Oilfield Review Spring 2011

Oilfield Review
Spring 2011
Offshore Pipelines
Managed Pressure Drilling
Formation Water
Dielectric Logging
11-OR-0002
Understanding the E&P Challenge—Defining the Basics
The supply of safe, affordable and transportable energy is
one of the fundamental prerequisites for global economic
development. For more than a hundred years, hydrocarbonbased fuels—including oil, coal and gas—have made up
the bulk of the world’s energy needs and today remain the
only viable option for meeting up to 80 percent of the
world’s energy demand forecast to 2030. For the exploration
and production of oil and gas, this dependence represents
two major challenges.
First, it is becoming much harder to ensure future supply. The E&P industry is investing heavily to maximize production from existing reserves, while simultaneously
developing new resources in more challenging environments such as the arctic and deep water. It is also increasing exploration and production in unconventional reserves
such as shale gas, shale oil and heavy oil.
Second, it has become imperative that we protect
and preserve our environment. E&P activities must
leave a smaller operational footprint and provide
greater assurance against environmental damage, particularly as the industry continues to explore more
sensitive ecological environments.
Given this context, the industry is becoming increasingly
dependent on technology as an enabler for future supply.
Technologies deployed in E&P activities today offer exceptional breadth and depth compared with the technologies
of only a few decades ago. This is exciting from the perspective of young professionals who are joining the E&P
industry today, but technology, because of its complexities,
can also create barriers to understanding.
In this issue of Oilfield Review, we are launching a
series of articles that details the underlying concepts and
technologies on which the E&P industry is built. These
“Defining …” articles are written to be accessible to a
wider audience than the E&P professionals who typically
read Oilfield Review.
The first article is “Defining Logging” (see “Discovering
the Secrets of the Earth,” page 60). We chose this topic to
lead the series because it reflects the origin of Schlumberger
in subsurface logging. In the next few issues, we will introduce exploration, drilling, completions and production,
before moving into subtopics such as resistivity logging and
reservoir modeling.
I hope that you find these articles interesting and that
they provide you with a more in-depth knowledge of the
technical challenges and technological solutions that
encompass the E&P cycle. In addition, it is important
that we attract young professionals who are motivated to
pursue these challenges for the long term because our
industry has a major role to play in the sustainable
energy future.
Paal Kibsgaard
Chief Operating Officer
Schlumberger Limited
Paal Kibsgaard is Chief Operating Officer of Schlumberger Limited. Prior to
his most recent position as president of Reservoir Characterization, he held a
variety of global management positions including vice president of Engineering,
Manufacturing and Sustaining; vice president of Personnel for Schlumberger
Limited; and president of Schlumberger Drilling & Measurements. Earlier in his
Schlumberger career, he was a GeoMarket* manager for the Caspian region
after holding various field positions in technical sales and customer support.
A petroleum engineer with a master’s degree from the Norwegian Institute of
Technology, Paal began his career in 1992 working for ExxonMobil. He joined
Schlumberger in 1997.
* GeoMarket is a mark of Schlumberger.
1
Schlumberger
Oilfield Review
www.slb.com/oilfieldreview
Executive Editor
Mark A. Andersen
Advisory Editor
Lisa Stewart
1
Understanding the E&P Challenge—Defining the Basics
Editorial contributed by Paal Kibsgaard, Chief Operating Officer, Schlumberger Limited
Senior Editors
Matt Varhaug
Rick von Flatern
Editors
Vladislav Glyanchenko
Tony Smithson
Contributing Editor
Ginger Oppenheimer
Design/Production
Herring Design
Mike Messinger
Illustration
Chris Lockwood
Tom McNeff
Mike Messinger
George Stewart
4
Pipeline to Market
Pipelines provide an economical and reliable means of
transporting oil and gas to market, and are as vital to the
development of offshore oil and gas resources as are the
wells and platforms they support. The pipeline industry must
meet a broad range of technical challenges as it expands this
key infrastructure.
Printing
Wetmore Printing Company
Curtis Weeks
14 Managed Pressure Drilling Erases the Lines
Increasingly complex wellbores make it ever more difficult to
stay within prescribed bottomhole pressures using traditional
drilling methods. Managed pressure drilling techniques offer
drillers a method for maintaining a BHP that is neither too
high nor too low.
Managed pressure
drilling
On the cover:
An engineer prepares a dielectric tool
to run into a well. The caliper arm (right )
pushes the articulated pad (left ) securely
against the borehole wall. The pad’s
transmitters send out microwaves that
return to multiple receivers also located
on the pad. Transmitter-receiver spacing,
electromagnetic-field orientation and
fluids in the pores determine shape and
depth of the sensed region (inset ).
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.
© 2011 Schlumberger. All rights reserved.
Reproductions without permission are
strictly prohibited.
For a comprehensive dictionary of oilfield
terms, see the Schlumberger Oilfield
Glossary at www.glossary.oilfield.slb.com.
Spring 2011
Volume 23
Number 1
ISSN 0923-1730
Advisory Panel
Abdulla I. Al-Kubaisy
Saudi Aramco
Ras Tanura, Saudi Arabia
24 Finding Value in Formation Water
Formation water analysis is a crucial step in hydrocarbon
exploration and production. It provides input to petrophysical
evaluation, helps assess potential for corrosion, scaling and
souring, and aids in the understanding of reservoir connectivity.
This article explains the causes of variation in formation
water chemistry—between formations and over time. Case
studies highlight methods for ensuring sample purity and
demonstrate applications of downhole and laboratory evaluation techniques.
Dilip M. Kale
ONGC Energy Centre
Delhi, India
Roland Hamp
Woodside Energy Ltd.
Perth, Australia
George King
Apache Corporation
Houston, Texas, USA
Richard Woodhouse
Independent consultant
Surrey, England
36 Zapping Rocks
3
ke
ca
R XA
ud
4
M
R XA
2
ob
pr
R XA
e
R XA
1
TA
TB
Dielectric logging tools provide supplemental information for
analyzing freshwater reservoirs and identifying movable hydrocarbons. A recently introduced tool offers a dielectric dispersion measurement to evaluate rock texture in carbonates and
shale effects in siliciclastics. Case studies from freshwater,
heavy-oil and carbonate reservoirs illustrate applications of
dielectric data.
Alexander Zazovsky
Chevron
Houston, Texas
R XB
1
R XB
2
R XB
3
R XB
4
53 Contributors
55 New Books and Coming in Oilfield Review
60 Defining Logging:
Discovering the Secrets of the Earth
Editorial correspondence
Oilfield Review
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Oilfield Review is pleased to welcome
Alexander Zazovsky to its editorial advisory panel. He is Completions Engineering
Advisor and Research Consultant at
Chevron in Houston, where he is responsible for managing and leading technology
development and technical services projects. Prior to joining Chevron in 2011, he
was an engineering advisor for
Schlumberger in Sugar Land, Texas.
Alexander received an MS degree in
applied mathematics, a PhD degree in
fluid mechanics, and a doctorate of technical sciences in petroleum engineering
(Habilitation), all from Gubkin Russian
State University of Oil and Gas in
Moscow. He began his career in Moscow,
where he worked at the Research Institute
of Nuclear Geophysics and Geochemistry,
the Institute for Problems in Mechanics of
the Academy of Sciences, the All-Union
Oil Institute for Scientific Research
(VNIIneft), and the Oil and Gas Research
Institute of the Academy of Sciences.
Next, Alexander worked at the Laboratoire
d’Aérothermique du CNRS, Meudon,
France, as an invited scientist before joining Schlumberger in 1993. He has been
editor of several professional journals and
a consulting editor of the Russian edition
of Oilfield Review.
3
Pipeline to Market
Alexander P. Albert
Houston, Texas, USA
The success of every prospect depends as much on an operator’s ability to move oil
Daniel L. Lanier
Geoscience Earth and Marine Services, Inc.
Houston
pipelines offer the most economical and dependable means of transporting hydro-
Brian L. Perilloux
Williams Midstream Services, LLC
Houston
and gas to market as it does on getting the product out of the ground. In many regions,
carbons from wellhead to refinery. Pipeline companies go to great lengths to safely
install and operate their transmission systems.
Andrew Strong
Southampton, Hampshire, England
Oilfield Review Spring 2011: 23, no. 1.
Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to Kamran
Akbarzadeh, Edmonton, Alberta, Canada; Michael Carney,
Houston; Marsha Cohen, Terra et Aqua magazine, The
Hague; Julie Gentz, The Williams Companies, Inc., Tulsa;
Stelios Kyriakides, The University of Texas at Austin;
Domitille Lucereau, La Défense, France; Frank McWilliams,
Tata Steel International, Sugar Land, Texas; and Matt Pond,
Corrosion Resistant Alloys, Houston.
Integriti Platinum, PIPESIM and RealView are marks
of Schlumberger.
1. For more on infield pipeline systems: Amin A, Riding M,
Shepler R, Smedstad E and Ratulowski J: “Subsea
Development from Pore to Process,” Oilfield Review 17,
no. 1 (Spring 2005): 4–17.
2. Codes and practices for subsea pipeline design,
construction and inspection have been published by a
number of technical institutes, such as the American
National Standards Institute, American Petroleum
Institute, American Society of Mechanical Engineers,
Det Norske Veritas, Institution of Gas Engineers and
Managers, and United Kingdom Offshore Operators
Association. A listing of various international codes can
be found in the UK Health and Safety Executive: “Use of
Pipeline Standards and Good Practice Guidance,” http://
www.hse.gov.uk/pipelines/resources/pipelinestandards.
htm (accessed November 25, 2010).
3. Connelly M: “Deepwater Pipelines—Taking the
Challenge to New Depths,” Offshore Magazine 69,
no. 7 (July 1, 2009): 94–97.
4. MacPherson H: “Unique Challenges in Managing
Deepwater Pipeline Integrity,” PetroMin Pipeliner 5,
no. 3 (July–September 2009): 14–25.
5. KCI Publications (ed): “Clad Pipes: Growing Market
Increasing Requirements,” Stainless Steel World 20,
(January–February 2008): 18–21.
4
In response to maturing production in established
onshore and shallow-water basins, many E&P
companies are extending their quest for reserves
toward deeper offshore prospects. Drilling and
completion confirm prospect viability, then set
the stage for platform construction and placement. Even after the wells are tied in to the platform, the job is far from finished.
Some method of transporting the product to
market must be put in place. In developed areas
supported by an established infrastructure, this
often calls for installation of a few kilometers of
export line to tie a platform to an existing pipeline. In frontier areas, operators must either lay
extensive pipeline systems over several kilometers, or rely on ships—typically shuttle tankers
from a floating production, storage and offloading
(FPSO) vessel—to move the product to a receiving terminal. From there, it is usually piped to a
refinery. Until a means of transport is available,
hard-won reserves are simply stranded, and operators must leave those reserves in the ground.
Pipeline companies strive to keep pace with
E&P companies as they move deeper offshore.
To do so, the pipeline industry must design and
install pipeline systems that can push high-temperature, high-pressure fluids uphill over long
distances in a deep, dark, high-pressure, lowtemperature environment.
Even in the face of such challenges, the pipeline industry continues to break records. In 2000,
a 64-km [40-mi] pipeline laid to service the
Hoover-Diana project in the Gulf of Mexico,
reached water depths of 1,450 m [4,800 ft]. By
2005, the Blue Stream project had installed
386 km [240 mi] of twin pipelines in depths of
2,150 m [7,050 ft] in the Black Sea. In 2008,
206 km [128 mi] of pipeline at the Perdido Norte
project was laid between the Alaminos Canyon
and East Breaks areas of the Gulf of Mexico, in
record depths ranging from 1,067 m to 2,530 m
[3,500 ft to 8,300 ft]. The Galsi pipeline, slated for
construction in 2011, will stretch beneath the
Mediterranean Ocean from Algeria to Sardinia,
and is expected to set a new depth record of
2,824 m [9,265 ft]. Distance records are also
being set. Between 2004 and 2007, the Langeled
gas pipeline was laid between Norway and
England; at 1,173 km [729 mi], it is the world’s
longest subsea pipeline.
Whether it sets a record or not, each pipeline
has unique characteristics. Product chemistry
largely dictates metallurgy, while pipeline length
and depth gradients dictate operating pressures
and flow rates, both of which in turn influence
pipeline diameter and wall thickness. These
design considerations have a direct bearing on
operation and maintenance practices. This article
provides a broad overview of offshore pipeline construction, operations and monitoring activities.
Oilfield Review
Platform
Riser
Wellhead
Gathering line
Manifold
> Pipeline segments. Infield lines (pink) run from the wellhead to the platform or other preliminary gathering and processing facility. Export, or sales, lines
(green) run downstream from the platform.
Design Considerations
Pipeline systems consist of all the pipe, valves,
pumps, meters and facilities through which production streams are transported. These systems
can be divided into distinct segments (above).
Infield lines are relatively small-diameter pipelines (less than 16 in.) consisting of flowlines,
gathering lines and risers, which run between the
wellhead and the production platform or FPSO.1
The infield lines transport a raw, unrefined well
stream, usually consisting of a multiphase mixture
of gas, oil and water from oil wells; or the lines
transport gas, natural gas liquids and water from
gas wells. Export pipelines, also called trunklines
or transmission or sales lines, generally consist of
larger diameter pipelines (ranging from 16 in. to
44 in.) for transporting processed fluids to shore
from one or more fields. The processed stream,
having undergone separation and initial treatment
aboard a production platform or FPSO, usually
consists of oil with minor amounts of water, or of
gas and condensate. These pipelines typically tie
in to onshore pipelines that transmit the fluids to
refineries located farther inland.
Pipelines are built in accordance with stringent codes and standards.2 Design requirements
for subsea pipelines must account for a variety of
factors, including projected length, water depth
Spring 2011
and temperature, the composition and flow rate
of fluids carried by the pipeline as well as the
topography on which the pipeline will be laid.
These factors will ultimately impact the pipeline
costs, manufacturing processes, pipe-lay techniques and operating strategies.
Pipelines are designed to withstand the internal pressures generated by a specified rate of
flow. However, in deep waters, internal pressure
concerns are secondary to the need for pipelines
to withstand external collapse pressures imposed
by water depth—especially during the installation phase when no fluids are being pumped
through the pipeline. Resistance to hydrostatic
collapse is governed by the ovality and the compressive strength afforded by the pipe’s metallurgy and wall thickness.3 Thus, while internal
pressure dictates pipe thickness in conventional
settings, hydrostatic pressure is the dominant
influence on thickness in deepwater pipelines.
While burst and collapse pressures are prime
drivers, pipeline design must also consider other
factors. A study of Gulf of Mexico pipelines showed
that the single most significant cause of damage to
pipelines is corrosion.4 The composition and temperature of fluids transmitted through a pipe can
affect its susceptibility to internal corrosion, thus
metallurgy becomes a significant design consideration—not only for strength but for offsetting the
threat of corrosion. Infield lines transport unprocessed fluids; these fluids may contain hydrocarbons mixed with a corrosive blend of water, carbon
dioxide, chlorides or hydrogen sulfide [H2S], often
at elevated temperatures. And conditions generally change over time as reservoir depletion alters
the fluid mixture.
The pipeline industry has developed a variety
of approaches to mitigate corrosion problems.
Some pipeline designs increase pipe wall thickness to compensate for the expected loss of metal
caused by corrosion. Others use corrosion-resistant alloys (CRAs). These alloys combine metals
such as stainless steel, chrome, nickel, iron, copper, cobalt, molybdenum, tungsten or titanium.
CRAs resist corrosion more effectively than carbon-steel pipe, and are chosen based on their
resistance to specific produced fluid properties.
Although resistant to corrosion, CRAs may not
have the tensile and compressive strength of
carbon-steel pipe.
CRA cladding can be used to line the inside of
the pipe. In such cases, the carbon-steel outer
pipe withstands the internal and external pressure, while the alloy cladding provides corrosion
protection.5 CRA selection must also take into
consideration the strength, toughness and weldability of the alloy.
5
Second coating
First coating
Pipe
> Fusion-bonded epoxy coating. To protect pipe from corrosion and
mechanical damage, epoxy resin coatings are electrostatically applied to
the steel pipe. The resin is applied at temperatures up to 110°C [230°F]; it
then hardens thermoplastically. Typical thickness ranges from 350 um to
450 um. A second layer may be applied for additional protection.
(Illustration courtesy of EUROPIPE GmbH.)
In combination with corrosion-resistant metallurgy, chemical inhibition is often employed to
mitigate corrosion: This technique introduces
chemical additives into the production stream to
reduce the fluid’s corrosiveness.
Pipelines are susceptible to external
corrosion—for subsea pipelines, the primary
culprit is seawater, an efficient electrolyte that
promotes aqueous corrosion. All metals and
alloys in this environment are subject to corrosion, depending on their individual electrical
potential and the pH of the seawater. The electrochemical reaction that causes corrosion can be
mitigated to an extent by cathodic protection.6
However, with increasing depth, water temperature falls, decreasing conductivity, hence
decreasing the effectiveness of anodes intended
to protect the pipeline.
Water
current
Pipe
In addition, design specifications must preclude biochemical reactions. Sulfate-reducing
bacteria in marine silts generate H2S, which can
attack pipelines; other organisms, such as limpets or barnacles, can rasp or bore into unprotected metals. To ward off the ravages of the
subsea environment and extend the life of pipelines, fusion-bonded epoxy (FBE) or other external coatings may be employed in conjunction
with cathodic protection (above).
Pipeline design must also thwart fatigue—
progressive, localized damage caused by cyclic
loading of the pipe. One form of cyclic loading
can be caused by vortex-induced vibrations
(VIVs) as water currents flow above and below
unsupported pipeline spans. These freespans
result as the pipeline crosses dips and valleys in
the seabed terrain or as water currents scour and
Eddies
> Pipe strakes. Water currents flowing past unsupported spans create eddies on the trailing side of
the pipe (inset). As the vortices break away from the pipe, they set up vibrations that can cause the
pipe to fail through cyclic loading. VIV strakes can be strapped to the outside of the pipe (yellow) to
break up the flow of the water current, forcing vortices well beyond the pipeline. (Illustration courtesy
of Mark Tool & Rubber Co. Inc.)
6
erode the seabed beneath unburied pipelines.
VIV suppression devices, such as helical fin
strakes and fairings, can be used to protect
freespans from hazards created by ocean currents (below left).
Thermally induced stress is another problem.
The flow of hot crude oil through a pipeline can
result in metal expansion, which may cause the
pipeline to shift position. In a straight line
between two fixed and immobile points, such
movement could result in catastrophic failure in
the pipeline system. However, engineers can compensate for expansion and contraction by planning a gently meandering pipeline that permits
lateral movement along the line; this configuration can even dampen the effects of movement
caused by earthquakes and mudslides.
Pipe Manufacture
The pipe used for building pipelines is known as
line pipe. Most line pipe is made of carbon steel;
often specific alloys are chosen to attain crucial
mechanical and metallurgical properties, and
stainless steel may be used on occasion.7 The
mechanical property requirements for pipeline
steel are very stringent, demanding high strength,
ductility, toughness, corrosion resistance and
weldability in a single grade of steel. Line pipe
design properties are achieved by carefully regulating alloy chemistry and thermo-mechanical
processing during production. Quality control is
monitored throughout the production process,
from the steel mill to the pipe yard.
Line pipe specifications often call for specialized processes, from the casting of steel slabs to
the subsequent rolling of the plates into strips
that are shaped into the pipe. Much of the process is computer controlled, then checked by a
comprehensive array of nondestructive tests,
including ultrasonic, magnetic particle, and
X-ray evaluations of thickness and welds.
Line pipe is either seamless or seam welded.
Seamless pipe can be manufactured up to about
16 in. OD. The seam-welded variety is commonly
manufactured in sizes ranging from 16 in. to
64 in. OD.
Most seamless pipe starts as cast ingots or billets that are heated in a rotary hearth furnace,
then pierced by a center punch. The pierced
ingot goes to a pierce rolling mill where it is
lengthened as its diameter and wall thickness are
reduced. A mandrel is inserted in the annulus of
the hollow ingot to hold and shape the ingot as it
passes through a series of rollers and then is
passed to a specialized mill to achieve exact pipe
shape, thickness and diameter.
Oilfield Review
Seam-welded pipes start with coils of steel,
which are split into widths that conform to the
requisite pipe diameter. They are then rolled and
pressed to form plates of specific size and thickness. The plates are cold formed to create a tubular shape whose seam is welded shut to create
the pipe.
Finished pipes are subjected to hydrostatic
testing, followed by a variety of mechanical tests
that measure hardness, tensile strength and other
properties. To protect against corrosion, the line
pipe may be coated with a layer of epoxy. Each pipe
is then individually numbered and issued a certificate that documents its metallurgy, physical properties and manufacturing history.
Pipeline Routing
Subsea pipeline routing must account for local
geography and the attendant vagaries of meteorologic and geologic hazards presented by hurricanes, tsunamis, subsea earthquakes, mudslides,
strong currents and erosion. Pipeline routing has
a direct bearing on the cost and feasibility of any
production project. The route is ultimately a compromise that considers:
sTHENEEDFORMINIMIZINGTHELENGTHOFTHEPIPEline while reducing the need for presweeping of
rock or debris that could damage the pipeline
sMINIMIZINGTHENEEDFORTRENCHINGBURYINGAND
freespan remediation
sAVOIDINGPIPELINECROSSINGS8
Pipeline route selection involves far more than
simply running a straight line between two points.
Route design must consider the topography and
stability of the sediments on which the pipeline is
to be laid, its impact on benthic communities, the
effects of shipping, fishing, drilling and construction activities and the presence of existing pipelines that may cross the path of the proposed
pipeline.9 Furthermore, routes may be influenced
by uneven or rugged seafloor topography, which
increase the potential for freespans and failure
from VIV or bending stress (above right). Uneven
terrain also contributes to severe terrain-induced
pressure fluctuations as hydrocarbons are pumped
up and down steep slopes.10
Long before a potential route is surveyed, a
preliminary desktop survey is carried out. The
desktop evaluation maps geopolitical boundaries,
existing pipelines, offshore structures, environmentally sensitive areas, archeological sites,
restricted areas and known geologic or oceanic
hazards that may lie between the pipeline’s proposed starting point and its landfall. It lays out
prescribed seabed coring intervals, and indicates
Spring 2011
Freespan
> Freespan. Uneven topography or seabed erosion by water scouring beneath a pipeline can cause
freespans. To prevent pipeline problems associated with freespans, the low areas may be filled in with
rock using vessels designed especially for this purpose.
where bottom conditions or routing requirements call for additional sediment samples. This
preliminary assessment is instrumental in developing a proposed pipeline route, identifying areas
that require more-detailed evaluations and
determining how the subsequent preinstallation
survey will be conducted. Thus, for example,
when a desktop assessment identifies a known
ordnance dumping zone near the pipeline route,
it would call for a visual survey to be conducted
using a remotely operated vehicle (ROV).
Next, a seafloor survey contractor conducts a
preinstallation survey and maps the locations of
any shallow hazards, seafloor obstructions,
archeological evidence and benthic communities
along the proposed route. The preinstallation
survey covers a wide swath, which includes an
offset on either side of the proposed pipeline
path to cover areas that pipe-lay barge anchors
might disturb. This swath also creates a margin
for fine-tuning the proposed route without need
for resurveying each adjustment. In deep water,
the standard swath is about 760 m [2,500 ft] wide.
The surveys assess geologic and man-made
features on the seafloor and in the shallow subsurface. Seafloor geologic hazards include boulders, fault scarps, gas vents, reefs and unstable
slopes; subsurface geologic hazards include gascharged sediments, abnormal pressure zones and
buried channels. Man-made obstructions include
pipelines, wellheads, shipwrecks, ordnance, communication cables, wellheads and debris from
previous oil and gas activities.
Surveys play an important role in protecting
the marine environment. They are useful in identifying high-density accumulations of deepwater
benthic inhabitants such as chemosynthetic
communities, corals and hardbottom communities. Chemosynthetic communities, in particular,
are unlike most other life on Earth. They utilize
chemical energy from hydrocarbons and create
colonies of unusually high biomass compared
with the surrounding sea bottom.11 These communities are thought to be closely linked with geologic faults, natural hydrocarbon seeps and
hydrocarbon-charged sediments.
6. Cathodic protection is a technique used to minimize the
rate of corrosion of a pipeline or other metal structure.
This technique does not eliminate corrosion; rather,
it transfers corrosion from the protected structure to
sacrificial anodes (plates or metal bars) that can be
replaced. Cathodic protection relies on the electrochemical nature of corrosion, whereby electrical current
is discharged through sacrificial anodes that corrode
instead of the pipeline.
7. Kyriakides S and Corona E: Mechanics of Offshore
Pipelines, Volume I: Buckling and Collapse. Amsterdam:
Elsevier, 2007.
8. Bai Y and Bai Q: Subsea Pipelines and Risers.
Amsterdam: Elsevier, 2005.
9. Benthic communities consist of organisms that live near
or on the bottom of a body of water.
10. Cranswick D: “Brief Overview of Gulf of Mexico OCS Oil
and Gas Pipelines: Installation, Potential Impacts, and
Mitigation Measures,” New Orleans: US Department of
the Interior Minerals Management Service, OCS Report
MMS 2001-067, August 2001.
11. MacDonald IR (ed): “Stability and Change in Gulf of
Mexico Chemosynthetic Communities. Volume II:
Technical Report,” New Orleans: US Department of the
Interior, Minerals Management Service, OCS Study
MMS 2002-036, 2002.
7
Bow anchors
Lateral
anchors
Stern anchor
Laid pipeline
Direction of travel
Chain
Anchor
> Shifting anchors. A conventionally moored lay barge pays out pipeline over the stern as it advances
by winching ahead on its forward anchors and easing out anchor chain at the stern. Some anchors,
especially the lateral anchors, may be dragged sideways in the process, and eventually all anchors
will be reset by an anchor-handling vessel.
For their protection, bottom-dwelling communities generally require buffer zones of several
hundred feet. Benthic dwellers can be adversely
affected by pipe laying and attendant anchorhandling activities. Beyond the actual impacts of
pipeline touchdown, anchors and associated
ground tackle, there is also potential harm
caused by disturbance and resuspension of sediment resulting from these activities. Survey
results can be helpful in planning buffer zones.
Government approval of pipeline permits is conditioned largely on what a seafloor survey reveals.
Surveys scrutinize the seafloor using a variety
of instruments prescribed by government regula-
> S-lay vessel. The Allseas Solitaire, the largest pipe-lay vessel in the world, is 300 m [984 ft] in length
overall, excluding stinger. This vessel is capable of laying pipe from 2 in. to 60 in. OD, and has a holding
force of 1,050 t, enabling it to lay the heaviest of pipelines. The framework extending over the stern controls
the angle of the stinger, shown raised above the water (inset). (Photographs courtesy of Allseas.)
8
tion. Survey instrumentation is keyed to a differential GPS navigation system to ensure positioning
integration of the various data. Generally this
instrumentation includes, at a minimum:
sMAGNETOMETER TO DETERMINE THE PRESENCE OF
pipelines and other ferromagnetic objects
sSIDESCAN SONAR TO RECORD CONTINUOUS IMAGES
that permit detection and evaluation of seafloor
objects and features within the survey area
sSHALLOWPENETRATION SUBBOTTOM PROlLER TO
determine the character of near-surface
geologic features within the upper 15 m (50 ft)
of sediment
sHIGHFREQUENCY SINGLE AND MULTIBEAM SWATH
echosounders for continuous water depth measurements, with multibeam backscatter data
providing seabed textural information.
Follow-on investigations often involve underwater cameras, video, coring or additional geophysical survey lines.
Should any of these instruments indicate the
presence of shipwreck debris or concentrations
of man-made objects such as bottles, ceramics or
piles of ballast rock, the discovery will prompt an
imposition of a buffer zone and cessation of further operations to prevent the site from being
disturbed. Archeological discoveries require
immediate notification of government authorities
who will assess the site for its potential historical
significance. Thus, surveys, by providing a means
of detecting geohazards, benthic communities
and archeological sites, allow pipeline operators
to make adjustments along the proposed route to
preclude damage of both the environment and
the pipeline.
Pipeline Fabrication and Construction
The pipeline industry’s migration from shallow to
deep water is exemplified by changes in vessel
design and capabilities. Just as drilling rigs have
evolved to handle greater water depths, pipe-lay
vessels have followed a similar progression, from
shallow-water lay barges to deep-draft ships and
semisubmersibles.
Lay barges have long been employed for pipeline installation in relatively shallow waters of
the Continental Shelf. Early barges were conventionally moored and relied on multiple anchors—
often 12 or more, depending on the size of the
vessel (above left). As the pipestring was paid out
over the stern, the vessel moved forward by reeling in anchor chain at the bow while easing it out
over the stern. Once all the anchor chain was
paid out, an anchor-handling vessel reset the
anchors before the pipe-lay vessel advanced.
Long anchor chains, however, decrease stationkeeping precision, thus the depth in which con-
Oilfield Review
ventionally moored lay barges can be used is
limited to around 1,000 ft [305 m].12
Deep waters call for pipe-lay ships or semisubmersibles that employ dynamic positioning
for station keeping. These vessels use multiple
thrusters—propellers that swivel azimuthally to
create opposing thrusts—to maintain their
desired position. The dynamic positioning systems
are usually driven by a computer system linked to
a satellite-based geographic positioning system.
Dynamic positioning requires significantly more
fuel than conventional mooring, but increases the
efficiency of the pipe-lay operation.13
Pipeline design—particularly diameter, thickness and metallurgy—dictates the maximum
tension, compression and bending stresses that a
pipe can sustain during installation. Likewise, to
avoid stress limits that could cause the pipe to
buckle during installation, the choice of installation technique is crucial. The selection is largely
governed by water depth; the most common are
the S-lay, J-lay, pipe-reel and tow-in techniques.
The S-lay technique—so designated because
the pipeline assumes an elongated S-shaped
profile as it is lowered from the vessel to the
seafloor—was originally developed for relatively
shallow waters. An S-lay vessel is distinguished
by a long stinger, a truss-like structure, which is
equipped with rollers and a tensioner (previous
page, bottom). The stinger is mounted off the
stern to support the pipe as it leaves the vessel.
On an S-lay vessel, individual joints of line pipe
are laid out horizontally, welded together, X-rayed
or ultrasonically inspected and coated with FBE
as the pipeline is built on deck.
Stinger configuration affects the bending
stresses that occur as the pipe is lowered to the
seafloor. The pipe departs the stinger at the liftoff
point, and contacts the seabed tangentially at the
touchdown point (above right). The pipe experiences the greatest stresses at the overbend, where
the pipe leaves the vessel, and in the sagbend,
which extends upward from the pipeline touchdown point on the seafloor. The curvature of the
overbend is controlled by the rollers on the stinger;
sagbend curvature is controlled by the tensioner
and vessel positioning.14
12. Cranswick, reference 10.
13. Kyriakides and Corona, reference 7.
14. Kyriakides and Corona, reference 7.
15. Kammerzell J: “Pipelay Vessels Survey Expands to
Include Worldwide Fleet,” Offshore Magazine 69,
no. 11 (November 2009).
16. Flowlines from Cheyenne field, set in 8,960 ft [2,731 m] of
water, were laid to the Independence Hub platform at
Mission Canyon Block 920 in the Gulf of Mexico.
17. A moonpool is an opening in the vessel hull designed to
permit the passage of equipment between the deck and
sea. A moonpool may be found on reel-lay vessels and
on certain J-lay vessels.
Spring 2011
Pipe overbend
Liftoff point
Stinger
Thrusters
Pipe sagbend
Touchdown point
> S-lay configuration. Bow and stern thrusters hold the pipe-lay vessel in
position while the pipeline is lowered onto the seabed. A long stinger
projects from the stern, and its configuration controls the angle between
the liftoff and touchdown points. (Illustration courtesy of Allseas.)
The S-lay method has evolved for operations
in ultradeep waters through modifications of the
stinger and tensioner system.15 Deep waters
require a steep liftoff angle to accommodate the
overbend segment, which can be achieved by a
longer and more curved stinger. To date, this
method has been used in waters as deep as
8,960 ft [2,731 m], and on such projects, the
stinger length can easily exceed 450 ft [137 m].16
The J-lay method was developed for laying
pipe in deep waters. J-lay vessels are distinguished by a near-vertical fabrication tower
(below). Lengths of pipe are positioned at the
uppermost station of the tower, where they are
vertically joined together at automated welding
stations. The pipe is then lowered to an ultrasonic inspection station and a field coating station before it passes through the moonpool and
into the water.17 On some vessels, a short stinger
extends beneath the hull to support the pipe
string, which takes on a J-shaped profile as it
contacts the seabed. This profile puts less bending stress on the pipe string in deep waters.
However, the J-lay method becomes impractical
for shallower waters, where depths of less than
200 to 500 ft [61 to 152 m] limit the shape of the
Welding station
Field coating
Tensioners
Suspended
pipe
Thrusters
Pipe sagbend
Touchdown point
> J-lay configuration. Pipe is raised to the top of the vertical tower, and
travels through welding, ultrasonic inspection and field-coating stations as
it is lowered toward the water. The J-lay method is suitable for deep water
because the pipeline is bent only once—at the seabed—and thus
experiences less stress during installation. The J-lay method is less suitable
for shallow waters because it imposes a bend that the pipe cannot
accommodate. (Adapted from Kyriakides and Corona, reference 7.)
9
Reels
DEEP BLUE
Moonpool
Thrusters
> Spoolbase. The Technip spoolbase near Mobile, Alabama, USA, is capable of handling and welding
pipe up to 18 in. OD for reel lay. The fabrication building houses two independent welding lines with
alignment, welding, nondestructive examination and field joint coating stations. Technip’s Deep Blue
pipe-lay vessel, docked at the end of the queue (upper left), is reeling aboard pipe. The vessel (inset),
is 677.5 ft [206.5 m] long, and is equipped with twin reels, 131 ft [40 m] in diameter, each capable of
carrying 2,800 t of rigid pipeline ranging from 4 in. to 18 in. OD. Flexible pipeline can be carried below
deck. (Graphics courtesy of Technip USA Inc.)
pipe angle and impose severe bending stresses on
the pipe.
Pipeline installation is also carried out by reel
ship. At an onshore spoolbase, long sections of
rigid steel pipeline, each about 1 km [0.62 mi]
long, are welded together (above). The welds are
inspected and coated with a resilient protective
coating of flexible epoxy or polyethylene, then
the pipe is spooled aboard a vessel-mounted reel.
After reeling the pipe on board, the ship departs
for the pipe-laying area.
