solutions to lost circulation;
reached a clear consensus on the exact mecha- wellbore strengthening is the focus of that
research. As the industry attempts to feed the
nism at work.
This lack of industrywide agreement has growing global appetite for energy from increasspurred a series of JIPs designed to study the fun- ingly expensive and unconventional hydrocarbon
damentals of fracture sealing, develop product resources, it will likely rely on wellbore strengthsolutions and set industry standards for wellbore ening solutions to help operators drill wells
more efficiently. —TM
strengthening investigations.
The initial JIPs were hosted by Shell E&P
Company, but now are being led by M-I SWACO, a
Schlumberger company. M-I SWACO conducted
the first JIP from 2004 to 2006 and counted Shell,
BP, ConocoPhillips, Chevron and Statoil among
its members. The JIP was designed to first define
35
The Best of Both Worlds—A Hybrid Rotary
Steerable System
Edwin Felczak
Ariel Torre
Oklahoma City, Oklahoma, USA
Neil D. Godwin
Kate Mantle
Sivaraman Naganathan
Stonehouse, England
The transition from vertical to horizontal drilling has been spurred by evolving
Richard Hawkins
Ke Li
Sugar Land, Texas, USA
technology that led the industry away from a dependency on conventional bottomhole
assemblies and whipstocks and toward mud motors and rotary steerable systems.
The latest innovation is a hybrid design that combines the performance capabilities of
Stephen Jones
Katy, Texas
a rotary steerable system with the high build rates of a positive displacement motor.
Fred Slayden
Houston, Texas
Oilfield Review Winter 2011/2012: 23, no. 4.
Copyright © 2012 Schlumberger.
For help in preparation of this article, thanks to Elizabeth
Hutton and Emmanuelle Regrain, Houston; and Edward
Parkin, Stonehouse, England.
DOX, Drilling Office, IDEAS, PERFORM Toolkit, PowerDrive
Archer, PowerDrive X5 and PowerPak are marks of
Schlumberger.
The shortest distance between two points is a
straight line. However, it may not be the fastest,
or most economical, when it comes to directional
drilling. E&P companies increasingly turn to
complex well trajectories to hit distant targets,
Kickoff p
oint
Kickoff
intersect fractures, penetrate multiple fault
blocks or reach deep into a reservoir. Although
more difficult to drill than other profiles, these
well paths often improve drainage efficiency by
increasing wellbore exposure to the pay zone.
PowerDrive
A
Positive di rcher rotary steerabl
splacemen
e system
t motor
Conventio
nal rotary
steerable
system
point
Landing
point
TD
Landing
36
point
TD
Oilfield Review
Complex horizontal and extended-reach trajectories are just the current apex in the evolution of directional drilling. The first nonvertical
wells were not intentionally drilled that way, but
by the late 1920s, drillers began to figure out how
to point a wellbore in a particular direction.
Since then, directional drilling technology has
progressed beyond a reliance on basic bottomhole assemblies for influencing the course a bit
might take, to using surface-controlled rotary
steerable systems that precisely guide the bit to
its ultimate destination. During the past decade,
the development of new drilling technologies has
continued to gain momentum.
This article describes advances that led to the
development of rotary steerable systems and
focuses on one of the latest steps in their evolution:
the PowerDrive Archer rotary steerable system.
This hybrid system produces the high build rate of a
positive displacement motor with the rapid rate of
penetration of a rotary steerable system.
A Brief History
The intentional deviation of wellbores came into
practice during the late 1920s as operators sought
to sidetrack around obstructions, drill relief wells
and avoid surface cultural features; directional
drilling techniques were even employed to keep
vertical holes from turning crooked.
In part, the ability to drill deviated wells
arose from the development of rotary drilling and
roller cone bits. The design of these bits causes
them to drift laterally, or walk, in response to
various formation and drilling parameters such
as formation dip and hardness, rotary speed,
weight on bit and cone design. In some regions,
experienced drillers recognized the natural tendency of a bit to walk in a somewhat predictable
manner. They would frequently try to build a certain amount of lead angle to compensate for
anticipated drift between the surface location
and bottomhole target (below left).
Drillers also found that modifications to the
rotary bottomhole assembly (BHA) could change
a drillstring’s angle of inclination. By varying
stabilizer placement, drillers could affect the
balance of the BHA, prompting it to increase,
maintain or decrease wellbore inclination from
vertical, commonly referred to as building, holding or dropping angle, respectively. The rate at
which a rotary BHA builds or drops angle is
affected by variables such as distance between
stabilizers, drill collar diameter and stiffness, formation dip, rotary speed, weight on bit, formation
hardness and bit type. The ability to balance the
BHA against these factors can be crucial for
reaching a planned target.
A BHA configured with a near-bit stabilizer
beneath several drill collars will tend to build
angle when weight is applied to the bit (below).
In this configuration, the collars above the stabilizer will bend, while the near-bit stabilizer acts
as a fulcrum, pushing the bit toward the high side
Fulcrum (Angle-Building) Assembly
Bit
First string stabilizer
Drill collar
Near-bit stabilizer
Pendulum (Angle-Dropping) Assembly
Second string stabilizer
First string stabilizer
Packed (Angle-Holding) Assembly
Second string stabilizer
Surface location
N
Lead angle
First string stabilizer
Fulcrum assembly
Pendulum assembly
Stabilizer
°E
S 20
Lead line
Target azimuth
Near-bit stabilizer
Target
> Lead angle, plan view. Rotary cone bits tend to
walk to the right. Knowing this, drillers sometimes
used a lead angle to orient the wellbore to the left
of the target azimuth.
Winter 2011/2012
Near-bit stabilizers
ing
ild e
Bu angl
g
pin
op gle
r
D an
> Using a BHA to change inclination. By strategic placement of drill collars
and stabilizers in the BHA, directional drillers can increase or decrease
flexibility, or bowing, of the BHA. They use this flexibility to their advantage as
they seek to build, drop or hold angle. A fulcrum assembly (upper frame, top)
uses a full gauge near-bit stabilizer and sometimes a string stabilizer. Bowing
of the drill collars above the near-bit stabilizer tilts the bit upward to build
angle (lower frame, left). A pendulum assembly (upper frame, middle) has
one or more string stabilizers. The first string stabilizer acts as a pivot point
that lets the BHA bow beneath it, thus dropping angle (lower frame, right). A
packed assembly uses one or two near-bit stabilizers and string stabilizers to
stiffen the BHA (upper frame, bottom). By reducing the tendency to bow, the
packed assembly is used to hold angle.
37
Casing
Cement
New borehole
Whipstock
Watermelon
mill
Window mill
Cement plug
> Cased hole whipstock. This cylindrical steel
ramp (green) is run in the hole to a predetermined
kickoff depth and oriented azimuthally. A window
mill opens a hole in the casing, which is dressed
by the watermelon mill. This assembly is then
pulled and replaced by a drilling BHA.
of the borehole. Another type of BHA is used to
drop angle. This variation uses one or more stabilizers; the collars below the lowest stabilizer in
the BHA act as a pendulum, which allows gravity
to pull the bit toward the low side of the borehole. Upon reaching the desired angle, the driller
may use a different BHA to hold angle. The
packed BHA utilizes multiple stabilizers, spaced
along its length, to increase stiffness.
Drillers employ other mechanical means to
help divert a well from its vertical path, most
notably the whipstock. Simple in principle, this
long steel ramp is concave on one side to hold
and guide the drilling assembly. Used in either
open or cased holes, the whipstock is positioned
at the desired depth, oriented to the desired azimuth, then anchored in place to provide a guide
to initiate, or kick off, a new well path (above).
While early techniques allowed some degree of
control over wellbore inclination, they provided little
azimuthal control. They were also inefficient, requiring multiple trips in and out of the hole to install a
whipstock or to change BHA configurations.
The early 1960s witnessed a significant change
in directional drilling when a BHA with a fixed
bend of approximately 0.5° was paired with a
downhole motor to power the drill bit.1 Drilling
mud supplied hydraulic power to a motor that
38
turned the bit.2 The motor and bent sub offered
much greater directional control than was possible with earlier BHAs, while significantly increasing the angle of curvature that a driller was able
to build. Early assemblies had fixed tilt angles
and required a trip out of the hole to adjust the
angle of inclination.
These steerable motors operate on the tiltangle principle. The bent sub provides the bit
offset needed to initiate and maintain changes in
course direction. Three geometric contact
points—the bit, a near-bit stabilizer on the motor
and a stabilizer above the motor—approximate
an arc that the well path will follow.3
Some motors use a downhole turbine; others
use a helical rotor and stator combination to
form a positive displacement motor (PDM). The
basic PDM with bent sub has evolved, leading to
the development of a steerable motor. Modern
steerable motor assemblies still use PDMs, but
include surface-adjustable bent housings (below
right). A typical steerable motor has a powergenerating section, through which drilling fluid is
pumped to turn a rotor that turns a drive shaft
and bit. The surface-adjustable bend can be set
between 0° and 4° to point the bit at an angle
that differs only slightly from the axis of the wellbore; this seemingly minor deflection is critical
to the rate at which the driller can build angle.
The amount of wellbore curvature imparted by
the bent section depends, in part, on its angle,
the OD and length of the motor, stabilizer placement and the size of drill collars relative to the
diameter of the hole.
Steerable motors drill in either of two modes:
rotary mode and oriented, or sliding, mode. In
rotary mode, the drilling rig’s rotary table or its
topdrive rotates the entire drillstring to transmit
power to the bit. During sliding mode, the drillstring does not rotate; instead, mud flow is
diverted to the downhole motor to power the bit.
Only the bit rotates in sliding mode—the nonrotating portion of the drillstring simply follows
along behind the steering assembly.
Different motors may be selected on the basis
of their ability to build, hold or drop angle during
rotary mode drilling. Conventional practice is to
drill in rotary mode at a low number of revolutions per minute (RPM), rotating the drillstring
from the surface and causing the bend to point
equally in all directions, thereby drilling a
straight path. Inclination and azimuth measurements can be obtained in real time by measurement-while-drilling (MWD) tools to alert the
driller to any deviations from the intended
course. To correct for those deviations, the driller
must switch from rotary to sliding mode to
change wellbore trajectory.
The sliding mode is initiated by halting rotation of the drillstring so the directional driller can
orient the bend in the downhole motor to point in
the direction, or toolface angle, of the desired trajectory. This is no small task, given the torsional
forces that can cause the drillstring to behave like
a coiled spring.4 After accounting for bit torque,
drillstring windup and contact friction, the driller
must rotate the drillstring in small increments
from the surface while using MWD measurements
as a reference for toolface direction. Because a
drillstring can absorb torque over long intervals,
this process may require several rotations at the
surface to turn the tool just once downhole. When
the proper toolface orientation is confirmed, the
driller activates the downhole motor to commence drilling in the prescribed direction. This
process may need to be repeated several times
during the course of drilling because reactive
torque that is generated as the bit cuts into the
rock may force reorientation of the toolface.