There, the pipe is fed off the reel, straightened and anchored to the seabed. In deep waters,
the pipe may need to be tensioned to minimize
sag that would otherwise develop as the pipe is
lowered from the surface to the seabed. If the sag
bend becomes too severe, the pipe will buckle.
The ship then steams ahead at about one knot
[1.85 km/h, or 1.15 mi/h], depending on weather
conditions, as it slowly reels out the pipe. When
all pipe has been led off the reel, a bull-plug is
welded in place to seal the end of the pipe, then
it is lowered to the seabed. A buoy is attached to
mark the end of the pipe. The ship then proceeds
to port to replenish the reel or to take on a new,
fully loaded reel. Upon returning offshore, the
end of the previous pipeline is retrieved from the
seafloor, welded to the new line, and the process
is repeated.18
10
A fourth approach, called the tow-in method,
is used typically for insulated pipe-in-pipe or
bundled pipe assemblies. This method first calls
for welding, inspection, joint coating and anode
installation at an onshore fabrication facility. The
assembled pipe is then placed in the water and
submerged. Buoyancy tanks and chain weights
are usually attached to achieve neutral buoyancy.
Seagoing tugboats or offshore support vessels
then tow the pipe along a tightly controlled route
that has been surveyed to identify potential seafloor hazards.
The main advantages of the tow-in method are
that it permits complex or specialized fabrication
techniques to be carried out in controlled conditions at facilities ashore. However, the length of
the pipeline is also constrained by the space
limitations of the fabrication facility.19 This
method is especially suitable for bundled pipelines, where several pipe sections or umbilicals
are tied together and shrouded within a carrier
pipe. However, the tow-in method carries
increased risk that the pipeline could be damaged
through contact with a submerged obstruction.
A combination of techniques may be employed
over the course of the pipeline installation, particularly if water depths change drastically along
the proposed route. Perhaps the most challenging problem arises when an offshore pipeline
makes landfall and must be installed in the often
treacherous zone between land and sea.
To address the issue, a cofferdam can be
extended from the beach for hundreds of feet,
into near-shore waters. A dredge deepens the
seaward approach to enable a pipe-lay vessel to
reach the cofferdam. The cofferdam provides a
stable framework in which a concrete conduit
can be buried well below the depth of the existing
beach floor.
This approach was used to land the Langeled
pipeline at Easington, on the east coast of
England (next page). The 44-in. gas line approaches
shore in a pre-excavated offshore trench, dredged
some 12 mi [20 km] from shore, starting in water
120 ft [37 m] deep. As required in shallow waters,
to prevent anchor, trawl and dropped-object damage, the 6.5-ft [2-m] deep trench was backfilled
to bury the pipeline. For the shore crossing, a
temporary causeway had to be constructed during low tides using land-based heavy construction
equipment. This causeway provided access
through the intertidal zone for construction of a
787-ft [240-m] long sheet-piled cofferdam, built
alongside the causeway. Starting at a tie-in pit
located inland from the high-water mark, the cofferdam extended from the beach 200 ft [60 m]
beyond the low-tide level.20
An unstable cliff face stood between the beach
and a gas terminal. A tunnel-boring machine created a 1,247-ft [380-m] long concrete tunnel that
provided a conduit through the cliff to permit
access between the gas terminal, tie-in point and
cofferdam. The tunnel and cofferdam were completed in advance of the lay barge arrival. A 500-t
winch was then used to pull the pipeline from the
lay barge into the tie-in pit, and the pipe was tied
in 43 ft [13 m] below the low-tide level. Pipe welds
were inspected and coated as the offshore pipeline was tied in to the onshore line. Once the tunnel and pipeline were safely buried, the causeway
and cofferdam were removed and the site was
restored to its natural state, providing no visible
evidence of landfall for a pipeline that carries
nearly 20% of the UK’s demand for natural gas.
Operations and Maintenance
Deepwater pipelines operate in low water
temperatures under high hydrostatic pressures.
Despite this hostile setting, the life span of most
pipelines is 20 to 40 years, in part because
corrosion management strategies and attentive
pipeline monitoring are helping to increase
their longevity.
Oilfield Review
> Langeled pipeline landfall. The dredging vessel J.F.J. De Nul deepens the seaward approach toward a cofferdam extending from the beach. A temporary
sand causeway provides access to the cofferdam, which has been constructed of metal pilings situated on the right-hand side of this causeway. The
cofferdam stretches beyond the intertidal zone. (Photograph courtesy of Terra et Aqua magazine.)
A chief concern for deepwater pipeline engineers is the formation of solid compounds, such
as asphaltenes, hydrates and wax.21 Under certain
conditions, these compounds can increase fluid
viscosity and restrict flow within pipelines.
Pressure, temperature, fluid composition, pipe
surface, flow regime, and shear can affect the
deposition of waxes and asphaltenes. To precisely
understand how these individual parameters
affect deposition inside pipelines, Schlumberger
engineers have developed a testing cell.
The RealView live solids test cell measures oil
deposition in turbulent flow, with temperature
control from 4°C to 150°C [39°F to 302°F] and
pressure adaptability to 103 MPa [15,000 psi].
This deposition cell is suitable for testing sour,
H2S-entrained fluids. In closed batch mode, the
cell requires a sample volume of only 150 ml
[9.15 in.3] per test run, but can accept up to one
liter [61 in.3] for flow-through testing. The
Spring 2011
RealView test cell consists of a cylindrical vessel
with an axially centered heat source. The outer
wall of the vessel is stationary, and the inner wall,
or spindle, rotates to create either a turbulent or
laminar flow regime in the annular space.
Controls on this live solids deposition cell
enable precise and independent regulation of
pressure, temperature, differential temperature
and spindle speed. The deposits are collected
and then quantified using high-temperature gas
chromatography for wax deposit analysis.
Simulated distillation, a technique that uses gas
chromatography to simulate the distillation process in the laboratory, is employed for asphaltene
deposit analysis. Deposit mass is then used to
calculate a deposition rate. RealView live solids
deposition studies can help operators evaluate
the effects of chemical additives on deposits
under representative conditions. The RealView
experimental data can also be used in commercial software such as PIPESIM production system
analysis software to build wax- and asphaltenedeposition simulations. Armed with these results,
operators can fine-tune flow rates in their pipeline system, determine how frequently remedial
procedures need to be conducted and select the
optimal chemical treatment and dosage.
18. Kyriakides and Corona, reference 7.
19. As of 2007, the maximum length of towed-in pipeline was
7 km [4.35 mi]. Kyriakides and Corona, reference 7.
20. Vercruysse W and Fitzsimons M: “Landfall and Shore
Approach of the New Langeled Pipeline at Easington,
UK,” Terra et Aqua 102 (March 2006): 12–18.
21. For more on asphaltenes: Akbarzadeh K, Hammami A,
Kharrat A, Zhang D, Allenson S, Creek J, Kabir S,
Jamaluddin A, Marshall AG, Rodgers RP, Mullins OC and
Solbakken T: “Asphaltenes—Problematic but Rich in
Potential,” Oilfield Review 19, no. 2 (Summer 2007): 22–43.
Hydrates are discussed further in: Birchwood R, Dai J,
Shelander D, Boswell R, Collett T, Cook A, Dallimore S,
Fujii K, Imasato Y, Fukuhara M, Kusaka K, Murray D
and Saeki T: “Developments in Gas Hydrates,”
Oilfield Review 22, no. 1 (Spring 2010): 18–33.
11
> Smart pig. Pipeline inspection gauges were originally created to remove internal buildup and
maintain flow. Modern pigs are sophisticated devices that closely measure a pipe’s internal surfaces,
weld integrity, state of cathodic protection and corrosion. Using magnetic flux leakage and ultrasonic
testing technology, this pig can detect metal loss and pipeline wall features in a single inspection run.
This device runs in 16-in. pipelines and is approximately 3.6 m [11.8 ft] long. (Photograph courtesy of
ROSEN Group.)
Some pipelines require insulation or heating
to meet proper thermodynamic conditions. Many
pipelines rely on chemical injections of inhibitors
or solvents, such as ethylene glycol, tri-ethylene
glycol or methanol. Operators also routinely
resort to a mechanical approach to remove buildups from their pipelines.
Pipeline inspection gauges, or pigs, are
plunger-like devices that clean the inner walls of
the pipeline. Pigs are available in various sizes,
shapes and materials, ranging from metal pipe
scrapers and flexible brushes to plastic foam
spheres. Most have an outside diameter nearly
equal to the inside diameter of the pipe to ensure
a fairly tight fit. Some pigs are equipped with sensors (above). These “smart pigs” are even capable of detecting internal corrosion or locating
leaks in pipelines.22
A pig is forced through the pipeline by exerting pressure on a gas or liquid to the back, or
upstream end, of the pig. As the pig travels downstream, it scrapes the inside of the pipe and
sweeps any accumulated buildup or liquids ahead
of it. These are collected, along with the pig, at
the end of a segment of pipe known as a pig trap.
22. Cranswick, reference 10.
23. Det Norske Veritas: “Selection and Use of Subsea Leak
Detection Systems,” Høvik, Norway, Recommended
Practice DNV-RP-F302, April 2010.
24. For more on fiber-optic DTS: Brown G: “Downhole
Temperatures from Optical Fiber,” Oilfield Review 20,
no. 4 (Winter 2008/2009): 34–39.
12
Routine pigging operations remove deposits
in the pipe as a normal part of production operations. The frequency of pigging varies with flow
rates, operating temperatures and nature of the
produced fluid, and may be carried out on weekly,
monthly or less frequent intervals.
Monitoring at the Speed of Light
Operators monitor the integrity of pipelines to
ensure their continued performance, protect the
environment and prevent product loss. There are
two approaches to monitoring pipelines. Periodic
inspection and surveying use mobile units such as
pigs, ROVs or autonomous underwater vehicles
(AUVs). Continuous monitoring involves permanently installed leak detection sensors.
A variety of sensor technologies has been
adapted for subsea pipeline monitoring.23 These
include the following:
s#APACITIVE SENSORS MEASURE CHANGES IN THE
dielectric constant of the medium surrounding
the sensor. The capacitor is formed by two
concentric, insulated capacitor plates. The
sensor’s capacitance is directly proportional to
the dielectric constant of the medium between
the capacitor plates. Because the dielectric
constants of seawater and hydrocarbons differ,
direct contact with hydrocarbons will register
as a change in measured capacitance.
s&LUORESCENCE DETECTORS USE A LIGHT SOURCE TO
excite molecules in the target material to a
higher energy level. When those molecules
relax to a lower state, light is emitted at a different wavelength, which is measured by a fluorescence detector.
s-ASS BALANCE METHODS MONITOR THE PRESSURE
drop between two or more pressure sensors
installed in the pipeline.
s-ETHANE SNIFFERS RELY ON THE DIFFUSION OF DISsolved methane through a membrane and into
a sensor chamber, where the dissolved methane changes the electrical resistance, which
generates a signal from the detector. A variation on this method uses optical nondispersive
infrared spectrometry. Using this method, the
methane concentration is measured as the
degree of absorption of infrared light at a certain wavelength, in which the intensity of infrared light at the detector is a measure of the
methane concentration.
s0ASSIVE ACOUSTIC SENSORS USE HYDROPHONES TO
measure the pressure of a sound wave generated by a rupture or leak as it is transmitted
through a structure or water. By using more
than two sensors to measure the arrival time of
sound, it is possible to triangulate on the origin
of the sound.
s3ONAR DETECTORS EMIT PULSES OF SOUND THAT
are reflected by impedance changes between
different media. The impedance depends on
sound velocity, density, salinity and temperaTUREOFTHEMEDIUM&LUIDSOFDIFFERENTDENSITY
such as water and hydrocarbons, will have
different acoustic impedance.
s6IDEOCAMERASENABLEVISUALSURVEILLANCEOFTHE
subsea system.
Ideally, a monitoring system would continuously detect and locate conditions that might
forewarn operators of potential troubles anywhere along the pipeline, then combine and
interpret the outputs of multiple measurements
in a meaningful, prioritized display. These capabilities have been incorporated into fiber-optic
monitoring systems that are being installed in
offshore and onshore pipelines worldwide.
Optical-fiber sensors have an established
track record of reliability, and distributed temperature sensors (DTS) have been in use since
the mid-1980s. This type of sensor uses the optical fiber itself as both the sensing element and
the data highway back to the controller. These
sensors are based on optical time domain reflectometry (OTDR), a proven technique long used in
the telecommunications industry. DTS systems
are able to make precise temperature measurements every few meters along the optical fiber for
distances up to 100 km [62 mi]. More-localized
measurements use a technology known as fiber
Bragg gratings, which performs highly precise
Oilfield Review
measurements of parameters such as strain and
temperature using optical gratings inscribed in
the core of the optical fiber.24
The Integriti Platinum fully integrated pipeline monitoring system uses fiber-optic technology to help pipeline operators monitor conditions
along the length of the pipeline. Continuous temperature, strain and vibration measurements
enable the detection of a wide range of events
that may threaten a pipeline’s integrity. This
fiber-optic system uses variations on the DTS
theme: Distributed strain temperature sensors
(DSTSs) have been developed for monitoring
strain; distributed vibration sensors (DVSs) measure vibrations or acoustic signals along the optical fiber. The Integriti Platinum system can
measure temperature variations of 2°C [3.6°F]
across 100 km of pipeline and measure strain
with a resolution of 40 microstrain at 10-m [33-ft]
intervals. The integrated sensors can detect and
locate small pipeline leaks that are below the
threshold of traditional leak detection systems
based on pipeline flow rate—typical gas leak
response time is just 30 s. The system can be used
for a number of monitoring applications.
Onshore pipeline operators have used the
DVS capability to detect the approach of heavy
equipment, thus warning of digging and construction activity taking place near their pipeline. The vibration sensors are sensitive enough
to detect human foot traffic. Offshore or onshore
gas leaks may initially be detected by DVS, which
identifies the characteristic noise of escaping
high-pressure gas and issues an alert. This event
can be followed by DTS or DSTS detection of
localized Joule-Thomson cooling. Fluid leaks and
flow assurance problems are detected by the temperature anomalies sensed by DTS or DSTS.
Ground movement or pipeline strains affect
optical-fiber strain and can be detected by fiber
Bragg gratings or DSTS.
DTS technology is being used by Total in the
Dalia field, offshore Angola (above right). One of
the challenges for Total in developing this deepwater field was to maintain the flow of produced fluids in the integrated production bundle (IPB)
risers. The temperature of the relatively viscous oil
(21 to 23 degrees API) is 45°C to 50°C [113°F to
122°F] when it leaves the reservoir. After reaching
the seabed, where the water temperature is only
4°C [39°F], the fluid is piped 1,650 m [5,413 ft] to
the FPSO facility through the IPB risers.
Accurate temperature monitoring in the bundles is essential for flow assurance. If the temperature in the risers falls below a critical level,
waxes and hydrates may form and cause blockages, which result in costly downtime. Successful
Spring 2011
> Dalia field production system. This field, operated by Total, is located 135
km [84 mi] off the coast of Angola in waters ranging from 1,200 m to 1,500 m
[3,940 ft to 4,920 ft] in depth. Production from three main reservoirs is routed
through infield lines and risers to an FPSO at the surface. (Illustration
courtesy of Total.)
transfer requires that produced fluids arrive at
the FPSO facility at a temperature greater than
34°C [93°F]. Even in the event of a shutdown, the
fluid temperature must be maintained above
21°C [70°F].
To accommodate the optical fiber, each of the
eight riser bundles was constructed with a stainless steel tube that spirals around the bundle from
surface to seabed then doubles back to surface to
form a long loop. After the IPBs were installed offshore, Schlumberger engineers pumped optical
fiber into one end of the spiral tube to convey it
down to the seabed and back to the FPSO.
The double-ended optical system interrogates
the fiber from both ends of the loop. This method
provides more precise temperature measurements than single-ended systems. Accurate, realtime readings are recorded at 1-m [3.3-ft]
intervals along the length of the riser bundle. In
the unlikely event of fiber breakage, each portion
of fiber will continue to function as a singleended system, which provides some redundancy
until a new replacement fiber can be pumped
down. A customized graphical user interface displays the normal operating temperatures of the
production pipe and the gas lift tubing, and
alarms indicate the location of any temperature
deviation. As well as helping to avoid blockages,
the fiber-optic system facilitates efficient management of the electrical heating system.
A different type of temperature challenge
awaited Statoil at Gullfaks field in the North Sea,
where production from satellite wells is connected to platforms by long subsea flowlines. To
avoid blockages, the lines are heated above
the critical temperature for wax and hydrate
deposition. However, operating at higher-thannecessary temperature is inefficient and wastes
energy. As conditions vary along the flowline,
knowledge of the temperature at every point
along the production bundle is invaluable for flow
assurance and minimizing energy consumption.
A condition monitoring system allowed Statoil
to observe temperatures in the bundles so they
could be efficiently operated just above the critical temperature. The first system was installed in
a 14-km [8.7 mi] flowline bundle comprising two
flowlines, three hot-water heating lines, and a
small-diameter conduit, all in an insulated
sleeve. After the flowline bundle was installed
and connected to the Gullfaks C platform,
Schlumberger operators pumped a continuous
fiber-optic temperature sensor down the conduit.
This technology has helped to optimize operation
of the heating system and reduce the amounts of
wax and hydrate inhibitors required. The system
helps minimize disruptive pigging operations to
clear blockages, and when temperature anomalies resulting from extreme flow and pressure
changes at restrictions in the flowline are
detected, the system data can help optimize the
pigging operations required to clear any blockages, thus saving money and reducing downtime.
These monitoring systems make up just a fraction of the highly evolved and specialized technologies required to install and operate a subsea
oil and gas transmission system. Far from being
dumb iron or brute, insensitive conduits, each
subsea pipeline is, by necessity, formed of specialized metallurgy, fabricated with great care, laid
with utmost attention to subsea pressure and
stress, and attentively monitored.
—MV
13
Managed Pressure Drilling Erases the Lines
Dave Elliott
Shell E&P
The Hague, The Netherlands
For generations, prudent drilling engineers have maintained mud density in a well
such that its hydrostatic pressure was greater than the pore pressure of the formations
being drilled. Engineers today are learning the benefits of managing pressure at the
Julio Montilva
Shell E&P
Houston, Texas, USA
surface to manage drilling conditions downhole, thereby pushing back the limits
once imposed on them by wellbore stability and formation-fracture pressures.
Paul Francis
The Hague, The Netherlands
Don Reitsma
Jaye Shelton
Houston, Texas
Vincent Roes
Talisman Energy
Calgary, Alberta, Canada
Oilfield Review Spring 2011: 23, no. 1.
Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to Sonny
Espey, Paul Fredericks, Wayne Matlock, Marie Merle,
Mike Rafferty, Roger Suter and Eric Wilshusen, Houston.
HOLD is a mark of Schlumberger.
AUTOCHOKE and WARP are marks of M-I L.L.C.
14
Drilling operations exist in a world circumscribed by high and low pressures. The unexpected appearance of either can lead to delays,
increased costs and even to failure. With increasing frequency, operators are arming themselves
against the consequences of pressure-related
surprises with techniques different from those
used in the past. One such departure from tradition is called managed pressure drilling (MPD).
Traditional drilling practices rely on maintaining hydrostatic pressure in the annulus to
prevent formation fluids from entering the borehole. Ideally, when drilling fluid, or mud, is circulated down the drillstring and up the annulus, an
equivalent circulating density (ECD) is created
that is greater than pore pressure, but is below
the pressure necessary to fracture the formation
being drilled.1 This pressure is often referred to
by drilling experts as the fracture gradient. The
pressure range above pore pressure and below
fracture initiation pressure is the drilling margin,
or pore-pressure–fracture-gradient window. If at
any point the ECD goes outside these bounds,
operators must set casing and begin drilling the
next, smaller hole size.
The practice of maintaining a borehole pressure that exceeds the pore pressure gradient is
called overbalanced drilling (OBD). It has been
the method of choice for the majority of wells
drilled since the early 20th century. But OBD has
Oilfield Review
1. ECD is the effective density exerted by a circulating
fluid against the formation The ECD is calculated as:
ECD = d + P/ (0.052*D), where d is the mud weight in
pounds per gallon (lbm/galUS). P is the pressure drop
(psi) in the annulus between depth D and surface, and
D is the true vertical depth (feet).
2. Differential sticking occurs when the drillstring cannot be
moved (rotated or reciprocated) along the axis of the
wellbore. Differential sticking typically occurs when
high-contact forces caused by low reservoir pressures,
high wellbore pressures, or both, are exerted over a
sufficiently large area of the drillstring. The sticking force
is a product of the differential pressure between the
wellbore and the reservoir and the area that the differential
pressure is acting upon. This means that a relatively low
differential pressure applied over a large working area
can be just as effective in sticking the pipe as can a high
differential pressure applied over a small area.
Spring 2011
20-in.
16-in.
13 3/8 -in.
Zone A
Kick
11 3/4 -in.
Depth
its drawbacks. Foremost among them is its
dependence on the use of multiple casing strings
to prevent fluid losses as the fluid density
required to contain formation pressure is
increased and ECD approaches fracture initiation pressure. In some instances, particularly in
wells in ultradeep water, pore pressures may be
high relative to formation strength even in the
shallower sections of the well, which forces the
operator to set numerous casing strings before
reaching the target formation. The result can be
a well whose diameter at TD may be too small to
accommodate production tubing large enough to
produce economic volumes of hydrocarbons
(right). Additional strings of casing usually raise
the final cost of the well significantly above initial estimates.
Besides these considerations when drilling
overbalanced, mud filtrate and mud solids can
cause damage to the formation. When solids
invade and are deposited in pore spaces, they
may impair productivity and lower ultimate
recovery. In addition, high overbalance during
drilling can cause differential sticking and other
problems related to hole cleaning.2 Efforts to free
stuck pipe routinely result in hours or even days
of NPT. In the worst cases, particularly in the
presence of other aggravating conditions, such as
cuttings beds packing around it, the drillstring
may become permanently stuck and the hole may
be lost or require a sidetrack (below, right).
The drilling fluids industry has developed
chemical additives and practices to reduce the
severity and frequency of mud-induced formation
damage and stuck pipe. But in the 1980s, as operators drilled horizontal sections to expose enough
formation to make their wells profitable, they
found it impossible to maintain ECD below the
fracture gradient. That is because while the fracture gradient increases with TVD, it remains virtually unchanged from the heel to the toe of
horizontal wells; however, as the wellbore lengthens, friction pressure losses increase. Pump pressure must then be increased to maintain
9 5/8 -in.
Kick
Zone B
7-in.
10
11
12
13
14
lbm/galUS
Pressure gradients
Fracture initiation pressure
Resistivity pore pressure estimate
Seismic pore pressure estimate
15
16
17
ECD
> Conventional drilling. In response to increased pore pressure (kicks) in
zones A and B when drilling overbalanced, the ECD (blue line) is increased by
raising mud density, which causes BHP to approach the fracture initiation
pressure (purple line). In response, a casing string must be set to protect the
formation, which can result in additional casing points and subsequent
narrowing of the wellbore diameter (black triangles). In deepwater wells, the
window between fracture initiation pressure and pore pressure is often very
narrow. In this instance, the operator was forced to set six increasingly
smaller–ID casing strings, which resulted in a borehole too small to
accommodate economic volumes of oil and gas.
Cutting beds
> Cuttings beds. Though they may occur in any well configuration, beds of
cuttings, or solids (light brown), are particularly prevalent in deviated wells
where cuttings and cavings settle to the low side of the hole. When the
pumps are shut off, the BHA may become stuck in these beds as cuttings and
cavings (not shown) slide down the annulus and pack off the drillstring. This
phenomenon, known as avalanching, may also occur while pumps are on.
15
Fracture
initiation
pressure
Depth
MPD
OBD
UBD
Wellbore
stability
pressure
Pore pressure
Pressure
> Managing pressure. Conventional drilling methods are predominantly
concerned with containing formation fluid inflow during drilling. This
overbalanced drilling (OBD) method uses drilling fluids to create an ECD that
results in a BHP greater than pore pressure (purple line) but less than the
fracture initiation pressure (red line) of the formation being penetrated.
Underbalanced drilling (UBD) is focused on preventing drilling fluid loss to the
formation and so maintains an ECD that is less than pore pressure but greater
than pressure required to maintain wellbore stability. This allows the formation
fluid to flow out of the formation, preventing drilling fluid from flowing into the
formation. Managed pressure drilling (yellow) is aimed at overcoming drilling
problems by using surface pressure to maintain a constant downhole pressure
that prevents the flow of formation fluids into the wellbore while keeping
pressure well below fracture initiation pressure. During drilling operations, the
ECD of OBD and MPD may, at some depths, be equal.
sufficient circulation rates to lift cuttings to the
surface via the annulus. Given sufficient length
along a horizontal section, the ECD will result in
a bottomhole pressure (BHP) that equals and
then exceeds the fracture initiation pressure,
with inevitable unacceptable levels of fluid loss.
In wells or sections of wells with very narrow
drilling margins, operators have addressed the
issue of fluid loss through underbalanced drilling
(UBD), during which ECD is kept below the pore
pressure of the formation being drilled. As a consequence, fluid from exposed formations are
allowed to flow into the wellbore during drilling
operations. This prevents drilling fluids from
entering even underpressured zones.
But as the industry honed its ability to drill
very long extended-reach wells, it was met with
challenges other than fluid loss. Operators
encountered various pressure-associated challenges while drilling these wells, including wellbore instability and well control problems.
Efforts to overcome these challenges gave rise to
the development of MPD.3 MPD is used primarily
to drill wells that do not lend themselves to
either conventional overbalanced or underbalanced methods, such as in areas where flar-
16
ing is forbidden, or while drilling through
high-permeability formations.
In wells with sufficiently large drilling margins, pressure losses may also be manageable
through the manipulation of drilling fluid properties, flow rates and rates of penetration. Drilling
fluids experts at M-I SWACO, a Schlumberger
company, have developed a micronized weighting
agent and a fluid system built around it. The
WARP system uses a weighting agent composed of
particles ground ten times smaller than conventional barite, with 60% being less than 2 um in
diameter. And although accepted wisdom would
dictate that such finely ground particles would
yield a highly viscous fluid, because of the manufacturing process, WARP fluid systems are characterized by low viscosities, low gel strengths and
low sag potential.4
Because these characteristics minimize ECD
while maintaining good cuttings transport ability,
WARP fluid systems are particularly well suited to
use with MPD on extended-reach wells. One
major operator in the Gulf of Mexico has used the
system to drill 13 of its 16 MPD wells.
This article discusses the development and
practice of MPD and the techniques and equip-
ment required to execute it. Case histories from
US and Australia onshore and offshore wells
demonstrate its application in mature fields,
high-pressure and high-temperature environments and fractured formations.
Closed Vessels
Conventionally drilled wells are open systems. As
a well is drilled, fluid is pumped down the drillpipe, through the bit and back to the surface
along the annulus between the drillstring and the
borehole. The return line at the surface—which
leads to the shale shaker and mud pits where
drilling fluid is processed and stored in preparation for reuse—is open to the atmosphere.
Though they are quite different, UBD and
MPD methods use closed systems that deploy a
rotating control device (RCD) to divert formation
and drilling fluid flow to a separator. Among operators who require two barriers between the well
and the surface, the RCD and the drilling fluids
are considered primary barriers, and the blowout
preventer is a backup. MPD operations use the
RCD to create a closed system and a drilling
choke manifold and backpressure pump to control downhole pressure. In that way, engineers
can maintain a constant BHP during drilling
operations while the mud pumps are on and while
the pumps are turned off to make connections.
Once the downhole pressure environment has
been defined by pore pressures, fracture pressures and wellbore-stability pressures—often
through the use of real-time fingerprinting, with
annular pressure decreases to induce flow or
increases to induce losses—MPD is used to
maintain an appropriate annular hydraulic pressure profile. Thus MPD allows operators to keep
the ECD within a narrow pore-pressure–fracturegradient window while still maintaining pressures conducive to wellbore stability. This is
accomplished primarily through manipulation of
backpressure on the annulus while taking into
account factors that affect the ECD such as fluid
density, fluid rheology, annular fluid velocity, circulating friction and hole geometry (above left).5
Maintaining a constant downhole pressure
within the prescribed boundaries minimizes
formation damage, prevents mud loss, inhibits
formation fluid influx and often results in higher
rates of penetration. MPD may permit the operator to extend a casing setting point or even eliminate a casing string. It also offers operators the
ability to instantaneously react to downhole pressure variations, which may be used to minimize
formation influxes or mud losses without interrupting drilling. Additionally, because its density
Oilfield Review
Outflow
Drive bushing
assembly
AUTOCHOKE
body
Visual
indicator pin
Latching lug
Seal element
Static trim
Orifice
Bearing
assembly
Wear sleeve
High-pressure
seals
Shuttle
assembly
Inflow from
casing
To choke
Dynamic trim
Blowout
preventer
Mounting
spool
Hydraulic set point
pressure chamber
Inlet
flange
> RCD and automatic choke. The HOLD RCD (center) is mounted on top of the blowout preventer (red,
left), providing a seal that converts the drilling well from a normally open system to a closed system.
The drive bushing, installed into or removed from the RCD via the drillstring, contains the seal element,
which provides the seal between the annulus and the drillstring. A high-pressure seal provides a
barrier that prevents wellbore fluids from entering the bearing chamber of the RCD and contaminating
the lubrication system, which would destroy the bearings. A visual indicator lets the driller know that
the latching system holding the drive bushing seal element is locked in place. The mounting spool
connects the RCD to the BOP stack and the receptacle of the bearing assembly and to the flowline
carrying returns away from the drill floor.
The AUTOCHOKE unit (right) uses a dynamically positioned shuttle assembly that slides inside the
AUTOCHOKE body. The dynamic trim is connected to the shuttle assembly and slides inside the static
trim to form a circular orifice. Hydraulic pressure from the AUTOCHOKE console (not shown) is applied to
the backside of the shuttle assembly inside the hydraulic set point pressure chamber, and casing
pressure is applied to the front side of the shuttle assembly. If the casing pressure is higher than the
hydraulic set point pressure, the shuttle assembly moves back, increasing the orifice size, thus
reducing the casing pressure. If the casing pressure is lower than the hydraulic set point pressure, the
shuttle assembly moves forward, reducing the orifice size and raising the casing pressure. As the
shuttle assembly moves back and forth, it regulates the flow of fluid or gas from the well by
automatically adjusting the orifice size as it balances the two pressures.
remains unchanged, there is no need to circulate
the mud during these events and so MPD practices save rig time.6
Parts That Make the Hole
MPD relies on the driller’s ability to maintain,
either manually or automatically, a precise target
downhole pressure. The key to this ability is the
creation of a closed system, which is made possible by the use of the RCD, sometimes called a
rotating head. The RCD provides a seal around
the drillpipe during rotary drilling operations
and diverts drilling fluids to a drilling choke man-
Spring 2011
ifold and to the mud pits (above). The choke
allows drillers to adjust backpressure on the
annulus while the pumps are on and the drilling
fluid is being circulated. When the mud pumps
are turned off, for example during connections, a
dedicated pump supplies required fluid to the
system to compensate for the loss of ECD when
the system goes from dynamic to static mode.
3. Malloy KP, Stone CR, Medley GH Jr, Hannegan D,
Coker O, Reitsma D, Santos H, Kinder J, Eck-Olsen J,
McCaskill J, May J, Smith K and Sonneman P:
“Managed-Pressure Drilling: What It Is and What It Is
Not,” paper IADC/SPE 122281, presented at the IADC/
SPE Managed Pressure Drilling and Underbalanced
Operations Conference and Exhibition, San Antonio,
Texas, USA, February 12–13, 2009.
4. Taugbøl K, Fimreite G, Prebensen OI, Svanes K,
Omland TH, Svela PE and Breivik DH: “Development
and Field Testing of a Unique High-Temperature/
High-Pressure (HPHT) Oil-Based Drilling Fluid With
Minimum Rheology and Maximum Sag Stability,” paper
SPE 96285, presented at Offshore Europe, Aberdeen,
September 6–9, 2005.
Sag refers to particles of weighting material settling out
of the drilling mud.
5. ECD is often converted to equivalent mud weight in
lbm/galUS and is equal to the mud weight required to
generate pressure at depth during static operations.
6. van Riet EJ and Reitsma D: “Development and Testing
of a Fully Automated System to Accurately Control
Downhole Pressure During Drilling Operations,” paper
SPE/IADC 85310, presented at the SPE/IADC Middle East
Drilling Technology Conference & Exhibition, Abu Dhabi,
UAE, October 20–22, 2003.
17
Pressure
Casing
shoe
ture
Frac
Depth
sure
pres
sure
tion
pres
a
initi
Pore
Conventional drilling
Hydrostatic pressure
Dynamic pressure
MPD
Drilling window
Hydrostatic pressure
Hydrostatic pressure + backpressure
Dynamic pressure + backpressure
> Fluid densities and BHP. To keep the BHP between pore pressure (black line)
and fracture initiation pressure (blue line) when using conventional drilling
methods below a casing shoe, the BHP resulting from the mud weight must be
greater than pore pressure so that it may contain formation pressure when the
rig pumps are off (solid red line) and less than fracture initiation pressure
when the pumps are on (dashed red line). MPD allows the operator to use a
drilling fluid that creates a hydrostatic pressure less than pore pressure when
the pumps are off (solid green line). When pumps are off, formation pressure is
contained by adding backpressure (short-dashed green line) to increase BHP
without increasing mud density. When the pumps are on (long-dashed green
line), backpressure is reduced to a point that results in a BHP above pore
pressure but below fracture initiation pressure.
This manipulation of backpressure in reaction to pressure variations caused by drilling
operations is frequently referred to as dynamic
pressure control. Downhole pressure is equal to
surface pressure plus annular pressure, which is
itself made up of a static component and a
dynamic component.
Dynamic pressure includes friction pressure
losses, and its value is a function of circulating
conditions. Therefore, when the pumps are off,
the dynamic pressure is equal to zero, and only
the hydrostatic pressure of the fluid acts on the
formation. Also, during drilling operations with
the mud pumps on, dynamic pressure may fluctuate because of variations in the mud pump rate or
mud density, or in response to events such as
drilling motor stalls, cuttings loading and pipe
rotation (above).7
18
With the ability to react to annular pressure
variations, the operator can drill with a fluid that
creates sufficient ECD to contain formations
uphole from the bit, even though the well may
become underbalanced when static. Using MPD
techniques, the driller can safely stop the pumps
while making connections even though the
hydrostatic pressure of the mud column alone is
less than the pore pressure of the formation.
When wells are drilled through relatively
stable formations, with widely separated pore
pressure and fracture initiation pressure, there
may be sufficient margin to accommodate the difference between dynamic and static downhole
pressures. In these cases, reaction to changing
conditions need not be overly precise. It is possible to maintain constant BHP through manual
manipulation of the choke, mud pumps and
dedicated pump.
However, narrow drilling margins, high pressures and temperatures, highly permeable or
fractured reservoirs and hole instability are situations for which MPD is particularly suited.
These conditions demand adjustments be made
with an accuracy and frequency possible only
through automated MPD.
In the early 2000s, engineers at Shell
International E&P developed and tested an automated MPD system that incorporated a hydraulically operated choke manifold and connected a
positive displacement pump to the annulus.8 Two
computer systems—one to run a hydraulics
simulator and another for user interface—and a
programmable logic controller adjust the choke
manifold. The intent of the automated MPD system was threefold: to automatically calculate in
real time the backpressure required to maintain
constant downhole pressure, to control the choke
and pump that generate backpressure at all
times and to provide automatic kick detection.
The resulting dynamic annular pressure control (DAPC) system calculates in real time the
backpressure, or set point, required to maintain a
desired downhole pressure. It imposes this backpressure on the annulus by continuously adjusting the hydraulically controlled choke and pump
settings based on real-time data acquisition
(next page).
The control system varies with each application but consists essentially of five parts:
sSINGLEPHASEHYDRAULICSMODEL
sDATA COMMUNICATION INTERFACE AND HISTORICAL
database
sGRAPHICALUSERINTERFACE'5)
sPROPORTIONALINTEGRALDERIVATIVE0)$DEVICE
controller
sPROGRAMMABLELOGICCONTROLLER0,#SENSORS
and controls.
Drilling engineers use the hydraulics model
to calculate the surface pressure set point that
will deliver the desired downhole pressure. Input
to the model includes frequently changing data,
such as pump rate; static values, such as well
drillstring geometry; and slowly changing properties, such as mud density and viscosity.
Data are delivered using the wellsite inforMATION TRANSFER SPECIlCATIONS 7)43 ,EVEL ))
protocol and may be internally measured and
logged in a historical database.94HE'5)ALLOWS
operators to configure the system with limits on
variables, which can be set up to issue warnings
WHENTHOSELIMITSAREBREACHED4HE'5)ISAVAILable for manual operation of chokes and valves.
The control system, using a PID controller, determines the optimal choke position to control the
Oilfield Review
Rig pump
RCD
DAPC backpressure pump
AC-1
AC-2
Trip tank
DAPC
choke manifold
Shale shaker
AC-3
Flowmeter
Blowout
preventer
Gas vent
Main
controller
Auxillary
controller
DAPC control system
Separator
Mud pit
> Automated DAPC system. To maintain constant BHP during transition from drilling to making connections when the
pumps are shut off, the DAPC system stabilizes the backpressure by pumping drilling fluid into the choke manifold
regulated through choke AC-1. Backpressure is reduced or not applied when the pumps resume for drilling. The DAPC’s
control system, which is directly linked to the real-time hydraulics analysis and continuous kick detection, stabilizes and
controls the BHP through adjustment of the DAPC backpressure pump and chokes AC-2 and AC-3. A flowmeter (dashed
oval) connected to the low-pressure side of the choke manifold provides flow-out data, which the pressure manager
continuously monitors and compares to flow-in data for kick detection.
backpressure.10 One PLC runs the PID controllers
and another is used as a sensor interface and for
choke positioning.
Shell tested the DAPC system in a wellsimulation facility that included a fully equipped
rig and vertical hole about 1,530-m [5,020-ft]
deep, with 51/2-in. casing and a 2 7/8-in. drillstring
run to bottom. The well was configured so that
nitrogen could be injected into the annulus to
simulate gas kicks. Downhole pressures were
recorded in real time.
To determine optimal settings, a single operational parameter was changed for each test.
Results showed the system was able to significantly reduce pressure variations downhole, and
through fine-tuning, engineers were able to further enhance that ability. Test results also indicated that faster cycling of the pumps caused
larger pressure variations. Tripping and drilling
tests showed the system was able to compensate
for pressure variations over a wide range
of conditions.
The team also simulated drilling problems
such as choke plugging, hole bridging and fluid
loss. In all cases, the system compensated for
these events and maintained constant downhole
pressures. Additionally, the controller was able to
use the automated choke and pump to circulate
out simulated gas kicks. This was achieved by
increasing backpressure at the surface to compensate for the reduction in static pressure
caused when nitrogen pumped into the annulus
reduced the density of the fluid column.11
7. Reitsma D and van Riet E: “Utilizing an Automated
Annular Pressure Control System for Managed
Pressure Drilling in Mature Offshore Oilfields,” paper
SPE 96646, presented at Offshore Europe, Aberdeen,
September 6–9, 2005.
8. van Riet and Reitsma, reference 6.
9. WITS is an industry-standard communications format
used to transfer a wide variety of wellsite data from one
computer system to another. A WITS data stream
consists of discrete data record types, each of which can
be turned on and off by the rig operator and assigned
sampling rates. WITS also enables computers at remote
locations to send instructions to another computer to
change parameters, including data type and sampling rate.
10. A PID controller is used in many industrial applications
to calculate the difference between a measured variable
and a desired set point such as surface pressure. The
PID controller attempts to minimize differences between
the two by adjusting the process inputs.
11. van Riet and Reitsma, reference 6.
Taking it to Mars
The Shell DAPC system was first used in deep
water at the company’s Gulf of Mexico Mars platform located about 130 mi [209 km] southeast of
New Orleans in about 3,000 ft [914 m] of water.
As in most deepwater fields, the difference
Spring 2011
19
Conventional drilling: Mars A-14 sidetrack prognosis
12,000
FIT
12,500
13,000
13,500
TVD, ft
14,000
14,500
15,000
15,500
16,000
16,500
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
Pore-pressure–fracture-gradient
Equivalent mud weight, lbm/galUS
14.0
15.0
16.0
17.0
Managed pressure drilling: Mars A-14 sidetrack prognosis
12,000
FIT
12,500
13,000
13,500
TVD, ft
14,000
14,500
15,000
15,500
16,000
16,500
5.0
6.0
7.0
Pore pressure
8.0
9.0
Static MW
10.0
11.0
12.0
13.0
Pore-pressure–fracture-gradient
Equivalent mud weight, lbm/galUS
MPD Static EMW
14.0
Dynamic EMW
15.0
16.0
17.0
Fracture gradient
> Conventional drilling and MPD in deepwater. Diagnoses of two failed sidetracks at the Shell-operated
Mars platform led to a prognosis that conventional drilling (top) would result in an ECD that was within
0.05 lbm/galUS [0.006 g/cm3] equivalent mud weight (EMW) of the formation integrity test (FIT) (red
dots, top) value. Using MPD methods (bottom), the EMW could be reduced (green) and, by adding 525
psi [3.62 MPa] annular pressure, the gap between the FIT (red dots) and the ECD would be expanded
to 0.3 lbm/galUS [0.036 g/cm3] equivalent (red dots, bottom). (Adapted from Roes et al, reference 12.)
between pore pressure and fracture initiation
pressure is often small. In the case of Mars, the
field had experienced considerable zonal depletion. This made controlling ECD even more critical and more difficult because deepwater
developments typically use high-angle, very long
wells to reach stranded or secondary reserves.
Consequently, the wellbore must often pass
repeatedly through low-pressure depleted zones
and high-pressure virgin sands.
20
Furthermore, hydrocarbon extraction may
change rock stress characteristics. Because the
wells have been on production since 1996, reservoir and nonreservoir rock formation strength has
become reduced. Therefore, lowering mud density
has resulted in wellbore instability. However, during attempts to sidetrack the Mars A-14 well, the
use of high-density drilling fluids caused lost-circulation problems in depleted zones.
The A-14 well targeted the waterflooded
M1/M2 reservoir that contained the majority of
the field’s reserves. In May 2003, it had been shut
in because of sand production; sidetrack operations to reenter the M1/M2 reservoir were begun
in 2004. The first attempt failed when the BHA
was lost at 21,144 ft [6,445 m] MD, 16,340 ft
[4,980 m] TVD, due to lost circulation and wellbore stability problems. An attempt to sidetrack
from the previous casing shoe failed when the
Oilfield Review
High Pressure, Depletion and Cement
MPD is particularly suited to wells targeting highpressure formations. The subsurface in which
these wells locations are found is often marked
by uncertain pressures, complex lithology and
indeterminate flowback, which is the volume of
drilling fluid that flows from the annulus after
Spring 2011
Mexico HPHT well
Wellbore flow prior to MPD
500
450
Pressure, psi and flow, galUS/min
same problems prevented engineers getting an
expandable liner to depth.
Shell turned to the DAPC system developed
by its E&P research arm. At the Mars platform,
the DAPC control system was modified to communicate with a third-party choke controller
system. The DAPC controller was therefore
limited to determining the necessary backpressure and communicating that to the choke
controller system.
BHP was calculated in real time using a Shell
hydraulics steady-state model that contained
static data such as mud weight, BHA configuration, well geometry and directional data, and was
updated by rig data every second. Though there
was generally good agreement between model
and measured BHPs, string rotation was not
properly compensated for, which resulted in the
actual equivalent mud weight of the BHP being
about 0.2 lbm/galUS [0.024 g/cm3] higher than
the model. To address this, the model was manually adjusted with corrected values.
The well was drilled to TD using a mud
density of 13.1 lbm/galUS [1.57 g/cm3], which is
0.3 lbm/galUS [0.036 g/cm3] less than the previous
two attempts. This was made possible by using
the DAPC to maintain a BHP set point equivalent
to 13.7 lbm/galUS [1.64 g/cm3] (previous page).
Using these specifications, there were no indications of hole instability or lost circulation and the
liner was run without incident.12
Following this success, Shell chose to use
MPD on 11 more wells. In one field, after repeatedly failing to reach TD using conventional
methods, engineers reached target depth in six of
six tries using MPD. The program was so successful in the maturing field, production facilities
reached capacity.
MPD proved to be the solution in two more
Shell-operated deepwater fields and six more
wells with similar challenging relationships
between fracture initiation pressure, pore pressure and wellbore stability. Shell is also applying
the technique in other challenging circumstances including cementing wells that prove difficult because of depletion, safely penetrating
high-pressure, high-temperature (HPHT) sections and for drilling wells that are otherwise
impossible to drill within existing HSE standards.
400
350
Loss
300
250
200
150
100
Gain
50
0
22:40:00
22:48:20
22:56:40
23:05:00
23:13:20
Time
Flow-in rig pumps, galUS/min
Backpressure, psi
Flowmeter, galUS/min
> Fingerprinting flowback. This fingerprint of the flowback in one high-pressure, high-temperature
(HPHT) well in Mexico was recorded during the second connection by the DAPC system before MPD
operations. The volume of flowback, or gain, after the pumps are turned off (green shaded area) is
complemented by the losses (gray shaded area) when the pumps are turned back on and the operator
goes from static to dynamic drilling mode. (Adapted from Fredericks et al, reference 13.)
the mud pumps are shut off. Additionally, in
highly pressured formations, apparent kicks, if
misdiagnosed or mishandled, are more likely to
become well control events than in normally
pressured environments.
Typically, HPHT wells are further complicated
by narrower drilling margins and little offset well
information. Faced with one or both of these situations, drillers must be prepared for the consequences of higher-than-anticipated pressures
even when dealing with routine situations. For
example, during traditional drilling operations,
multiple prediction and detection methods help
reduce uncertainty related to pressure. However,
some operators are loath to rely on the practice
of pore pressure prediction in HPHT wells.
Shell uses MPD equipment on wells characterized by a high degree of pressure uncertainty.
By routinely and intentionally inducing flow during MPD operations—essentially using both UBD
and MPD in different sections of the well—
engineers are able to determine pore pressure in
real time. Armed with accurate pore-pressure
data, the operator can drill ahead while maintaining a constant bottomhole pressure to stay within
the drilling window. Additionally, Shell manipulates the drilling fluid systems to strengthen the
borehole, effectively altering the fracture gradient and thus expanding the drilling margin.
Unusual flowback volumes are often an indication of what is known as wellbore breathing or
ballooning. This phenomenon occurs when drilling-induced fractures absorb a volume of drilling
fluid. When the pumps are shut off and the ECD is
reduced, these fractures close and expel the fluid,
resulting in flowback at the surface. By recording
the flowback volume before and immediately after
drilling out of casing—a process known as fingerprinting—drillers can establish a baseline flowback volume to be expected from a particular well
when the pumps are shut off (above). When the
flowback volume exceeds the fingerprint volume,
the excess is often mistakenly interpreted as a
kick, a pressure-induced influx of formation fluids
rather than wellbore breathing.
Drillers react to a kick by increasing mud
density. However, doing so when the volume gain
is due to wellbore breathing can have serious
consequences; an increase in mud density may
turn a slightly overbalanced condition into a
severely overbalanced condition that causes even
greater fluid loss.
By drilling with an MPD package and maintaining a constant BHP, engineers can eliminate
not only the pressure fluctuations between
dynamic and static drilling modes that cause
12. Roes V, Reitsma D, Smith L, McCaskill J and Hefren F:
“First Deepwater Application of Dynamic Annular
Pressure Control Succeeds,” paper IADC/SPE 98077,
presented at the IADC/SPE Drilling Conference, Miami,
Florida, USA, February 21–23, 2006.
21
Mexico HPHT well
Connection 5
18.5
500
400
18.0
350
300
17.5
250
200
150
17.0
100
ECD Equivalent mud weight, lbm/galUS
Pressure, psi and flow, galUS/min
450
50
16.5
2:16
2:15
2:14
2:13
2:12
2:11
2:10
2:09
2:08
2:07
2:06
2:05
2:04
2:03
2:02
2:01
2:00
1:59
1:58
1:57
1:56
1:55
1:54
1:53
1:52
1:51
1:50
1:49
1:48
1:47
1:46
0
Time
Backpressure pump, galUS/min
Flow-in rig pumps, galUS/min
Backpressure, psi
ECD set point pressure, lbm/galUS
Flow out flowmeter, galUS/min
ECD, lbm/galUS
> No wellbore breathing. Pressure data recorded by DAPC during the fifth connection on the same
HPHT well as in previous figure show no signs of wellbore breathing (orange line). As the rig pumps
are cycled (green), the DAPC backpressure pump pressure and rate (black and purple lines) are
increased or decreased automatically to maintain the ECD set point pressure (red line) and density
(blue line) in both dynamic and static drilling modes. The absence of gains or losses due to flowback
or wellbore breathing indicates the well is at equilibrium at this constant BHP. (Adapted from
Fredericks et al, reference 13.)
wellbore breathing but also any possibility of misdiagnosis (above). Moreover, the accuracy and
speed with which they can react to pressure
variations make automated MPD systems well
suited to quickly identifying and addressing
numerous common drilling hazards before they
become issues.13
In some cases, once drilling hazards have
been identified, MPD practices may be used with
other technologies to overcome them. In the
Shell-operated McAllen-Pharr field in Hidalgo
County, Texas, USA, for example, the operator was
faced with drilling through produced zones in
which depletion prediction was complicated by
difficult-to-map faulting. Additionally, zones that
had been depleted to as much as 5,000 psi
[34 MPa] below original pressure were often
found between layers of overpressured virgin
sands, which made isolating them with a drilling
liner impractical.14
In nearby fields, as a consequence of raising
mud weight in preparation for tripping out of the
hole, the operator had experienced severe fluid
losses when the liner setting point was reached.
Liner or casing drilling—in which the drillstring
is replaced by a liner or casing that can be left in
22
the hole, thus eliminating tripping and the need
to raise mud density—was used to solve the problem in those wells.
Liner drilling worked in these fields because
the low permeability of the zones being drilled
prevented flow into the wellbore even when the
pumps were shut off and the equivalent mud density fell below pore pressure. Uncertainty about
pressure and an expectation of high permeability
made use of this strategy alone untenable in the
McAllen-Pharr field.
Shell turned to automated MPD equipment,
adapting its system to onshore applications.
Engineers decreased the size and weight of the
choke manifold by reducing the number of
chokes, valves and bypass lines, which also drove
improvements to the hydraulic power system.
The reduced manifold moved from a three-choke
to a two-choke design, with one choke dedicated
to backpressure management and the other to
duty as both a backup and for automated pressure relief.15 A rig pump, rather than a dedicated
pump, provided backpressure when the primary
mud pumps were off.
The first well in the field drilled with the modified unit, the Bales 7, was characterized by complex faulting and little offset data. This made it
difficult to predict the pore-pressure and fracturegradient regimes in the target reservoir sands
through which Shell intended to drill.
The operator’s plan called for a 7 5/8-in. casing
shoe at about 8,700 ft [2,652 m] MD. A 2,100-ft
[640-m] horizontal reach was then to be drilled
conventionally in an S-shaped trajectory along a
19° tangent.16 Next, a 61/2-in. hole was to be
drilled vertically using jointed pipe and automated MPD to 10,360 ft [3,158 m]. From there
the 61/2-in. section would be drilled to 11,065 ft
[3,373 m] using casing drilling and MPD (next
page). The entire 61/2-in. section was to be drilled
statically underbalanced.
The ECD set point was 14.15 lbm/galUS
[1.7 g/cm3] at the casing shoe, increasing to
14.9 lbm/galUS [1.8 g/cm3] at TD. On average,
the system controlled the ECD to within
±0.12 lbm/galUS [0.01 g/cm3] of the set point by
continuously managing the backpressure
between 100 and 200 psi [0.7 and 1.38 MPa]. In
the section drilled with conventional drillpipe,
this included 16 pump transitions; during these
times the pumps were turned off and on for 15
connections and one time to replace leaking
seals in the rotary control device.
The second section of the 61/2-in. hole met
with pore pressures of at least 1.5 lbm/galUS
[0.02 g/cm3] higher than any encountered
uphole. Combined with expected depletion
levels, it was determined that fluid losses would
be too great with a conventional drilling assembly, so engineers opted to casing drill to final
TD.17 Static mud weight for the entire section was
15.7 lbm/galUS [1.8 g/cm3] and ECD was a constant 16.2 lbm/galUS [1.9 g/cm3].
Though gas flowed from the well during drilling and the flow volume increased with depth,
BHP was held constant to within an average
equivalent mud weight of ±0.18 lbm/galUS
[0.02 g/cm3], including through 13 pump transitions. Using MPD to avoid losses while maintaining a constant ECD, engineers reached TD with a
31/2-in. casing drillstring.
Finally, engineers used automated pressure
control practices to cement the production casing, holding 90 psi [0.6 MPa] of backpressure
while circulating bottoms up ahead of cementing.
Once returns were stabilized, the pumps were
shut down to install a cementing head and the
BHP held constant by application of 200 to
210 psi [1.38 to 1.45 MPa] backpressure. After
the spacer was pumped, the choke was used to
maintain a constant 16.2 lbm/galUS [1.9 g/cm3]
ECD during cementing. As a result, the well was
successfully cemented with no fluid losses.
Oilfield Review
Bales 7 well, vertical section
While liner drilling the McAllen-Pharr wells
using MPD equipment, gas was circulated
through the gas buster. In order to minimize fluid
losses, mud weight was occasionally adjusted.
Shell used this melding of MPD, UBD and casing
drilling to expand its casing drilling program to
other fields in South Texas and to avoid the
significant expense of using a liner as part of a
contingency plan.18
0
kickoff
joint
1,000
2,000
3,000
4,000
19˚ tangent
5,000
6,000
7,000
Drilling the Impossible, the Very Hot and More
Using externally applied backpressure in a closed
drilling system to maintain a constant downhole
pressure is a relatively new approach to drilling
through narrow drilling margins. Operators continue to discover new applications for MPD as
they seek answers to unique pressure-related
drilling challenges.
For example, in maturing basins, operators
often opt to drill sidetrack wells from existing
wellbores to reach stranded reserves with which
to shore up falling production. These efforts are
often hampered, however, by high annular fluid
losses as wellbores pass through depleted zones.
Conventional drilling practices in this environment frequently fail to access the stranded oil
because of drilling issues such as stuck pipe or
difficulty running casing.
While MPD would seem a likely solution, the
challenge is further complicated because these
13. Fredericks P, Sehsah O, Gallo F and Lupo C: “Practical
Aspects and Value of Automated MPD in HPHT Wells,”
paper AADE 2009NTCE-04-04, presented at the AADE
National Technical Conference and Exhibition,
New Orleans, March 31–April 1, 2009.
14. Montilva J, Fredericks P and Sehsah O: “New
Automated Control System Manages Pressure and
Return Flow While Drilling and Cementing Casing in
Depleted Onshore Field,” paper SPE 128923, presented
at the IADC/SPE Drilling Conference and Exhibition,
New Orleans, February 2–4, 2010.
15. Montilva et al, reference 14.
16. For more on extended reach drilling: 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.
17. For more on casing drilling: Fontenot KR, Lesso B,
Strickler RD and Warren TM: “Using Casing to Drill
Directional Wells,” Oilfield Review 17, no. 2 (Summer
2005): 44–61.
18. Montilva et al, reference 14.
19. Njoku JC, Husser A and Clyde R: “New Generation
Rotary Steerable System and Pressure While Drilling
Tool Extends the Benefits of Managed Pressure Drilling
in the Gulf of Mexico,” paper SPE 113491, presented at
the Indian Oil and Gas Technical Conference and
Exhibition, Mumbai, March 4–6, 2008.
20. @balance: “Successful Use of Managed Pressure
Drilling to Eliminate Losses and Control Influx in Hot
Fractured Rock Geothermal Wells,” http://www.
atbalance.com/NE_News_Geothermal.html (accessed
December 1, 2010).
21. For more on subsalt drilling: Perez MA, Clyde R,
D’Ambrosio P, Israel R, Leavitt T, Nutt L, Johnson C
and Williamson D: “Meeting the Subsalt Challenge,”
Oilfield Review 20, no. 3 (Autumn 2008): 32–45.
Spring 2011
8,000
5
7 /8 -in. casing at 8,278 ft TVD
9,000
10,000
11,000
2,500
2,000
1,500
1,000
500
0
12,000
Horizontal length, ft
> Wellbore profile. The Bales 7 well was drilled as a high-angle well to the
75/8-in. casing point and then turned vertical. The production section was then
drilled in two steps aimed at addressing varying pore pressure and fracture
initiation pressure regimes that engendered fluid loss in some sections and
gas influx in others. (Adapted from Montilva et al, reference 14.)
slimhole sidetracks are drilled traditionally using
positive-displacement motors. These motors create continuous fluctuations in ECD as they move
from sliding to rotating mode, making constant
BHP nearly impossible. The solution for one operator in the Gulf of Mexico was MPD in combination with a new generation of rotary steerable
tools and pressure-while-drilling sensors.19 Based
on this company’s success, operators throughout
the Gulf are reevaluating opportunities for
extending life and profitability from mature fields
through slimhole sidetracks.
In Australia, while drilling wells for a geothermal project in the Cooper Basin, Geodynamics
Limited found that the granite basement was
unexpectedly overpressured by as much as
5,200 psi [36 MPa]. Additionally, the existing
stress regime of the granite created conditions
that led to kicks and fluid losses. In this first well,
drilled using conventional techniques, the operator incurred considerable NPT when it was forced
to use a 4.0-lbm/galUS [0.5 g/cm3] mud density
increase to control and kill a fluid influx from the
overpressured basement.
The operator then turned to DAPC to maintain the delicate balance between the overpressure and fracture gradient on the next two wells.
On the second well, engineers used the system to
control and kill a fluid influx in 90 minutes while
raising the mud density by only 0.7 lbm/galUS
[0.1 g/cm3]. They also used the system to maintain a constant ECD by manipulating the back-
pressure between 220 and 295 psi [1.5 and
2.0 MPa] during drilling operations and 525 and
625 psi [3.6 and 4.3 MPa] during connections.20
The Proper Tool for the Proper Job
Due to its flexibility and continuous flow and
pressure control, MPD is often a safer and less
costly drilling method than either under- or
overbalanced drilling. This is especially true for
environments with narrow or unknown drilling
margins. MPD has been used, for example, in
forestalling kicks while crossing the rubble zones
in subsalt drilling. It has also been used to
replace Coriolis mass flowmeters—which can be
sensitive to entrained gas and vibration and
highly susceptible to poor maintenance—for
early kick detection.21
Getting the most value from MPD requires it
be applied in drilling situations for which it is
best suited. While it is often and correctly viewed
as a way to successfully drill wells that would
otherwise not reach their targets, it should be
thought of neither as the answer to all drilling
problems nor the method of last resort. The
most appropriate candidates for MPD are for
wells with offsets characterized by wellbore
instability, excessive drilling fluid losses or those
that will be drilled through pressured, virgin
zones and depleted, or otherwise underpressured
ones. Those parameters alone suggest the number of wells that are good MPD candidates is
quite considerable.
—RvF
23
Finding Value in Formation Water
Operators usually consider formation water an undesirable byproduct of hydrocarbon
production. However, samples and analysis of that same water can provide vital
information for the field development plan, including optimization of completion
design, materials selection and hydrocarbon recovery.
Medhat Abdou
Abu Dhabi Company for Onshore Operations
Abu Dhabi, UAE
Andrew Carnegie
Woodside Petroleum
Perth, Western Australia, Australia
At the mention of unexpected formation water in
their wells, many oil and gas producers react with
alarm. Unanticipated water production, particularly if it contains unwanted impurities, can
significantly reduce the value of a hydrocarbon
asset. It can accelerate equipment damage and
increase water handling and disposal costs. But
capturing a certain amount of formation water is
also valuable; water properties contain a wealth
of information that can be used to significantly
impact field economics.
S. George Mathews
Kevin McCarthy
Houston, Texas, USA
Michael O’Keefe
London, England
Bhavani Raghuraman
Princeton, New Jersey, USA
Wei Wei
Chevron
Houston, Texas
ChengGang Xian
Shenzhen, China
Oilfield Review Spring 2011: 23, no. 1.
Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to Sherif
Abdel-Shakour and Greg Bowen, Abu Dhabi, UAE; Ahmed
Berrim, Abu Dhabi Marine Operating Company, Abu Dhabi,
UAE; Hadrien Dumont, Balikpapan, Indonesia; Will Haug,
Cuong Jackson and Oliver Mullins, Houston; Chee Kin
Khong, Luanda, Angola; Cholid Mas, Jakarta; and Artur
Stankiewicz, Clamart, France.
InSitu Density, InSitu Fluid Analyzer, InSitu pH, MDT,
Oilphase-DBR, PS Platform and Quicksilver Probe are marks
of Schlumberger.
1. Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesis
and Reservoir Quality,” Oilfield Review 22, no. 2
(Summer 2010): 14–27.
2. Interstitial water is the water between grains. For more
on evaporites: Warren JK: Evaporites: Sediments,
Resources and Hydrocarbons. Berlin, Germany:
Springer, 2006.
24
Oilfield Review
Formation water analysis plays a role in
dynamic modeling of reservoirs, quantifying
reserves and calculating completion costs, including how much will be spent on casing and surface
equipment—capital expenditures (capex). Water
analysis also helps operators estimate operating
expenditures (opex), such as the cost of chemical
injection. Quantifying water chemistry aids in the
understanding of reservoir connectivity and in
characterizing transition zones in carbonates,
thereby impacting estimates of reservoir extent. It
helps development planners determine whether
new discoveries can be tied into existing infrastructure and is crucial for designing water injection projects.
Formation water properties vary from one
reservoir to another as well as within reservoirs.
Water composition depends on a number of
parameters, including depositional environment,
mineralogy of the formation, its pressure and
temperature history and the influx or migration
of fluids. Consequently, water properties can
change over time as the water and rock interact,
and as reservoir fluids are produced and replaced
with water from other formations, injected water
or other injected fluids.
This article examines the causes of variation
in water composition and describes the value of
formation water analysis throughout reservoir
life, from exploration to development and production. Examples from Norway, the Middle East,
the Gulf of Mexico and China illustrate methods
for collecting high-quality water samples and
show how formation water analysis both downhole and at surface conditions contributes to reservoir understanding and development.
Water Composition
Most reservoir rocks are formed in water, by the
deposition of rock grains or biological detritus.
The water that remains trapped in pores as the
sediments compact and bind together is called
connate water; the water in the reservoir at the
time it is penetrated by a drill bit is called formation water. Connate water reacts with the rock to
an extent that depends on temperature, pressure, the composition of the water and the mineralogy of the formation. Chemical and biological
reactions may begin as soon as sediments are
deposited. The reactions can continue and accelerate as the formation is subjected to greater
pressure and temperature during burial. The
combined effects of these chemical, physical and
biological processes are known as diagenesis.1
Although a great deal of effort has gone into
studying the impact of diagenesis on rock formations, relatively little has been made to under-
Spring 2011
stand how it affects the original fluid within the
rock—the water.
Connate water varies with depositional environment. In marine sediments, it is seawater. In
lake and river deposits, it is freshwater. In evaporite deposits, the interstitial water is highsalinity brine (right).2 These water solutions contain ionic components, including cations such as
sodium [Na+], magnesium [Mg2+], calcium
[Ca2+], potassium [K+], manganese [Mn2+],
strontium [Sr2+], barium [Ba2+] and iron [Fe2+
and Fe3+]; anions such as chloride [Cl–], sulfate
[SO42–], bicarbonate [HCO –3 ], carbonate [CO32–],
hydroxide [OH–], borate [BO33–], bromide [Br–]
and phosphate [PO43–]; and nonvolatile weak
acids. The water may also contain dissolved gases,
such as carbon dioxide [CO2] and hydrogen
sulfide [H2S], nitrogen, organic acids, sulfurreducing bacteria, dissolved and suspended solids
and traces of hydrocarbon compounds.
Concentrations of these components may vary
as water is expelled by compaction and as it reacts
with formation minerals. Some minerals react
easily. For example, the clay mineral glauconite
has approximately the following composition:
2+
K0.6Na0.05Fe 3+
1.3Mg0.4Fe 0.2Al0.3Si3.8O10(OH)2. If the
connate water is undersaturated in the components of the clay, it will interact with the mineral
grain by ion exchange, leaching ions from the
glauconite into the aqueous solution. Other minerals, such as quartz [SiO2], have higher resis-
Water Type
Salinity, Parts
per Thousand
Average river water
Seawater
Evaporite systems
Formation water
0.11
35
35 to 350
7 to 270
> Salinity variations. Salinity of connate water
varies with depositional environment, increasing
from the freshwater of rivers to seawater and
briny evaporite systems. Formation water, the
result of water mixing and other physical and
chemical processes, can have a wide range of
salinities. (Data from Warren, reference 2.)
tance to dissolution and remain as grain matrix. If
the water is saturated with the rock’s ions, minerals can precipitate and form new grains or grow
on existing grains. Water properties such as pH
and ion concentration are some of the factors that
control or influence water-rock interactions.
Even after equilibrium is reached, water-rock
interactions continue. However, changes in temperature, pressure, depth and structural dip can
disrupt equilibrium, as can the migration and
accumulation of oil and gas, which force the
water deeper as the lighter hydrocarbons rise
through a formation. The influx of water from
other sources, such as meteoric water, aquifers,
injected water and other injected fluids, can also
cause water properties to change (below).
Rain (meteoric water)
Sea
Hydrocarbon
accumulation
Shale
Faults
Sandstone
Basement
Salt
Shale
> Water movement and processes that can influence the evolution of
formation water. Composition of formation water originally filling a
sandstone layer can be modified by the addition of water from other
sources (arrows), such as meteoric water and water expressed from
compacting shales and salt. The water can also be altered by the influx of
migrating hydrocarbons. Sealing faults and other flow barriers can create
compartments with different water compositions. On the other hand,
conducting faults can facilitate flow.
25
> Scale buildup in production tubing. Scale causes reduced flow rates and
can, eventually, completely block production.
Production of formation water is another
cause of disequilibrium; dissolved minerals and
gases may come out of solution as the fluid is
brought to the surface—especially in reaction to
sulfates introduced into the formation through
drilling fluid invasion or injection of seawater.
These losses of the dissolved components alter
the composition of the produced or sampled
water, so water recovered at the surface may not
represent the actual formation water in place. For
this reason it is important to collect and analyze
formation water under in situ conditions, and to
continue to do so as reservoir conditions change.
Applications of Water Analysis
Formation water is rich with information about
the rock in which it resides, and it can provide
crucial input to analyses during every stage in the
life of a reservoir. Early in field life, analysis of formation water establishes the salinity and resistivity of the water for petrophysical evaluation.3
Archie’s water saturation equation, from which oil
saturation and reserves are most frequently computed from logs, requires formation water resistivity as an input. That value is often computed from
resistivity and porosity logging measurements
made in a water zone, where the water may not
have the same composition as the reservoir formation water in other zones. Analysis of formation
water samples from the oil leg is considered one
of the most reliable ways to obtain water salinity
and resistivity for saturation calculations.
26
Before the material for casing or production
tubing is selected, it is vital to evaluate the corrosivity of the gas, oil and water to be produced.
Free gas in the formation may contain corrosive
constituents—such as H2S and CO2—and these
same constituents may be dissolved in the formation water. Wells producing such fluids at concentrations exceeding certain limits require casing
with special metallurgical formulations that will
resist corrosion, or treatment with corrosioninhibiting chemicals.4 Furthermore, pipelines
and surface facilities must be capable of handling
the produced water with its accompanying gases
(see “Pipeline to Market,” page 4). To design production tubing, flowlines and surface facilities,
engineers must know the chemical composition
of the formation water. The water pH and salinity
values used in metallurgical calculations for
selection of tubulars must include values for
downhole conditions of reservoir pressure and
temperature and water composition.5
As reservoir fluids are produced, the accompanying pressure reduction may cause the
release of gas from solution and the precipitation
and deposition of solids in the reservoir pores
and on production tubing and downhole equipment. For example, as pressure decreases, formation water liberates CO2 gas, water pH increases
and the solution becomes supersaturated with
calcium carbonate [CaCO3], which can result in
scale deposition that may eventually choke off
flow (left).6 Precipitation can be predicted through
modeling or laboratory experimentation if formation water chemistry is known.
Scale can also form when waters of different
compositions mix.7 For example, precipitation of
barium sulfate [BaSO4] or strontium sulfate
[SrSO4] solids is a common problem when seawater, which contains sulfates, is injected into
formations that contain barium or strontium. It
also occurs when sulfates from drilling-fluid
invasion interact with the formation water, and
is the primary reason behind recent industry
practices using low-sulfate drilling fluids. Such
scale may be deposited in the formation or in
production tubing.8 Partially blocked tubing can
sometimes be cleaned with workover tools that
deploy abrasives and jetting action. However, if
the scale is too thick, there is little that can be
done except to pull the tubing and replace it—at
significant cost.