Power section
Surface-adjustable
bent housing
Stabilizer
Bit
> Positive displacement motor. Downhole
motors, such as this PowerPak steerable motor,
provide much more directional control than
conventional BHAs.
Oilfield Review
Each mode brings distinct challenges. In
rotating mode, the bend in the drilling assembly
causes the bit to rotate off-center from the BHA
axis, resulting in a slightly enlarged and spiralshaped borehole. This gives the wellbore rough
sides that increase torque and drag and may
cause problems while running in the hole with
completion equipment—especially through long
lateral sections. Spiral boreholes may also affect
logging tool response.
In sliding mode, the lack of rotation introduces other difficulties. Where the drillstring
lies on the low side of the borehole, drilling fluid
flows unevenly around the pipe and impairs the
mud’s capacity to remove cuttings. This, in turn,
may result in the formation of a cuttings bed, or
a buildup of cuttings on the low side of the hole,
which increases the risk of stuck pipe. Sliding
also decreases the horsepower available to turn
the bit, which, combined with sliding friction,
decreases the rate of penetration (ROP) and
increases the likelihood of differential sticking.
In extended-reach trajectories, frictional
forces may build until there is insufficient axial
weight to overcome the drag imposed by drillpipe against the wellbore. This makes further
drilling impossible and leaves some targets out of
reach. Additionally, switching between sliding
and rotating modes can create undulations or
doglegs that increase wellbore tortuosity, thus
increasing friction while drilling and running
casing or completion equipment.5 These undulations may also create low spots, or sumps, where
fluid and debris collect, impeding flow after the
well is completed.
A number of these problems were addressed
in the late 1990s with the development of a rotary
steerable system (RSS). The single most important aspect of the RSS is that it allows for
continuous rotation of the drillstring, thereby
1. McMillin K: “Rotary Steerable Systems Creating Niche in
Extended Reach Drilling,” Offshore 59, no. 2 (February
1999): 52, 124.
2. Unlike conventional rotary drilling techniques, in which
rotation of the entire drillstring is required to drive the bit,
the drillstring does not rotate when a mud motor is
employed. Instead, the mud motor relies on hydraulic
power supplied through the circulation of drilling mud to
turn a shaft that drives the bit.
3. Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P:
“Extended-Reach Drilling: Breaking the 10-km Barrier,”
Oilfield Review 9, no. 4 (Winter 1997): 32–47.
4. Downton G, Hendricks A, Klausen TS and Pafitis D:
“New Directions in Rotary Steerable Drilling,”
Oilfield Review 12, no. 1 (Spring 2000): 18–29.
5. A dogleg is an abrupt turn, bend or change of direction
in a wellbore.
6. Schaaf S, Pafitis D and Guichemerre E: “Application of
a Point the Bit Rotary Steerable System in Directional
Drilling Prototype Wellbore Profiles,” paper SPE 62519,
presented at the SPE/AAPG Western Regional Meeting,
Long Beach, California, USA, June 19–23, 2000.
Winter 2011/2012
> Comparison of borehole quality. Caliper displays show how a positive
displacement motor created a spiralled borehole (top), while the rotary
steerable system drilled a much smoother bore (bottom).
eliminating the need to slide while drilling directionally. RSS tools provide a nearly instantaneous
response to commands from the surface when
the driller needs to change downhole trajectory.
Early on, these systems were utilized primarily to
drill extended-reach trajectories, in which the
ability to slide steerable motors had been limited
by hole drag. These jobs often resulted in
improved ROPs and hole quality over previous
systems (above). Today, the RSS is widely used for
its performance drilling, hole cleaning and accurate geosteering capabilities.
Revolutionary Steerables
Rotary steerable systems have evolved considerably since their introduction. Early versions utilized mud-actuated pads or stabilizers to cause
changes in direction—a design concept that continues to enjoy success to this day. With a dependence on contact with the borehole wall for
directional control, the performance of these
tools can sometimes be affected by borehole
washouts and rugosity. Later versions included
designs that relied once again on a bend to produce changes in toolface angle, thereby reducing
borehole environmental influences on tool performance.6 Thus, two steering concepts were
born: push-the-bit and point-the-bit.
The push-the-bit system pushes against the
borehole wall to steer the drillstring in the
desired direction. One version of this RSS uses a
bias unit with three actuator pads placed near
the bit to apply lateral force against the formation (below). To build angle, each mud-actuated
pad pushes against the low side of the hole as it
Extended pad
When pads push against
the high side, the bit
cuts toward the low side.
Control unit
Bias unit
Extended pad
Bit
Stabilizer
> Push-the-bit RSS. Pads extend dynamically from a rotating housing to create a side force directed
against the formation, which in turn, causes a change in the drilling direction.
39
rotary valve that opens and closes the mud supply to the pads in concert with the drillstring
rotation. The system synchronously modulates
the extension and contact pressure of the actuator pads as each pad passes a certain orientation
point. By applying hydraulic pressure each time
a pad passes a specific point, the pad forces the
drillstring away from that direction, thus moving
it in the desired direction.
A point-the-bit system uses an internal bend
to offset the alignment between tool axis and
borehole axis to produce a directional response.7
In a point-the-bit system, the bend is contained
within the collar of the tool, immediately above
the bit (left). Point-the-bit systems change well
trajectory by changing the toolface angle. The
trajectory changes in the direction of the bend.
This bend orientation is controlled by a servomotor that rotates at the same rate as the drillstring,
but counter to the drillstring rotation. This allows
the toolface orientation to remain geostationary,
or nonrotating, while the collar rotates.8
The latest development in the evolution of
these rotary steerables—the PowerDrive Archer
high-build-rate RSS—is a hybrid that combines
performance features of both push-the-bit and
point-the-bit systems (below).
Power-generating
turbine
Mud flow
Sensor package
and control system
Motor
Bit shaft
Bit
> Point-the-bit RSS. A bit shaft is oriented at an
offset angle to the axis of the tool. This offset
is held geostationary by a counter-rotating
servomotor.
rotates into position; to drop angle, each pad
pushes against the high side. Driller commands
sent downhole by mud pulse telemetry direct the
timing and magnitude of pad actuation. A control
unit positioned above the bias unit drives a
Internal universal joint
The Hybrid RSS
Until recently, RSS assemblies were unable
to deliver well profiles as complex as those
drilled by steerable motor systems. However, the
PowerDrive Archer rotary steerable system demonstrated its capability to attain high dogleg
severities (DLSs) while achieving ROPs typical of
rotary steerable systems.9 Just as important, it is
a fully rotating system—all external tool components rotate with the drillstring, enabling better
hole cleaning while reducing the risk of sticking.
Internal actuator pistons
Stabilizer
blades
Unlike some rotary steerables, the PowerDrive
Archer RSS does not rely on external moving
pads to push against the formation. Instead, four
actuator pistons within the drill collar push
against the inside of an articulated cylindrical
steering sleeve, which pivots on a universal joint
to point the bit in the desired direction. In addition, four stabilizer blades on the outer sleeve
above the universal joint provide side force to the
drill bit when they contact the borehole wall,
enabling this RSS to perform like a push-the-bit
system. Because its moving components are
internal—thus protected from interaction with
harsh drilling environments—this RSS has a
lower risk of tool malfunction or damage. This
design also helps extend RSS run life.
An internal valve, held geostationary with
respect to toolface, diverts a small percentage of
mud to the pistons. The mud actuates the pistons
that push against the steering sleeve. In neutral
mode, the mud valve rotates continuously, so bit
force is uniformly distributed along the borehole
wall, enabling the RSS to hold its course.10
Near-bit measurements, such as gamma ray,
inclination and azimuth, allow the operator to
closely monitor drilling progress. Current orientation and other operating parameters are
relayed to the operator through a control unit,
which sends this information uphole via continuous mud pulse telemetry. From the surface, the
directional driller sends commands downhole to
the control unit located above the steering unit.
These commands are translated into fluctuations
in mud flow rates. Each command has a unique
pattern of fluctuations that relate to discrete
points on a preset steering map, which has been
programmed into the tool prior to drilling.
Operators have been quick to capitalize on
the capabilities of the PowerDrive Archer steer-
Internal geostationary
rotary valve
Stabilizer blades
Control unit
Bias unit
Steering unit
> PowerDrive Archer rotary steerable system. This hybrid system combines actuator pads with an offset steering shaft—all located inside the drill collar for
protection from the downhole environment.
40
Oilfield Review
ing system. Because it can drill the vertical,
curved and horizontal sections, it can attain complex 3D trajectories and drill from one casing
shoe to the next in just one run.
Putting It to the Test
Until recently, steerable PDMs tended to dominate the realm of high-dogleg drilling projects.
Despite their directional capabilities, drilling
with PDMs may consume a lot of rig time. With
this approach, a conventional rotary BHA is typically used to drill the vertical section of the well.
Upon reaching the kickoff point (KOP), the
driller trips out of the hole to change the BHA. A
PDM is then installed, with a bent housing set to
the angle needed to drill the curve. After landing
the bit in the target formation, the driller again
trips out to dial down the angle of the adjustable
bent housing to a less aggressive build rate, then
trips back into the hole to drill the lateral section. This process results in a good deal of flat
time, in which the bit is not on bottom and not
actively drilling.
Using the PowerDrive Archer RSS, an operator can drill the vertical, curved and lateral sections with a single BHA, thereby increasing
drilling efficiency, ROP and borehole quality.
And by circumventing the practice of alternating
between sliding and rotating modes, drilling
with the RSS achieves lower borehole tortuosity,
drag and friction caused by poor hole quality.
This permits drilling of longer lateral sections
that reach farther into the reservoir.
The PowerDrive Archer RSS has been used in
a wide range of environments, onshore and off,
from the US to the Middle East and Australia. The
high-build-rate capabilities first demonstrated in
shale plays are now used to help drillers maintain
trajectories through problematic unconsolidated
formations. Throughout a variety of plays, operators are beginning to appreciate the flexibility in
designing and revising well trajectories that this
hybrid RSS affords.
One such play, the Marcellus Shale in the
Appalachian basin of North America, spans an
area estimated to be approximately 3.5 times
larger than that of the Barnett Shale, which has
proved to be one of the most prolific sources of
unconventional gas in the US. The Devonian-age
Marcellus Shale contains an estimated 363 Tcf
[10.3 trillion m3] of recoverable gas. Ultra
Petroleum Corporation is engaged in exploration
and development of this play.11
In the past, operators completed Marcellus
wells using vertical boreholes, which provided
comparatively little exposure of the source
rock to the wellbore. However, horizontal drilling
Winter 2011/2012
Kickoff po
int
Tan
gen
t se
ctio
n
Landing
point
in azimuth
nge
Cha
Reservoir
section
TD
> Three-dimensional trajectory. In this Marcellus Shale well, the operator used the PowerDrive Archer
RSS to kick off from vertical, drill a 3D curve with more than 100° change in azimuth, then hold the
tangent section. Uncertainty in the geologic model forced the operator to change the landing point by
more than 70 ft [21 m]. Once the geologic marker was identified, the RSS quickly built angle to 16°/100 ft
[16°/30 m] to reach the target, then the operator switched to a 2° build rate to a create a soft landing
within the reservoir section.
technology has significantly changed the economics of gas production in the Marcellus play,
with horizontal wells drilled from multiwell pads
and completed with multistage fracture stimulation of the lateral section. Operators frequently
used air to drill the vertical section, then
switched to mud drilling upon reaching the KOP.