Effective scale management is an important
issue for field development planning and can have
a direct impact on production viability, especially
in marginally economic fields.9 The formation
water’s potential to create scale when mixed with
injected water must be assessed if any part of a
field is to be produced with pressure support from
injected fluids. In several cases, operators have
had to change plans—for example, halting seawater injection and finding another, more costly
source for injection water—based on knowledge
of formation water properties.10
In assessing scaling potential, one of the
greatest uncertainties may be the formation
water composition and downhole properties.
Some companies have adopted water monitoring
as routine practice for scale-prone fields. For
example, Statoil monitors the composition of
water produced from the majority of its oil and
gas wells, and uses crossplots of the ratio of ion
concentrations to assist in defining producing
water zones.11 Sampling frequency depends on
the need: In cases of high scale potential, water is
sampled every one to two weeks.
An additional use of water modeling in
development planning is the optimization of
well-stream mixing and process sharing: when
production streams from several wells, especially subsea wells, are combined before being
piped to intermediate separators or processing
facilities. To minimize risk of pipeline scaling
and corrosion, operators must fully understand
the chemical interaction of produced water from
different sources before committing to large
capital expenditures.
Oilfield Review
Formation water composition plays a role in
“souring,” a process in which H2S concentration
increases in the reservoir.12 In many cases, souring
is attributed to microbial activity; injected seawater provides a source of sulfate-reducing bacteria
(SRB) and the formation water supplies nutrients
in the form of low–molecular weight organic acids
known as volatile fatty acids (VFAs). The consequences of reservoir souring are potentially costly.
Increased levels of H2S increase safety risks for
oilfield personnel, decrease the sales value of produced hydrocarbons and increase corrosion rates
in downhole equipment and surface facilities. An
estimated 70% of waterflooded reservoirs worldwide have soured.13 Understanding water properties and modeling their changes throughout
reservoir life help chemical engineers predict H2S
generation and make informed decisions regarding materials selection and facility design. Lowcontamination water samples, therefore, are
essential to establish the level of VFAs in the formation water.14
Variations in formation water composition
can also reveal compartmentalization—or lack
of hydraulic communication between adjacent
reservoir volumes—if the reservoirs have been
isolated long enough for their formation waters
to have reached different equilibrium states.
Understanding reservoir connectivity is important for estimating the extent of aquifer support—the natural water drive present in many
reservoirs—and for planning development well
locations, formulating injection-related recovery
3. Warren EA and Smalley PC (eds): North Sea Formation
Waters Atlas. London: The Geological Society, Geological
Society of London Memoir 15 (1994).
4. For more on corrosion, see Acuña IA, Monsegue A,
Brill TM, Graven H, Mulders F, Le Calvez J-L, Nichols EA,
Zapata Bermudez F, Notoadinegoro DM and Sofronov I:
“Scanning for Downhole Corrosion,” Oilfield Review 22,
no. 1 (Spring 2010): 42–50.
5. Williford J, Rice P and Ray T: “Selection of Metallurgy
and Elastomers Used in Completion Products to Achieve
Predicted Product Integrity for the HP/HT Oil and Gas
Fields of Indonesia,” paper SPE 54291, presented at the
SPE Asia Pacific Oil and Gas Conference and Exhibition,
Jakarta, April 20–22, 1999.
6. Ramstad K, Tydal T, Askvik KM and Fotland P: “Predicting
Carbonate Scale in Oil Producers from High Temperature
Reservoirs,” paper SPE 87430, presented at the Sixth
International Symposium on Oilfield Scale, Aberdeen,
May 26–27, 2004.
7. Mackay DJ and Sorbie KS: “Brine Mixing in Waterflooded Reservoir and the Implications for Scale
Prevention,” paper SPE 60193, presented at the Second
International Symposium on Oilfield Scale, Aberdeen,
January 26–27, 2000.
8. Bezerra MCM, Rosario FF, Rocha AA and Sombra CL:
“Assessment of Scaling Tendency of Campos Basin
Fields Based on the Characterization of Formation
Waters,” paper SPE 87452, presented at the Sixth
International Symposium on Oilfield Scale, Aberdeen,
May 26–27, 2004.
Spring 2011
programs and detecting injection-water breakthrough. Analysis of formation water, and in particular, comparison of its natural isotopic
composition with that of injection water, has
been used for monitoring waterfloods.15 Isotopes
act as tracers in the water to help reservoir engineers identify high-permeability layers, fractures
and other causes of interwell communication.
Sampling Water
Water samples can be collected by several methods. Samples of produced water can be obtained
at the wellhead or from surface separators, but
these may not be representative of formation
water if gases have evolved or compounds have
precipitated. However, these samples are useful
and are typically collected for production surveillance. Surface samples are used to monitor
changes in water properties over time, to identify
breakthrough of injection water and to compare
with samples from other producing wells to
understand reservoir connectivity. Acquiring
such samples is less expensive than downhole
sampling and can be done more routinely. Water
samples can also be retrieved from preserved
core.16 However, samples recovered by this technique have undergone pressure and temperature
decrease, and therefore may not be representative of actual formation water.
During the exploration and appraisal stages,
when an operator builds an understanding of the
reservoir fluids and uses the data for modeling, it
is vital to have representative water samples.
For an overview of scaling causes and mitigation:
Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson A
and King G: “Fighting Scale—Removal and Prevention,”
Oilfield Review 11, no. 3 (Autumn 1999): 30–45.
9. Graham GM and Collins IR: “Assessing Scale Risks and
Uncertainties for Subsea Marginal Field Developments,”
paper SPE 87460, presented at the Sixth International
Symposium on Oilfield Scale, Aberdeen, May 26–27, 2004.
10. Graham and Collins, reference 9.
Andersen KI, Halvorsen E, Sælensminde T and
Østbye NO: “Water Management in a Closed Loop—
Problems and Solutions at Brage Field,” paper SPE
65162, presented at the SPE European Petroleum
Conference, Paris, October 24–25, 2000.
11. Ramstad K, Rohde HC, Tydal T and Christensen D:
“Scale Squeeze Evaluation Through Improved Sample
Preservation, Inhibitor Detection and Minimum Inhibitor
Concentration Monitoring,” paper SPE 114085,
presented at the SPE International Oilfield Scale
Conference, Aberdeen, May 28–29, 2008.
12. Farquhar GB: “A Review and Update of the Role of
Volatile Fatty Acids (VFA’s) in Seawater Injection
Systems,” paper NACE 98005, presented at the 53rd
NACE Annual Conference, San Diego, California, USA,
March 22–27, 1998.
Mueller RF and Nielsen PH: “Characterization of
Thermophilic Consortia from Two Souring Oil Reservoirs,”
Applied and Environmental Microbiology 62, no. 9
(September 1996): 3083–3807.
Representative samples can be collected by a
wireline formation tester equipped with a probe
or dual packer, a pumpout module, downhole
fluid-analysis capabilities and sample chambers.
The downhole water-sampling process begins
with a cleanup stage, in which fluid—initially a
mixture of mud filtrate and formation water—is
drawn from the formation through the probe into
the tool.17 As pumping time increases, the proportion of mud filtrate, or contamination, decreases,
and the proportion of pure formation water in the
flowline increases.
If the optical or resistivity properties of the
filtrate are significantly different from those of
the formation water, optical fluid analyzers or
resistivity sensors located in the tool flowline can
measure the difference and thereby monitor contamination in real time. In the early stages of
cleanup, the water is not pure enough to collect,
and it is returned to the borehole. When the contamination is below a designated level, the fluid
is directed into pressurized sample chambers,
which are brought to the surface and transported
to a laboratory for analysis.18
The quality of samples acquired downhole
depends on the method of sampling and the type
of drilling mud used in the sampled zones. In
zones drilled with oil-base muds (OBMs), highquality water samples can usually be obtained
because the mud filtrate is not miscible with the
formation water. Formation water and OBM typically have different optical and resistivity properties, allowing them to be distinguished by optical
13. Elshahawi H and Hashem M: “Accurate Measurement
of the Hydrogen Sulfide Content in Formation Water
Samples—Case Studies,” paper SPE 94707, presented
at the Annual Technical Conference and Exhibition,
Dallas, October 9–12, 2005.
14. Elshahawi and Hashem, reference 13.
15. Carrigan WJ, Nasr-El-Din HA, Al-Sharidi SH and
Clark ID: “Geochemical Characterization of Injected and
Produced Water from Paleozoic Oil Reservoirs in Central
Saudi Arabia,” paper SPE 37270, presented at the
International Symposium on Oilfield Chemistry, Houston,
February 18–21, 1997.
Danquigny J, Matthews J, Noman R and Mohsen AJ:
“Assessment of Interwell Communication in the
Carbonate Al Khalij Oilfield Using Isotope Ratio Water
Sample Analysis,” paper IPTC 10628, presented at the
International Petroleum Technology Conference, Doha,
Qatar, November 21–23, 2005.
Smalley PC and England WA: “Reservoir Compartmentalization Assessed with Fluid Compositional Data,”
SPE Reservoir Engineering (August 1994): 175–180.
Ramstad et al, reference 11.
16. Smalley and England, reference 15.
17. Mud filtrate is the portion of the drilling fluid that invades
the formation during the creation of mudcake on the
borehole wall. The filtrate is driven into the formation by
the pressure difference between the drilling mud and
the formation fluid.
18. Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H,
Hegeman P, O’Keefe M, Peters K and Zuo JY:
“Downhole Fluids Laboratory,” Oilfield Review 21,
no. 4 (Winter 2009/2010): 38–54.
27
fluid analyzers and resistivity sensors. Water-base
mud (WBM) filtrate, on the other hand, has optical properties similar to those of the formation
water, so the two are difficult to distinguish by
color. Also, WBM is miscible with formation water
and can mix and react with it, leading to contaminated and unrepresentative water samples unless
special care is taken to pump for a long time to
collect uncontaminated samples.
The Quicksilver Probe focused extraction
technology can collect virtually contaminationfree formation fluids, which is especially important when sampling formation water in the
presence of WBM filtrate.19 The tool’s articulated
probe, which contacts the formation at the borehole wall, draws filtrate-contaminated fluid to
the perimeter of the contact area, where it is
pumped into a discharge flowline. This diversion
preferentially allows pure reservoir fluid to flow
into the sampling flowline. The probe can be run
as a module combined with the InSitu Fluid
Analyzer tool in the MDT modular formation
dynamics tester.
Ideal sampling consists of collecting a singlephase sample and keeping it in single phase as it
is brought to the surface and transported to the
laboratory. The Oilphase-DBR single-phase multisample chamber (SPMC) uses a nitrogen charge
to maintain downhole pressure on the reservoir
fluid sample between the downhole collection
point and the laboratory. This practice ensures
that gases and salts remain in solution during the
trip from downhole to the laboratory, which may
not be possible with standard sample chambers.
Single-phase samples can also be obtained
from drillstem tests (DSTs). Usually, water is not
intentionally sampled during a DST, but some
operators make special efforts to study water
composition and will collect DST water samples
for laboratory analysis.20
Formation water samples can be obtained
later in field life during production logging operations. However, obtaining formation samples
prior to production is crucial for recording the
baseline composition. The Compact Production
Sampler captures conventional bottomhole samples in producing wells. It can be run in any section of the PS Platform production logging string,
conveyed by either slickline or electric line.
Once the samples have been retrieved, they
are transported to a laboratory and reconditioned to downhole conditions before analysis,
described in a later section. The results are
entered in a multiphase equilibrium model—
various models are available commercially—to
predict downhole pH and the potential for corrosion, scale and hydrate formation.
Because of the lack of a pH measurement on
reconditioned samples, chemical engineers use
equilibrium modeling to predict pH under reservoir conditions. However, uncertainties in the
thermodynamic models for formation waters at
high temperatures and pressures, as well as
uncertainties associated with the possible precipitation of salts, can propagate errors into
scale and corrosion models. Furthermore, unless
tools such as the SPMC are used, changes in pressure and temperature as the water sample is
transported uphole may induce phase changes
that are not always fully reversible during the
reconditioning process.21
Since pH is a key parameter in understanding
water chemistry and plays a major role in predicting corrosion and scale deposition, obtaining reliable pH measurements on formation water at
downhole conditions has been a priority for oilfield fluid specialists.
Spectroscopic
detector
Lamp
Tool wall
Optical density ratio (570:445)
10
1.0
Three-dye mix
Model
Experiment
0.1
2
4
6
8
10
pH
Dye
injector
Fluid
flow
> Downhole pH measurement. Equivalent to a downhole litmus test, the InSitu pH module (left) uses a mix of pH-sensitive dyes
and detects their color change as a function of pH. The spectroscopic detector measures optical density at two wavelengths:
570 nm and 445 nm. Laboratory experiments conducted as part of this technology development showed that pH is a predictable
function of the ratio of optical density at 570 nm wavelength to that at 445 nm (top right). The color of the water-dye mixture
ranges from yellow at a pH of 2 to purple at a pH of 10 (bottom right).
28
Oilfield Review
Spring 2011
Well 2, an appraisal well drilled in a gascondensate field, was drilled with an OBM system
to facilitate high-quality water sampling. Before
collecting samples at three depths, the tool measured pH, each time with multiple readings. At
the shallowest measurement station, the fluid
analyzer indicated the tool flowline contained a
mixture of oil and formation water. However, the
oil and water segregated within the tool, and the
dye mixed only with the water, allowing the pH of
the water slugs to be measured. The pH values
did not vary over time because the OBM filtrate
did not contaminate the formation water.
Laboratory analysis of the water samples
acquired from these wells quantified concentrations of major components and physical properties at surface conditions. Chemical engineers
used these results as input for models to predict
pH at downhole conditions.
For the sample from Well 1, the simulated pH
value matched the downhole pH value within
0.03 units, giving reservoir engineers confidence
in the downhole measurement, the condition of
the sample and the modeling method (below).
In Well 2, the sample from the shallowest
level had similar downhole and simulated pH values, different by only 0.03 units, again validating
the downhole measurement, the condition of the
Well
Depth, m
1
2
2
2
7.2
7.0
pH
Measuring pH In Situ
Schlumberger researchers developed a method
for measuring pH downhole using pH-sensitive
dyes.22 The InSitu pH reservoir fluid sensor works
on the same proven principles as other downhole
optical fluid analyzers designed for hydrocarbon
analysis.23 One difference, though, is that the
InSitu pH module injects pH-sensitive dye into
the tool flowline, where it mixes with the fluid
being pumped from the formation (previous
page). The fluid mixture changes color according
to the water pH, and optical sensors quantify the
color change by detecting optical density at multiple wavelengths. The wavelengths of the optical
channels in the InSitu pH device have been
selected to detect the colors expected when
waters of pH from about 3 to 9 react with a dye
mixture selected for this range. The measurement is similar to the well-known litmus test for
indicating pH, but the science and applications
were adapted to the high-pressure, high-temperature conditions encountered downhole.
At early pumping times in WBM systems, the
flowline fluid is predominantly filtrate, but as
pumping continues, the contamination level—
the concentration of mud filtrate—decreases,
producing a water sample more representative of
formation water. If the WBM-filtrate pH is significantly different from formation-water pH (typical
ranges are pH of 7 to 10 for WBM, pH of 4 to 6 for
formation waters), then the pH of the mixture
changes as contamination decreases (top right).
Monitoring this change helps interpreters qualitatively track water-sample purity in real time
before collecting the water sample. The pH measurement using this method is estimated to be
accurate to within 0.1 pH units.
An operator utilized this measurement technique in two wells offshore Norway, each proposed to be tied back to different existing floating
production platforms.24 Knowledge of both hydrocarbon and water composition is crucial for the
implementation of tieback development plans. In
particular, water analysis is important for flow
assurance in the seafloor pipelines, and tieback
requires water compatibility with the process
equipment on the main platform and with waters
flowing through it from other wells.
Well 1, an exploration well, was drilled with
WBM through an oil reservoir and into an underlying water zone. During cleanup of the water zone,
several series of dye injection followed by pH measurement showed a clear change of pH over time,
indicating reduced contamination of the fluid in
the flowline. Laboratory analysis of a tracer added
to the drilling fluid confirmed low WBM contamination of 0.2% in the collected sample.
6.8
6.6
6.4
0
2,000
4,000
6,000
8,000
Pumping time, s
> Monitoring water cleanup in an Egyptian well
before sample collection. As the tool pumped
fluid from the formation into the flow line, pH
measurements indicated the change in water
composition. Early in the cleanup process, the
fluid mixture had a high pH, indicating
predominantly WBM filtrate. After about 6,000 s
of pumping time, the pH leveled off to a low
value, signaling that the fluid had cleaned up to
an acceptable level of purity for sample collection.
sample and the model. The middle sample, 3.8 m
[12.5 ft] deeper, showed a significant mismatch
of 0.39 pH units between the simulated and measured values—a discrepancy several times
greater than the typical measurement accuracy.
Confidence in the downhole measurement at this
station comes from the averaging of 60 data
Temperature, °C
Downhole pH
Modeled pH
Y,Y08.5
53.8
6.26
6.29
X,X26.0
134.0
5.82
5.85
X,Y29.8
X,Y49.9
139.0
142.0
6.14
6.02
5.75
5.82
> Downhole and laboratory formation water measurements. The clean
formation water samples were analyzed in the laboratory. Chemical
engineers used the ion concentrations and physical properties measured
from the liquid and the composition of the gas as inputs (not shown) to
models to predict pH at downhole conditions. Comparison of these
predictions with downhole measurements shows reasonable matches in all
cases except for the sample from Well 2 at X,Y29.8 m. The mismatch may
indicate a compromise in the integrity of the sample during transfer from
downhole conditions to the laboratory.
19. For more on the Quicksilver Probe method, see:
Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B,
Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M,
Tarvin J, Weinheber P, Williams S and Zeybek M:
“Focusing on Downhole Fluid Sampling and Analysis,”
Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.
20. O’Keefe M, Eriksen KO, Williams S, Stensland D and
Vasques R: “Focused Sampling of Reservoir Fluids
Achieves Undetectable Levels of Contamination,”
paper SPE 101084, presented at the SPE Asia Pacific Oil
and Gas Conference and Exhibition, Adelaide, South
Australia, Australia, September 11–13, 2005.
21. It may have taken millions of years for the water to
equilibrate with the host formation. Once equilibrium is
disturbed, it may not be regained in time for laboratory
analysis.
22. Raghuraman B, O’Keefe M, Eriksen KO, Tau LA,
Vikane O, Gustavson G and Indo K: “Real-Time
Downhole pH Measurement Using Optical
Spectroscopy,” paper SPE 93057, presented at the
SPE International Symposium on Oilfield Chemistry,
Houston, February 2–4, 2005.
23. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,
Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,
Jamaluddin A, Kurkjian A, Sass B, Mullins OC,
Rylander E and Van Dusen A: “Quantifying Contamination
Using Color of Crude and Condensate,” Oilfield Review 13,
no. 3 (Autumn 2001): 24–43.
24. Raghuraman et al, reference 22.
29
Resistivity
Rxo
Moved Hydrocarbon
0.2
Water
Moved Hydrocarbon
Oil
Water
Dolomite
Oil
Calcite
Resistivity-Based Fluid Analysis
Volumetric Analysis
50
%
0 100
%
ohm.m 2,000
Medium
0.2
ohm.m 2,000
0.2
ohm.m 2,000
Deep
Formation Pressure, psi
0
4,430
Pretest Mobility
4,530 0.1
mD/cP 1,000
1.082 g/cm3 (water)
1.111 g/cm3 (water)
1.140 g/cm3 (water)
> Contradictory interpretations in a potential oil-bearing zone. High predicted oil saturation (left, green
shading) near the top of this zone is in contrast to the pressure measurements (right), which exhibit a
gradient indicative of water (blue dots). Pink dots are measurements in low-mobility zones and were
excluded from the gradient calculation. In situ measurement of pH (not shown) supported an
interpretation of injection water breakthrough in this interval.
points with a standard deviation of 0.02 pH
units—well within the expected measurement
accuracy. The discrepancy between the in situ
measurement and the value obtained by modeling based on laboratory results may indicate a
compromise in the integrity of the sample during
transfer from downhole conditions to the laboratory, emphasizing the benefit of the real-time
measurement. The pH of the third sample from
Well 2 is within 0.2 units of the simulated value,
which is a more acceptable match.
These tests demonstrated the capability and
accuracy of the real-time downhole pH measurement. The tool is able to take multiple measurements at each station to verify water purity
before sample collection. In addition, it can analyze pH at any number of depths without acquiring samples.
30
Water Assumptions
Downhole water pH measurements have also
been used to resolve formation evaluation challenges in a Middle East carbonate field.25 In a
giant offshore field, Abu Dhabi Marine Operating
Company (ADMA-OPCO) hoped to identify undepleted thin pay zones and track movement of the
oil/water contact (OWC) in the main reservoir.
The main reservoir has undergone decades of
production with water injection, but some thin
zones have not been tapped yet, and they are
appraisal targets.
Most wells in the field, including the four
wells in this study, were drilled with WBM using
seawater as the base. The WBM and formation
water cannot be distinguished using resistivity,
but the formation water has low pH, from 5.0 to
5.6, compared with that of the WBM (greater
than 7.0). The WBM and formation water also
have markedly different strontium concentrations, allowing them to be differentiated through
laboratory analysis, which was the standard practice before the availability of real-time pH measurements. In Well A, a water sample was
collected by traditional methods and sent for
laboratory analysis; that sample provided a basis
for comparison with the results from the three
other wells.
Well C penetrated the main reservoir and several thin zones believed to be untapped. At one
station, a pH measurement was performed after
just a few liters of fluid had been pumped from
the formation. The fluid was expected to be rich
in WBM filtrate, and indeed, it exhibited a downhole pH of 7.3. Samples of the WBM were collected for laboratory analysis at the surface.
Resistivity log analysis suggested this thin,
20-ft [6-m] layer had high mobile oil saturation
and could be a potential pay zone. Pressure tests
at three stations in the interval indicated low
mobility but were inconclusive on fluid density.
Downhole fluid analysis at the location with
the highest mobility detected tiny amounts of oil
flowing with water in the flowline. After about
280 L [74 galUS] of formation fluid had been
pumped through the tool, dye injection followed
by pH measurement yielded a pH of 5.1. From
previous experience with downhole measurements in the field, interpreters concluded the
water was formation water, and samples were collected. Subsequent laboratory analysis of the
strontium concentration confirmed the interpretation that this sampling depth was in the oilwater transition zone.
Furthermore, the small fractional flow of oil
detected in the downhole fluid analysis implies
that the oil saturation is only slightly higher than
the residual oil saturation, and that the sampling
depth is close to the OWC. This example demonstrates the benefits of downhole fluid analysis in
characterization of complex limestone transition zones, especially in thin intervals where
pressure and resistivity log interpretations can
have uncertainties.
At the top of the main reservoir zone, fluid
content estimates—calculated using an
assumed value for formation water salinity—
indicated high oil saturation (above left).
However, pressure measurements across the
interval suggested a formation fluid density
equivalent to that of water, contradicting the
interpretation of high oil saturation.
Downhole fluid analysis performed in the
middle of this zone, after several hundred liters
of fluid had been pumped from the formation,
Oilfield Review
6.4
WBM contamination, %
80
6.2
60
6.0
40
Contamination
pH
20
0
0
2
5.8
4
6
8
10
Pumping time, 1,000 s
> Contamination monitoring in an ADCO well. As the tool pumped fluid from
the formation at X,X51 ft, the optical sensor detected a decrease in the
fraction of blue-colored WBM with pumping time, indicating a reduction in
mud contamination of the formation water. Measurements of pH at four
times show a drop from 6.47 to 5.7 as the fluid in the flowline cleans up.
in both the pH and in the optical density of the
tracer-doped mud (above). The pH dropped from
6.47 at high contamination to 5.7, which engineers interpreted as the pH of the nearly clean
formation water.
At the next sampling station, 10 ft [3 m]
above the first, the optical analyzer detected only
water until pumping time reached 7,443 s. At that
time, oil appeared in the flowline, and by 12,700 s,
the oil fraction had increased to 90% (below).
X,X41 ft
50
6.0
0
5.5
90% oil, 10% formation water
Oil %
pH
X,X41
100
pH
Oil
6.5
4
0
8
12
Time, 1,000 s
X,X??
Oil/water contact
ontact
X,X51
X,X51 ft
100% formation water
pH
Oil
pH
6.5
100
50
6.0
Oil %
Depth, ft
Whence the Water?
Abu Dhabi Company for Onshore Operations
(ADCO) used the downhole pH measurement in a
production well to delineate the oil/water contact, characterize the oil-water transition zone
and identify the sources of water in various layers.26 The low resistivity contrast between the
WBM and the formation fluid precluded using
resistivity to track filtrate contamination. Instead,
ADCO selected two other methods for monitoring
contamination: in situ pH and a colored tracer in
the WBM that allows quantitative estimates of
contamination before sample collection.
The first sampling station was at X,X51 ft,
near the bottom of the suspected oil-water transition zone. This was confirmed by the optical analyzer, which showed only water and no oil flowing
at this depth. Monitoring the pH and optical
responses of the colored tracer during the
cleanup phase showed a reduction in WBM contamination with pumping time. The decrease in
contamination manifested as downward trends
100
Hd
indicated only water in the tool flowline. Realtime measurements of pH returned a value of
6.2—lower than that expected of WBM, but
higher than that of the anticipated formation
water. Because so much fluid had been pumped
from the formation before taking the pH measurement, WBM contamination of the water was
expected to be low. Fluid analysts suspected that
the fluid was not formation water, but water from
a nearby injection well. This interpretation was
corroborated by laboratory analysis of three
water samples collected at this depth.
The injection-water breakthrough had gone
undetected during initial openhole logging
because the water had not been analyzed, and
default values of formation water salinity caused
the log interpretation to wrongly predict that the
zone contained high volumes of mobile oil. The
true salinity of the water in this zone is about
one-sixth that of the default formation water, dramatically changing the interpretation. Correctly
identifying water origin by measuring its pH in
situ can have significant implications in terms of
completion and production planning to minimize
water production.
0
5.5
4
6
8
10
Time, 1,000 s
25. Xian CG, Raghuraman B, Carnegie AJ, Goiran P-O and
Berrim A: “Downhole pH as a Novel Measurement Tool
in Carbonate Formation Evaluation and Reservoir
Monitoring,” Petrophysics 49, no. 2 (April 2008): 159–171.
26. Raghuraman B, Xian C, Carnegie A, Lecerf B, Stewart L,
Gustavson G, Abdou MK, Hosani A, Dawoud A, Mahdi A
and Ruefer S: “Downhole pH Measurement for WBM
Contamination Monitoring and Transition Zone
Characterization,” paper SPE 95785, presented at the
SPE Annual Technical Conference and Exhibition, Dallas,
October 9–12, 2005.
Spring 2011
> Constraining the oil/water contact. Measurements at two depths, X,X41 ft
and X,X51 ft, narrow the OWC to somewhere between them. At the deeper
station, optical fluid analysis detected water only, and pH measurements
indicated the presence of formation water. At the transition-zone station,
10 ft higher, optical fluid analysis detected water initially, but eventually oil
arrived and increased in volume fraction to 90%. The pH measurement at
this station showed the water to be a mixture of formation water and filtrate,
confirming the presence of mobile formation water. Therefore, the OWC is
constrained to the 10-ft interval between these two stations.
31
Zone
1
2
3
4
5
6
Fluid
Measurement
Permeability
Oil
Oil and water
Water
Water
Water
Water
Oil sample
OWC delineation
pH, water sample
pH, water sample
None
pH, water sample
High
High
1 mD to 10 mD
Less than 1 mD
Too tight to flow
Less than 1 mD
Downhole pH
Modeled pH
6.5
7.3
6.6
7.8
6
6.3
> Fluid sampling data. In a well drilled with OBM to facilitate water sampling, ADCO collected fluids
from five of six carbonate zones. The water in Zone 4 is clearly different from that in the other
water-filled zones. The water from Zone 6 may be different from the water in Zone 3; these data were
combined with those shown below and on the next page to determine the source of water produced
from Zone 2.
Na+K/1,000
Cl/1,000
Ca/100
–10
–8
Sulfate/10
–6
–4
–2
0
2
4
6
meq
Oil producers
Mg/10
Carbonate/10
Na+K/1,000
Cl/1,000
Ca/100
–10
–8
Sulfate/10
–6
–4
–2
0
2
4
6
meq
Oil producers
Zone 2
Zone 3
Zone 4
Zone 6
Mg/10
Carbonate/10
> Comparing water compositions. Stiff diagrams allow visual identification
of similarities and differences between water samples. Concentrations of
cations are plotted to the left of the vertical axis, and concentrations of
anions are plotted to the right. Compositions of water samples from the
producing wells (top) are all similar, whereas compositions of samples from
the new well (bottom) show large variability. The waters from Zones 2 and 3
are similar to the produced water, but the compositions of samples from
Zones 4 and 6 are different in most cations and anions.
32
Without a pH measurement to characterize the
type of water, there is no way to know if the water
is WBM filtrate or formation water. The presence
of pure WBM filtrate implies the formation water
is immobile, while the presence of any formation
water implies that formation water is mobile at
this depth.
A pH measurement taken at 6,452 s, slightly
before the arrival of the oil, gave a value of
5.77, indicative of a WBM–formation water mix.
Optical measurement of the colored tracer confirmed this interpretation. This implies that oil
and water are both mobile at this depth.
Therefore, the oil/water contact must be between
the two measurement stations, narrowing it to
between X,X41 and X,X51 ft.
In another ADCO example, a well was drilled
to determine the source of water appearing in
nearby oil-producing wells. The new well, drilled
with OBM to simplify water sampling, penetrated
six limestone zones. The shallowest, Zone 1, contained only oil; Zone 2 contained oil and water,
and the bottom four zones were water bearing.
ADCO wanted to know if the water produced
from the second layer was coming from the flank
of the reservoir through Zone 3, or from the
deeper zones.27
Of the water zones, Zone 5 was too tight to
flow, but in the other three the formation tester
measured downhole pH and collected pressurized samples for laboratory analysis.
The downhole pH measurements indicated
that the water in Zone 4 was significantly different from that in the other zones, and modeling
based on laboratory findings confirmed this (above
left). However, to identify which layer was supplying water to the oil-producing zone required comparison with the produced water. There were no
pH measurements on the previously produced
water, but laboratory analysis on stock tank samples provided ion concentrations for the waters
from the existing producers, and these were compared with concentrations from the waters sampled in the new well.
Scientists used a graphical method called a
“Stiff diagram” to compare the compositions of
the various water sources.28 Each plot shows the
relative concentrations of anions and cations for
a particular water sample, scaled in milliequivalents per liter (meq) (left).29 All samples of the
produced water showed a similar pattern.
However, samples from the new well exhibited
differences. The samples from Zones 2 and 3 had
patterns resembling those of the produced water,
while Zones 4 and 6 contained waters with distinctly different compositions.
Oilfield Review
δ = R sample – 1 × 1,000
R standard
–5
5
Zone 2
–10
δ 18OSMOW
R sample = ratio of heavy to
light isotope in the sample
R standard = ratio of heavy to
light isotope in standard
mean ocean water (SMOW)
3
Zone
δDSMOW
Zone 3
10
Zone 6
Zone 3
Zone 2
2
Zone 4
Zone 4
4
5
6
Zone 6
0.7074
0.7076
0.7078
0.7080
87Sr/ 86Sr
> Isotopic analysis of water samples from the new ADCO well. Many elements have isotopes, or atoms
with different atomic weights. The most common form of hydrogen (with one proton) has an atomic
weight of 1, and is written as 1H. A less common isotope, 2H, with one proton and one neutron, is
usually written as D, for deuterium. Similarly, oxygen has three isotopes, 16O, 17O and 18O. Isotopes have
similar chemical properties but different physical properties. For example, they “fractionate” during
evaporation and condensation, leaving water enriched in heavy isotopes. Comparing ratios of
hydrogen and oxygen isotopes is a common method to distinguish waters from different sources. In
the ADCO case, analysis shows that the water in Zone 4 is different from those in the other zones (left).
Comparison of strontium [Sr] isotope ratios (right) is another technique for highlighting differences
between water sources. Here, waters from Zones 4 and 6 are significantly different from those in
Zones 2 and 3.
Isotopic analysis corroborated the compositional information. A plot of hydrogen and oxygen
isotope ratios for samples from the new well confirmed that the water from Zone 3 was similar to
that in Zone 2. Also, the waters from Zones 4 and
6 were quite different from each other and from
those of Zones 2 and 3 (above). Strontium isotopic ratios were also different.
These analyses showed that Zone 3 is the
source of water produced in Zone 2—the oilproducing layer—allowing ADCO engineers to
conclude that water sweep is from the flanks of
the reservoir, and there is no water support from
Zones 4 and 6, below the reservoir.
Laboratory Measurements on Live Waters
Traditional laboratory analysis is usually performed on “dead” or stock tank water, and this
analysis may be useful for production surveillance. However, during the initial exploration
and appraisal stages, when the operator builds
an understanding of the reservoir fluids and
uses that data for modeling water chemistry at
reservoir and pipeline conditions, it is critical to
work on representative live-water samples.
Through downhole fluid analysis, specialists
are able to perform direct measurements on live
fluids—fluids that still contain dissolved gas—
at reservoir conditions. Furthermore, samplecollection technology, which has the ability to
monitor contamination and maintain water sam-
Spring 2011
ples at elevated pressure, allows operators to
bring live fluids to the surface and transport
them intact to a laboratory.
In the laboratory, the collected water samples
are reconditioned to downhole temperature and
pressure, encouraging any gases and solids that
have come out of solution to redissolve. The samples are flashed—the sample bottles are opened
and the fluids are exposed to surface pressure
and temperature—before laboratory analysis.
Laboratory specialists measure the gas/water
ratio (GWR) and perform gas chromatography to
analyze the composition of the liberated gas.
They also analyze ion composition, pH and low–
molecular weight organic acids in the water
phase. A more rigorous process employed by
some operators involves partitioning the flashed
water sample into three parts. Acid is added to
one part of the sample to preserve cations, which
are then analyzed by inductively coupled plasma
(ICP). Sodium hydroxide is added to the second
part to preserve organic acids, which are then
analyzed by ion chromatography. The third portion is kept untreated and is used to measure
density, pH, conductivity, alkalinity (by titration)
and anions by ion chromatography.
For the most part, commercial laboratories
have not been equipped to directly analyze live
water at reservoir conditions, but some are making advances in this direction. Schlumberger scientists have developed a new laboratory technique
for measuring pH of live formation water samples
at reservoir temperature and pressure.30 The sample remains in the pressurized bottle in which it
was brought to the surface. A heated jacket brings
the bottle to reservoir temperature. As the water
sample flows through a pressurized flowline—
which is similar to the tool flowline—it mixes
with the same dye used in the downhole measurement, and the fluid mixture passes through a
spectrometer that analyzes the color.