After setting 9 5/8-in. casing, they kicked off an
8 3/4-in. hole, building angle with a PDM before
landing the well within the Marcellus interval. To
drill the curved and lateral sections, a PDM
might drill for 90% or more of the interval in sliding mode. This approach has several drawbacks,
including lower ROP, poor hole cleaning and tortuous well paths—and often required trips out of
the hole to adjust the bent housing when geologic
uncertainties forced well path corrections.
Drilling in this play can involve complex 3D
well profiles, high curvature rates and directionally challenging formation dips that affect DLS.
Ultra Petroleum recognized the potential for
such problems in a recent project and selected
the PowerDrive Archer RSS to meet these challenges, drill the wells quickly and place them in
the productive zones of the formation. In 2010,
Ultra began an aggressive drilling campaign,
having identified numerous targets within this
play. The company drilled the first Marcellus
well using a steerable PDM to establish a benchmark. The next 10 wells were drilled using the
PowerDrive Archer RSS. Some of these wells
were kicked off from vertical with a long turn in
azimuth of 90° or more to line up with the target
while simultaneously building angle at rates up
to 8°/100 ft [8°/30 m]. Geologic uncertainties
near the landing point sometimes called for corrective action, often requiring higher build
rates (above).
7.Bryan S, Cox J, Blackwell D, Slayden F and
Naganathan S: “High Dogleg Rotary Steerable System:
A Step Change in Drilling Process,” paper SPE 124498,
presented at the SPE Annual Technical Conference and
Exhibition, New Orleans, October 4–7, 2009.
8.Al-Yami HE, Kubaisi AA, Nawaz K, Awan A, Verma J and
Ganda S: “Powered Rotary Steerable Systems Offer
a Step Change in Drilling Performance,” paper
SPE 115491, presented at the SPE Asia Pacific Oil and
Gas Conference and Exhibition, Perth, Western
Australia, Australia, October 20–22, 2008.
9.A dogleg is typically quantified in terms of dogleg
severity, which is measured in degrees per unit of
distance.
10.Bryan et al, reference 7.
11.Auflick R, Slayden F and Naganathan S: “New
Technology Delivers Results in Unconventional Shale
Play,” presented at the Mediterranean Offshore
Conference and Exhibition, Alexandria, Egypt,
May 18–20, 2010.
41
0
Depth, ft
5,000
10,000
Plan
As drilled
15,000
20,000
0
20
40
60
Time, days
> Time versus depth curve. To drill the Kappus 1-22H well in the Woodford
Shale, Cimarex used the PowerDrive Archer system. The operator was able
to drill to TD in 49 days instead of 59, saving 10 days of drilling time against the
projected time frame.
into the target section, resulting in more than a
twofold increase in production rates.
A different resource play has been receiving
attention in central Oklahoma, USA, where
Cimarex Energy Company has been drilling the
With one exception, the wells drilled subsequent to the benchmark PDM well realized significant savings in rig time. In addition, all
completion strings were run without incident.
The hybrid RSS was also able to reach farther
ff point
Conventional kicko
jectory
Conventional tra
Archer
PowerDrive
kickoff point
PowerDrive
trajectory
Archer
> Shortened curve. The PowerDrive Archer RSS achieved an 11°/100 ft build rate that allowed the
operator to extend the vertical section of the trajectory while shortening the curve to reduce drilling
time and the amount of liner required.
42
Woodford Shale. Cimarex selected PathFinder, a
Schlumberger company, to utilize the PowerDrive
Archer RSS in drilling the curve section of the
company’s Kappus 1-22H well. Using this RSS to
drill the 8 3/4-in. hole with an 8°/100 ft build rate,
the operator achieved an 80% increase in ROP
over that of previous wells drilled with PDMs.
Having attained a smooth wellbore through the
curve, the operator was able to switch to a
PowerDrive X5 RSS, which drilled a 4,545-ft
[1,385-m] lateral section to TD in just one run. A
fast ROP through the curve, combined with high
build rate and smooth drilling operations in the
lateral section resulted in a savings of 10 drilling
days (left).
The high-build-rate capability of this hybrid
RSS makes for a shorter curved section, enabling
operators to design trajectories with deeper
KOPs. A deep KOP lets the operator expand the
length of the vertical section, which typically
drills faster than the curved section. An operator
in the Middle East used the PowerDrive Archer
RSS to drill an 8 1/2-in. curve section for 846 ft
[258 m] at a build rate of 7.6°/100 ft [7.6°/30 m].
After meeting the objectives for this well, the
operator selected the same system to drill a second well.
The second well required a more aggressive
build rate, but in carrying out this plan, the operator was able to boost overall ROP by drilling
through a longer vertical section before kicking
off, which enabled a rapid ROP through the vertical section. After drilling the 12 1/4-in. section, the
operator set casing and kicked off the 8 1/2-in. section. The hybrid RSS consistently maintained an
11°/100-ft [11°/30-m] DLS and drilled the 742-ft
[226-m] interval in a single run of 15 hours (left).
The well was landed within 1 ft [0.3 m] vertically
and 3.8 ft [1.2 m] laterally of its intended target.
Because the 8 1/2-in. section was shortened, the
operator also saved nearly 700 ft [210 m] of liner.
Pushing the kickoff point deeper sharpened the
curve, which reduced the amount of drilled footage needed to reach the reservoir and allowed
drilling engineers to consider downsizing the casing strings to achieve further savings.12
In northwest Arkansas, USA, SEECO, a
wholly owned subsidiary of Southwestern
Energy Company, tested the performance of the
PowerDrive Archer system as it drilled the vertical, curved and lateral sections of an Atoka
Formation well. The vertical section was drilled,
12.Eltayeb M, Heydari MR, Nasrumminallah M, Bugni M,
Edwards JE, Frigui M, Nadjeh I and Al Habsy H: “Drilling
Optimization Using New Directional Drilling Technology,”
paper SPE/IADC 148462, presented at the SPE/IADC
Middle East Drilling Technology Conference and
Exhibition, Muscat, Oman, October 24–26, 2011.
Oilfield Review
Planning for Success
The success of PowerDrive Archer steering technology can be attributed largely to extensive
planning, modeling and testing. BHA design and
modeling of bit and BHA response go into each
PowerDrive Archer job.
As a first step, Schlumberger drilling engineers obtain offset well information from the
operator and focus on drilling issues and bit performance data. Engineers use DOX Drilling Office
integrated software to design a trajectory to land
within the designated target zone while optimizing drilling efficiency. This software package
integrates trajectory design with drillstring specifications and BHA design, hydraulics, torque and
drag. The DOX software lets drilling engineers
quickly run multiple scenarios to optimize the
well path. A well plan and equipment plan are
then formulated to reach the given target, taking
into account known drilling issues. Anticollision
modeling ensures that the proposed trajectory
will avoid nearby wells.
Hole quality is a critical issue in high DLS or
extended-reach wells; poor hole quality may
impact the success of a well by hampering
efforts to deploy drilling and completion equipment through tight curves and may limit the
footage that can be drilled through the lateral
section. Extensive testing has played an important role in developing capabilities to deliver
high-quality boreholes. One such test involved a
series of blocks, each with a different compressive strength. These test blocks were arranged
side by side to form a rectangle nearly 45 m
[150 ft] long. The PowerDrive Archer RSS
drilled through the blocks using various combinations of bits and power settings to simulate
downhole drilling conditions. Once the holes
were drilled, a laser caliper measured the borehole gauge in each block and consistently found
no borehole rugosity (right).
2,000
True vertical depth, ft
then the well was kicked off along the planned
azimuth. The driller built angle at 10°/100 ft
[10°/30 m] DLS before making a soft landing at
the desired target point with an 88.2° inclination. Using an automated inclination hold feature, the RSS drilled ahead, with inclination
maintained within 0.5° of the planned trajectory. After drilling for about 1,000 ft [305 m], the
directional driller nudged the well path upward
to follow the general dip of the reservoir, with
the RSS building inclination up to 92° before an
unexpected fault created an abrupt lateral termination of the reservoir (right).
2,500
Original plan
As drilled
Revised plan
3,000
Pilot hole
0
500
1,000
1,500
2,000
2,500
3,000
Lateral section, ft
> Two-dimensional curve and lateral section. SEECO developed two drilling scenarios to accommodate
uncertainties in Atoka Formation dip. The actual well path (red) differs from the two planned
trajectories. Geosteering LWD sensors proved the dip to lie between those assumed in the two plans.
Faulting terminated the reservoir and shortened the lateral section considerably. (Adapted from Bryan
et al, reference 7.)
> Smooth drilling through test blocks. Laser calipers revealed no borehole rugosity in the borehole drilled
by the PowerDrive Archer RSS (bottom). (Photographs courtesy of Edward Parkin, Stonehouse, England.)
Winter 2011/2012
43
von Mises stress,
psi
1.184 × 105
1.036 × 105
8.880 × 104
7.400 × 104
5.920 × 104
4.440 × 104
2.960 × 104
1.480 × 104
1.257 × 104
Pin
Box
Pin
Box
> Tool joint stress contours. Drillstring tool joint
connections are subjected to a variety of loads
that affect the fatigue life of a tool. In particular,
tool joints are subjected to torque as they are
made up on the drill floor, when the pin is screwed
into the box (inset). This is followed later by
bending moments as the curve section is drilled.
Finite element analysis can be used to predict
stress along a threaded connection by accounting
for the torque and bending moments expected on
each job. This plot indicates higher von Mises
stress in the pin than in the box when the
threaded connection is made up and subjected to
a bending moment. This information is useful in
predicting the fatigue life of the connection.
Although modeling of BHA and bit response
has been notoriously difficult, recent advances
make it possible to analyze dynamic downhole
drilling conditions and compute drillstring
stresses. The forces generated by the bit and
their effects on BHA steering performance can
also be predicted. This is followed by laboratory
testing and, finally, field testing to deliver optimized BHA and bit designs.
13. The IDEAS program was developed in the 1990s by
Smith Bits, which was later acquired by Schlumberger.
For more on bit design using the IDEAS system:
Centala P, Challa V, Durairajan B, Meehan R, Paez L,
Partin U, Segal S, Wu S, Garrett I, Teggart B and
Tetley N: “Bit Design—Top to Bottom,”
Oilfield Review 23, no. 2 (Summer 2011): 4–17.
44
Schlumberger performed finite element analysis and bending moment modeling and analysis
on components of the PowerDrive Archer BHA
(left). Field testing validated BHA behavior to
ensure steerability at high build rates. After the
BHA design was finalized, engineers conducted
shock and vibration analysis to identify critical
resonance frequencies and RPMs to be avoided
while drilling. Torque and drag simulations for
drilling and tripping operations were run to
ensure BHA integrity. Hydraulics modeling was
also conducted across various mud weight and
flow ranges.
Drillbit technology is another factor that is
vital to the success of any well. The bit affects
drilling efficiency, or the ability to achieve and
maintain a high average ROP. Bit design also
impacts steerability, or the ability to place the
well in the right part of the reservoir. Push-thebit systems generally require an aggressive sidecutting bit for delivering doglegs, while
point-the-bit systems tend to rely on stabilization from a less aggressive bit with a longer side
gauge. With a hybrid system, using the right bit is
especially critical. For this RSS, engineers conducted extensive testing to characterize interactions between the bit, tools and formation to
best match the bit profile to the tools and maximize performance.
Bits for the PowerDrive Archer system can be
tailored to enhance steerability and deliver
improved ROP for a particular field. The IDEAS
integrated drillbit design platform lets drilling
engineers optimize bit selection based on modeling the drilling system overall.13 The IDEAS software accounts for a wide range of variables in its
bit design and BHA optimization packages:
•rock type and formation characteristics
•interaction between bit cutter surface and
rock face
•contact between drillstring and wellbore
•detailed bottomhole assembly design
•casing program
•well trajectory
•drilling parameters.
Modeling data were also used as input to a
fatigue management system that predicts fatigue
life for each component of the BHA. When subjected to rotation through high doglegs, BHAs
will experience large bending moments. Fatigue
life decreases exponentially with increasing
build rate and can reduce the life of standard
BHA components to a matter of hours. Fatigue
modeling and tracking is helping drillers avoid
twist offs and other catastrophic failures.
Schlumberger tracks fatigue life automatically to ensure integrity of BHA components.
With the aid of PERFORM Toolkit data optimization and analysis software, the wellsite engineer
can record RPM, ROP, DLS and other contributors to fatigue, providing real-time fatigue management information and predictions of fatigue
life. Monitoring fatigue life is not a trivial task:
The position of each component along the well
path must be tracked and the bending moment
caused by DLS—along with RPM and time—
needs to be quantified. Tracking fatigue in real
time, including time off-bottom rotating, can significantly improve the accuracy of the fatigue life
estimates. These fatigue data may be monitored
remotely at operations support centers, where
the data can be reviewed by drilling experts who
can advise operators when critical components
need to be replaced.
Advances in directional drilling technology
are helping operators access hydrocarbons that
could not otherwise be produced. The latest generation of rotary steerables is achieving well trajectories and step-outs that were previously
unimaginable, while delivering lower cost and
lower risk wells and improving production. These
increasingly complex well trajectories are spurring the industry to reach further in the search
—MV
for new reserves. Oilfield Review
Contributors
Matthew Billingham, based in Roissy-en-France,
France, is Schlumberger Wireline Operations Manager
for Saudi Arabia, Kuwait and Bahrain. Previously, he
was the tractor and conveyance product champion for
Schlumberger, and was responsible for planning activity, ensuring service quality and guiding the development of tractor technology. After earning a BEng
degree in electrical and electronic engineering from
the University of Leicester, England, he spent two
years in university-related work before joining
Schlumberger in 1994 as a wireline engineer in Great
Yarmouth, England. He was involved in developing horizontal production logging, downhole conveyance in
horizontal wells and perforating techniques as a field
service manager for MaxPro* production services in
Norway. He subsequently transferred to Algeria as a
field service manager for MaxPro services, where he
helped update many wireline operations policies.
Matthew was a service quality coach in Aberdeen
before assuming his current position in 2003.
Vincent Chatelet is Head of the Electronics and
Mechanics Department with Schlumberger Geoservices
in Roissy-en-France, France. He began his career with
Schlumberger as an electronics engineer in 1991. In his
21 years with Schlumberger, he has been a project
leader, head of electronics service, and electronics and
manufacturing department manager. Vincent received
BS and MS degrees in electronics engineering from
the Institute Nationale des Sciences Appliquées in
Lyon, France.
John Cook, a Scientific Advisor for Schlumberger,
works in the drilling department at the Cambridge
Research Center, England. Since joining Schlumberger
in 1983, he has worked on a wide range of problems
involving geomechanics and rock behavior. He holds
MA and PhD degrees in materials science and physics,
respectively, from the University of Cambridge,
England. John is joint author of the geomechanics
chapter of the SPE Advanced Drilling and Well
Technology handbook and is the author of many SPE
and other papers.
Morris Cox began his career in 1985 with Watters
Wireline & Snubbing Consultants Inc as a slickline
operator and consultant. From 1989 to 2007, Morris
worked for Halliburton Energy Services, first as a slickline operator and then as global project manager.
Since 2007, he has been a Senior Completions
Engineer for Nexen Petroleum USA Inc. in Houston.
David A. Edwards, who is based in Abingdon, England,
is a Principal Software Engineer with Schlumberger
and leads the well modeling team in the INTERSECT*
simulator group. David began his career in 1988 as a
systems engineer with Smith Associates in Guildford,
England, and later joined Exploration Consultants Ltd
in Henley-on-Thames, England. He earned a BS degree
in physics from the University of Warwick, England,
and a PhD degree in astrophysics from the University
of Oxford, England.
Winter 2011/2012
Edwin Felczak is a Schlumberger Drilling Services
Sales Engineer for PathFinder in Oklahoma City,
Oklahoma, USA. He joined Schlumberger in 2003 and
has worked in various positions in the field as well as
in testing, quality, coordinating and sales. He has a
BS degree in mechanical engineering from Texas A&M
University, College Station, USA.
Paul A. Fjerstad is a Reservoir Engineering Advisor in
Houston for the Chevron Energy Technology Company.
He has more than 25 years of experience in technology
development and change management processes and
deployment. He is the Chevron INTERSECT Change
Management Project Manager responsible for deployment of the next-generation reservoir simulator. Paul
began his career in 1985 with Norsk Hydro ASA as a
reservoir engineer for North Sea field development
and reservoir management planning in Oslo and
Bergen, Norway. He was next involved in field development planning, formation evaluation and prospect
evaluation for BP plc in Stavanger. From 1992 to 1994,
he was a reservoir engineering advisor to Kuwait Oil
Company working on rebuilding oil production capacity and evaluating reservoir damages caused by battle.
From 1994 to 2001, he led software support, sales and
marketing for Schlumberger in Dubai, and prior to
joining Chevron in 2005, he was the ECLIPSE* reservoir simulation software product champion for
Schlumberger in the UK.
Jessica Franco is a Reservoir Engineer for Total SA,
where she has worked since 2005. She focuses on the
numerical design of experiments and has managed
thermal simulations for heavy oil and enhanced oil
recovery studies. Since 2011, she has been in Angola
working on a deepwater field, focusing on new well
developments and numerical simulations. Jessica
obtained a PhD degree in applied mathematics from
the Ecole National Supérieure des Mines de SaintEtienne, France.
Neil D. Godwin has worked for Schlumberger at
Stonehouse Technology Center in England since 2008.
He wrote and developed a suite of manuals for the
PowerDrive Archer* rotary steerable system and is
now creating modular manuals for several precommercial products under development in Stonehouse.
Before joining Schlumberger, he interned with
Lockheed Martin UK, where he wrote technical documentation on military aircraft. Neil holds a BA degree
in English and an MA degree in technical communications from the University of Portsmouth, England.
Fred Growcock is the Global Fluids Advisor for
Occidental Oil and Gas Corporation in Houston, where
he provides technical support to the company’s worldwide drilling fluid field operations. He began his career
as a scientist at the US Department of Energy
Brookhaven and Oak Ridge National Laboratories in
the mid-1970s working on coal liquefaction and gasification and nuclear reactor safety. He then moved to
Dowell Schlumberger to develop acidizing corrosion
inhibitors and foamed fracturing fluids. Subsequently,
he joined Amoco Production Company to carry out
drilling fluids R&D and served as an adjunct professor
of chemical engineering at the University of Oklahoma
in Norman. He moved to M-I SWACO, a Schlumberger
company, to focus on research and provide technical
service support. Fred earned BA and BS degrees in
chemistry from The University of Texas at Austin and
MS and PhD degrees in physical chemistry from New
Mexico State University, Las Cruces, USA. He has
authored numerous papers and holds a dozen patents
on corrosion inhibitors, drilling fluid systems and completion fluid products. Fred served as a 2009/2010 SPE
Distinguished Lecturer.
Dayal Gunasekera is a Reservoir Engineering
Marketing Manager for Schlumberger in Abingdon,
England. He has more than 25 years of industry experience and has held his current position since 2009. His
previous positions include Engineering, Manufacturing
and Sustaining competency manager, global software
métier manager, Well Services engineering applications manager and FloGrid* program manager; he has
also been a petroleum engineering software developer.
He is a member of the scientific committee of the
European Association of Geoscientists and Engineers
European Conference on the Mathematics of Oil
Recovery and has served as a member of the SPE
Reservoir Simulation Symposium technical committee.
Dayal received bachelor’s and master’s degrees in general engineering from the University of Cambridge,
England. He has a doctoral degree in electronic and
electrical engineering from the University of Wales,
Swansea.
Quan Guo, who is based in Houston, is Manager for
Industry Initiatives and a Schlumberger Eureka
Technical Career Advisor. He has been with
M-I SWACO, a Schlumberger company, since 2003; his
current primary technical focus is on geomechanics
and subsurface issues related to drilling fluids, wellbore strengthening and shale gas. Previously, he was
with Advantek International llc in Houston and
TerraTek, Inc, in Salt Lake City, Utah, USA, prior to its
acquisition by Schlumberger. He has written more
than 50 journal and SPE articles. Quan has been a
technical editor for the journal SPE Drilling and
Completion and has served on the program committee
of several SPE applied technology workshops. He holds
a BS degree in mathematics and mechanics from
Lanzhou University, China, an MS degree in engineering mechanics from Huazhong University of Science
and Technology, Wuhan, Hubei, China, and a
PhD degree in mechanical engineering from
Northwestern University, Evanston, Illinois, USA.
Richard Hawkins, based in Sugar Land, Texas, is a
Product Champion for the PowerDrive Archer rotary
steerable system, a position he has held since
August 2010. Before this, he served as a drilling services manager and a directional drilling supervisor for
Schlumberger. Richard joined the company in 1996
as an MWD and LWD supervisor in Aberdeen. He
obtained a BS degree in mechanical engineering
from the University of Lincolnshire and Humberside,
Lincoln, England.
45
Viet Hoang is a Senior Engineering Advisor at Chevron
Energy Technology Company in San Ramon, California,
USA. He has more than 30 years of experience with
Chevron in heavy oil recovery and reservoir simulation R&D, as well as geothermal and enhanced oil
recovery chemical development and applications.