Comparison of the laboratory pH measurement with the real-time in situ pH measurements made on the same formation water allows
27. Carnegie AJG, Raghuraman B, Xian C, Stewart L,
Gustavson G, Abdou M, Al Hosani A, Dawoud A,
El Mahdi A and Ruefer S: “Applications of Real Time
Downhole pH Measurements,” paper IPTC 10883,
presented at the International Petroleum Technology
Conference, Doha, Qatar, November 21–23, 2005.
28. Stiff HA: “Interpretation of Chemical Water Analysis by
Means of Patterns,” Transactions of the American
Institute of Mining and Metallurgical Engineers 192 (1951):
376–378. [Also published as paper SPE 951376 and
reprinted in Journal of Petroleum Technology 3, no. 10
(October 1951): 15–17.]
29. An equivalent is the amount of a material that will react
with a mole of OH– or H+. A milliequivalent is an
equivalent/1,000.
30. Mathews SG, Raghuraman B, Rosiere DW, Wei W,
Colacelli S and Rehman HA: “Laboratory Measurement
of pH of Live Waters at High Temperatures and
Pressures,” paper SPE 121695, presented at the SPE
International Symposium on Oilfield Chemistry, The
Woodlands, Texas, USA, April 20–22, 2009.
33
6.3
6.2
pH
6.1
6.0
5.9
5.8
8,000
12,000
16,000
20,000
Pressure, psi
> High-pressure, high-temperature (HPHT) laboratory measurements of pH. Schlumberger scientists
performed pH measurements on live waters at reservoir pressure and temperature (19,542 psi and
242°F) and at a range of pressures down to 8,000 psi (bottom). The optical spectrum of the aqueous
system was measured using probes connected to an HPHT scanning cell (top right). Optical signal
monitoring (top left) indicated that water stayed in single phase down to 8,000 psi with no scale onset.
The pH measurement is calibrated only to 10,000 psi: The scarcity of thermodynamic data in the
literature makes calibration difficult and uncertain at pressures greater than that. In this figure,
calibration parameters for 10,000 psi are used for the data at pressures of 10,000 psi and greater,
which are indicated by a dashed line.
fluid analysts to validate the integrity of the
sample. A good match indicates the sample is
still representative of the formation water.
Sample validation in this manner is an implementation of the “chain of custody” concept.31
The laboratory setup also allows chemists to
measure the live-water pH as a function of temperature and pressure and flag the onset of
scale precipitation. These additional measurements can be used to better constrain and tune
water-chemistry models.
Chevron tested this technique on formation
water samples from two Gulf of Mexico wells.32 In
Well A, the zone of interest is a thick, permeable
water zone—a potential supply for injection
water—thousands of feet above the reservoir. The
company wanted to assess the corrosion potential
of the water and evaluate its compatibility with
the reservoir formation water. Downhole mea-
34
surements of pH were made and samples were
collected at two depths. Laboratory measurements matched the downhole measurements to
within 0.08 pH units, giving Chevron chemists
confidence that the reconditioned live samples
were representative of formation water.
Comparison with predictions from two different simulators indicated a good match (within
0.15 units) for one sample. For the second sample, the discrepancies were larger, not just
between predicted and measured values, but also
between the two commercial models used for the
simulation (0.24 to 0.65 units). The reasons for
the differences in predicted values from the two
simulators are due to the different thermodynamic databases upon which they are based, as
well as the different approaches to using the
inputs in modeling. The differences highlight the
uncertainties that can arise when flashed water
analysis is used as input to simulators and underscore the importance of direct measurements on
live waters to constrain and tune the models.
In Well B, the zone of interest is a water-rich
interval beneath the oil target; it is considered to
be a potential source of water cut sometime in
the future life of the field. The pH of this water
may have sizeable impact on equipment design,
selection and costs.
Live-water pH measurements were performed
at the in situ temperature of 242°F [117°C] and
pressure of 19,542 psi [134.7 MPa], and then at
pressures down to 8,000 psi [55 MPa] to test the
sensitivity of the measurement to pressure (left).
Fluid analysts monitored the optical signal during this change in pressure and did not detect
any solid precipitation from scale onset or gas
evolution that would have caused light scattering. This indicates that the water stayed as a single phase all the way from reservoir pressure
down to 8,000 psi. The ability to measure pH and
track scale onset with pressure and temperature
in this setup makes it a potentially powerful
method to collect data for tuning and improving
confidence in water chemistry simulator models.
Other Fluid Measurements
Downhole fluid analysis currently can quantify
many fluid properties in situ, including pressure,
temperature, resistivity, density, composition,
gas/oil ratio, pH, fluorescence and optical density. Although most of these fluid property measurements were originally designed with
hydrocarbons in mind, several of them—in addition to pH—may be applied to analysis of formation water.
Recently, a downhole fluid density measurement was tested as an alternative to pH for
detecting WBM contamination and oil/water
contacts. The InSitu Density sensor is a tiny
vibrating rod—a mechanical resonator—in the
tool flowline. The resonance frequency of the rod
decreases as the fluid density increases. The density measurement is useful when the pH of the
WBM is similar to that of the formation water.
Another advantage is that density measurements
may aid in fluid typing in cases that are problematic for pressure-gradient interpretation of fluid
contacts, such as thin beds, low-permeability formations and poor-condition wellbores.
The InSitu Density device has been used for
downhole water analysis in WBM-drilled wells offshore Vietnam, Norway and China.33 Applications
include monitoring contamination cleanup before
collecting water samples, analyzing formation
Oilfield Review
Formation Pressure, psi
2,200
Dry Test
Lost Seal
2,200
Fluid
Lost Seal Fraction
Pretest Quality
Gamma Ray
250
0
3,200 Fluid
Lost Seal Fraction
Dry Test
Pretest Quality
Gamma Ray
gAPI
2,200
3,200
Dry Test
Pretest Quality
0
Formation Pressure, psi
Formation Pressure, psi
3,200
gAPI
250
Gamma Ray
Depth,
m
1.0124 g/cm3 (water)
1,600
0
Sand A
gAPI
Depth,
m
250
1.0124 g/cm3 (water)
Sand A
1,600
0.8859 g/cm3 (oil)
1,700
1.0195 g/cm3 (water)
Sand B
Sand C
1,800
0.8859 g/cm3 (oil)
1,900
Free-water level:
1,693.5 m
2,000
1.3545 g/cm3 (mud)
1,700
1.3545 g/cm3 (mud)
2,100
0.7807 g/cm3 (oil)
Sand B
0.8929 g/cm3 (oil)
Sand D
0.7807 g/cm3 (oil)
1.0195 g/cm3 (water)
2,200
Sand C
Sand E
> Looking for fluid contacts. Fluid densities interpreted from gradients in
pressure measurements (left) in five sands indicated oil only in the deepest
zone, Sand E (below 2,200 m). Pressure measurements (dots) are colorcoded based on quality: green is high and yellow is satisfactory. In Sand D,
around 2,100 m, the gradient suggests a fluid heavier than water, such as
drilling mud. Optical characterization (middle, Depth Track) of the fluids
pumped from Sands A and C identified these intervals as water-prone
layers (blue shading in Depth Track); Sands B and D contain oil (green
water for future reinjection with seawater, evaluating of reservoir vertical connectivity and assessing flow assurance in pipelines and flow streams
to be tied back to processing equipment on a
main platform.
In an exploration example from offshore
China, pressure pretests in five sands yielded
inconclusive fluid-typing results in all but the
deepest zone, Sand E, which had a pressure gra31. Betancourt SS, Bracey J, Gustavson G, Mathews SG
and Mullins OC: “Chain of Custody for Samples of Live
Crude Oil Using Visible-Near-Infrared Spectroscopy,”
Applied Spectroscopy 60, no. 12 (2006): 1482–1487.
32. Mathews et al, reference 30.
33. Mas C, Ardilla M and Khong CK: “Downhole Fluid
Density for Water-Base Mud Formation-Water Sampling
with Wireline Formation Tester,” paper IPTC 13269,
presented at the International Petroleum Technology
Conference, Doha, Qatar, December 7–9, 2009.
34. Creek et al, reference 18.
Spring 2011
shading in Depth Track). Measurements from the InSitu Density tool give
precise density values (gray shaded) for these fluids, values that can be
extended along pressure gradients. In an expanded view (right), gradient
analysis helps interpreters understand reservoir architecture. The
intersection of the water gradient in Sand C (lower blue line) with the oil
gradient in Sand B (green line) identifies the free-water level in Sand B at
1,693.5 m. The nonintersection (dashed circle) of the water gradients
confirms the lack of communication between Sand B and Sand A.
dient indicative of oil. Only one pressure reading
could be obtained from each of Sands A, B and C,
so it was impossible to compute gradients in
those zones. The gradient from the two pressures
measured in Sand D corresponded to the mud
density, indicating whole-mud invasion. Optical
analysis of fluids pumped from the five sands gave
additional but surprising information: Sands A
and C produced water, and Sands B and D produced oil. Real-time downhole fluid density measurements on these same fluids corroborated the
optical and pressure analyses and helped determine the free-water level in Sand B (above).
The number of fluid analysis measurements
that can be made in situ is increasing. Current
capabilities have been likened to having a downhole fluids laboratory.34 Undoubtedly some of the
new measurements will find applications to formation water analysis, increasing the ability of
oil and gas companies to understand their reservoirs, optimize completions, select materials and
monitor water injection.
Extending the array of downhole measurements will likely force high-pressure, hightemperature laboratory techniques to keep pace.
Currently, high-accuracy pH measurements can
be made both in situ and at similar conditions in
the laboratory. In the future, additional analyses
will extract even more information and value
from formation water.
—LS
35
Zapping Rocks
Romulo Carmona
Petróleos de Venezuela, S.A.
Caracas, Venezuela
Eric Decoster
Rio de Janeiro, Brazil
Jim Hemingway
Houston, Texas, USA
Mehdi Hizem
Laurent Mossé
Tarek Rizk
Clamart, France
Dale Julander
Chevron U.S.A. Inc.
Bakersfield, California, USA
Jeffrey Little
Bakersfield, California
Tom McDonald
Perth, Western Australia, Australia
By zapping a formation with microwave energy, dielectric logging tools can analyze
freshwater environments and identify movable hydrocarbons. The measurements
made by these tools are especially useful in characterizing heavy-oil reservoirs. After
a long period of niche application, a new tool is breathing life into this technology.
This resurgence is aided by a recently developed dispersion technique that evaluates
carbonate rock texture and shale effects in sandstones.
Petroleum technologists enjoy finding new methods to poke, prod and probe the Earth. One such
technique, dielectric logging, involves zapping a
formation with microwaves to determine rock and
fluid properties. Although not widely used within
the petrophysics community, dielectric information answers a number of difficult interpretation
questions. The success of a recently introduced
dielectric tool is generating considerable interest
because it provides information that isn’t readily
available from standard logging suites.
Introduced to the oil and gas industry in the
late 1970s, dielectric logging did not find universal acceptance. Lack of acceptance of new technologies is not unusual. Technologies often need
time to evolve, gain a level of appreciation by
users and, finally, be assimilated. The first commercial microwave oven, for example—a radically new technology at the time—was introduced
in 1947. It was taller than the average man and
weighed more than three times as much. Not surprising, domestic sales were nonexistent. But
Jonathan Mude
Petroleum Development Oman
Muscat, Sultanate of Oman
Nikita Seleznev
Cambridge, Massachusetts, USA
Oilfield Review Spring 2011: 23, no. 1.
Copyright © 2011 Schlumberger.
Dielectric Pro, Dielectric Scanner, EPT, FMI, HRLA,
LithoDensity, MR Scanner, Platform Express, and
Rt Scanner are marks of Schlumberger.
1. Serra O: Well Logging Handbook. Paris: Editions
Technip, 2008.
2. Dispersion is the variation in dielectric permittivity and
conductivity when measured at different frequencies.
3. Serra, reference 1.
4. Named for James Clerk Maxwell, this set of partial
differential equations unifies the fundamentals of
electricity and magnetism. There are four basic
equations, but multiple iterations can be developed from
them. For a full derivation of the equations related to
electromagnetics and dielectric response: Serra,
reference 1.
5. Depending on the reference source, microwaves are
generally considered electromagnetic waves with
wavelengths from 1 m to 1 mm, which corresponds to a
frequency range of 300 MHz to 300 GHz.
36
Oilfield Review
today, compact units that little resemble those
early industrial-grade models are standard equipment in kitchens around the world.
Radically new technologies fall into different
categories of acceptance. Some fully supplant
older technologies. Others supplement existing
methods without replacing them. In the example
of the microwave oven, although it may be possible to prepare a complete multicourse meal with
one, rarely is it the primary method of meal preparation. However, as a means for reheating food, a
microwave oven is usually a better option than
previous methods, such as a conventional oven.
Clearly, it is a supplemental technology.
Similarly, a dielectric tool is a supplemental
technology for the oil and gas industry. These
tools were originally developed to analyze formations with freshwater, low-salinity water or where
water salinity was unknown. They respond primarily to the water in the pore network and measure water-filled porosity. From water-filled
porosity, resistivity-independent fluid saturations
can be derived. Log analysts also combined
dielectric measurements with data from deeperreading tools to identify zones with hydrocarbon
mobility, which is crucial information for evaluating heavy-oil reservoirs.
Unfortunately, data quality for earlygeneration tools was frequently compromised
by hole rugosity—a common condition in the
environments in which these tools offered the
greatest benefit—and measurement accuracy
was difficult to quantify. After sparking initial
interest within the petrophysics community,
dielectric tools never reached a level of universal
acceptance for formation evaluation. The introduction of nuclear magnetic resonance (NMR)
tools in the 1990s virtually ended the use of
microwave-based dielectric tools, except in some
specialized applications.1
The recently introduced Dielectric Scanner
multifrequency dielectric dispersion service is
designed to overcome limitations of earlier tools.
It has the ability to measure water-filled porosity,
and, in conjunction with other porosity measurements, fluid saturations. Its collocated transmitter-receiver arrays probe the formation at
multiple depths of investigation and offer
stand-alone oil mobility assessment in heavy-oil
reservoirs. In addition, the tool offers a new
measurement—dielectric dispersion—with which
petrophysicists can determine rock textural properties and shale effects.2
This article presents the basic theory of
dielectric measurements applied to petrophysics,
including a description of the new dielectric dispersion technique. Case studies describe textural
Spring 2011
analysis of carbonates, evaluation of formations
with variable- or low-salinity formation water and
heavy-oil applications.
Microwave Frequency Logging
Three parameters define a rock electrically:
magnetic permeability, electrical conductivity
and dielectric permittivity.3 Reservoir rocks comprise mostly nonmagnetic minerals, thus their
magnetic permeability is negligible. Because the
rock matrix has little conductivity, the electrical
conductivity of the formation, the inverse of
resistivity, is primarily a function of the fluids
that fill the pore network and the connectivity of
the pores. Formation conductivity is generally
measured with induction and laterolog devices
and is a crucial input, along with porosity, in
Archie’s water saturation equation.
Dielectric permittivity is not a measurement
that is generally considered when evaluating reservoir rocks. It is defined as the frequency-dependent
capacity of a medium to store energy from an
applied field and is a function of the degree to which
a material becomes polarized in the presence of
an electric or electromagnetic field. A material’s
dielectric permittivity, ε, can be expressed as its
dielectric constant, which is the permittivity normalized to the lossless environment of a vacuum.
The dimensionless dielectric constant is not really a
constant because it is a function of the frequency
of the electromagnetic field. It is computed from
dielectric data using Maxwell’s equations.4
Minerals, rocks, fluids
Relative dielectric constant
(relative to vacuum)
Anhydrite
Gypsum
Petroleum
Gas
Sandstone
Dolostone
Limestone
Shale
Dry colloids
Fresh water
Water
6.35
4.16
2.0 to 2.4
1.0
4.65
6.8
7.5 to 9.2
5 to 25
5.76
78.3
56 to 80
> Dielectric constants for common minerals,
rocks and fluids.
For most minerals and fluids found in reservoir rocks, with the important exception of water,
dielectric permittivity is quite low (above). For
water, the absolute dielectric permittivity, ε*,
comprises three terms: a real term related to
polarizability, a complex term related to conductivity at a given frequency and a second complex
term related to dipolar relaxation (below).
Because of the large difference between matrix
and water permittivities, a reservoir rock’s dielectric permittivity measured in the microwave range
is primarily a function of the water filling the
pores.5 The permittivity values of oil and the
matrix are similar, and as a result, the presence of
hydrocarbons makes it impossible to invert for
Bulk water 25°C
εr
ε* = εr +i ωσε + i εx
0
Dipolar
σ
ω ε0
Atomic
Electronic
Infrared
Ultraviolet
εx
1.1 GHz
20 GHz
Frequency
> Dielectric permittivity plot for water. The absolute dielectric permittivity, ε*,
for bulk water comprises a combination of real and complex terms and is a
function of the frequency of the electromagnetic field. The real component,
εr (blue), is linear to about 1 GHz and then decreases as the frequency of
the electromagnetic field increases. The complex conductivity term (black)
depends on the frequency of the electromagnetic field, ω, and is normalized
for the permittivity of vacuum, ε0. The conductivity component decreases
as the frequency increases, especially across the frequency range used in
downhole dielectric tools. The second complex term, iεx (purple), is related
to dipolar relaxation and peaks around 20 GHz. It has minimal effect on the
total permittivity measured by downhole tools because they operate in a
frequency range below about 1.1 GHz.
37
Change in amplitude
Transmitter
Phase shift
Receiver
Transmitter-to-receiver spacing, r
Receiver voltage = ƒ (ω, ε, σ, r )
Frequency, ω
Vacuum
Medium
Amplitude change Α
Phase shift
}
ƒ
–1
{
ε Permittivity
σ Conductivity
φ Water-filled porosity
> Microwaves to petrophysics. The dielectric tool transmits an electromagnetic
wave (red sine wave) with a frequency ω into a formation where, as a result
of interactions with the fluids and minerals, its amplitude is attenuated and the
velocity of the wave changes. The velocity change corresponds to a measureable
phase shift. The change in amplitude, Α, and the phase shift of the wave (black
sine wave) after it has passed through the media are measured at the receiver;
they are functions of the initial frequency, ω, dielectric permittivity of the media,
ε, the conductivity of the media, σ, and the transmitter-to-receiver spacing, r.
The change in amplitude and phase shift are then inverted to output permittivity,
conductivity and water-filled porosity, φ.
both water-filled porosity and total porosity using
dielectric data alone. However, in conjunction with
an independent porosity measurement, dielectric
data can quantify fluid saturations.
A second factor affecting a rock’s dielectric
permittivity and conductivity is the manner in
tpo method
φEPT =
tpo – tpma
tpwo – tpma
CTA method
tpl = φSxo tpw + φ (1– Sxo ) tph + (1– φ) tpma
Α = φSxo Αw
CRI method
ε* = (1 – φT) εm+ φT (Sw ε*w + (1 – Sw) εoil )
which its different constituents are mixed
together. This factor is generally small when measured at a frequency of about 1 GHz but dominates the measurement at lower frequencies. For
this reason, rock texture and shale content can
cause frequency-sensitive dispersion in both
permittivity and conductivity measurements.
tpo = lossless traveltime
tpma = traveltime through the matrix
tpwo = lossless traveltime through water
tpl = lossy traveltime (tool measurement)
tpma = traveltime through the matrix
tpw = lossy traveltime through water
tph = lossy traveltime through hydrocarbon
φ = porosity
Sxo = water saturation in the flushed zone
Α = attenuation (tool measurement)
Αw = attenuation through water
ε* = dielectric permittivity
εm = permittivity of the matrix
εw* = permittivity of water
εoil = permittivity of hydrocarbon
Sw = water saturation
φT = total porosity
> Evolution of dielectric petrophysics. An early porosity transform for dielectric
tools, the tpo method (top), looks similar to the Wyllie equation used to compute
porosity from acoustic data. The transfrom is valid only for lossless traveltime,
which is not representative of the downhole environment. The complex time
average (CTA) method (middle) provides water-filled porosity from attenuation,
traveltime and water saturation in the flushed zone. It includes corrections for
losses, but is not as accurate as the complex refractive index (CRI) method
(bottom). The CRI method uses the dielectric permittivity, ε*, measured at
downhole conditions. Matrix, hydrocarbon and water permittivities, used in the
equation, are also adjusted for downhole conditions. Water saturation is solved
for using a total porosity, φT, provided by another source, such as the crossplot
porosity from density and neutron tools.
38
Schlumberger introduced the first commercial downhole device capable of measuring
dielectric properties using microwaves, the EPT
electromagnetic propagation tool, in the late
1970s.6 It operated at a single frequency of
1.1 GHz and measured attenuation and phase
shift of waves traveling through the formation.
Mathematical inversions were then applied to
the attenuation and phase shift to derive petrophysical properties—including dielectric permittivity, conductivity and water-filled porosity
(left). Petrophysicists determined fluid saturations by comparing this water-filled porosity to
the total porosity.
After the introduction of the EPT tool, other
service companies developed dielectric tools,
each designed to operate at a company-chosen
frequency. Because of the frequency dependence
of dielectric information, data recorded at different frequencies often yielded different results
and comparing the results between wells could
be problematic. The differences can be attributable to the measurement’s sensitivity to rock texture, clay content and fluid salinity. These
sensitivities, however, were not well understood.
Water-filled porosity from the earliest tools
was computed following the tpo method, which is
based on the propagation time of the electromagnetic waves as they passed through the rock
(below left). This calculation involved a simple
transform that resembles the Wyllie equation
used to compute sonic porosity. It requires knowledge of the water salinity and temperature to estimate the propagation time in formation water.
Formations, however, consist of more than just
water. There are pore fluids—water, oil and gas—
and minerals in the rock matrix. Relationships
between each of these constituents, as they exist
in the formation, can alter the electromagnetic
waves. The tpo method was not adequate for computing water-filled porosity and, therefore, various
mixing laws have been proposed to account for the
interaction of the electromagnetic field with the
various elements in the formation.7
The complex time average (CTA) method, combining both phase-shift and attenuation measurements, was an early technique for calculating
petrophysical properties of a mixture. Two independent equations can be written, one for phase
shift and one for attenuation of the signal, to determine the volume of water in the pore network.
An alternate approach, the complex refractive index (CRI) method, is based on Maxwell’s
equations. Because of the time-dependent sinusoidal nature of an electromagnetic field, the
time derivative of Maxwell’s equations can be
greatly simplified.8 It is reduced to two terms that
Oilfield Review
define the absolute dielectric permittivity, a
real-number permittivity term and a complex
frequency-dependent conductivity term.9 The
complex number term consists of the angular frequency of the applied electromagnetic field and
a conductivity that can be expressed as a real
number. A single equation transforms the propagation time and attenuation into physical quantities—permittivity and conductivity. Because
matrix minerals and hydrocarbons are poor conductors and generally act as insulators, the conductivity signal is dominated by the water in the
region sensed by the tool—the flushed zone.
Solving for the dielectric conductivity provides
the conductivity of the fluids that fill the pores in
the near-wellbore region.
Mud filtrate from the invasion process enters
the flushed zone and alters the properties of the
fluids that were originally in place. This invasion
is not uniform or easily quantified. Early methods
for computing dielectric properties, such as the
tpo method, assumed fixed values of fluid conductivity. Directly solving for the conductivity of the
fluid in this region, which is possible with the CRI
method, provides more-accurate results for the
water-filled porosity measurement. For this and
other reasons, the CRI method has become the
generally accepted technique for computing petrophysical properties from dielectric data.10
In addition, textural parameters of rocks,
which are difficult to quantify from the tools used
in conventional logging suites, can be derived
from the dispersion of dielectric data made at multiple frequencies. At frequencies around 1 GHz, textural parameters have limited effects on outputs
derived from the CRI method. An exception, however, is high-salinity environments, which can
enhance textural dispersion even with frequencies in the 1-GHz range. At lower frequencies, textural effects significantly impact dielectric
permittivity measurements—this is especially
true in carbonate reservoirs.11 Several dispersion
models have been developed to account for the
frequency-dependent phenomenon.
A dispersion analysis, discussed below, has
been developed that uses multifrequency dielectric outputs to quantify the cementation exponent, m, which is one of two crucial texture-related
inputs in Archie’s water saturation equation. For
carbonates, values for these parameters are generally derived from core data, which are then
applied to offset wells. The method used for measuring these parameters from core is a lengthy
and expensive process. With continuous outputs of
m for Archie’s equation from dielectric dispersion
Spring 2011
Polarization
Type
E
E=0
Center of + and –
8+
Electronic
8+
Center of –
Center of +
+
Orientational
8+
+
Interfacial
Oil
Matrix
Water
Salt ions
> Polarization mechanisms. Several mechanisms related to a material’s polarizability affect dielectric
measurements. For electronic polarization (top), balanced atomic structures may shift in the presence
of an electromagnetic field, E, but the effects are minimal. In contrast, water molecules exhibit
orientational polarization (middle) because they are dipolar. In the initial state, these easily polarizable
water molecules are found as randomly oriented dipoles. When exposed to an electromagnetic field,
they attempt to align with the direction of the field. Interfacial polarization for reservoir rocks (bottom)
is influenced by the presence of charged clays, brine and oil in the pore network and the matrix
minerals. Minerals and elements in the rock that might not be polarizable in isolation often behave
differently in a mixture, exhibiting a larger permittivity value than any of the constituent components.
This phenomenon is an example of the Maxwell-Wagner effect.
information, petrophysicists can better evaluate
carbonates using downhole data. Accurately characterizing texture in this rock type is important
because an estimated 60% of the world’s remaining oil is found in carbonate reservoirs.
Dielectrics and Dipoles
Materials that become polarized when exposed to
a static electromagnetic field are referred to as
dielectrics.12 A material’s susceptibility to polarization is directly related to its dielectric permittivity. There are three primary polarization
mechanisms that can be related to petrophysical
properties: electronic polarization, molecular orientation and interfacial polarization (above). To
understand how electromagnetic waves interact
with various media, consider a porcelain mug,
filled with coffee and placed in a microwave oven.
The mug is essentially unaffected by the microwaves as they pass through it, but the coffee in the
mug heats rapidly. Accidently leaving a metal
spoon in the mug can be disastrous because of the
interaction of microwaves with good conductors
such as metal.
6. A Russian dielectric tool predated the EPT tool by
10 years but had limited availability.
7. For more on the various mixing laws: Seleznev N, Boyd
A and Habashy T: “Dielectric Mixing Laws for Fully and
Partially Saturated Carbonate Rocks,” Transactions of
the SPWLA 45th Annual Logging Symposium, Noordwijk,
The Netherlands (June 6–9, 2004), paper CCC.
8. For assumptions made and the full derivation from
Maxwell’s equations: Böttcher CJF and Bordewijk P:
Theory of Electric Polarization: Dielectrics in
Time-Dependent Fields, vol 2, 2nd ed. New York City:
Elsevier Scientific Publishing Company (1978): 10–19.
9. A third complex number can be ignored for downhole
applications.
10. The CRI method was proposed in Wharton RP, Hazen GA,
Rau RN and Best DL: “Electromagnetic Propagation
Logging: Advances in Technique and Interpretation,”
paper SPE 9267, presented at the 55th SPE Annual
Fall Technical Conference and Exhibition, Dallas,
September 21–24, 1980.
For a comparison of the CTA and CRI methods:
Cheruvier E and Suau J: “Applications of Micro-Wave
Dielectric Measurements in Various Logging
Environments,” Transactions of the SPWLA 27th
Annual Logging Symposium, Dallas (June 9–13, 1986),
paper MMM.
11. Kenyon WE: “Texture Effects on Megahertz Dielectric
Properties of Calcite Rock Samples,” Journal of Applied
Physics 55, no. 8 (April 15, 1984): 3153–3159.
12. Melrose DB and McPhedran RC: Electromagnetic
Processes in Dispersive Media. Cambridge, England:
Cambridge University Press, 1991.
39
These materials respond to electromagnetic
energy differently because of their atomic and
molecular properties and their intrinsic conductivities. Rather than becoming polarized when struck
by microwaves, metal objects, such as the spoon,
may experience an induced current. This is because
there are free electrons in the metal that move
when it is exposed to the electromagnetic field.
Resistance to current flow can generate extreme
heat and the induced current may arc if a conductive path is unavailable. Because they are electrical
conductors, most metals have a dielectric permittivity that can be a negative value. For this reason,
metals are not generally classed as dielectrics.
The porcelain mug, on the other hand, is nominally affected by the electromagnetic field, and
it becomes only slightly polarized. The origin of
its polarization lies in the electronic clouds
surrounding the nuclei of the atoms. When the
electric field is applied, the electrons’ trajectories shift. This phenomenon is called the electronic polarization. The resulting dielectric
constant, in the range from 5 to 7, is similar to
that of reservoir rocks.13
The coffee, or more specifically, the water
portion of the coffee, exhibits an entirely different
behavior in the presence of the electromagnetic
field. Water molecules—composed of two hydrogen atoms and one oxygen atom—are asymmetrical: the centers of their positive and negative
charges do not coincide. This asymmetry results
in a permanent dipole moment for water molecules. Because of its much greater susceptibility
to polarization, water’s dielectric constant is
around 80—an order of magnitude higher than
that of porcelain.
30% Water, 70% Matrix
In the absence of an electric field, individual
water dipoles point in random directions, so the
net moment per unit volume is zero. However,
when an electric field is applied, in addition to
electronic polarization of the oxygen and hydrogen atoms, the field tends to orient the individual
dipoles, resulting in a net positive moment per
unit volume. This effect is called orientational
polarization. The collisions of the molecules in
their thermal motion disorient the molecules and
limit the net dipole moment per unit volume.
Thus the magnitude of the orientational polarization is a result of the type of polar molecule and
its temperature.
Orientation of polar molecules under the
influence of an applied field is not instantaneous.
It requires a finite time due to the molecular
moment of inertia and, as a result, there is resistance to realignment as the field reverses direction. If the frequency of the applied field is
sufficiently high, for instance in the microwave
range, the polar molecules do not have enough
time to orient along the field direction and the
contribution of orientational polarization is
diminished. The water molecules’ resistance to
the rapidly changing polarity can be expressed as
heat. This phenomenon is referred to as dipolar
relaxation loss.
A dielectric phenomenon of saltwater, or
brine, is that with increasing salinity, the conductivity of a solution increases but the permittivity
of the solution decreases. Adding salt to a solution increases the number of water molecules
nonrotationally bound to the NaCl molecules,
thereby decreasing the orientational polarization. At the same time, the concentration of ions
10% Water, 20% Oil, 70% Matrix
Sw = 100%
φ Total = 30%
φ Dielectric = 30%
Sw = 33%
φ Total = 30%
φ Dielectric = 10%
> Saturation from dielectric measurements. Petrophysicists generally use Archie’s water saturation
equation, which requires inputs for porosity and resistivity. The dielectric method requires no
resistivity. The simplified relationship shown here demonstrates how this is carried out. The dielectric
porosity is a measurement of the water-filled portion of the porosity. When all the pore space is
filled with water (left), the porosity from the dielectric tool, φDielectric, matches the total porosity
measurement, φTotal, which must come from another source such as density-neutron crossplot
porosity. Because their dielectric properties are similar, hydrocarbons are indistinguishable
from the matrix for dielectric measurements. Thus, decreases in the porosity as measured by the
dielectric tool that are not mirrored by the total porosity relate directly to increases in the volume of
hydrocarbons (right).
40
contributing to current conduction increases. A
temperature increase has a similar effect on the
solution properties: the solution conductivity will
increase, and the solution permittivity will
decrease due to the stronger effect of the thermal
dipole disorientation.
As the electromagnetic wave passes through
various media, it is altered by interaction with
the media. The amplitude and the velocity of the
wave decrease as a function of the amount of
energy imparted, and the phase of the wave
shifts. For materials with low dielectric constant
values, such as the coffee mug or rock matrix,
there are minimal effects on the returning electromagnetic wave. In contrast, water’s high
dielectric constant causes a large effect.
As early as the 1950s, petrophysicists experimenting with microwaves recognized that the
dielectric permittivity measurement from saturated core samples was controlled primarily by
the amount of water in the pores and could be
directly related to water-filled porosity. However,
to compute the water fraction of a rock sample
from dielectric measurements, the relationships
between the dielectric properties of the constituents that comprise the core sample must be
known. Mixing laws were established under
controlled laboratory conditions to model the
effects of these relationships.
In the laboratory, dielectric properties can be
measured by different methods employing various sample sizes and shapes. The measurement
technique depends on the frequency of interest.
For instance, the capacitive technique is
typically employed for frequencies up to several
MHz. The material is placed between the plates
of a capacitor, and from the measurements of the
capacitance the dielectric constant can be calculated. This model works well if the wavelength is
much longer than the space between the conductor plates.
At high frequencies, it is difficult to measure the
total voltage and current at the device ports.
Because of the impedance of the probes and the difficulty of placing the probe at the desired position,
one cannot simply connect a voltmeter or a current
probe and get accurate measurements. For frequencies in the GHz region, scientists developed techniques such as a transmission line or a microwave
resonator. Transmission line methods are widely
utilized because they allow for broadband measurements. The spanned bandwidth is limited, on the
low end, by decreasing sensitivity to the sample’s
dielectric constant with increasing wavelength. The
maximum measurement frequency depends on the
type of the transmission line, the forward model and
the limitations of the acquisition system.
Oilfield Review
13. Virtual Institute of Applied Science Encyclopedia:
“Dielectric Constant,” http://www.vias.org/
encyclopedia/phys_dielectric_const.htm
(accessed February 11, 2011).
14. Poley JPh, Nooteboom JJ and de Waal PJ: “Use of
V.H.F. Dielectric Measurements for Borehole Formation
Analysis,” The Log Analyst 19, no. 3 (May–June, 1978):
8–30.
15. Akkurt R, Bachman HN, Minh CC, Flaum C, LaVigne J,
Leveridge R, Carmona R, Crary S, Decoster E, Heaton N,
Hurlimann MD, Looyestijn WJ, Mardon D and White J:
“Nuclear Magnetic Resonance Comes Out of Its Shell,”
Oilfield Review 20, no. 4 (Winter 2008/2009): 4–23.
16. For more on carbonate reservoir analysis:
Al-Marzouqi MI, Budebes S, Sultan E, Bush I, Griffiths R,
Gzara KBM, Ramamoorthy R, Husser A, Jeha Z,
Roth J, Montaron B, Narhari SR, Singh SK and
Poirer-Coutansais X: “Resolving Carbonate Complexity,”
Oilfield Review 22, no. 2 (Summer 2010): 40–55.
17. Ali SA, Clark WJ, Moore WR and Dribus JR:
“Diagenesis and Reservoir Quality,” Oilfield Review 22,
no. 2 (Summer 2010): 14–27.
18. For more on the derivation of models used for textural
inversion: Stroud D, Milton GW and De BR: “Analytical
Model for the Dielectric Response of Brine-Saturated
Rocks,” Petrophysical Review B 34, no. 8 (October 15,
1986): 5145–5153.
Baker PL, Kenyon WE and Kester JM: “EPT
Interpretation Using a Textural Model,” Transactions of
the SPWLA 26th Annual Logging Symposium, Dallas
(June 17–20, 1985), paper DD.
Kenyon, reference 11.
Spring 2011
Carbonate 1
Carbonate 2
CRI method
50
45
40
Permittivity
Quantifying water-filled porosity from dielectric measurements is important because the ratio
of the water-filled porosity to the total porosity
represents the water saturation (previous page).
The dielectric permittivity measurement can
determine water saturation independent of a
resistivity measurement—a critical and necessary
input for Archie’s water saturation equation.14
Both freshwater and hydrocarbons have high
resistivity values. Typical oilfield brines found in
reservoir rocks have low resistivity. Archie’s
equation is based on the assumption that a
contrast exists between the resistivity of
hydrocarbon-bearing formations and those filled
with brine. It does not provide accurate saturation results in reservoirs with freshwater, lowsalinity water or where the salinity of the
formation water is unknown. In these environments, the large contrast between the dielectric
permittivity of hydrocarbons and water, regardless of brine salinity, makes for an ideal saturation measurement.
Nuclear magnetic resonance (NMR) tools
are also able to detect hydrocarbons in freshwater environments by measuring the diffusion of
the fluids.15 Because they do not rely on the
resistivity of the fluids in the pore spaces to
determine saturations, dielectric and NMR tools
are often the primary means for quantifying
hydrocarbon volumes in freshwater environments or where the formation-water salinity is
unknown. The dielectric tool measurement,
however, must be combined with porosity from
another source to provide hydrocarbon satura-
35
EPT tool
operating
frequency
30
25
20
15
10
10 2
10 3
Frequency, MHz
> Dispersion in carbonates. Scientists found that, because of differences
in rock texture, otherwise similar carbonates can have very different
dielectric responses, especially at lower frequencies. Laboratorymeasured values of permittivity of two different carbonate samples with
similar porosity, permeability and saturating fluids are shown along with
permittivity computed using the CRI method (black). The permittivity of
Carbonate 2 (red) is similar to the results from the CRI method, but the
permittivity of Carbonate 1 (green) is different. Neither sample provided an
exact match—except around 1 GHz, which corresponds to the EPT tool’s
operating frequency (red dashed line). Because other factors were equal,
this frequency-related dispersion is associated with the different textures of
the carbonate samples.
tions. The results do not depend on the hydrocarbon type or the pore network.
Dielectric and NMR tools have a shallow
depth of investigation, which prevents them from
fully supplanting traditional triple-combo logging
suites. Whereas resistivity tools measure up to a
few meters into the formation, the nature of NMR
and dielectric measurements limits them to the
first few centimeters from the wellbore wall: the
flushed zone, where the virgin fluid has been
invaded by mud-filtrate.
However, the shallow nature of the dielectric
measurement provides important information
about oil mobility. Comparing the saturation
derived from dielectric measurements corresponding to the flushed zone with that of the
virgin zone can help quantify the volume of oil
flushed by water-base mud filtrate. This oil is
movable and can be produced using primary
production means; however, zones with oil that
is not flushed generally require other methods,
such as steam injection, water or CO2 floods or
any of a multitude of enhanced oil recovery techniques to flush the oil from the rock. Ultimately,
these data are best described as information
that, when combined with other logging results,
aides the petrophysicist in accurately characterizing the reservoir.
Dielectric tools, however, offer petrophysicists more than the ability to quantify water-filled
porosity and compute hydrocarbon volume. Using
a newly developed measurement technique that
relies on dielectric dispersion, the tools are also
able to determine rock properties. This has been
shown to be especially useful in carbonates but
also provides insight for evaluating shaly sands.
Dispersion
Because biological and sedimentological factors
can produce a complicated pore network, carbonates have a much more complex structure
than siliciclastic rocks.16 The pore network may
also be chemically altered through postdepositional diagenesis.17 This makes evaluation of petrophysical properties of carbonates challenging—
especially permeability and fluid saturations,
which are not directly measured but derived from
combinations of measurements using an appropriate model.
Schlumberger researchers found that dielectric properties computed with a frequency of
1 GHz using the CRI technique were accurate for
carbonate rock samples saturated with oil-brine
mixtures (above). However, factors other than
mineralogy and water content affect permittivity
at lower frequencies.18 Permittivity dispersion
measurements on two carbonate rocks with similar porosity, mineralogy and water saturation highlighted this frequency-dependent textural difference. The observation of frequency dependence
41
φ = 15.6%
40
10 0
Conductivity, S/m
50
Permittivity
φ = 15.6%
0.051 ohm.m
0.211 ohm.m
1.010 ohm.m
4.890 ohm.m
Dried
60
30
20
10 -1
10
1
10 1
10 2
10 3
10 -2
10 1
10 2
10 3
Frequency, MHz
Frequency, MHz
> Effects of fluid salinity on dielectric measurements. Cores were saturated with four different brines ranging in resistivity from 4.890 to 0.051 ohm.m.
Permittivity (left) and conductivity (right) were computed for a frequency range of 10 MHz to 10 GHz. The permittivity measurements converged around
1 GHz. For comparison, a baseline permittivity measurement was made on a dried core sample (blue). The core saturated with the highest salinity brine
(green) displayed the highest dispersion and was the only one that did not converge at 1 GHz. Dielectric conductivity on the other hand, did not converge
but increased with frequency for all four samples, demonstrating the dispersive effects of fluid salinity.
0.50
50
0measurement
45
Laboratory0.45
Textural model
0.40
Conductivity, S/m
Permittivity
40
30
0.30
0.20
20
0.10
10
106
107
108
0
109
106
107
Frequency, Hz
108
109
Frequency, Hz
0.50
50
0measurement
45
Laboratory0.45
CRI method0.40
Conductivity, S/m
Permittivity
40
30
0.30
0.20
20
0.10
10
106
107
108
Frequency, Hz
109
0
106
107
108
109
Frequency, Hz
> Model comparison. Permittivity and conductivity (blue) from laboratory core measurements for a
carbonate sample were compared to values computed using the CRI method (bottom, black) and the
new dispersion textural model (top, red). The CRI method matches core-derived properties at 1 GHz;
however, there is little agreement between the carbonate samples and the CRI method at lower
frequencies, especially for conductivity. The textural model almost perfectly matches the core data.
The example shown is one of several carbonate cores tested; all tested cores showed similar results.
(Adapted from Seleznev et al, reference 19.)
42
for dielectric properties led the scientists to
develop a dielectric dispersion model to characterize rock texture.
Researchers also experimented with permittivity and dielectric conductivity of siliciclastic
core samples saturated with brines of different
salinity.19 Although the permittivity of a dry sample is constant over a wide range of frequencies,
the permittivity values of the brine-soaked
samples change with salinity, converging at frequencies around 1 GHz (above). The dielectric
conductivities, however, are not linear, and the
effect of the brine on the value of the conductivity increases with the frequency of the applied
electromagnetic field. Therefore, any variation in
the dielectric permittivity with applied frequency
must be related to either textural properties or
fluid salinity.
Over the years, various models have been
developed to quantify dispersion. The textural
model utilizes geometric elements—platy
grains—to account for differences in textural
parameters. To validate the models, scientists
acquired experimental dielectric permittivity
and conductivity data using a wide range of frequencies for rocks with several distinct textures.
They then used the dispersion model to fit their
measurements. This inversion technique generated results for dielectric permittivity and conductivity that more closely matched core
measurements than with the traditional CRI
technique (left).
Oilfield Review
The textural method can be used to derive the
cementation exponent, m, used in Archie’s water
saturation equation. Cementation data computed
using the textural model compared favorably
with cementation exponents independently measured from carbonate cores. Laboratory data
were successfully modeled across a wide range of
m-values from 1.7 to 2.9 (right). This technique
has been used to explain carbonate texture–
related resistivity variations that result in misleading saturation estimates (below right).
Dispersion effects are not limited to carbonate analysis; they can also be applied to shalysand evaluation. However, the dispersion models
for shales are different from the one used for carbonate analysis because the clays, which make
up the shale, induce specific dispersion behaviors.
19. Seleznev N, Habashy T, Boyd A and Hizem M:
“Formation Properties Derived from a Multi-Frequency
Dielectric Measurement,” Transactions of the SPWLA
47th Annual Logging Symposium, Veracruz, Mexico
(June 4–7, 2006), paper VVV.
20. Laminated sands are characterized by intervals of
stacked, thin sand and shale layers. The presence
of the shale laminae results in lower bulk resistivity
measurements and can mask the presence of
hydrocarbons. Laminae thickness is generally below the
resolution threshold of conventional logging tools.
Computed m from textural model
3.5
3.0
2.5
2.0
1.5
1.0
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Laboratory measured m from cores
> Cementation exponent for Archie’s water saturation equation. The
cementation exponent, m, can be measured from core data, but it is a
time-consuming process. The textural model, developed from dielectric
dispersion analysis, was used to solve for m in a number of carbonate core
samples. The crossplot of the values from both methods demonstrates close
agreement over a wide range. The default value of 2 for Archie’s equation
would not be appropriate for most of these samples for which the value
ranges from 1.7 to 2.9. (Adapted from Seleznev et al, reference 19.)
Resistivity
Oil
m
Saturation,
1.0
Depth, Salinity
m 0 ppk 50 6
1
3.5 Corrected m
Gamma Ray
0
Dielectric Deep
gAPI
Caliper
in.
0 % 100
100
Saturation,
m=2
16 0 % 100
ohm.m
1,000
Dielectric Shallow
Lithology
Shaly Sands
Quantifying shaliness has been limited to correlations with gamma ray, sonic, neutron capture
spectroscopy or differences in neutron and density porosity logs. The results are not a direct
measurement but are based on empirical inferences. The dielectric dispersion model directly
quantifies shale effects such as those seen in
laminated sand-shale sequences.20 This is especially useful in freshwater shaly sands where the
measured resistivity is determined in large part
by the clay content. But applications of dielectric
data for shaliness are not limited to just freshwater. Because the dispersive response of a clay’s
4.0
1
ohm.m
Dielectric Porosity
1,000 50
Deep Induction
1
ohm.m
%
0
Total Porosity
1,000 50
%
0
X,750
X,760
X
,770
X,770
X,780
X,790
X,800
X,810
X,820
> Validating the dispersion model. Because of textural effects, computing Archie’s water saturation
in carbonates using traditional techniques can yield incorrect results. In this example, the deep
induction resistivity data (Track 5, red) are higher from X,764 to X,778 m (blue-shaded zone) than above
or below. Water saturation computed using Archie’s equation (Track 3, red) with a fixed cementation
exponent, m = 2, indicates the possible presence of oil (green shading) in this interval. The porosity
from the dielectric tool (Track 6, blue) overlays the total porosity (black), which implies that there are
no hydrocarbons. The dispersion-derived value for m (Track 2, blue) varies from 1.9 to 2.6 across this
interval. Water saturation computed using this corrected m-value in Archie’s equation results in 100%
water saturation (Track 3, black), which is more in line with expectations.
Spring 2011
43
Smectite-water mixture
Kaolinite-water mixture
400
Ottawa sand–water mixture
Real permittivity, εr
300
200
Δ εr
100
0
10 1
10 0
10 2
10 3
Frequency, MHz
> Interfacial polarization. Mixtures of sand and clay exhibit dispersive
dielectric permittivity behavior depending on the clay type. The real
permittivity measured in a smectite-water mix has a large frequency
dependence—compare the real permittivity at 10 MHz with that at 1
GHz. For a kaolinite-water mixture, the effects are present, though less
pronounced. There is little dispersion in the sand-water mixture. Because
of the larger volume of bound water associated with smectite than with
kaolinite, there is an associated decrease in permittivity with increased
frequency. This correlation between dispersion and shale content and type
can be used to compute the cation-exchange capacity (CEC) and quantify
shale effects from dielectric data.
Oil
Hydrocarbon
Sw
Archie
Horizontal Resistivity
Depth,
ft
FMI Image
Sw
Dielectric
0 % 100
Lithology
0 % 100
1
ohm.m
Dielectric Porosity
1,000 50
Vertical Resistivity
1
ohm.m
%
0
Crossplot Porosity
1,000 50
%
0
1,350
1,360
> High-resolution hydrocarbon saturation. Differences in horizontal and vertical resistivities (Track 4)
from a triaxial induction device, such as the Rt Scanner tool, can help interpreters identify anisotropy.
However the laminations in the FMI fullbore formation microimager data (Track 1) are finer than the
resolution of the induction tool or the density-neutron tools, as shown in the crossplot porosity (Track
5, black). This can result in an excessively high net-pay calculation. The vertical resolution of the
saturation measurement from the Dielectric Scanner tool (Track 2, black) can be as small as 2.5 cm. The
resolution difference is highlighted by comparing the Archie water saturation (Track 2, red) with the
dielectric saturation (black). Incorporating dielectric data into the analysis results in a more accurate
sand count and reserves estimate.
44
dielectric properties directly relates to the physics controlling its conductivity, the dispersion
technique yields accurate clay estimation (left).21
As demonstrated with carbonates, the relative permittivity computed from the CRI model
may not match core-derived data at frequencies
lower than 1 GHz. This dispersive behavior is also
seen in shaly sands and sand-shale sequences but
for different reasons. For these rocks, it correlates with the cation-exchange capacity (CEC) of
the minerals in the formation, which relates to
both the electrochemical polarization, also
referred to as a double-layer effect, and to
Maxwell-Wagner interfacial polarization. Both
effects are present, and electrochemical effects
dominate at lower salinity while interfacial polarization dominates at high salinities.
The CEC is the quantity of cations (positively
charged ions) that a clay mineral can accommodate on its negatively charged surface. Clays are
aluminosilicates that have had some of their
aluminum and silicon ions replaced by elements
with a different valence, or charge. The presence
of ions from clays enhances electrochemical
interfacial polarization.22
Nonconductive elements found in the formation, when mixed together, may exhibit dielectric
conductivity that would not be present when
these elements are in isolation. This is due to the
geometric Maxwell-Wagner phenomenon, which
is related to charge accumulation at the interface
between brine and rock or brine and oil. Between
these charged surfaces, the brine forms macroscopic dipoles, which give rise to frequencydependent macroscopic polarizations. When
exposed to a low-frequency electromagnetic
field, the dipoles reach equilibrium before the
field changes direction. When exposed to a highfrequency field, the dipoles cannot follow the
rapidly changing field, resulting in energy dissipation, increased electrical conductivity and
reduced dielectric permittivity.23
In the Dielectric Scanner tool’s frequency
range (20 MHz to 1 GHz), both electrochemical
and geometric (Maxwell-Wagner) polarization
mechanisms contribute to the overall dielectric
dispersion measured in clay-containing formations. The electrochemical response decreases
21. Myers MT: “A Saturation Interpretation Model for
the Dielectric Constant of Shaly Sands,” paper 9118,
presented at the Fifth Annual Society of Core
Analysts Conference, San Antonio, Texas, USA,
August 20–21, 1991.
22. Seleznev et al, reference 19.
23. Toumelin E and Torres-Verdín C: “Pore-Scale Simulation
of KHz-GHz Electromagnetic Dispersion of Rocks: Effects
of Rock Morphology, Pore Connectivity, and Electrical
Double Layers,” Transactions of the SPWLA 50th Annual
Logging Symposium, The Woodlands, Texas, USA
(June 21–24, 2009), paper RRR.
Oilfield Review
with increasing brine salinity. Maxwell-Wagner
effects increase with increasing brine salinity.
For a given brine salinity, an increase in the
rock’s clay content causes an increase in its CEC
value and an increase in its dielectric dispersion
due to both the electrochemical and MaxwellWagner mechanisms simultaneously.
The relative importance of each mechanism is
influenced by the brine salinity. For example,
measurements of a vacuum-dried sample show no
frequency dependence, but in sedimentary rocks,
dielectric permittivity will increase with increased
surface area and CEC. By relating dispersion from
shale effects to the CEC, petrophysicists can
quantify the shale content of reservoir rocks.
Attempts to determine clay volume as well as
clay type are motivated by the need for a CEC
input to water saturation equations. CEC determines the effect of the clay on resistivity measurement as well as the bound water volume that
needs to be excluded from the total porosity measurement so that water saturation and oil volume
can be properly determined. Measuring CEC
Caliper
arm
3
ke
ca
R XA
ud
4
M
R XA
2
ob
pr
R XA
e
R XA
Articulated
pad
1
TA
TB
1
R XB
2
R XB
directly rather than estimating it from clay type
and volume is a simpler and more robust means
of determining water saturation in shaly sands.
An added benefit of the dielectric measurement is the ability to directly measure shale content and saturation at high resolution. Although
techniques have been developed for measuring
anisotropy with resistivity devices such as the Rt
Scanner triaxial induction tool, this measurement does not have the vertical resolution of the
dielectric tool. Nuclear porosity devices can provide inputs for high-resolution saturation measurements, but the vertical resolution of these
data is limited by physics and detector spacing.
The dielectric measurement provides water-filled
porosity at resolutions in the 2.5-cm [1-in.] range.
The dielectric information allows petrophysicists
to more accurately calculate reserves and estimate production than they currently can with
resistivity and porosity from other sources,
including new technology such as triaxial induction tools (previous page, bottom).
The ability to measure shaliness and shale
effects is crucial in characterizing anisotropic
freshwater shaly-sand reservoirs. Interpreters
identify the presence of hydrocarbons in anisotropic reservoirs by observing the difference between
horizontal and vertical resistivities, such as those
from the Rt Scanner tool. However, use of this
technique is not effective in freshwater environments because of the lack of contrast between the
resistivity of freshwater, shale laminations and oil.
Log analysts can, however, determine high-resolution anisotropy using the transverse and longitudinal measurements from the Dielectric Scanner
tool. From these data, shale effects and oil saturation can be quantified.
3
R XB
4
R XB
> The Dielectric Scanner tool. This recently introduced tool incorporates several
features to improve data acquisition and provide greater measurement accuracy.
Unlike previous generation tools that used fixed pads, the Dielectric Scanner tool
uses the caliper arm to push the articulated pad against the formation. The pad’s
curvature also helps improve contact with the borehole wall. The transmitters
(TA and TB) and antenna sets (RXA1 to RXA4 and RXB1 to RXB4) operate at discrete
frequencies from 20 MHz to 1 GHz. Transmitters and antennas are collocated crossdipoles and can operate simultaneously in transverse (red arrow) and in longitudinal
(blue arrow) polarization modes. Two open electric dipoles (open-ended coaxialcable probes) measure mudcake properties and provide quality control. For moreaccurate fluid property input, the tool measures both temperature and pressure at
the point of measurement. Borehole compensation is used to eliminate unbalanced
transmitter-receiver pairs. For each measurement cycle, 72 attenuation and 72 phase
measurements are made for each of the four frequencies. Depth of investigation is
2.5 cm to 10.2 cm [1 in. to 4 in.] depending on transmitter-to-receiver spacing and
formation fluid properties.
Spring 2011
The Dielectric Scanner Tool
Measurements from electromagnetic devices
that operate at frequencies in the kHz range,
such as an induction tool, are better known than
dielectric measurements acquired at very high
frequencies. Lower-frequency measurements are
dominated by the conductivity of the formation,
but as the frequency increases, dielectric effects
begin to appear and then predominate. Very highfrequency measurements offer the ability to evaluate conductivity and permittivity simultaneously.
In addition, obtaining information about texture
and shaliness using dielectric dispersion requires
a high-quality measurement acquired at multiple
frequencies. The Dielectric Scanner tool was
developed to provide a full dataset necessary for
these applications (left).
45
Longitudinal
Transverse
E
H
E
H
Longitudinal
sensed region
Transverse
sensed region
Combined
sensed region
> Tool operational modes. Dielectric tools generate electromagnetic waves and create a field
whose electric components (E) and magnetic components (H) are perpendicular to one another.
The polarization of the wave determines the direction of the created fields. Longitudinal (left) and
transverse (right) polarization modes correspond to measurements in horizontal and vertical planes
with respect to the tool. Each mode generates a specific field orientation and shaped sensed region
(insets). The colored bands represent multiple depths of investigation, which are functions of the
transmitter-receiver spacing and formation properties. The sensed regions of the two modes overlap
(bottom middle); differences in the measurements from the two orientations help identify anisotropy.
F0
Ra
dia
l
inv
es
tig
ati
Mudcake
Invaded zone
pa
cin
es
ipl
on
:m
ult
Virgin zone
R4
gs
Transition zone
R3
F2
F3
Molecular orientation
Electronic polarization
105
Structural investigation: multiple polarizations
R2
F1
Interfacial polarization
R1
10 6
107
10 8
Frequency, Hz
109
10 10
Textural investigation: multiple frequencies
Formation homogeneity
Anisotropy
> Dimensions of dielectric measurements. With its four operating frequencies (F0 to F3) and four pairs
of transmitter-receiver spacings (R1 to R4), the Dielectric Scanner tool has three investigation ranges:
textural, radial and structural. The operating frequencies were chosen to exploit interfacial, molecular
and electronic polarization mechanisms, which are related to textural and shale effects. The radial
investigation is facilitated by four pairs of transmitter-receiver spacings that model the near-wellbore
region, which includes mudcake and invaded zones, and, depending on the depth of invasion, may
extend into the transition and virgin zones. Structural investigation is made possible by polarization
orientation. Measuring in the horizontal and vertical planes allows identification of formation
anisotropy at high resolution.
46
The tool has a fully articulated pad to position
the transmitters and receivers against the borehole wall. The pad shape is cylindrical and the
antennas are designed to be perfect magnetic
dipoles. Each of the two transmitters and eight
receivers can operate with longitudinal or transverse polarization.24 The measurement is performed at four discrete frequencies from 20 MHz
to approximately 1 GHz. Each measurement cycle
includes 72 transmitter-receiver amplitudes and
72 phase measurements. Multiple transmitterreceiver pairs allow for borehole compensation,
and a quality-control algorithm can extract
unbalanced pairs and eliminate them from the
computation. Depth of investigation (DOI)—
a function of the transmitter-receiver spacing,
operating frequency and formation properties—
varies from 2.5 cm to 10.2 cm [1 in. to 4 in.].
A 2.5-cm vertical resolution is achieved.
Electric dipoles on the pad face provide two
modes of operation. In propagation mode, they
make the shallowest transverse measurement
and are used to estimate mud properties. In
reflection mode, they measure the dielectric
properties of the material directly in front of the
pad: mud or mudcake.
Because the tool acquires data in both
longitudinal and transverse polarizations, highresolution anisotropy effects can be quantified.
Longitudinal polarization probes the permittivity
and conductivity in a plane that is orthogonal to
the tool axis (above left). Transverse polarization
probes both horizontal and vertical permittivity
and conductivity.
Temperature and pressure measurements are
also needed for compensation in the dielectric
models. Under downhole conditions, pressure
has an appreciable effect on the dielectric properties of water.25 The temperature, salinity and
pressure dependencies should all be included in
a dielectric model to produce accurate interpretation of the logs at downhole conditions.
Temperature is measured with the integrated
mud sensor and a dedicated sensor is used to
measure hydrostatic pressure.
The tool investigates three main areas: radial
information, geologic structure information and
matrix texture (left). The data from the various
transmitter-receiver pairs at all frequencies are
inverted to output permittivities and conductivities
for several layers: the mudcake, the near flushed
zone and the far flushed zone. Petrophysical properties can be computed using the CRI model for each
of the four frequencies. Dispersion processing with
Oilfield Review
CRI Method
Dispersion Model
φT, ε matrix, temperature and pressure
φT, ε matrix, temperature and pressure
Dispersion model
Water model
Dielectric model
Water model
εr, SH, F3
S W, SH
σ Dielectric
Inversion
Input uncertainty
Dielectric constant SH
Parameter uncertainty
Deep invaded zone
εSH, F3
σSH, F3
S W, SH
σwater, SH
> The CRI method versus the dispersion textural model. The Dielectric
Scanner tool has four operating frequencies and multiple transmitterreceiver spacings. For the CRI method (left), the inputs consist of total
porosity, φT, matrix permittivity, εmatrix, temperature and pressure. The
inversion takes the real permittivity measurement and the dielectric
conductivity and outputs water saturation, water conductivity and dielectric
constant for any combination of frequency and transmitter-receiver
spacing. Shown is the shallow (SH) measurement. For reference and quality
inputs from multiple frequencies can be performed
at different DOIs (above).
To facilitate integration of dielectric data
with other logging tool data, engineers have
developed the Dielectric Pro dielectric dispersion interpretation software. Full data processing and interpretation are available using
porosity, resistivity and saturation analysis from
conventional tools. Conductivity and permittivity at multiple frequencies can be computed.
Crossplots of the data provide insight into dispersion for both textural analysis and shaliness.
Various interpretation models are incorporated
into the workflows and provide alternative
methods of analyzing the data. Radial processing can derive variations in formation conductivity and permittivity for anisotropy analysis.
But, the real test of dielectric logging comes
from downhole applications.
Spring 2011
SW, SH
σwater, SH
Inversion
Input uncertainty
Mudacake
Mudacake
Shallow invaded zone
σwater, SH
ε r, SH, F0, σDielectric, SH, F0
ε r, SH, F1, σDielectric, SH, F1
ε r, SH, F2, σDielectric, SH, F2
ε r, SH, F3, σDielectric, SH, F3
Dielectric constant SH
Textural parameters
Parameter uncertainty
Shallow invaded zone
Deep invaded zone
ε SH, F0, σSH, F0
ε SH, F1, σSH, F1
ε SH, F2, σSH, F2
ε SH, F3, σSH, F3
ε Deep, F0, σ Deep, F0
ε Deep, F1, σ Deep, F1
ε Deep, F2, σ Deep, F2
ε Deep, F3, σ Deep, F3
control, the measurement uncertainty of the inputs can be computed and
applied to the outputs as well. Inputs for the dispersion model (right) are
similar but permittivity and conductivity at multiple frequencies are required
for processing. Outputs include water saturation, conductivity, dielectric
constant and textural parameters. The data can be inverted for different
depths of investigation, which are functions of transmitter-receiver spacing
and formation properties. (Adapted from Seleznev et al, reference 19.)
Research to Reservoir
Petroleum Development Oman (PDO) tested the
Dielectric Scanner tool in several wells. PDO
objectives included evaluating laminated sandshale sequences, heavy-oil carbonates, shaly
sands and ultrahigh-salinity carbonates.26 For one
of the test wells, the objectives were to quantify
the volume of residual oil—oil that has not been
flushed by invading mud filtrate—independent of
resistivity measurements and to integrate dielectric data with a full suite of openhole logging
tools. PDO evaluated the tool’s ability to detect oil
mobility and provide textural information in this
test. The selected well was in a carbonate reservoir. The mud filtrate salinity was approximately
180,000 parts per million (ppm) NaCl.
Because the dielectric tool measures the
water-filled portion of the porosity, the difference
between density-neutron crossplot porosity and
dielectric porosity is the residual oil saturation.
In this case, the difference was large, clearly
24. Longitudinal and transverse acquisition compare to
endfire and broadside modes from the older generation
EPT tools, which are modes that required completely
separate sets of hardware.
25. Heger K, Uematsu M and Franck EU: “The Static
Dielectric Constant of Water at High Pressures and
Temperatures to 500 MPa and 550°C,” Berichte der
Bunsengesellschaft für physikalische Chemie 84, no. 8
(August 1980): 758–762.
26. Mude J, Arora S, McDonald T and Edwards J:
”Wireline Dielectric Measurements Make a Comeback:
Applications in Oman for a New Generation Dielectric
Log Measurement,” Transactions of the SPWLA 51st
Annual Logging Symposium, Perth, Western Australia,
Australia (June 19–23, 2010), paper GG.
47
Lithology
Oil
Illite
Difference
Calcite
Archie
Saturation
Dolomite
Water
100 %
0
Array Laterolog
0.2
in.
16
2,000
Porosity
Invaded Zone
0.2
Oil
Dielectric Bound Water 0.2
Archie Inputs, Scanner
m =n
Porosity
Saturation
Depth,
m 0
3.5 100 % 0 100 %
0 0.2
6
ohm.m
ohm.m
ohm.m
Total Porosity
50
2,000
HRLA True
ohm.m
F3–
F2
F2–
F3
F2–
F1
F1–
F2
F0–
F1
F0–
F1
Hydrocarbon
2,000
Dielectric Scanner
Invaded Zone
Conductivity
Caliper
Residual Oil
Saturation
Permittivity
Dispersion
Effects
Resistivity
2,000 50
%
0
Dielectric Scanner
Water-Filled Porosity
%
0
X10
X20
X30
X40
> Middle East carbonate test. Log analysts incorporated Dielectric Scanner data with those from
a LithoDensity–Array Porosity–HRLA logging suite. The porosity analysis (Track 5) includes total
porosity (black) and dielectric porosity (blue). The difference between the porosities (green shading)
represents residual hydrocarbons. The dielectric conductivity, converted to resistivity (Track 4, blue),
was presented alongside the HRLA resistivities (red and black) and the shallow resistivity from the
LithoDensity tool (green). Water saturation was computed from the dielectric data (Track 2, black)
and Archie’s equation (red), which was corrected for variations in the m-exponent (Track 1, blue)
derived from the dielectric data. Dispersion effects can be visualized by comparing the permittivity
and conductivity differences computed from pairs of frequencies (Track 6). The difference between
frequency responses is color coded (cyan, blue and red).
48
indicating the presence of considerable unmoved
hydrocarbon (left). This quantification of residual oil, independent of the resistivity measurement, met PDO’s first objective of the test.
To achieve the second objective, analysts computed the dielectric textural output for use in
Archie’s water saturation equation. The dispersion
analysis indicated that the cementation exponent,
m, varied from 1.5 to 2.5 across the interval in
question. PDO attributed the variability of m to
textural and facies differences in the carbonate.
The use of a more accurate m-parameter resulted
in more precise hydrocarbon saturation determination. General practice is to use a constant value
for m, which, based on these findings, would yield
inaccurate results.
Next, the dielectric data were integrated in an
analysis and compared to water saturation computed from inputs that are typical for the field. In
the upper section, where a high Archie saturation
parameter, or n-value, is commonly used, there is
good agreement between the two methods. This
fixed value for n was obtained from a nearby field
and is appropriate for oil-wet rocks (next page).
Across a transition from an oil to a water zone,
there is a difference between the output using
this constant n-value and from that derived from
dielectric measurements. This is most likely
because the rock is less oil-wet in this zone than
the oil-bearing zone. Rather than using the high
n-value used in the upper section to compute
water saturation with Archie’s equation, log analysts learned that they should use a lower value.
Saturation Solution
Shallow, heavy-oil reservoirs, which include some
of the few areas where dielectric tools are in use
today, can be found in a number of regions around
the globe. Canada, the USA, Mexico, Indonesia
and Venezuela are among a number of places
with vast heavy-oil reserves.27 In California, USA,
heavy-oil production has been underway since
the 1890s. Most of this heavy oil is found at depths
of less than 3,000 ft [1,000 m].
These shallow heavy-oil reservoirs are beset
with interpretation difficulties associated with
freshwater. Interpretation is further complicated
because many of the reservoirs have been under
steam- or waterflood for more than 50 years.28 The
fluids encountered by newly drilled wells in these
reservoirs may little resemble those originally in
place, or may change drastically across seemingly
homogeneous reservoir sections because of differences in operational histories.
Oilfield Review
Density
Porosity
Array Neutron
Porosity
Caliper
Rxo HRLA Tool
in.
16 0.02 ohm.m 2,000 45
%
Gamma Ray
Rt HRLA Tool
Bulk Density
0
6
Depth,
m
0
gAPI
60 0.02 ohm.m 2,000
-15
1.95 g/cm3 2.95 0
%
Dielectric
Porosity
%
40
Archie Water
Saturation
40 100
%
Dielectric Water
Saturation
0 100
%
0
X25
X50
X75
> Improved water saturation computation. In this Middle East carbonate, standard inputs were used
to compute water saturation (Track 5). A constant n-value, obtained from offset core data, was used
in Archie’s water saturation equation. Water saturation was also computed from dielectric data
(Track 6). There is good agreement in the upper interval (light-green shaded zone), confirming the
n-value. The dielectric water saturation in the lower interval (light-blue shaded zone), which includes
a zone that transitions from oil to water, is lower—indicating more oil—than that using the n-value
appropriate for the upper interval. Results such as these can affect oil-reserve estimates, which
impact equipment requirements and field development.
Beginning in the mid-1980s, petrophysical
analysis of shallow, heavy-oil reservoirs in
California often included the EPT tool to estimate hydrocarbons in place, and the use of the
tool became routine in the 1990s. The tool measured flushed-zone water-filled porosity. An
added benefit of using dielectric tools in these
reservoirs, where there is little invasion from
drilling mud filtrate and where the oil is virtually
immobile, is that the information reflects that of
the virgin zone. Whereas the EPT tool was initially developed to analyze reservoirs where the
formation water was known to be fresh, today
dielectric tools are also used where formation
27. Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C,
Brough B, Skeates C, Baker A, Palmer D, Pattison K,
Beshry M, Krawchuk P, Brown G, Calvo R, Cañas
Triana JA, Hathcock R, Koerner K, Hughes T, Kundu D,
López de Cárdenas J and West C: “Highlighting Heavy
Oil,” Oilfield Review 18, no. 2 (Summer 2006): 34–53.
28. Little JD, Julander DR, Knauer LC, Aultman JT and
Hemingway JL: “Dielectric Dispersion Measurements in
California Heavy Oil Reservoirs,” Transactions of the
SPWLA 51st Annual Logging Symposium, Perth, Western
Australia, Australia (June 19–23, 2010), paper D.
Spring 2011
water salinity is unknown because of the alterations caused by injection of fluids for enhanced
oil recovery.
Obtaining quality data from wells in California
heavy-oil reservoirs has been problematic. In
many reservoirs, the sand grains are held
together by the viscous oil originally in place.
Depleted zones often exhibit rugose wellbores
because they become unstable after some of the
oil is removed. The mandrel design of the EPT
pad often resulted in measurements that were
compromised by borehole rugosity. The articulated pad of the Dielectric Scanner tool was
designed to improve contact with the borehole
wall when the hole is in less than ideal condition.