Viet has contributed extensively to reservoir engineering and simulation studies for numerous oil and
gas recovery and geothermal projects. He has a
PhD degree in mechanical engineering from the
University of California at Berkeley.
Mike Hodder is Director of the M-I SWACO Aberdeen
Research and Technology Centre in Scotland. He has
an MS degree in geology and chemistry from the
University of Cambridge, England, and has more than
30 years of experience in the drilling fluids business.
Mike began his career in research, next became a field
engineer and has since worked in various technical
and marketing positions in the UK, France and the
US. In the late 1990s, Mike established the Dowell
Technical Center in New Orleans, which focused on
well construction issues such as drilling fluids and
cement in deepwater wells.
Stephen Jones is a PathFinder Business Development
Manager for Schlumberger in Katy, Texas. In 1999, he
joined Schlumberger as a directional drilling supervisor in Aberdeen. Previously, he was a field engineer
and directional driller for Halliburton Energy Services.
Stephen is currently involved in development of highperformance rotary steerable directional drilling solutions. He received his BS degree in mechanical
engineering and an MS degree in offshore engineering
at Robert Gordon University, Aberdeen.
Jitendra Kikani is the Manager for Reservoir
Performance Products at Chevron Energy Technology
Company in Houston, where he is responsible for
R&D in reservoir simulation. He is also the Program
Manager for INTERSECT collaboration with
Schlumberger. Previously, he held various positions at
Chevron, including manager of gas assets in Angola
and subsurface manager for flare elimination projects.
He has worked for Chevron for more than 15 years, has
twice been an SPE Distinguished Lecturer and published extensively in the areas of reservoir surveillance, well testing and permanent downhole gauges.
Jitendra earned a BS degree in petroleum engineering
from the Indian School of Mines, Dhanbad, Jharkhand,
India, an MS degree in mechanical engineering from
the University of California at Berkeley and an MS
degree in mathematics and a PhD degree in petroleum
engineering from Stanford University in California.
Ke Li joined Schlumberger in 2006 as a mechanical
engineer and next became a simulation and modeling
engineer in the Mechanical Technology and Simulation
Group at Sugar Land, Texas. He became the Sugar Land
Simulation and Modeling Group Leader in 2011. He
obtained a PhD degree in mechanical engineering–
engineering mechanics from Michigan Technological
University, Houghton, USA. Ke has published numerous
journal and conference papers in the areas of solid
mechanics, materials modeling and structural analysis.
Kate Mantle, who is based in Stonehouse, England,
began her career with Schlumberger as a mud logger
in 1989. In 1995, she became a directional driller.
Between 1998 and 2007, Kate worked as a consultant
directional driller on Schlumberger jobs, and became
involved in PowerDrive Archer rotary steerable system
operations. In 2008, she worked as service quality engineer in the PowerPak* Sustaining Team at Stonehouse
Drilling, Rotary steerable and Motors (SDRM). In
January 2012, she became Directional Drilling Advisor
to the SDRM Archer Operations Support Team. She
received a BS degree in geology in 1988 from
University College, Cardiff, Wales.
Jonathan Morris is the INTERSECT Program Manager
for Schlumberger in Abingdon, England, and has
25 years of experience in the software industry. Prior
to his current position, he was lead software architect
for the simulation group in Abingdon. Jonathan holds
bachelor’s and master’s degrees from the University of
Cambridge, England, and an MSc degree from the
University of Oxford, England, all in mathematics.
Stuart Murchie began his Schlumberger career in well
testing in Aberdeen in 1984 after graduating from the
University of Dundee, Scotland, with a BS degree in
mechanical engineering. In 1988, he transferred to
Wireline, where he held various field operation positions
in Asia followed by a posting in Paris as new technology
manager for Wireline and Testing. In 1999, he was
appointed vice president of Data & Consulting Services,
based in Houston. He next served as QHSE manager for
Oilfield Services North and South America, then moved
to Thailand as the managing director for Oilfield
Services Central East Asia. He returned to the UK in
2004 as managing director for Oilfield Services UK and
Ireland. In 2005, he became personnel manager for
Schlumberger Integrated Project Management and then
regional vice president for the Europe/Africa/Caspian
area. Now based in Roissy-en-France, Stuart assumed
his current position as Marketing and Technology
Manager for Slickline Services in 2011.
Sivaraman Naganathan, who is based in Stonehouse,
England, works as Schlumberger Europe, Caspian and
Africa Area Asset Manager. Sivaraman began his oilfield
career in 1995 as an MWD engineer, and has held a variety of positions in the oil and gas industry. He received
his BS degree in instrumental and control engineering
and MS degree in physics from the Birla Institute of
Technology and Science, Pilani, Rajasthan, India.
William B. Paulsen began his career in 1977 with the
Red Adair Company as a well control specialist in
Houston. He then worked as a sales and service technician at Texas Oilfield Sales & Service Company. In
1997, he became a petroleum consultant for BP
Exploration, where he was responsible for field supervision of remedial well operations in the BP Cusiana
and Cupiagua development project in Colombia. He
currently works for ATP Oil and Gas Corporation, in
Houston, as a Production Superintendent. William
manages the decommissioning of pipelines, wellbores
and platforms and is responsible for through-tubing
recompletions and workovers on shelf properties;
he is also involved in deepwater riserless well intervention planning.
Lisette Quettier is a Reservoir Simulation Expert at
Total SA, in Pau, France, where she has worked since
1981. Her work focuses on reservoir simulation, including code development, R&D, support, training and
knowledge management. She is currently working on
46
INTERSECT thermal developments and testing. She
began her career working on thermal enhanced oil
recovery techniques with the development of a simulator and on several experimental projects and simulation studies on steam injection pilots. Lisette earned a
degree in hydraulic engineering from Institut National
Polytechnique de Grenoble, France, and a PhD degree
in fluid mechanics from Institut de Mécanique des
Fluides de Toulouse, France.
Gareth Shaw began his career as a research fellow at
Delft University of Technology, the Netherlands. Based
in Abingdon, England, he has been an INTERSECT Engine
Project Manager with Schlumberger since 2009. Gareth
has a BS degree in mathematics from the University of
Bristol, England, and MS and doctoral degrees in
mathematics from the University of Oxford, England.
Kevin Shaw is a Simulator Product Champion for
Schlumberger and a Commercialization Lead for the
INTERSECT reservoir simulator. Kevin, who is based in
Abingdon, England, joined Schlumberger in 1989. Prior
to his current positions, he worked in Abingdon on the
commercialization of ECLIPSE software, near wellbore
modeling, Avocet* Integrated Asset Modeler and
INTERSECT field management system.
Fred Slayden, who is based in Houston, has worked
for Schlumberger as a US Land Drilling Manager since
2006. Prior to his career with Schlumberger, he worked
for Baker Hughes, Williams Engineering and
Weatherford International. Fred has had more than
40 years of experience in the oil industry. He received
his BS degree in chemical engineering from
Texas A&M University, College Station, and Tarleton
State University, Stephenville, Texas.
Ariel Torre joined Schlumberger in 1996 as an MWD
specialist in Argentina. He has also worked in Abu
Dhabi, Brazil, Qatar and the US. Currently, he works
as an Eastern Division Operations Manager for
PathFinder in Oklahoma City, Oklahoma. In 1997, Ariel
obtained his bachelor’s degree in electronics engineering at Universidad Nacional de Córdoba, Argentina.
Eric van Oort, who has worked at Royal Dutch Shell
Company for 20 years, joined the company as a
research scientist to focus on wellbore instability in
shale formations and the design of novel water-base
mud systems. In 1996, he moved to Houston to work as
a research team lead at the Shell Bellaire Technology
Center and since then has held various senior technical and managerial positions within Shell Oil
Company. He currently serves as Well Performance
Improvement and Onshore Gas Technology Manager
for Shell Upstream Americas in Houston. Eric is a former SPE Distinguished Lecturer, a best paper award
recipient from SPE Drilling & Completion and a frequent conference organizer, chair, discussion panel
member and invited speaker. He holds a PhD degree
in chemical physics.
Dominic Walsh began his career in 2001 at Riversoft
Ltd in London. Currently, he is based in Abingdon,
England, where he works for Schlumberger as an
Engine Architect on the INTERSECT simulation project,
a position he has held since 2006. He is responsible for
the architecture of simulator engines, with particular
focus on parallel scalability. Dominic has a BS degree in
physics from The Imperial College of Science,
Technology and Medicine, London, and a PhD degree in
physics from the University of Durham, England.
An asterisk (*) is used to denote a mark of Schlumberger.
Oilfield Review
Coming in Oilfield Review
NEW BOOKS
offering the cogent, invigorating
argument that only by embracing
uncertainty can we truly progress.
“The Blind Spot,” Kirkus Reviews (May 1, 2011),
http://www.kirkusreviews.com/book-reviews/
non-fiction/william-byers/blind-spot-scienceuncertainty/#review (accessed August 29, 2011).
The Blind Spot: Science and
the Crisis of Uncertainty
William Byers
Princeton University Press
41 William Street
Princeton, New Jersey 08540 USA
2011. 208 pages. US$ 24.95
ISBN: 978-0-691-14684-3
Mathematician William Byers maintains
that the unpredictable, the uncertain,
the unknowable and the ambiguous,
rather than a faith in scientific certainty, are what give rise to better
science. The author draws on examples
from Wall Street to mathematics to
illustrate the blind spots in our understanding and decision making in the
sciences, mathematics and technology.
Contents:
• The Blind Spot
• The Blind Spot Revealed
• Certainty or Wonder?
• A World in Crisis!
• Ambiguity
• Self-Reference: The Human Element
in Science
• The Mystery of Number
• Science as the Ambiguous Search for
Unity
• The Still Point
• Conclusion: Living in a World of
Uncertainty
• Notes, References, Index
The author argues that while
reconfiguring the human attitude
toward embracing uncertainty may be
uncomfortable, ultimately it will
enable creative opportunity on a
massive scale; that an acceptance of
ambiguity is ‘the price we pay for
creativity.’ Byers suggests that a
continuing adherence to certainties
may allow the fundamental uncertainty of modern culture to manifest
itself in a variety of catastrophic
ways. . . . Byers incorporates many
brilliant thinkers and seminal scientific breakthroughs into his discussion,
Winter 2011/2012
The Beginning of Infinity:
Explanations That Transform
the World
David Deutsch
Viking Penguin, a member of
Penguin Group (USA) Inc.
375 Hudson Street
New York, New York 10014 USA
2011. 487 pages. US$ 30.00
ISBN 978-1-101-54944-5
Deutsch looks at human progress,
especially the rapid changes we’ve
made since the Enlightenment. He
proposes that the cause of such progression is the quest for good explanations,
which have the scope and power to
cause change. He also posits that such
a quest is the operating principle of
not only science but of all successful
human endeavor. He explains how
this flow of improving explanations
has infinite reach.
Contents:
• The Reach of Explanations
• Closer to Reality
• The Spark
• Creation
• The Reality of Abstractions
• The Jump to Universality
• Artificial Creativity
• A Window on Infinity
• Optimism
• A Dream of Socrates
• The Multiverse
• A Physicist’s History of Bad
Philosophy
• Choices
• Why Are Flowers Beautiful?
• The Evolution of Culture
• The Evolution of Creativity
• Unsustainable
• The Beginning
• Bibliography, Index
Mr. Deutsch’s previous tome,
The Fabric of Reality, took a broadranging sweep that encompassed
evolution as well as knowledge,
computation and physics, and earned
him a fan base that has been eagerly
awaiting his second publication. The
Beginning of Infinity is equally bold,
addressing subjects from artificial
intelligence to the evolution of culture
and of creativity; its conclusions are
just as profound. Mr. Deutsch argues
that decent explanations inform moral
philosophy, political philosophy and
even aesthetics. He is provocative and
persuasive. Who knows? Perhaps he
is also right.
“In the Beginning—A Quantum Physicist’s
Long-Awaited Second Book,” The Economist (March 24, 2011), http://www.economist.com/
node/18438055 (accessed October 3, 2011).
David Deutsch’s The Beginning of
Infinity is a brilliant and exhilarating
and profoundly eccentric book. It’s
about everything: art, science, philosophy, history, politics, evil, death,
the future, infinity, bugs, thumbs, what
have you. . . . Deutsch (who is famous,
among other reasons, for his pioneering contributions to the field of
quantum computation) is so smart,
and so strange, and so creative, and
so inexhaustibly curious, and so
vividly intellectually alive, that it is a
distinct privilege, notwithstanding
everything, to spend time in his head.
Albert D: “Explaining It All: How We Became the
Center of the Universe,” The New York Times
(August 12, 2011), http://www.nytimes.
com/2011/08/14/books/review/the-beginning-ofinfinity-by-david-deutsch-book-review.
html?pagewanted=all (accessed October 3, 2011).
Plug and Abandon. Thousands of
onshore and offshore wells around
the world are reaching the end of
their economic lives. Owners of these
wells need to permanently plug and
abandon them in a safe and environmentally responsible manner. The
cost of these operations ranges from
a relatively small expense for most
onshore wells to millions of US dollars for offshore wells with complex
infrastructure that must be removed.
This article looks at the tools and
methods available to support plug
and abandon operations.
Jars. For more than 80 years, drilling jars have been widely accepted
as unglamorous, inexpensive insurance against stuck pipe. While the
basic technology of jars has changed
little, understanding of the dynamics
necessary to ensure a successful
jarring operation has expanded
significantly in recent years. This
article looks at the lessons learned
and surveys how the industry is
solving the challenge of using jars
in today’s increasingly complex
well configurations.
Mud Logging. Mud loggers monitor
a variety of drilling parameters to alert
drilling personnel to changes in downhole drilling conditions. Through
examination of formation cuttings,
augmented by measurements of drilling rates and chromatographic analysis
of mud gases, mud loggers often
obtain the earliest indicators of reservoir potential. Recent advances in
drilling sensor technology and mud gas
analysis are expanding the range of
mud logging services.
LWD Sonic Advances. Acoustic
LWD tools were first introduced to
the oil and gas industry in the
mid-1990s, but they have evolved
considerably since then. LWD sonic
data now include results that were
once available only with wireline
logging tools. Drilling engineers now
use a new quadrupole sonic tool for
monitoring accurate pore pressure,
determining geomechanical properties and managing drilling fluid for
borehole stability. Case studies
demonstrate the use of this tool for
real-time measurement of geomechanical properties and for drilling
optimization.
47
Why Geology Matters: Decoding
the Past, Anticipating the Future
Doug Macdougall
University of California Press
2120 Berkeley Way
Berkeley, California 94704 USA
2011. 285 pages. US$ 29.95
ISBN: 978-0-520-26642-1
The Techno-Human Condition
Braden R. Allenby and
Daniel Sarewitz
The MIT Press
55 Hayward Street
Cambridge, Massachusetts
02142 USA
2011. 222 pages. US$ 24.95
ISBN: 978-0-262-01569-1
This book gives an overview of Earth’s
history from information extracted from
ice cores, rocks and other natural
archives. Macdougall explores how an
understanding of geosciences illumi­
nates many of the world’s present
problems—energy availability, fresh­
water accessibility, agriculture sustain­
ability and biodiversity maintenance—
and how we can use geosciences to
prepare for the future.
Contents:
• Set in Stone
• Building Our Planet
• Close Encounters
• The First Two Billion Years
• Wandering Plates
• Shaky Foundations
• Mountains, Life, and the Big Chill
• Cold Times
• The Great Warming
• Reading LIPs
• Restless Giants
• Swimming, Crawling, and Flying
Toward the Present
• Why Geology Matters
• Bibliography, Further Reading, Index
Macdougall . . . . gives an up-todate overview of what scientists now
know about the history of Earth and
explains why Earth’s past is relevant
to contemporary human society. The
author’s discussion of the history of
climate change over the past several
billion years and the causes thereof,
for instance, is directly applicable to
modern debates about climate
change. He also addresses ways to
apply geology to questions of energy
resources, sustainable agriculture,
biodiversity, and access to fresh water
and presents all in an enjoyable
reading style. Highly recommended.
Dimmick CW: Choice 49, no. 2
(October 2011): 336.
48
Authors Allenby and Sarewitz argue that
humans have always coevolved with
their technologies, but today we are
additionally transformed by the applica­
tion of internal technologies such as a
re-engineered immune system, artificial
joints and neurochemical mood enhanc­
ers. As a result, the authors say, humans
now need to embrace a new “technohuman relationship,” exploring what it
means to be human in an era of techno­
logical complexity.
Contents:
• What a Long, Transhuman Trip It Has
Already Been
• In the Cause-and-Effect Zone
• Level I and II Technology:
Effectiveness, Progress, and
Complexity
• Level III Technology: Radical
Contingency in Earth Systems
• Individuality and Incomprehensibility
• Complexity, Coherence, Contingency
• Killer Apps
• In Front of Our Nose
• Epilogue: The Museum of Human
Frailty
• Bibliography, Index
The Techno-Human Condition . . .
illustrates how technology is a part of
all individuals, including their cultures and institutions. Allenby and
Sarewitz . . . encourage the reader to
understand, embrace, and celebrate
people’s ignorance of the complexity
of techno-human systems in order to
begin to manage technological and
scientific prowess with rationality,
ethics, humility, and responsibility.
The authors illustrate th[eir] model
by analyzing two. . . systems: railroads and modern military technology. Recommended.
Bauchspies WK: Choice 49, no. 2
(October 2011): 323.
The Theory That Would Not Die:
How Bayes’ Rule Cracked the
Enigma Code, Hunted Down
Russian Submarines, and
Emerged Triumphant from Two
Centuries of Controversy
Sharon Bertsch McGrayne
Yale University Press
302 Temple Street
New Haven, Connecticut 06511 USA
2011. 320 pages. US$ 27.50
ISBN: 978-0-300-16969-0
Bayes’ Rule, the mathematical theorem
formulated in the 1740s by the
Reverend Thomas Bayes, links condi­
tional probability to its inverse. The
author follows the people who furthered
the theorem as well as those who
vehemently opposed it; she explores the
development of the theorem from its
discovery, rise, near demise and redis­
covery through its many controversies
and successes and concludes with its
present-day application to crises
characterized by great uncertainty.
Contents:
• Part I. Enlightenment and the AntiBayesian Reaction: Causes in the Air;
The Man Who Did Everything; Many
Doubts, Few Defenders
• Part II. Second World War Era: Bayes
Goes to War; Dead and Buried Again
• Part III. The Glorious Revival: Arthur
Bailey; From Tool to Theology;
Jerome Cornfield, Lung Cancer, and
Heart Attacks; There’s Always a First
Time; 46,656 Varieties
• Part IV. To Prove Its Worth: Business
Decisions; Who Wrote The
Federalist?; The Cold Warrior; Three
Mile Island; The Navy Searches
• Part V. Victory: Eureka!; Rosetta
Stones
• Appendixes, Notes, Glossary,
Bibliography, Index
data who contributed, for good or for
worse, to its historical perambulations to the present day, in the process
making the theory come alive through
her prose in a way that is very accessible to the patient non-statistician.
Bottone M: “The Theory That Would Not Die by
Sharon Bertsch McGrayne,” Significance,
http://www.significancemagazine.org/details/
review/1062663/The-Theory-That-Would-NotDie-by-Sharon-Bertsch-McGrayne.html (accessed
September 14, 2011).
The theorem has a long and
surprisingly convoluted history, and
McGrayne chronicles it in detail. . . .
Statistics . . . can be applied to almost
any area of science or life, and this
litany of applications is intended to be
the unifying thread that sews the book
into a coherent whole. It does so, but
at the cost of giving it a list-like,
formulaic feel. More successful are
McGrayne’s vivifying sketches of the
statisticians who devoted themselves
to Bayesian polemics and
counterpolemics.
Paulos JA: “The Mathematics of Changing Your
Mind,” The New York Times (August 5, 2011),
http://www.nytimes.com/2011/08/07/books/
review/the-theory-that-would-not-die-by-sharonbertsch-mcgrayne-book-review.html (accessed
September 14, 2011).
In a densely packed and engaging
book, Sharon Bertsch McGrayne
traces the remarkable history of
Bayes’ Rule. . . . At times reading like
a historical account, at times like
investigative journalism, at yet other
times like a statistical commentary,
Bertsch McGrayne does an admirable
job of giving a voice to the scores of
famous and non-famous people and
Oilfield Review
Wrestling with Nature:
From Omens to Science
Peter Harrison, Ronald L. Numbers and
Michael H. Shank (eds)
The University of Chicago Press
1427 East 60th Street
Chicago, Illinois 60637 USA
2011. 416 pages. US$ 95.00
ISBN: 978-0-226-31783-0
This collection of essays examines the
investigation of nature through the
millennia and explains the content,
goals, methods and practices associated
with such investigations. The authors
explore the concept of the history of
science and attempt to answer the
questions “When and where did
science begin?”
Contents:
• Introduction
• Natural Knowledge in Ancient
Mesopotamia
• Natural Knowledge in the
Classical World
• Natural Knowledge in the
Arabic Middle Ages
• Natural Knowledge in the
Latin Middle Ages
• Natural History
• Mixed Mathematics
• Natural Philosophy
• Science and Medicine
• Science and Technology
• Science and Religion
• Science, Pseudoscience, and Science
Falsely So-Called
• Scientific Methods
• Science and the Public
• Science and Place
• Contributors, Index
This tightly focused collection of
essays examines the diverse
approaches to studying nature from
the earliest civilizations to the present. . . . the editors of this volume of
historical essays warn against reading modern ideas about the nature of
science back into the past. . . . These
essays should appeal to a broad
audience interested in the diverse
origins of modern science.
Recommended.