Interpretation of EPT measurements is also
influenced by changes in downhole conditions
created by steamflooding. The temperature
profile of steamflooded wells does not follow a
typical linear gradient, which is assumed for
interpretation of dielectric measurements.
Because the EPT tool lacks an external temperature sensor, it cannot correct the raw data for
temperature, thus introducing errors in the measurement. To overcome this limitation and provide additional environmental corrections, the
Dielectric Scanner tool incorporates pressure,
temperature and mudcake sensors in its articulated pad.
Chevron U.S.A. Inc. tested the Dielectric
Scanner tool in its heavy-oil steamflood operation in the Cymric field, located in the southwest margin of the San Joaquin Valley,
California. One of the main producing intervals
is the Tulare Formation, which is Pliocene to
Pleistocene in age and mostly poorly consolidated fluvio-deltaic sandstone deposits bounded
by shales. Producing sands are at depths from
50 ft to 1,600 ft [15 m to 490 m]. Average porosity is 34%, permeability is 2,000 to 3,000 mD and
oil saturation averages 55% to 65%. The oil is
9 to 14 API gravity. Production commenced in
the early 1900s and steamflooding was first
introduced in the 1970s. Water saturation calculations from resistivity data are challenging at
Cymric because of alterations in the original
formation water salinity caused by years of
steam injection.
Chevron ran a Platform Express triple-combo
logging suite along with the Dielectric Scanner
tool in the Cymric well. The logging suite included
an EPT tool so the company could compare legacy measurements with those from the new tool.
Sidewall cores were taken throughout the producing interval.
49
Water
Caliper
8.5 in. 18.5
Clay
Resistivity
Standoff
Resistivity
Standoff
2.5 in.
Depth, ft
0.5
ohm.m
0.5
ohm.m
5,000
Dielectric
Invaded Zone
Resistivity
0
0.5
ohm.m
Hydrocarbon
Core
Water Saturation
0
5,000 0
%
Quartz
100
Total Porosity
50
Dielectric Scanner
Water Saturation
%
%
100 100
%
Total Porosity
0 50
%
0
Dielectric Scanner
Dielectric Scanner
Water-Filled Porosity Water-Filled Porosity
50
Dielectric Scanner
Water Saturation
Residual
Hydrocarbon
Residual
Hydrocarbon
Irreducible
Water Volume
Residual
Hydrocarbon
5,000
Invaded Zone
Resistivity
0
Density
Standoff
2.5 in.
Carbonate
2-ft Array Induction
Resistivity Deep
Density
Standoff
%
0 50
Core Porosity
0 50
%
%
0
EPT Porosity
0 50
%
0
600
800
> Overcoming rugosity. The articulated pad of the Dielectric Scanner tool, which follows the contours
of the borehole, compensates for hole rugosity and washouts. The EPT tool is a mandrel device,
meaning the pad is fixed in place; Chevron wanted to compare data from the two tools in their Cymric
heavy-oil well. After logging the well, engineers observed an apparent mudcake (Depth Track,
light-blue shaded zone) in the zone from 780 ft to 820 ft from the LithoDensity tool’s microlog sensor
(olive gray shading). Mudcake, if present, can indicate permeability and moved oil. The water-filled
porosity from the EPT tool (Track 5, red) from 810 ft to 820 ft was higher than it was in other intervals
such as from 540 ft to 605 ft. This could indicate filtrate replacing original oil, and the engineers might
have assumed primary production was possible in this zone. However, the improved design of the
Dielectric Scanner pad overcame hole rugosity effects and the water-filled porosity (Tracks 4 and 5,
blue) showed no increase across this interval. The log response from the LithoDensity tool indicating
mudcake was attributed to refilling of a slumping formation with circulated cuttings.
The well intersected the oil/water contact at
a depth of 830 ft [253 m] (above). Below that
depth, the dielectric porosity closely matched
the crossplot porosity from the LithoDensity photoelectric density and neutron porosity tools,
which indicated the formation is filled predominantly with water.
The sidewall cores were analyzed for porosity,
permeability and fluid saturation. Log-derived
water saturations from the shallow-reading
dielectric tool matched the saturations from the
sidewall cores. Although sidewall samples and
dielectric log measurements represent the flushed
50
zone immediately around the wellbore, fluid saturations obtained from both methods are generally equivalent to saturations in the virgin zone
for this field.
The Dielectric Scanner tool’s articulated pad
helps compensate for hole rugosity and washouts.
The EPT tool is a mandrel device, meaning the
pad is fixed on the tool body. A comparison was
made between the two devices in the Cymric
heavy-oil well. The caliper curve indicated rugosity and washouts and the articulated pad handled
the borehole irregularities better than the mandrel design did.
The Platform Express flushed-zone resistivity measurement appeared to indicate the presence of mudcake. Mudcake builds up as filtrate
displaces oil and pushes fluids deeper into the
formation, which makes it an indicator of permeability and oil mobility. But, in heavy-oil reservoirs, it is possible to use the multiple depths
of investigation from the Dielectric Scanner tool
to look for evidence of mobile oil. If all four
depths of investigation deliver the same waterfilled porosity, evidence of oil mobility is lacking. If they differ, then the data suggest oil
mobility in the reservoir—a potential completion target.
The porosity measurement from the EPT tool
should overlay the Dielectric Scanner porosity,
and this was the case in most of the intervals.
However, in the two rugose sections, the EPT tool
sensed higher water-filled porosity, which
equated to 23 saturation units lower than the
Dielectric Scanner results. If this difference was
not from oil mobility, it could have been attributed to preferential water or steam breakthrough.
Data from the Dielectric Scanner tool did not
indicate invasion or oil mobility.
Based on the caliper reading, the borehole at
the zones in question was enlarged. Unconsolidated sands, such as in this well, may slough off
and mud solids have a tendency to build up along
the borehole wall. Hole instability and rugosity
caused the conflicting results, not mudcake from
invasion or the presence of formation water.
These zones could have been misinterpreted
as containing movable hydrocarbons due to viscosity variations in the oil column, having lower
oil saturations or experiencing early water breakthrough. The error in water saturation, which
equates to 23% less hydrocarbon in place, might
have caused an operator to bypass both potential
pay zones. Increased confidence in the dielectric
measurements helped Chevron make informed
completion decisions.
Moved Oil
Venezuela’s Orinoco Belt contains the largest
deposit of heavy-oil reserves in the world. The
operator, PDVSA, found that the region had a
complex depositional setting where thick homogeneous intervals could rapidly transform into
thin, discontinuous layers. The complex geology
was further complicated by significant differences in sand quality, which made log interpretation more difficult.
Early water production convinced engineers
of the need for greater understanding of the reservoir. The identification and elimination of
zones with high water production potential were
Oilfield Review
29. Mosse L, Carmona R, Decoster E, Faivre O and Hizem M:
“Dielectric Dispersion Logging in Heavy Oil: A Case
Study from the Orinoco Belt,” Transactions of the
SPWLA 50th Annual Logging Symposium, The
Woodlands, Texas (June 21–24, 2009), paper AAA.
30. In this simulation, 5 pu of water represents a water
saturation of 14%. After the formation is flushed by 15 pu
of filtrate, this represents a water saturation of 43%.
Spring 2011
Permittivity, F1
Transverse Polarization
Longitudinal Polarization
Conductivity, F1
Longitudinal Polarization
Transverse Polarization
0
No invasion
No invasion
5
0.1 in.
10
1 ft
Simulated depth, ft
15
20
25
30
35
40
Fully invaded
Fully invaded
45
Permittivity, F3
Longitudinal Polarization
Transverse Polarization
Conductivity, F3
Longitudinal Polarization
Transverse Polarization
0
No invasion
No invasion
5
10
15
Simulated depth, ft
crucial for proper development of the region.
Formation resistivity is often used to identify
water-producing zones, but engineers discovered
that this method was not reliable because of sand
quality variability, the presence of freshwater
and previously flushed layers that contained significant quantities of immovable residual oil in
conjunction with movable water.
This environment is ideal for incorporating
dielectric propagation measurements with standard logging suites, but operators were reluctant
to use the tools because of frequent adverse borehole conditions, complicated mud-filtrate invasion effects and complex interpretation issues.
PDVSA recognized the design differences of the
new Dielectric Scanner tool and actively participated in the field testing of the device.29
Early in the testing process, engineers
observed that filtrate invasion from the waterbase mud could complicate interpretation of
dielectric data. In the heavy-oil reservoirs of the
Orinoco Belt, invasion is usually shallow, on the
order of a few inches. Engineers modeled the
invasion response of the dielectric tool by
creating synthetic logs with typical well characteristics: 35% porosity sandstone with simulated
virgin to fully flushed conditions. Inputs for the
simulation included 5 porosity units (pu) of
irreducible water-filled porosity in the virgin
zone compared to 15 pu of water-filled porosity in
the fully-flushed zone.30 Mud-filtrate salinity for
the simulation was 5,000 ppm.
The CRI model, used to compute the tool
response, was applied to the four frequencies
available from the Dielectric Scanner tool along
with nine separate transmitter-receiver spacings.
The simulation provided 36 apparent dielectric
permittivities and 36 apparent conductivity measurements and generated a step-profile with
increments that were approximately 1 ft long by
0.1 in. deep [30 cm by 0.25 cm].
Analysis of the synthetic logs generated for
one of the lower frequencies showed that when
there was no invasion, the apparent permittivity
and conductivity were the same as those of the
virgin zone. As filtrate pushed deeper into the
formation, the deepest DOI values approached
those of the shallowest reading. For the highest
frequency, the situation was extremely complex.
Apparent permittivities and conductivities lost
linearity and DOI was not uniform (right).
20
25
30
35
40
Fully invaded
Fully invaded
45
> Modeling dielectric response. PDVSA’s Orinoco Belt has complex lithology and difficult interpretation
issues. PDVSA and Schlumberger tested the Dielectric Scanner tool by first modeling the response
to invasion in conditions anticipated in Orinoco wells. A total of 36 sets of attenuation–phase shift
measurements using nine spacings and four frequencies (F0 to F3) were used in the study. For the
analysis, each 1 ft [30 cm] of log interval represented 0.1 in. [0.25 cm] of invasion (inset). For simplicity,
synthetic apparent dielectric permittivity and conductivities are shown for frequency F1 (top) and for
F3 (bottom). There are two sets of permittivity and conductivity curves: longitudinal polarization (left set)
and transverse polarization (right set). The modeled responses are for the longest spacing (red curves)
to the shortest spacing (blue curves). For frequency F1 (top left), when the invasion depth is zero, shown
at the top of each log, permittivity curves read the deep zone value (dashed black line). As the simulated
invasion pushes into the formation and filtrate replaces oil, the permittivity curves from the longitudinal
polarization eventually converge to the fully flushed reading, shown at the bottom of the log; however,
the transverse data do not converge and only the shortest spacing data approach the flushed zone
value. For the highest frequency, F3 (bottom left), the permittivity from both longitudinal and transverse
polarizations initially read the deep zone value and, as the simulated invasion pushes deeper, the
transverse measurements converge on the flushed zone value while the longitudinal permittivities exhibit
an oscillatory response. Regardless of the direction of polarization, conductivity data behave better for
F1 frequency (top right). At the outset, longitudinal and transverse data reflect the value of no invasion
and converge at the flushed value at the bottom of the log. This is not the case for conductivity data from
F3 (bottom right), where oscillatory responses are seen for both polarizations. These results do not lend
themselves to quicklook analysis; however, a response model was created from this analysis to correct
data from Orinoco wells. (Adapted from Mosse et al, reference 29.)
51
8-in. Invaded Zone Resistivity
0.2
ohm.m
2,000
Residual Oil
Array Laterolog Resistivity
Resistivity
Standoff
Residual Oil
Moved Oil
1
Dielectric
Scanner Deep
Water Saturation
8
Depth,
ft –100
in.
SP
mV
18
%
%
1
100
Dielectric
Scanner Shallow
Water Saturation
0 0
Density
Standoff
100
Lithology
0
Caliper
in.
in.
Dielectric
Scanner
Mudcake
Thickness
1
in.
0.2
ohm.m
2,000
Moved Oil
2,000
Dielectric Scanner Shallow
Water-Filled Porosity
Water
Invaded Zone Resistivity
0
0.2
ohm.m
Dielectric Scanner Shallow Resistivity
0 0.2
ohm.m
2,000
50
Dielectric Scanner Deep Resistivity
0.2
ohm.m
2,000 50
HRLA True Resistivity
0 0.2
ohm.m
%
0
Dielectric Scanner Deep
Water-Filled Porosity
%
T1 Distribution
0
Total Porosity
2,000 50
%
T1 Cutoff
0 0.5
ms 5,000
X,450
X,500
X,550
X,600
X,650
X,700
X,750
X,800
> Applying the model. Armed with the information from the dielectric modeling exercise, PDVSA
logged an Orinoco Belt well with Platform Express–HRLA, MR Scanner and Dielectric Scanner
tools. Conventional methods of interpretation relied on differences in shallow and deep resistivity
measurements to indicate oil mobility. These data (Track 5) are not conclusive, even when dielectric
resistivities from different depths of investigation (red and blue curves) are included in the analysis.
NMR data (Track 7) show a bimodal distribution, indicative of possible oil mobility, across much of
the upper interval but not below X,650 ft. The differences between NMR data at the two blue-shaded
zones are significant. The lower interval could be interpreted as containing nonmovable oil. Data from
the Dielectric Scanner tool indicated a distinct difference between the deep and shallow porosity
measurements (Track 6), corresponding to the moved oil (gold shading). The interpretation suggests a
total of 150 ft [46 m] of low-resistivity movable oil. This was later confirmed with production tests after
casing was in place. (Adapted from Mosse et al, reference 29.)
Lessons learned from the simulation were
applied to permittivity and conductivity data
acquired in an Orinoco well. These results closely
resembled the simulated logs, providing a petrophysical inversion scheme that could be applied
to the well data. Based on these results, PDVSA
used the Dielectric Scanner tool on other wells.
The results from one well in particular
showed the benefit of using the dielectric measurement in conjunction with other logging tools.
An appraisal well was drilled in an area that was
first explored in the 1980s and had relatively poor
well control. PDVSA expected to encounter thick
reservoir sections with low resistivity. Based on
previous experience, such intervals were often
interpreted as having heavy residual oil flushed
with movable water. Log analysts expected these
zones to produce mainly water.
The logging program included a Platform
Express suite with an HRLA high-resolution
52
laterolog array tool and an MR Scanner expert
magnetic resonance service. In other wells in the
region, geologists had observed high resistivity in
the oil-bearing interval, but resistivity values
deeper in the interval were not as high. This well
encountered similar intervals exhibiting high
and low resistivity.
Conventional interpretation of oil mobility
relied on comparing deep and shallow resistivity
measurements. In this case the results were
inconclusive because of similarities in the formation water and filtrate salinities. In the highresistivity upper interval, the NMR log showed a
bimodal distribution with a strong oil signature.
With increasing depth, the apparent porosity and
the resistivity were reduced, and the NMR data
appeared to indicate no movable oil. Log analysts
called on the Dielectric Scanner data to validate
this interpretation.
Although the caliper log indicated significant
borehole rugosity, the pad of the Dielectric
Scanner tool maintained good contact with the
formation. The dielectric data resolved the
uncertainty associated with the deeper reservoir
section (left). In contrast to the NMR data indicating little oil mobility across two intervals, a
total 150 ft [45 m] of low-resistivity pay with
significant movable oil was indicated. PDVSA
included this new information in their production plan and reserves calculations. The interpretation based on dielectric data was later
confirmed from sidewall core samples.
Because water production is such a major concern in the Orinoco Belt development program, it
was important to identify and avoid water-productive zones. The dielectric measurement not only
revealed the zones that contained movable oil, but
was helpful in also identifying zones where only
water was mobile. Resistivity and spontaneous
potential (SP) techniques, commonly used to identify such zones, require some contrast between the
resistivities of the filtrate and formation water. In
this case, there was no contrast and it would not
have been possible to confirm water and oil mobility
without integration of the dielectric data.
The analysis was further confirmed by sampling the various intervals. From the deepest
interval, only water was produced. Oil and water
came from the transition zone. From both the lowand high-resistivity intervals, oil was produced.
This matched the interpretation from the dielectric measurements. PDVSA reservoir engineers
were able to determine the best intervals for both
production and additional field development.
Final Analysis
Dielectric measurements from downhole tools
have been available to petrophysicists since the
early 1980s. Recognized benefits from the information were overshadowed by measurement
complexity and tool limitations.
The introduction of the Dielectric Scanner tool
has combined better tool design with new processing techniques. The dielectric information provides
clear benefits for carbonate reservoir interpretation, shaly-sand analysis, heavy-oil reservoir evaluation and any formation where the water is fresh or
the water salinity is unknown.
Sometimes it takes a while for a technology to
evolve and find its niche. Just as not every kitchen
in the world has or needs a microwave oven, not
every oil well interpretation requires dielectric
data. But in certain situations, and for the right
environments, zapping a formation with microwaves may offer just that extra bit of information
the log analyst needs.
—TS
Oilfield Review
Contributors
Medhat Abdou is Vice President of Development for
the Abu Dhabi Company for Onshore Oil Operations
Bab field development in Abu Dhabi, UAE. He has several publications in the areas of reservoir management
and reservoir simulation. His current interests include
enhanced oil recovery and field development of large
heterogeneous reservoirs. Medhat holds a BS degree in
petroleum engineering from Tripoli University in Libya.
Alexander P. Albert, based in Houston, is the
Schlumberger North America Midstream and
Industrial Business Development Manager. Before
assuming his current post, he was product champion
of next-generation nuclear measurements for the
Schlumberger Wireline segment. He has held a variety
of positions in operations, management and marketing
throughout the US. Alex joined Schlumberger in 1998
as a wireline field engineer after receiving a BS degree
in mechanical engineering from Bucknell University,
Lewisburg, Pennsylvania, USA.
Romulo Carmona is a Consulting Petrophysicist, formerly with Petróleos de Venezuela, S.A. (PDVSA) from
1982 to 2001. Before his retirement from PDVSA, he
served in a number of capacities related to geology,
petrophysics and reservoir engineering. He has published numerous papers on the geology of Venezuela as
well as petrophysical field studies on the heavy-oil
reservoirs in the Orinoco Belt. He obtained a BS degree
in geological engineering from the Universidad Central
de Venezuela, Caracas, where he was a professor from
1992 to 1995. He also taught at the Universidad
Nacional Experimental De Los Llanos Ezequiel Zamora,
Barinas, Venezuela, from 1978 to 1992. Romulo is associated with the Colegio de Ingenieros de Venezuela, the
Geologists Association of Venezuela and the SPWLA.
Andrew Carnegie is a Reservoir Engineering Advisor
for Woodside Petroleum in Perth, Western Australia,
Australia. Previously he worked for Schlumberger for
20 years and INTERA for four years. He holds BSc and
PhD degrees, both in applied mathematics, from the
University of London.
Eric Decoster, based in Rio de Janeiro, is Petrophysics
Advisor for Schlumberger Latin America, where he
oversees new technology applications and integration.
His career with Schlumberger spans 32 years, beginning as a wireline field engineer in the Middle East.
Over the last 20 years, he has held various positions in
marketing and interpretation in the Middle East and
Latin America. In 1997, he became principal petrophysicist for the government of Venezuela, focusing on
the development of interpretation techniques and new
technology, including nuclear magnetic resonance and
spectroscopy. In Venezuela, he carried out the initial
field test of the Dielectric Scanner* prototype. He has
published several papers on the tool’s applications for
reservoir characterization. Eric received an engineering degree from the École Centrale de Paris, and a
master’s of engineering degree from the University of
Wisconsin, Madison, specializing in flow through
porous media. He currently serves as Director of the
SPWLA for Latin American.
Dave Elliott began his career with Shell International
Exploration and Production B.V. as a well test supervisor
in 1977. Since then he has held positions as plant, production and completion engineer, well test team leader,
Spring 2011
safety management development coordinator and asset
manager. Most recently he has served Shell International
E&P as global underbalanced drilling/managed pressure
drilling (UBD/MPD) implementation manager, with a
focus on global tight gas well technology. Dave is currently UBD/MPD Projects and Technology Engineer and
member of the Shell global UBD/MPD team. He holds a
BS degree in chemical engineering from Southern
Alberta Institute of Technology, Calgary.
Paul Francis is Business Development Manager,
Eastern Hemisphere for @balance, a Schlumberger
company. Prior to his current post, he held numerous
positions with Shell in the Netherlands and Oman. He
also worked as a hydrometallurgist for Anglo-American
Research Laboratories in Johannesburg, South Africa.
An SPE Distinguished Lecturer in managed pressure
drilling for 2011/2012, he earned a BSc degree in mineral technology engineering and a PhD degree in colloid and surface science, both from Imperial College,
London. Paul is the author of numerous technical
papers and articles.
Jim Hemingway, based in Houston, is a Petrophysics
Advisor with Schlumberger. He began his career in 1980 as
a field engineer, has held various log analyst and engineering positions and has authored many papers on pulsed neutron logging and log interpretation. In 1997, he joined the
Formation Evaluation department at the Schlumberger
Sugar Land Product Center, Texas, USA, working on the
RSTPro* tool and three-phase holdup interpretation techniques. In 2001, as new technology advisor, he moved to
Paris to teach new technology applications for formation
evaluation. In 2005, he became nuclear technology advisor.
Jim received a BS degree in chemistry from Emporia State
University, Kansas, USA, and a BS degree in chemical engineering from Texas A&M University, College Station.
Mehdi Hizem, located at the Schlumberger Riboud
Product Center (SRPC) in Clamart, France, has been
the Dielectric Scanner Project Manager since 2004.
He began at SRPC in 1996, where he was assigned to
the production services platform. He then moved to
Houston to work at the Integrated Products Center
where he worked on developing wireline downhole
tractor technology. He returned to SRPC in 2002,
where he was in charge of wireless telemetry for downhole testing and managed the Platform Express* 150
project. Mehdi obtained a master’s degree in engineering from École Centrale de Paris.
Dale Julander is a Senior Staff Petrophysicist at
Chevron U.S.A. Inc. based in Bakersfield, California,
USA. He started his career in 1982 as a geophysicist for
Chevron in California working in the exploration
department and in seismic processing before transferring to development geology in 1988. In the late 1980s
and 1990s, he worked on several onshore and offshore
projects focused on exploiting opportunities in the
Monterey Shales and various Plio-Miocene sandstone
reservoirs in California. He serves as the Supervisor of
the formation evaluation staff for the San Joaquin
Valley Business Unit for Chevron U.S.A. Inc. Dale has a
BS degree in geology from the University of Puget
Sound, Tacoma, Washington, USA, and an MS degree in
geophysics from the University of Utah, Salt Lake City,
USA. He received the A.I. Levorsen Memorial Award in
2004 for coauthoring the best paper at the Pacific
Section AAPG 79th Annual Meeting.
Paal Kibsgaard is Chief Operating Officer of
Schlumberger Limited. Prior to his most recent position as president of Reservoir Characterization, he
held a variety of global management positions including vice president of Engineering, Manufacturing and
Sustaining; vice president of Personnel for Schlumberger
Limited; and president of Schlumberger Drilling &
Measurements. Earlier in his Schlumberger career, he
was a GeoMarket* manager for the Caspian region
after holding various field positions in technical sales
and customer support. A petroleum engineer with a
master’s degree from the Norwegian Institute of
Technology, Paal began his career in 1992 working for
ExxonMobil. He joined Schlumberger in 1997.
Daniel L. Lanier is the Vice President of Geosciences
for Geoscience Earth and Marine Services (GEMS),
Inc., a Forum Energy Technologies Company based in
Houston. Before his current role, he served as project
manager and director of operations, specializing in
identifying and characterizing marine geohazards.
Daniel, who joined GEMS in 2001, is a graduate of
Texas A&M University, College Station.
Jeffrey Little is Principal Petrophysicist and
Department Head at Schlumberger Petrophysics Data
and Consulting services in Bakersfield, California. He
has 29 years of industry experience, starting as a field
engineer. He has worked in various field assignments
including California land and offshore operations,
deep desert operations in Syria and as high pressure
and temperature specialist in the North Sea. Jeffrey
has been working in log interpretation and application
development since 1995. He earned his BS degree in
physics from Colorado State University, Durango, USA.
S. George Mathews is the Schlumberger Oilphase-DBR*
Laboratory Manager in Houston, where his responsibilities include business development and management
of the Fluids and Flow Assurance Laboratory. Previous
to his current position and while at the Oilphase DBR
laboratory, he developed a method for measuring pH of
live formation water. He began his Schlumberger
career in 2001 as a senior project engineer specializing
in testing operations. Before that, he was an assistant
manager for design and projects at Gharda Chemicals
Limited in Mumbai. George received a bachelor’s
degree in chemical engineering from the National
Institute of Technology in Durgapur, West Bengal,
India, and an MBA degree from Jamnalal Bajaj
Institute of Management Studies in Mumbai.
Kevin McCarthy is a Geochemist with Schlumberger
Testing Services in Houston. He joined Schlumberger
in 2008 at the Heavy Oil Regional Technology Center in
Calgary. Before that, he held a variety of positions in
other fields. He was a research assistant at Tufts
University in Medford, Massachusetts, USA, where he
analyzed aqueous and soil samples in support of the
US National Aeronautics and Space Administration
Phoenix Mars Mission. He was a hydrologist consulting
on water-management issues in Sarasota County,
Florida, USA. At Woods Hole Oceanographic Institute
in Massachusetts, he researched deep sea hydrothermal
vents as a scientist diver in the manned submersible
ALVIN. Kevin has a master’s degree in geochemistry
with a special focus on hydrogeology from the University
of South Florida in Tampa, and a bachelor’s degree in
geology from Salem State College in Massachusetts.
53
Tom McDonald is currently Schlumberger
Petrophysics Domain Champion for West Australia,
based in Perth, Western Australia. He started his
career with Schlumberger in 1981 as a wireline engineer in Midland, Texas. After a number of positions in
the western US, in 1990 he began working as a petrophysics log analyst in Oman and has performed similar
work in a number of other locations, including the
UAE, Yemen, Vietnam, Papua New Guinea, Indonesia
and Angola. Tom obtained a bachelor’s degree in geological engineering from the University of Idaho,
Moscow, USA, and an associate’s degree in geophysics
from the Colorado School of Mines, Golden, USA.
Julio Montilva is Staff Drilling Engineer with Shell
Exploration and Production Company (SEPCo) in
Houston. He began his career as an engineer with
Lagoven, a division of PDVSA, in Venezuela in 1997. In
2002, he joined Shell Venezuela where he rose to the
position of head of well engineering before joining
SEPCo in 2007. Julio received a BS degree in chemical
engineering from the Universidad de Los Andes,
Mérida, Venezuela, and a master’s degree in industrial
projects management from the Universidad Rafael
Belloso Chacín, Maracaibo, Venezuela. He has authored
numerous International Association of Drilling
Contractors (IADC), SPE and American Association of
Drilling Engineers (AADE) technical papers.
Laurent Mossé is a Physicist with Schlumberger at
SRPC in Clamart, France, and leads the interpretation
and physics team of the Dielectric Scanner project.
He began his career with Schlumberger in 2002, first
working as a nuclear physicist for gamma-density tools
and developing extended temperature and borehole
corrections and cased-hole formation density algorithms. In 2004, he joined the Dielectric Scanner
physics and interpretation team, which he now leads.
Laurent obtained a master’s degree in engineering
from École Supérieure d'Électricité (Supélec), Gif-surYvette, France, and a PhD degree in physics from the
Alternative Energies and Atomic Energy Commission
(CEA), France. Before joining Schlumberger, Laurent
worked for two years at the European Organization for
Nuclear Research (CERN), Geneva, Switzerland.
Jonathan Mude is a Petrophysicist with Petroleum
Development Oman (PDO), in Muscat, Oman, where
he works with the maturation team in the Exploration
Directorate. He began his career in the oil and gas
industry in 1995 as a log analyst in Nigeria with
GeoQuest, a Schlumberger company. He moved to
Total Nigeria (formerly ELF) in 1998 and worked as a
petrophysicist, focusing primarily on drilling, logging,
database management and contract management. He
worked for Shell Nigeria as an operations petrophysicist from 2001 to 2008, and then moved to PDO.
Jonathan holds a BS degree in petroleum engineering
from the University of Benin, Benin City, Nigeria.
Michael O'Keefe is Senior Reservoir Domain
Champion for Schlumberger in London. Previously, he
was the product champion for downhole fluid analysis,
based in Hobart, Tasmania, Australia. He joined
Schlumberger in 1990 as a wireline field engineer in
Austria. Since then, he has had assignments in Norway
and Saudi Arabia as a production logging engineer,
senior reservoir engineer and field-test coordinator.
54
Author of many patents and technical papers, Michael
is a recipient of the 2005 and 2006 Performed by
Schlumberger Gold Medals and a member of the
focused probe development team that received the
2006 Hart Meritorious Award for Engineering Excellence.
He is also a 2010/2011 SPWLA Distinguished Lecturer.
Michael earned a BEng degree (Hons) in electronics
engineering from the University of Tasmania, Australia.
Brian L. Perilloux serves as Vice President, Gulf Coast
Region, for Williams Midstream Services, LLC. He has
previously served as director of Offshore Engineering
& Construction for Williams and worked in the engineering consulting sector prior to joining Williams. His
26 years of experience include managerial and technical project development of many domestic and international offshore and onshore facilities. A registered
Professional Engineer in Louisiana, USA, Brian
obtained a BS degree in mechanical engineering from
the University of New Orleans.
Bhavani Raghuraman is Center Manager at the
Schlumberger Princeton Technology Center, in New
Jersey, USA. The Center specializes in the design and
manufacture of nuclear detectors and generators. Before
taking her current position, she coordinated fluid and
core analysis related to product development projects
for Testing and was, previous to that, a scientific advisor in the novel sensors program at Schlumberger-Doll
Research in Cambridge, Massachusetts, USA. Bhavani
began her Schlumberger career at Schlumberger-Doll
Research in Ridgefield, Connecticut, USA. Among her
several projects there, she developed the downhole pH
measurement using optical spectroscopy, and then
managed the downhole fluid analysis program for sensor development on wireline, drilling and production
logging platforms. She received BS and PhD degrees in
chemical engineering from Mumbai University
Institute of Chemical Technology.
Don Reitsma is Vice President of Engineering and
Technology for @balance, a Schlumberger company.
Prior positions include European manager of the
underbalanced drilling global implementation team
for Shell International E&P and senior applications
engineer for Schlumberger. He has held engineering
posts in Yemen, Canada, China and Malaysia. Don has
served as chair of the IADC Managed Pressure Drilling
and Underbalanced Drilling Operations Committee
and cochaired the SPE Managed Pressure Drilling
Underbalanced Operations Technical Interest Group.
He obtained an MSc degree in petroleum engineering
from the University of New South Wales, Sydney.
Tarek Rizk is the Wireline Product Champion for
Dielectric Scanner and Geology projects, located at
SRPC, Clamart, France. He is responsible for product
development, field introductions and deployment of
new wireline projects. He joined Schlumberger in 2000
as a wireline field engineer; during his career he held
several positions in both the Middle East and Asia.
Tarek earned his BS degree in electrical engineering
from the University of Alexandria, Egypt.
Vincent Roes, based in Calgary, is Well Engineering
Team Leader for Talisman Energy in Kurdistan. Prior
to his current position, he was well engineer manager
for BG International Limited in Calgary. He has
worked around the world including assignments with
Shell in the Netherlands, the US, Argentina and Oman
and with Esso Resources in Canada. Vincent holds a
diploma in exploration technology from the Northern
Alberta Institute of Technology, Edmonton, Alberta,
Canada, and a BSc degree in petroleum engineering
from the University of Alberta, Edmonton. He is the
author of numerous IADC and SPE technical papers.
Nikita Seleznev is a Senior Research Scientist at
Schlumberger-Doll Research, Cambridge, Massachusetts,
USA. He conducts research in dielectric and resistivity logging tools and techniques as well as petrophysics
of conventional and unconventional reservoirs. He has
been developing interpretation products that directly
measure water volume and rock textural information
for the Dielectric Scanner tool. He also contributed to
the development of the Carbonate Advisor* petrophysics and productivity analysis program. He joined
Schlumberger in 1998 as a wireline field engineer.
Nikita received his PhD degree in petrophysics from
the Delft University of Technology, the Netherlands.
Jaye Shelton began his oil industry career as a
cementer in 1974 with Halliburton Services before
moving to district manager for Grant Oil Tool Company
in 1977. He joined Smith Services when that company
bought Grant. Jaye is currently an Engineer Technical
Service Advisor III with Smith Services, a
Schlumberger company. He earned a BS degree in
agricultural sciences and business from Texas Tech
University in Lubbock and is a member of the SPE, the
API and the IADC Managed Pressure Drilling
Underbalanced Drilling subcommittee and work group
that developed the API 16 RCD Specification for Drill
Through Equipment—Rotating Control Devices.
Andrew Strong, based in Southampton, Hampshire,
England, is the Global Product Manager, Sensing
Systems for Teledyne Technologies Inc. Previously he
was domain champion, distributed measurements,
with the Schlumberger Subsea segment. He is a
Chartered Engineer and Fellow of The Institution of
Engineering and Technology and has 25 years of experience in optical fiber technology. He has been
involved in both telecom and sensing and has published a number of papers and patents in these fields.
Andrew has a BSc (Hons) in physics with physical
electronics from the University of Bath, England.
Wei Wei, has been a Geochemist with Chevron for four
years; she is based in Houston. Wei received a bachelor’s degree in chemistry from Beijing University,
China, and a PhD degree in earth sciences from
Scripps Institution of Oceanography, University of
California, San Diego.
ChengGang Xian, based in Shenzhen, China, is a
Principal Reservoir Engineer and Reservoir Domain
Champion for Schlumberger, providing technical support for all reservoir engineering–related wireline logging activities in China. He began his Schlumberger
career in 2001 at the Beijing Geosciences Center,
working on reservoir simulation. He has also held positions as a reservoir engineer in the UAE and Libya.
Prior to joining Schlumberger, he worked at the
Petroleum Economic and Information Center of the
China National Petroleum Corporation (CNPC) in
Beijing. ChengGang obtained a doctorate degree in
reservoir engineering from the China University of
Petroleum in Beijing.
An asterisk (*) is used to denote a mark of Schlumberger.