An Empire of Ice: Scott,
Shackleton, and the Heroic Age
of Antarctic Science
Edward J. Larson
Yale University Press
302 Temple Street
New Haven, Connecticut 06511 USA
2011. 326 pages. US$ 28.00
ISBN: 978-0-300-15408-5
While the early Antarctic explorers
Amundsen, Scott and Shackleton are
known for their individual quests to be
the first to reach the South Pole, the
author places these single-minded goals
into a larger story—that of massive
scientific enterprises. Larson looks at
the larger scientific, social and geopolitical context of the era and explores
the nascent days of international
scientific cooperation.
Contents:
• “Three Cheers for the Dogs”
• A Compass Pointing South
• The Empire’s Mapmaker
• In Challenger’s Wake
• Taking the Measure of Men
• March to the Penguins
• Discovering a Continent’s Past
• The Meaning of Ice
• Heroes’ Requiem
• Notes, Index
Extremely well written and documented, An Empire of Ice is a gripping account that reads almost like a
thriller, demonstrating the explorers’
well-known courage and persistence
in the face of atrocious hardship. At
the close of another International
Polar Year, it demonstrates how
international scientific cooperation in
the world’s coldest regions came to be
established. Highly recommended.
Bottled Lightning:
Superbatteries, Electric Cars,
and the New Lithium Economy
Seth Fletcher
Hill and Wang, a division of
Farrar, Straus and Giroux
18 West 18th Street
New York, New York 10011 USA
2011. 260 pages. US$ 26.00
ISBN: 978-0-8090-3053-8
Starting with the invention of the
battery and ending with electric cars,
the author traces the arc of scientists’
quest to convert stored chemical energy
into electrical energy. Lithium, which
powers nearly all batteries today, is at
the heart of the story; Fletcher travels
from the salt flats of Bolivia to university laboratories to follow the path of
this essential element. The book focuses
on the environmental movement, the
American auto industry, patent wars
and government policies, all of which
play a part in the shaping of the lithium
battery and its uses.
Contents:
• Prologue
• The Electricians
• False Start
• The Wireless Revolution
• Reviving the Electric Car
• The Blank Spot at the Heart of the Car
• The Lithium Wars
rolling in the last quarter of the
book—rollicking story. [He gives] us
the history, the science, the business
and the characters without veering off
into irrelevant territory. . . . Fletcher
ends his book with a look at how—
211 years after the battery’s invention—we are practically speaking just
at the beginning of its potential.
LeVine S: “Book Review: Seth Fletcher’s ‘Bottled
Lightning’,” Foreign Policy (May 17, 2011), http://
oilandglory.foreignpolicy.com/posts/2011/05/16/
book_review_seth_fletchers_bottled_lightning
(accessed August 29, 2011).
Mr. Fletcher does a good job
surveying this old-yet-nascent industry in the U.S. . . . Some commentators
worry that we’re going to replace our
dependence on foreign oil with a
dependence on foreign batteries—and
foreign lithium. Bottled Lightning
alleviates at least one worry: By
taking us to the salt flats of the
‘Lithium Triangle’ in Chile, Bolivia
and Argentina, Mr. Fletcher shows us
the abundance of the metal and puts
to rest any fears of ‘peak lithium.’ . . .
Mr. Fletcher makes a good case that
the electric-car trend may soon be
able to shed its dubious reputation as
a public-private hybrid and roll under
its own power.
Bailey R: “Charging Ahead,” The Wall Street
Journal (May 16, 2011), http://online.wsj.com/
article/SB100014240574870373080457631748127
6537422.html (accessed August 26, 2011).
• The Brink
• The Stimulus
• The Prospectors
• The Lithium Triangle
• The Goal
• Epilogue
• Appendix: Global Lithium Reserves
and Identified Resources
• Notes, Selected Bibliography, Index
Ives JD: Choice 49, no. 2 (October 2011): 336.
Fletcher, a senior editor at
Popular Science magazine, clearly
sides with the scientists and engineers
who occupy this tightly written
book. . . . he hopes they are right, and
that the era of oil winds down. But he
does not fall into the technologywriter’s trap of becoming gee-whizzy
about his subject, which is just the
right tone. This is a well-written,
smart and—when Fletcher gets
Hagen JB: Choice 49, no. 2 (October 2011): 327.
Winter 2011/2012
49
DEFINING COMPLETION
The fourth in a series of introductory articles describing basic concepts of the E&P industry
The Science of Oil and Gas Well Construction
Rick von Flatern
Senior Editor
Once a well has been drilled to total depth (TD), evaluated, cased and
cemented, engineers complete it by inserting equipment, designed to optimize production, into the hole. The driver behind every well completion
strategy, whether for a complex or basic well, is to recover, at a reasonable
cost, as large a percentage of the original oil in place (OOIP) as possible.
The decision to case and cement a well for production or plug and abandon it as a dry hole relies heavily on formation evaluation (FE) using openhole logs. For the purposes of this article, completion refers to all operations
following the placement of cement behind the production casing, which is
performed after FE.
Once FE log analysis indicates the existence and depth of formations
likely to produce commercial volumes of hydrocarbons, steel casing is run in
the borehole and cement is pumped behind it. Completion engineers then
displace the drilling mud in the well with a completion fluid. This may be a
clear fluid or brine formulated to be nonreactive with the formation.
A primary reason to cement casing is to prevent communication between
producing zones, thus engineers run a cement bond log (CBL) to ascertain
Incorrect Density
Poor Drilling Fluid Removal
Formation strata
Borehole
Cement
Casing
Premature Gelation
Excessive Fluid Loss
> Cement sheath flaws. Cement bond logs can detect negative results from
poor cementing practices or designs, which may allow fluid flow (blue
arrows) from one zone to another or to the surface. Some causes of flaws
include incorrect cement density (top left), poor drilling fluid removal (top
right), premature gelation, or setting (bottom left), and excessive fluid loss
from the cement slurry (bottom right).
Oilfield Review Winter 2011/2012: 23, no. 4.
Copyright © 2012 Schlumberger.
50
that the cement sheath between the casing and the borehole wall is without
flaws (below left). If gaps exist, engineers remedy the problem by injecting
cement through holes made in the casing at the appropriate depths. This is
referred to as a cement squeeze job.
Engineers then perforate through the casing and cement sheath into
sections of the formation where FE analysis indicates conditions are favorable for hydrocarbon flow. Perforations are holes made in the casing, usually
using small, shaped charges fired from perforating guns. The guns may be
lowered into the hole on wireline, tubing or coiled tubing.
Often, these operations leave debris in the well and in the perforations
themselves, which may hamper the flow of formation fluids into the borehole. To reduce the impact of this debris, engineers may pump a weak acid
solution downhole to the affected area to dissolve the debris.
Depending on their knowledge of the formations being completed, operators may then perform a well test. In some instances this is carried out
through a drillstem test (DST) valve attached to the bottom of a string of
tubing or drillpipe called a workstring. The DST valve can be opened from the
surface and the well fluids flowed through a separator—a device that separates the oil, gas, water and completion fluids at the surface. By measuring
rates of water, gas and oil produced, operators gain information with which
to make deductions about future well performance. Well tests also give operators extensive information about the character and extent of the reservoir.
Completion engineers may then consider several options, which are
determined by formation characteristics. If the formation permeability is
low, engineers may choose to create a hydraulic fracture by pumping water
and sand or other materials—a slurry—through the perforations and into
the formation at high pressure. Pump pressure builds against the unyielding
formation until the rock yields and cracks open. The slurry is then pumped
into the newly created formation fractures. When the pumps are turned off
and the well opened, the water flows out, leaving behind the sand. This proppant holds open the newly created fractures. The result is a high-permeability pathway for the hydrocarbons to flow from the formation to the wellbore.
While oil and gas flow readily through permeable rocks, such formations
may be unconsolidated and subject to breaking into small sand particles
that may flow into the wellbore with produced fluids. These particles may
plug perforation tunnels and stop fluids entering the well. To prevent the
migration of these particles through the formation, engineers may inject
chemicals into the formation to bind the sand grains together. To prevent
sand from entering the wellbore, engineers may also opt for a sand control
technique—or a combination of techniques—that includes various types of
sand screens and gravel packing systems. Designed to block the migration
of sand, these systems allow fluids to freely flow through them.
The next stage in completion includes placing various pieces of hardware—referred to as jewelry—in the well; the jewelry is attached to production tubing. Tubing, the conduit between the producing formation and the
surface, is the infrastructure upon which almost all completions are built. Its
strength, material and size—weight/unit length and internal diameter—are
chosen according to expected production rates, production types, pressures,
depths, temperatures and corrosive potential of produced fluids.
Oilfield Review
Jewelry almost always includes packers, which seal against the inside of
the casing. Packers isolate producing zones within the casing-tubing annulus
in the same way cement does outside the casing. If the zone being produced
is the deepest in the well, fluids flow from the formation below the packer
and through the end of the tubing to the surface. In wells with multiple
zones, a more common scenario, flow enters the well between an upper and
lower packer and into the tubing through perforations or sliding sleeves
(below). A sliding sleeve is a valve that is opened or closed mechanically; a
Cement
Surface casing
Production casing
Casing-tubing
annulus
Tubing string
Packer
Packer
Sliding
sleeve
Perforations
Packer
> Single-zone and multizone well completions. In the single-zone completion
(left), a packer, which forms a seal inside the production casing, hydraulically
isolates the tubing string from the region above the packer, called the
“backside.” The backside contains completion fluid with corrosion inhibitors
to prevent casing corrosion. The multizone completion (right) employs at least
two packers that separate the producing zones. Fluids from all zones may be
allowed to commingle during production, or production from the upper zone
may be shut off by closing a sliding sleeve until operators have determined the
fluids may be commingled. Alternatively, operators may choose to allow the
lower zone to become depleted, then set a plug (not shown) above the lower
zone and open the sliding sleeve to produce only from the upper zone.
Winter 2011/2012
specially designed tool on slickline or coiled tubing moves the valve’s internal perforated sleeve up or down.
Nearly all completions also include safety valves. These come in a variety of forms but all are placed in the tubing within a few hundred feet of the
surface. They are designed to automatically shut in the well when the surface control system is breached. They can also be closed manually to add an
extra barrier between the well and the atmosphere when, for example, the
well is being worked on or a platform is being evacuated in preparation for
a storm.
With the basic jewelry deployed, many refinements are possible, depending on the specific needs of the field or well. For example, intelligent completions (ICs) are often used in situations or locations where entering the
well to change downhole settings is costly or otherwise problematic. ICs
include permanent, real-time remote pressure and temperature sensors
and a remotely operable flow control valve deployed at each formation.
In other wells, the formation pressure is, or eventually becomes, insufficient to lift the formation fluids out of the well. These wells must be
equipped with pumps or gas lift systems. Electric submersible pumps
(ESPs) pump fluids to the surface using a rotor and stator. Pump rotor
drives can be located on the surface. Reciprocating pumps, called pump
jacks, may be used to lift the fluid to the surface through a reciprocating
vertical motion.
Gas lift systems pump gas down the annulus between two casing strings.
The gas enters the tubing at a depth below the top of the fluid column. This
decreases the fluid density enough for buoyancy to lift the fluid out of the
well. The amount of gas entering the well may be regulated through a
sequence of valves located along the length of tubing, or it may be streamed
in at one or more locations.
Also in low-pressure formations, water or gas may be injected down one
well to push oil through the formation to producing wells. The producers
may be fitted with injection control devices (ICDs) that regulate how much
and where fluid enters the wellbore.
Before designing a completion, engineers take into consideration—for
every well—the types and volumes of fluids to be produced, downhole and
surface temperatures, production zone depths, production rates, well location and surrounding environment. Engineers must then choose from the
most basic openhole completion that may not have even a production casing
string, to highly complex multilateral wells that consist of numerous horizontal or high-angle wellbores drilled from a single main wellbore, each of
which includes a discrete completion.
The indispensible underpinnings of the optimal completion are solid
FE, data from nearby offset wells and flexibility. Armed with reliable
knowledge of target zones, how nearby wells accessing those formations
were completed and how they produced, engineers are often able to plan
the basic completion before the well is drilled. But completion engineers
know that not every well will behave as expected, so they include contingencies in their completion plans and are prepared to implement them. In
the end, how a well is completed—the culmination of all the decisions
about jewelry and processes—directly impacts the rate at which and how
long hydrocarbons will be produced from that well.
51
Oilfield Review Annual Index—Volume 23
ARTICLES
Basic Petroleum Geochemistry for
Source Rock Evaluation
McCarthy K, Rojas K, Niemann M,
Palmowski D, Peters K and
Stankiewicz A.
Vol. 23, no. 2 (Summer 2011): 32–43.
The Best of Both Worlds—
A Hybrid Rotary Steerable System
Felczak E, Torre A, Godwin ND,
Mantle K, Naganathan S, Hawkins R,
Li K, Jones S and Slayden F.
Vol. 23, no. 4 (Winter 2011/2012): 36–44.
Bit Design—Top to Bottom
Centala P, Challa V, Durairajan B,
Meehan R, Paez L, Partin U, Segal S,
Wu S, Garrett I, Teggart B and Tetley N.
Vol. 23, no. 2 (Summer 2011): 4–17.
Conveyance—Down and Out
in the Oil Field
Billingham M, El-Toukhy AM,
Hashem MK, Hassaan M, Lorente M,
Sheiretov T and Loth M.
Vol. 23, no. 2 (Summer 2011): 18–31.
Finding Value in Formation Water
Abdou M, Carnegie A, Mathews SG,
McCarthy K, O’Keefe M,
Raghuraman B, Wei W and Xian CG.
Vol. 23, no. 1 (Spring 2011): 24–35.
Intelligent Completions at
the Ready
Beveridge K, Eck JA, Goh G, Izetti RG,
Jadid MB, Sablerolle WR and
Scamparini G.
Vol. 23, no. 3 (Autumn 2011): 18–27.
Managed Pressure Drilling
Erases the Lines
Elliott D, Montilva J, Francis P,
Reitsma D, Shelton J and Roes V.
Vol. 23, no. 1 (Spring 2011): 14–23.
Open-Channel Fracturing—
A Fast Track to Production
d’Huteau E, Gillard M, Miller M,
Peña A, Johnson J, Turner M,
Medvedev O, Rhein T and Willberg D.
Vol. 23, no. 3 (Autumn 2011): 4–17.
Pipeline to Market
Albert AP, Lanier DL, Perilloux BL
and Strong A.
Vol. 23, no. 1 (Spring 2011): 4–13.
Reservoir Simulation: Keeping
Pace with Oilfield Complexity
Edwards DA, Gunasekera D, Morris J,
Shaw G, Shaw K, Walsh D, Fjerstad PA,
Kikani J, Franco J, Hoang V and Quettier L.
Vol. 23, no. 4 (Winter 2011/2012): 4–15.
Shale Gas: A Global Resource
Boyer C, Clark B, Jochen V, Lewis R
and Miller CK.
Vol. 23, no. 3 (Autumn 2011): 28–39.
Shale Gas Revolution
Alexander T, Baihly J, Boyer C, Clark B,
Waters G, Jochen V, Le Calvez J,
Lewis R, Miller CK, Thaeler J and
Toelle BE.
Vol. 23, no. 3 (Autumn 2011): 40–55.
52
Slickline Signaling a Change
Billingham M, Chatelet V, Murchie S,
Cox M and Paulsen WB.
Vol. 23, no. 4 (Winter 2011/2012): 16–25.
The Climate War: True Believers,
Power Brokers, and the Fight to
Save the Earth
Stabilizing the Wellbore to
Prevent Lost Circulation
Cook J, Growcock F, Guo Q, Hodder M
and van Oort E.
Vol. 23, no. 4 (Winter 2011/2012): 26–35.
Pooley E.
Vol. 23, no. 2 (Summer 2011): 58.
Gudmestad OT, Zolotukhin AB and Jarlsby
ET.
Vol. 23, no. 1 (Spring 2011): 57.
A Cubic Mile of Oil: Realities and
Options for Averting the Looming
Global Energy Crisis
Physics of the Future: How Science
Will Shape Human Destiny and
Our Daily Lives by the Year 2100
Technology for Environmental
Advances
Azem W, Candler J, Galvan J, Kapila M,
Dunlop J, Fastovets A, Ige A,
Kotochigov E, Nicodano C, Sealy I
and Sims P.
Vol. 23, no. 2 (Summer 2011): 44–52.
Zapping Rocks
Carmona R, Decoster E, Hemingway J,
Hizem M, Mossé L, Rizk T, Julander D,
Little J, McDonald T, Mude J and
Seleznev N.
Vol. 23, no. 1 (Spring 2011): 36–52.
DEFINING…INTRODUCING
BASIC CONCEPTS OF THE
E&P INDUSTRY
Defining Completion: The Science
of Oil and Gas Well Construction
von Flatern R.
Vol. 23, no. 4 (Winter 2011/2012): 50–51.
Defining Drilling: Turning to the
Right—An Overview of Drilling
Operations
Varhaug M.
Vol. 23, no. 3 (Autumn 2011): 59–60.
Defining Exploration: The Search
for Oil and Gas
Stewart L.
Vol. 23, no. 2 (Summer 2011): 59–60.
Defining Logging: Discovering the
Secrets of the Earth
Andersen MA.
Vol. 23, no. 1 (Spring 2011): 60, 59.
NEW BOOKS
The Beginning of Infinity:
Explanations That Transform
the World
Crane HD, Kinderman EM and
Malhotra R.
Vol. 23, no. 2 (Summer 2011): 56.
Cycles of Time: An Extraordinary
New View of the Universe
Penrose R.
Vol. 23, no. 2 (Summer 2011): 57.
Earth Materials
Frisch W, Meschede M and Blakey R.
Vol. 23, no. 3 (Autumn 2011): 58.
Remembering Einstein: Lectures on
Physics and Astrophysics
An Empire of Ice: Scott, Shackleton,
and the Heroic Age of Antarctic
Science
Quantum Man: Richard Feynman’s
Life in Science
Larson EJ.
Vol. 23, no. 4 (Winter 2011/2012): 49.
The Evolutionary World: How
Adaptation Explains Everything from
Seashells to Civilization
Vermeij GJ.
Vol. 23, no. 1 (Spring 2011): 56.
For the Love of Physics: From the
End of the Rainbow to the Edge of
Time—A Journey Through the
Wonders of Physics
Lewin W and Goldstein W.
Vol. 23, no. 2 (Summer 2011): 57.
Geological Methods in Mineral
Exploration and Mining,
Second Edition
Marjoribanks R.
Vol. 23, no. 1 (Spring 2011): 58.
The Geology of Stratigraphic
Sequences, Second Edition
Miall AD.
Vol. 23, no. 1 (Spring 2011): 57.
Geophysical Characterization
of Gas Hydrates
The Blind Spot: Science and
the Crisis of Uncertainty
Geothermal Energy: Renewable
Energy and the Environment
Byers W.
Vol. 23, no. 4 (Winter 2011/2012): 47.
Glassley WE.
Vol. 23, no. 1 (Spring 2011): 55.
Bottled Lightning: Superbatteries,
Electric Cars, and the New
Lithium Economy
Hidden Costs of Energy: Unpriced
Consequences of Energy
Production and Use
Pielke R Jr.
Vol. 23, no. 1 (Spring 2011): 56.
Plate Tectonics: Continental Drift
and Mountain Building
Sreekantan BV (ed).
Vol. 23, no. 2 (Summer 2011): 57.
Deutsch D.
Vol. 23, no. 4 (Winter 2011/2012): 47.
The Climate Fix: What Scientists
and Politicians Won’t Tell You
About Global Warming
Kaku M.
Vol. 23, no. 2 (Summer 2011): 56.
Hefferan K and O’Brien J.
Vol. 23, no. 1 (Spring 2011): 58.
Riedel M, Willoughby EC and
Chopra S (eds).
Vol. 23, no. 3 (Autumn 2011): 58.
Fletcher S.
Vol. 23, no. 4 (Winter 2011/2012): 49.
Petroleum Resources with
Emphasis on Offshore Fields
The National Research Council.
Vol. 23, no. 1 (Spring 2011): 56.
Information and the Nature of
Reality: From Physics to
Metaphysics
Krauss LM.
Vol. 23, no. 1 (Spring 2011): 57.
The Strangest Man:
The Hidden Life of Paul Dirac,
Mystic of the Atom
Farmelo G.
Vol. 23, no. 2 (Summer 2011): 58.
Street-Fighting Mathematics: The
Art of Educated Guessing and
Opportunistic Problem Solving
Mahajan S.
Vol. 23, no. 1 (Spring 2011): 56.
The Techno-Human Condition
Allenby BR and Sarewitz D.
Vol. 23, no. 4 (Winter 2011/2012): 48.
The Theory That Would Not Die:
How Bayes’ Rule Cracked the
Enigma Code, Hunted Down
Russian Submarines, and Emerged
Triumphant from Two Centuries of
Controversy
McGrayne SB.
Vol. 23, no. 4 (Winter 2011/2012): 48.
The Unfinished Game: Pascal, Fermat, and the Seventeenth-Century
Letter That Made the World Modern
Devlin K.
Vol. 23, no. 1 (Spring 2011): 58.
The Weather of the Future:
Heat Waves, Extreme Storms,
and Other Scenes from a ClimateChanged Planet
Cullen H.
Vol. 23, no. 2 (Summer 2011): 58.
Why Geology Matters: Decoding
the Past, Anticipating the Future
Macdougall D.
Vol. 23, no. 4 (Winter 2011/2012): 48.
Wrestling with Nature: From
Omens to Science
Harrison P, Numbers RL and
Shank MH (eds).
Vol. 23, no. 4 (Winter 2011/2012): 49.
Davies P and Gregersen NH (eds).
Vol. 23, no. 1 (Spring 2011): 55.
Oilfield Review