Oilfield Review
NEW BOOKS
Geothermal Energy: Renewable
Energy and the Environment
William E. Glassley
CRC Press
Taylor and Francis Group
6000 NW Broken Sound Parkway,
Suite 300
Boca Raton, Florida 33487 USA
2010. 290 pages. US$ 119.95
Coming in Oilfield Review
This . . . book provides an up-todate, comprehensive overview of basic
knowledge and essential information
pertaining to development of geothermal energy. . . . Numerous charts,
graphs, maps, photos, and equations
are especially useful to support the
text. Concise end-of-chapter summaries, reference lists, and sources for
further information are also very
helpful. . . . Glassley has written a
remarkably concise yet in-depth book
that is indispensible to advanced
students and a wide range of professionals interested in the many aspects
of the science, applications, economics, and potential contributions of
geothermal energy to the world of the
future. Highly recommended.
'ROSE4,4ChoiceNO
&EBRUARYn
)3".
The author, who is the executive
director of the California Geothermal
Energy Collaborative, discusses the
strengths and weaknesses of geothermal energy as well as techniques for
implanting geothermal energy projects.
He explores links between geothermal
acquisition and consumption and the
environment. Using real-world cases,
Glassley discusses principles of geosciences and exploration concepts and
methods as well as drilling operations,
techniques and equipment.
#ONTENTS
s)NTRODUCTION
s3OURCESOF'EOTHERMAL(EAT
%ARTHASA(EAT%NGINE
s4HERMODYNAMICSAND
'EOTHERMAL3YSTEMS
s3UBSURFACE&LUID&LOWˆ4HE
(YDROLOGYOF'EOTHERMAL3YSTEMS
s#HEMISTRYOF'EOTHERMAL&LUIDS
s%XPLORINGFOR'EOTHERMAL3YSTEMS
s2ESOURCE!SSESSMENTS
s$RILLING
s'ENERATING0OWER5SING
'EOTHERMAL2ESOURCES
s,OW4EMPERATURE'EOTHERMAL
2ESOURCES'ROUND3OURCE
(EAT0UMPS
s$IRECT5SEOF'EOTHERMAL2ESOURCES
s5SEOF'EOTHERMAL2ESOURCES
%NVIRONMENTAL#ONSIDERATIONS
s5SEOF'EOTHERMAL2ESOURCES
%CONOMIC#ONSIDERATIONS
s4HE'EOTHERMAL%NERGY&UTURE
0OSSIBILITIESAND)SSUES
s2EFERENCES)NDEX
Spring 2011
Information and the Nature of
Reality: From Physics to
Metaphysics
Paul Davies and
Niels Henrik Gregersen (eds)
Cambridge University Press
32 Avenue of the Americas
New York, New York 10013 USA
2010. 398 pages. US$ 30.00
)3".
This book is a collection of articles from
scientists, philosophers and theologians
who discuss quantum, biological and
digital information in a quest to understand nature. Going beyond mass and
energy as the primary currency of
nature, the authors also examine
physical and biological approaches to
information, including its philosophical,
theological and ethical implications.
#ONTENTS
s)NTRODUCTION$OES)NFORMATION
-ATTER
s(ISTORYFrom Matter to
Materialism . . . and (Almost) Back;
Unsolved Dilemmas: The Concept of
Matter in the History of Philosophy
and in Contemporary Physics
s0HYSICS Universe from Bit, The
Computational Universe, Minds and
Values in the Quantum Universe
s"IOLOGYThe Concept of Information
in Biology; What is Missing from
Theories of Information; Information
and Communication in Living Matter;
Semiotic Freedom: An Emerging
Force; Care on Earth: Generating
Informed Concern
s0HILOSOPHYAND4HEOLOGYThe
Sciences of Complexity—A New
Theological Resource?; God as the
Ultimate Informational Principle;
Information, Theology and the
Universe; God, Matter, and
Information: Towards a Stoicizing
Logos Christology; What is the
‘Spiritual Body’? On What May Be
Regarded as ‘Ultimate’ in the
Interrelation Between God, Matter,
and Information
s)NDEX
. . . [The book] . . . is a collection
of non-technical articles compiled by
Paul Davies (a physicist) and Niels
Henrik Gregersen (a theologian). . . .
Each article explores the hypothesis
that information is at the root of
everything. And I mean everything—
from atoms to, perhaps, a deity. . . .
The pinnacle of th[e] ‘theological’
section, . . . is the proposal by
Keith Ward that deity is a form of
information-theoretic principle. . . .
When the famous British geneticist
J B S Haldane was asked if his
research taught him anything about
God, he replied “The Creator, if He
exists, has an inordinate fondness for
beetles.” The collection by Davies and
Gregersen suggests, in line with my
own views, that we could go deeper
than Haldane: the ultimate answer
might just turn out to be a Creator
with an inordinate fondness for bits.
Certainly, bits of information are
present everywhere we look, and if
you want to know more about this
novel take on reality, then I highly
recommend Davies and Gregersen’s
erudite and entertaining collection.
6EDRAL6h!N)NORDINATE&ONDNESSFOR"ITSv
PHYSICSWORLDCOM*ANUARYHTTP
PHYSICSWORLDCOMCWSARTICLEINDEPTH
ACCESSED-ARCH
Bit design. At one time, bit selection
and design were based on rough
estimates, trial and error, basic
assumptions and experience. This
article looks at the tools available
today that allow engineers to optimize
bit design through complex, dynamic
modeling and digital simulations
of the interaction between all drilling components.
Geochemistry. As exploration and
production companies seek to exploit
gas shales and other challenging
trends, the need to quantify the
elements and processes controlling
the generation of hydrocarbons
becomes more acute. Geochemistry
can help E&P companies improve
exploration and production efficiency
by characterizing the quality and
distribution of petroleum-generating
source rocks in sedimentary basins.
This article describes basic geochemical tools and techniques that
geoscientists use to evaluate
source-rock quality, quantity and
thermal maturity.
Conveyance. In the past, the primary
method for getting logging tools
downhole and data back to the surface
was limited to gravity and various
types of cables. Today, cables are
still used for these purposes but a
wide range of other means of conveyance and data transmission
systems provides engineers and
petrophysicists with a variety of
options. This article reviews several
conveyance systems, including a
recently introduced logging platform,
tractors for logging and perforating,
and data delivery systems that
include wireless and memory options.
Environmental effectiveness. The
oil and gas industry has made great
strides in environmental stewardship.
Technological solutions in all phases
of the E&P cycle decrease emissions
and waste and help protect land
and marine animals and plants. This
article examines advances in green
technologies in the E&P industry.
55
The Climate Fix: What Scientists
and Politicians Won’t Tell You
About Global Warming
Roger Pielke, Jr.
Basic Books
387 Park Avenue South
New York, New York 10016 USA
2010. 276 pages. US$ 26.00
ISBN: 978-0-465-02052-2
In this book, the author examines the
intersection of politics and the science
of climate change. Pielke argues that
when environmental and economic
objectives are in opposition, economics
always wins. As a precondition for both
to succeed, climate policy must be
made compatible with economic growth
because energy growth is inevitable. He
focuses on policy adaptation to climate
change and calls for a broad-based
world climate policy.
Contents:
s$INNER4ABLE#LIMATE3CIENCEFOR
#OMMONSENSE#LIMATE0OLICY
s7HAT7E+NOWFOR3UREBUT
*UST!INT3O
s$ECARBONIZATIONOFTHE'LOBAL
%CONOMY
s$ECARBONIZATION0OLICIES!ROUND
THE7ORLD
s4ECHNOLOGICAL&IXESAND"ACKSTOPS
s(OW#LIMATE0OLICY7ENT/FF
#OURSEANDTHE&IRST3TEPS"ACKIN
THE2IGHT$IRECTION
s$ISASTERS$EATHAND$ESTRUCTION
s4HE0OLITICIZATIONOF#LIMATE3CIENCE
s/BLIQUITY)NNOVATIONANDA0RAGMATIC
&UTUREFOR#LIMATE0OLICY
s.OTES)NDEX
Pielke . . . provides a road map on
the intersection of politics and science
by dissecting the debate and providing diagnoses. The author explains in
nine engaging chapters certain steps
to be taken, such as expanding energy
access while increasing energy
security through technological innovation. Pielke summarizes by saying
that removing politicization and fear
factors will ultimately lead to a path
of decarbonziation that benefits
society and the world as whole.
Highly recommended.
(UNTER*(ChoiceNO
&EBRUARY
56
Street-Fighting Mathematics:
The Art of Educated
Guessing and Opportunistic
Problem Solving
The Evolutionary World: How
Adaptation Explains Everything
from Seashells to Civilization
Hidden Costs of Energy:
Unpriced Consequences of
Energy Production and Use
Sanjoy Mahajan
The MIT Press
55 Hayward Street
Cambridge, Massachusetts 02142 USA
2010. 152 pages. US$ 25.00
Geerat J. Vermeij
Thomas Dunne Books, an imprint of
St. Martin’s Press
175 Fifth Avenue
New York, New York 10010 USA
2010. 336 pages. US$ 27.99
)3".
)3".
The National Research Council
Committee on Health, Environmental,
and Other External Costs and Benefits
of Energy Production and Consumption
The National Academies Press
500 Fifth Street NW
Washington, DC 20001 USA
2010. 473 pages. US$ 47.00
Mahajan suggests that in problem
solving, as in street fighting, rules can
cause paralysis; he describes and
demonstrates tools for educated
guessing and problem solving for
disciplines from mathematics to
management. Originally a short
course taught by the author at the
Massachusetts Institute of Technology
(MIT) in Cambridge, Street-Fighting
Mathematics is intended to give readers
the mathematical tools to solve life’s
partly defined problems.
In this exploration of evolutionary
theory, Vermeij presents the way a
changing world has shaped our species
and our cultures. His discussion of
natural selection and human behavior
looks at evolution as a concept that
explains and connects a multitude of
seemingly unconnected facts and
phenomena. The author writes that
having an understanding of how evolutionary theory has had a bearing on
worldwide economic systems, disaster
preparedness and community development will help us learn how such systems
work and what challenges lie ahead.
Contents:
s$IMENSIONS
s%ASY#ASES
s,UMPING
s0ICTORIAL0ROOFS
s4AKING/UTTHE"IG0ART
s!NALOGY
s"IBLIOGRAPHY)NDEX
Bottom line: This is a very creative book. It contains an eclectic set
of topics . . . [and] is replete with
tricks, short cuts, and thought-provoking questions. . . . [M]y working
definition of an applied mathematician is someone who is comfortable
working on the interface between
mathematical rigor and physical
intuition, moving back and forth as
required, frequently corrugating that
interface with nonlinear disturbance[.] This book is a fine example
of such a philosophy and would be an
excellent supplement in standard (and
still necessary) ‘mathematical methods of physics’ and ‘methods of
applied mathematics’ courses.
!DAM*American Journal of PhysicsNO
.OVEMBERn
Contents:
s4HE%VOLUTIONARY7AYOF+NOWING
s$ECIPHERING.ATURES#ODEBOOK
s/N)MPERFECTION
s4AMING5NPREDICTABILITY
s4HE%VOLUTIONOF/RDER
s4HE#OMPLEXITYOF,IFEANDTHE/RIGIN
OF-EANING
s4HE3ECRETSOF'RASS)NTERDEPENDENCE
ANDITS$ISCONTENTS
s.ATURES(OUSING-ARKETOR7HY
.OTHING(APPENSIN)SOLATION
s$ISPATCHESFROMA7ARMER7ORLD
s4HE3EARCHFOR3OURCESAND3INKS
s)NVADERS)NCUMBENTSANDA#HANGING
OFTHE'UARD
s4HE!RROWOF4IMEANDTHE3TRUGGLE
FOR,IFE
s(ISTORYANDTHE(UMAN&UTURE
s3UGGESTED&URTHER2EADING.OTES
)NDEX
)3".
This book describes the effects of
energy production and use—such as
damage from air pollution from electricity generation, motor vehicle transportation and heat generation—as hidden
costs in energy market prices. It also
considers other effects arising from
climate change, air pollutants such as
mercury and risks to national security.
This analysis suggests that major
initiatives to further reduce emissions,
improve energy efficiency or shift to a
cleaner electricity generating mix could
reduce the damages of external effects.
Contents:
s)NTRODUCTION
s%NERGYFOR%LECTRICITY
s%NERGYFOR4RANSPORTATION
s%NERGYFOR(EAT
s#LIMATE#HANGE
s)NFRASTRUCTUREAND3ECURITY
s/VERALL#ONCLUSIONSAND
2ECOMMENDATIONS
s2EFERENCES!BBREVIATIONS#OMMON
5NITSAND#ONVERSIONS
s!PPENDICES
This report summarizes the
findings of prestigious panels of
experts in energy, health, economics,
and the environment, but it fails in its
mission to inform, due to the complexity of the issue and the large uncertainties in many of the parameters
and variables considered. As might be
expected, this is a tough read. . . .
A transcendent view of evolution
as adaptation, not only accounting for
the origin of species but as the force
that can explain the accumulation of
knowledge, economies and civilization itself. . . . an exhilarating narrative that will surely invite debate.
Probably a must for those deeply
involved in the economics of energy
delivery and policy; all other readers
will be disappointed by the lack of
accessibility and concrete information
on this incredibly important topic.
Recommended.
4ALLACK0Kirkus Reviews!UGUST
HTTPWWWKIRKUSREVIEWSCOMBOOKREVIEWS
NONlCTIONGEERATVERMEIJEVOLUTIONARYWORLD
ACCESSED*ANUARY
2ANSOM"ChoiceNO*ANUARY
Oilfield Review
Petroleum Resources with
Emphasis on Offshore Fields
O.T. Gudmestad, A.B. Zolotukhin
and E.T. Jarlsby
WIT Press
Ashurst Lodge
Ashurst, Southampton
SO40 7AA England
2010. 269 pages. US$ 198.00
understanding. Thus, an up-to-date
basic reference book is mandatory.
Here, Gudmestad, . . . Zolotukhin . . .
and Jarlsby . . . introduce essential
critical topics simply and exceptionally lucidly. . . . The text is straightforward and enhanced by excellent
interpretive drawings. Select references follow each chapter. This is
an indispensable resource for both
students and industry professionals
including scientists, engineers,
economists, lawyers, environmentalists, and politicians. Highly
recommended.
'ROSE4,4ChoiceNO
&EBRUARY
ISBN: 978-1-84564-478-9
This book presents lessons learned from
mature Norwegian offshore projects.
The authors take an interdisciplinary
approach in exploring the petroleum
industry’s upstream side, from locating
resources offshore to their conversion
to petroleum products. Gudmestad,
Zolotukhin and Jarlsby emphasize the
careful handling of natural resources,
safe and environmentally friendly
development practices, adherence to
ethical business practices and attention
to social responsibility.
Contents:
s4HE'EOLOGYOF0ETROLEUM2ESOURCES
s2ESERVOIRAND0RODUCTION%NGINEERING
s$RILLING7ELL$ESIGNAND7ELL
#OMPLETION
s&LOW!SSURANCE
s0ROCESSING2EQUIREMENTSIN/ILAND
'AS0RODUCTION
s(YDROCARBON/FFTAKE
s/VERALL&IELD$ESIGNAND3UPPORT
&ACILITIES
s4HE0ROJECT$EVELOPMENT0ROCESS
s$ECOMMISSIONING
s3AFETY-ANAGEMENT
s%NVIRONMENTAL-ANAGEMENT
s,ICENSINGAND&ISCAL2EGIMES
s4HE%CONOMICSOF0ETROLEUM
/PERATIONSAND)NVESTMENTS
s2ESPONSIBILITIESTO3OCIETYAND
"USINESS%THICS
The ‘upstream’ side of the petroleum industry worldwide is so complex and challenging that workers and
decision makers comprise interdisciplinary project teams requiring an
unusual breadth of knowledge and
Spring 2011
The Geology of Stratigraphic
Sequences, Second Edition
s#HRONOSTRATIGRAPHYAND#ORRELATION
An Assessment of the Current
Status of”Global Eustasy”: The
Concept of the Global Cycle Chart;
Time in Sequence Stratigraphy;
Chronostratigraphy, Correlation, and
Modern Tests for Global Eustasy
s&UTURE$IRECTIONS
s2EFERENCES!UTHOR)NDEX
3UBJECT)NDEX
This in-depth discussion of
stratigraphic sequences requires the
reader to have a strong background
in geology, preferably with experience
in stratigraphy and sedimentation
and some knowledge of petroleum
geology. . . . [I]t was the work of
Peter Vail, working with Exxon in
the 1960s–70s that revolutionized
sequence stratigraphy as the dominant paradigm in the science of
stratigraphy. In this new edition . . .
Miall . . . examines in detail the
results of Vail and his followers,
showing where he agrees with those
results and where he feels that the
Vail/Exxon model has gone too far in
extrapolating from these results. . . .
A must-read book for those actively
involved in stratigraphy. Highly
recommended.
$IMMICK#7ChoiceNO
*ANUARYn
Andrew D. Miall
Springer-Verlag GmbH
Heidelberger Platz 3
14197 Berlin, Germany
2010. 337 pages. US$ 99.00
)3".
This second edition, which stresses a
deductive approach to geology, situates
stratigraphic sequences within the
broader context of geologic processes
and attempts to answer the question:
Why do sequences form? The book
is intended for students of geology
and professional geologists involved
in hydrology and coal, gas and
petroleum geology.
Contents:
s4HE%MERGENCEOF-ODERN#ONCEPTS
Historical and Methodological
Background, The Basic Sequence
Model, Other Methods for the
Stratigraphic Analysis of Cycles of
Base-Level Change
s4HE3TRATIGRAPHIC&RAMEWORKThe
Major Types of Stratigraphic Cycle,
Cycles with Episodicities of Tens to
Hundreds of Millions of Years, Cycles
with Million-Year Episodicities,
Cycles with Episodicities of Less
Than One Million Years
s-ECHANISMSSummary of SequenceGenerating Mechanisms, Long-Term
Eustasy and Epeirogeny, Tectonic
Mechanisms, Orbital Forcing
Contents:
s4HE0ATHSTO'REATNESSLights,
Camera, Action; The Quantum
Universe; A New Way of Thinking;
Alice in Quantumland; Endings
and Beginnings; Loss of Innocence;
Path to Greatness; From Here to
Infinity; Splitting an Atom; Through
a Glass Darkly
s4HE2ESTOFTHE5NIVERSEMatter of
the Heart and the Heart of Matter;
Rearranging the Universe; Hiding in
the Mirror; Distractions and Delights;
Twisting the Tail of the Cosmos; From
Top to Bottom; Truth, Beauty, and
Freedom
s%PILOGUE#HARACTER)S$ESTINY
s3OURCES)NDEX
‘Richard Feynman was a legend
for a whole generation of scientists,
long before anyone in the public knew
who he was,’ writes Krauss in this
engaging biography. . . . Feynman’s
work has had an impact on almost
every aspect of modern science today,
from nanotechnology to particle
physics, semi-conductors and hightemperature superconductors. . . . In
the author’s view, he was arguably the
most important scientist in the latter
half of the 20th century, comparable
to Einstein in influence, although his
genius was not to achieve fundamentally new results but to look at ‘old
things from a new viewpoint.’ Krauss
explains the complicated scientific
material in a clear, lively style that
would have earned Feynman’s
approval. A worthy addition to the
Feynman shelf and a welcome followup to the standard-bearer, James
Gleick’s 'ENIUS (1992).
Kirkus Reviews: h1UANTUM-AN2ICHARD
&EYNMANS,IFEIN3CIENCEv*ANUARY
HTTPWWWKIRKUSREVIEWSCOMBOOKREVIEWS
NONlCTIONLAWRENCEMKRAUSSQUANTUMMAN
ACCESSED-ARCH
Quantum Man: Richard
Feynman’s Life in Science
Lawrence M. Krauss
W.W. Norton & Company, Inc.
500 Fifth Avenue
New York, New York 10110 USA
2011. 350 pages. US$ 24.95
)3".
The author presents a new look at
Richard Feynman, the physicist who
changed the way scientists thought
about quantum mechanics. Krauss, a
physicist himself, describes how the
Nobel Prize–winning physicist scrutinized everything from different points
of view before coming to his own
conclusions. The author traces
Feynman’s life and scientific career
from his early days at the Manhattan
Project to his rise as physics legend.
57
Earth Materials
Kevin Hefferan and John O’Brien
Wiley-Blackwell
111 River Street
Hoboken, New Jersey 07030 USA
2010. 624 pages. US$ 99.95
ISBN: 978-1-4443-3460-9
Encompassing the study of minerals
and rocks as well as soil and water, this
textbook is designed for a combined
mineralogy and petrology course. Its
comprehensive framework is intended
to serve not just students, but environmental scientists and engineering
geologists as well. The book covers
mineralogy, sedimentary petrology,
igneous petrology and metamorphic
petrology.
Contents:
s%ARTH-ATERIALSANDTHE'EOSPHERE
s!TOMS%LEMENTS"ONDSAND
#OORDINATION0OLYHEDRA
s!TOMIC3UBSTITUTION0HASE$IAGRAMS
AND)SOTOPES
s#RYSTALLOGRAPHY
s-INERAL0ROPERTIESAND
2OCK&ORMING-INERALS
s/PTICAL)DENTIlCATIONOF-INERALS
s#LASSIlCATIONOF)GNEOUS2OCKS
s-AGMAAND)NTRUSIVE3TRUCTURES
s6OLCANIC&EATURESAND,ANDFORMS
s)GNEOUS2OCK!SSOCIATIONS
s4HE3EDIMENTARY#YCLE%ROSION
4RANSPORTATION$EPOSITIONAND
3EDIMENTARY3TRUCTURES
s7EATHERING3EDIMENT0RODUCTION
AND3OILS
s$ETRITAL3EDIMENTSAND
3EDIMENTARY2OCKS
s"IOCHEMICAL3EDIMENTARY2OCKS
s-ETAMORPHISM
s-ETAMORPHISM3TRESS$EFORMATION
AND3TRUCTURES
s4EXTUREAND#LASSIlCATIONOF
-ETAMORPHIC2OCKS
s-ETAMORPHIC:ONES&ACIESAND
&ACIES3ERIES
s-INERAL2ESOURCESAND(AZARDS
s2EFERENCES)NDEX0ERIODIC4ABLE
,ISTOF%LEMENTS
58
%ARTH-ATERIALSprovides a
relatively balanced treatment of all
major topics involving the various
components of the earth. The book
also emphasizes the various roles of
earth materials as resources, hazards,
and human health influences and their
impact on the general global environment and economy. The well-illustrated text includes numerous, mostly
appropriate, photos/figures/sketches,
although color coding commonly is
not clearly defined, and some figures
are mislabeled. . . . This work should
fill an important niche for lower- to
intermediate-level earth and/or
environmental science courses.
Includes an extensive, up-to-date
reference list, a relatively thorough
index, and a companion web site.
Recommended.
-C#ALLUM-%ChoiceNO
*ANUARY
s2OTARY0ERCUSSIONAND!UGER$RILLING
s$IAMOND$RILLING
s3ATELLITE)MAGERY
s'EOPHYSICALAND
'EOCHEMICAL-ETHODS
s'EOGRAPHICAL)NFORMATION3YSTEMSAND
%XPLORATION$ATABASES
s!PPENDIX!.OTESONTHE5SEOF
'RAPHICAL3CALE,OGGING
s!PPENDIX"/RIENTED$RILL#ORE
4ECHNIQUESAND0ROCEDURES
s!PPENDIX##ALCULATING3TRIKE
AND$IPFROM-ULTIPLE$IAMOND
$RILL(OLES
s!PPENDIX$(OWTO5SEA3TEREO.ET
TO#ONVERT)NTERNAL#ORE!NGLESTO
'EOGRAPHIC#OORDINATES
s!PPENDIX%0RACTICAL
&IELD4ECHNIQUES
s!PPENDIX&3UGGESTED
&URTHER2EADING
s!CRONYMSAND!BBREVIATIONS)NDEX
Marjoribanks wrote this slim but
thoroughly informative volume . . . as
a ‘practical field manual for geologists engaged in mineral exploration.’
. . . The 10-chapter book begins with a
general discussion of exploration and
geological mapping in mineral
exploration. . . . This new edition
includes three more chapters than the
1997 edition, an expanded appendix
section, and ample references.
Recommended.
Geological Methods in Mineral
Exploration and Mining,
Second Edition
0ETERS7#ChoiceNO*ANUARY
Roger Marjoribanks
Springer-Verlag GmbH
Heidelberger Platz 3
14197 Berlin, Germany
2010. 238 pages. US$ 129.00
calculate risk. The author weaves these
ideas with the work of other early
mathematicians, offering insights into
how these basic concepts impact our
modern world.
Contents:
s-ONDAY!UGUST
s!0ROBLEM7ORTHYOF'REAT-INDS
s/NTHE3HOULDERSOFA'IANT
s!-ANOF3LIGHT"UILD
s4HE'REAT!MATEUR
s4ERRIBLE#ONFUSIONS
s/UTOFTHE'AMING2OOM
s)NTOTHE%VERYDAY7ORLD
s4HE#HANCEOF9OUR,IFE
s4HE-EASUREOF/UR)GNORANCE
s4HE+EY,ETTERFROM0ASCALTO&ERMAT
s)NDEX
Prior to the development of
statistics in the late seventeenth and
eighteenth centuries, even rationalists
were convinced that no human could
speculate on the future. Devlin . . .
shows us how that belief was transformed through the . . . critical letter
from Pascal to Fermat in which he
discusses ‘the problem of points’—
that is, how to determine the probable
outcome of a game of chance—as a
framework for a history of probability
theory and risk management, fields
which now dominate our social,
political and financial lives. . . . This
informative book is a lively, quick
read for anyone who wonders about
the science of predicting what’s next
and how deeply it affects our lives.
Publishers Weeklyh.ONlCTION2EVIEWv
3EPTEMBERHTTPWWWPUBLISHERS
WEEKLYCOMACCESSED
-ARCH
)3".
This step-by-step guide to searching for
metallic deposits describes fundamental geologic field techniques used for
the collection, storage and presentation
of geological data and their use in
locating ore. Marjoribanks includes
descriptions and examples from various
projects on which he has worked. The
author emphasizes traditional skills and
shows how they can be effectively
combined with modern technological
approaches.
Contents:
s0ROSPECTINGANDTHE
%XPLORATION0ROCESS
s'EOLOGICAL-APPINGIN%XPLORATION
s-INE-APPING
s4RENCHINGAND5NDERGROUND
$EVELOPMENT
s$RILLING!'ENERAL$ISCUSSION
THE)MPORTANCEOF$RILLING
The Unfinished Game: Pascal,
Fermat, and the SeventeenthCentury Letter that Made the
World Modern
Keith Devlin
Basic Books, a member of
The Perseus Books Group
387 Park Avenue South
New York, New York 10016 USA
2010. 208 pages. US$ 15.95
)3".
The author delves into the mathematical breakthrough that Blaise Pascal and
Pierre de Fermat developed in the
mid-1600s: what is now known as
probability theory. Devlin starts with a
1654 letter Pascal wrote to Fermat that
explains how he discovered how to
Oilfield Review
DEFINING LOGGING
Measurements
(continued from page 60)
Resistivity
Porosity
Lithology
Mineralogy
Saturation
Pore geometry
Permeability Fluid properties
Geomechanical
properties
Geologic
structure
Geologic
bedding
Electrical resistivity
Laterolog
Induction
Microlaterolog
Spontaneous potential
Electromagnetic propagation
Nuclear
Gamma ray density
Neutron porosity
Natural radioactivity
Induced gamma ray spectrometry
Nuclear magnetic resonance
Acoustic
Dipmeter and imaging
Formation testing and sampling
Rock sampling
Fluids sampling
Fluids pressure testing
Seismic
Measurement provides direct information about the reservoir property.
Measurement is influenced by or is sensitive to the reservoir property.
Measurement contributes to understanding the reservoir property.
> Logging measurements used to determine reservoir properties. Some tools provide a direct measurement of a reservoir property (blue) and some provide
partial information that is combined with other measurements to determine the property (green). In addition, tools are often sensitive to a property, even
though they do not provide a measurement of that property (brown).
resource is present to economically justify completing and producing the
well. Logging indicates the basic parameters of porosity (fluid-filled portion of the rock); the water, oil and gas saturations and the vertical extent
of a productive hydrocarbon zone, or net pay (above). Logging tools are
calibrated to properly determine these and other quantities from the reservoir so companies can calculate accurate reserve values. Most logging
tools designed for formation evaluation are based on electric, nuclear or
acoustic measurements.
based on the rock type, and the average of the two, a density-neutron log, can
be a good measure of porosity. In the presence of gas, the two detection methods
separate in a distinctive manner that is recognized as a gas indicator. Some
contemporary tools use a pulsed neutron generator, which can generate neutrons only while power is applied.
The chemical makeup of minerals in a formation can be determined
with a neutron source that uses elemental capture spectrometry. This information helps geologists determine the rock composition.
Electric Logging
Oil and gas are more resistive than the salty water that fills most deeply
buried rocks. Engineers created two types of electric sondes; both of them
measure that difference. One type, a laterolog, measures formation resistivity by creating an electric circuit. Current flows from a tool electrode
through the formation and back to another electrode. The other design uses
induction coils to measure conductivity, the inverse of resistivity. This has
similar physics to an electric transformer: A tool coil induces a current loop
in the formation that is measured by a pickup coil on the tool. An extensive
zone filled with hydrocarbon is apparent on an electric log typically as more
resistive than an adjacent water-filled zone.
Acoustic Logging
The speed at which sound travels through rock depends on its mineral composition and porosity. An acoustic or sonic logging tool transmits a sound
pulse into the formation and a receiver on another part of the tool detects the
transmitted pulse. The travel distance of the pulse is known, so its travel time
provides a sound velocity that is proprotional to a porosity measurement.
The mechanical properties of a solid affect properties of sound waves
passing through it. Some sonic tools measure these changes to quantify
those mechanical properties.
Detecting Radiation
Quartz and carbonates, which compose the most common hydrocarbon reservoirs, have little or no intrinsic radioactivity. Shales, which often act as seals
above reservoirs, include several naturally occurring radioactive components.
Most logging strings include a gamma ray sonde to detect this radiation and
discriminate geologic layers. A characteristic pattern on the gamma ray log
often repeats in logs for wells throughout a given area. Geologists correlate
these patterns from well to well to map geologic layers across the field.
Some logging tools use chemical sources that generate radioactive particles.
The particles interact with the surrounding formation, and detectors on the
sonde pick up the resulting signals. Gamma radiation is absorbed proportionally
to the density of the formation. Other radioactive particles—neutrons—are
absorbed proportionally to the amount of hydrogen. Measurements from both of
these types of logs can be converted to porosity values. Each has a variability
Spring 2011
A Multitude of Measurements
Geoscientists and engineers have access to a wide variety of logging tools
that provide much more than the basic information described above.
Nuclear magnetic resonance tools obtain information about pore sizes and
fluids in situ. Imaging logs can provide a high-resolution and 360° view of
various formation properties at the wellbore wall. Other tools can bring rock
or fluid samples to surface or measure properties of fluids as they flow into
the wellbore. And at a larger scale, measurements made with a source in
one well and a receiver in another indicate formation and fluid properties
between them.
Well logging requires robust technology because of harsh well conditions
and cutting-edge technology because of complex reservoir properties.
Scientists use sophisticated methods to design new tools and evaluate the data
they collect. Most hydrocarbon discoveries today are in remote areas and often
are difficult to produce. These resources—and the people to find, evaluate and
produce them—are vital to fulfill the growing energy needs of the world.
59
DEFINING LOGGING
The first in a series of articles introducing basic concepts of the E&P industry
Discovering the Secrets of the Earth
Mark A. Andersen
Executive Editor
Oil and gas reservoirs lie deep beneath the Earth’s surface. Geologists and
engineers cannot examine the rock formations in situ, so tools called sondes
go there for them. Specialists lower these tools into a wellbore and obtain
measurements of subsurface properties. The data are displayed as a series of
measurements covering a depth range in a display called a well log. Often,
several tools are run simultaneously as a logging string, and the combination
of results is more informative than each individual measurement (right).
The Dawn of an Era
The first well log was obtained in 1927 in Pechelbronn field in Alsace,
France. The tool, invented by Conrad and Marcel Schlumberger, measured
electrical resistance of the earth. Engineers recorded a data point each
meter as they retrieved the sonde, suspended from a cable, from the borehole. Their data log of resistivity changes identified the location of oil.
Today, geologists depend on sets of well logs to map properties of subsurface formations (below). By comparing logs from many wells in a field,
geologists and engineers can develop effective and efficient hydrocarbon
production plans.
45
0
Gamma Ray
gAPI
Depth,
ft
0.2
150
7,000
Resistivity
ohm.m
20 1.90
Neutron Porosity
%
–15
Bulk Density
g/cm3
2.90
Shale
7,100
Gas
Hydrocarbon
Oil
Sand
7,200
Brine
Brine
Shale
7,300
> Basic log. A common combination of logging measurements includes
gamma ray, resistivity, and neutron and density porosity combined on one
toolstring. The gamma ray response (Track 1) distinguishes the low gamma
ray value of sand from the high value of shale. The next column, called the
depth track, indicates the location of the sonde in feet (or meters) below a
surface marker. Within the sand formation, the resistivity (Track 2) is high
where hydrocarbons are present and low where brines are present. Both
neutron porosity and bulk density (Track 3) provide measures of porosity,
when properly scaled. Within a hydrocarbon zone, a wide separation of the
two curves in the way shown here indicates the presence of gas.
Oilfield Review Spring 2011: 23, no. 1.
Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to Austin Boyd, Rio de Janeiro; Michel Claverie,
Clamart, France; Martin Isaacs, Sugar Land, Texas, USA; and Tony Smithson, Northport,
Alabama, USA.
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> Assembling a logging tool on a rig floor. One logging operator holds a
logging tool in place (left) while another assembles a connection (right).
The upper part of the tool is suspended from the rig derrick (not shown,
above the men). The operators will connect that to the lower section of the
tool, seen protruding above the rig floor between the men. That part of the
tool is suspended in the wellbore, held in place at the rig floor by the flat
metal C-clamp. Most logging tools have a small diameter but can be the
height of an average one-story building. The combination of several sondes
in one toolstring can be many stories tall.
Types of Logs
Immediately after a well is drilled, the formations are exposed to the wellbore. This is an opportune time to determine the properties of the rocks
using openhole logging tools. In some cases, particularly in wells with complex trajectories, companies include logging tools as part of the drilling tool
assembly. This approach is referred to as logging while drilling, or LWD.
Drillers typically stabilize formations by cementing metal casing in the
well. The metal of the casing interferes with many logging measurements,
but over the past 30 years the industry has dramatically improved its ability
to measure formation properties and even locate bypassed oil behind casing
using cased-hole logs. In addition, many cased-hole tools measure fluid flow
rates and other production parameters in the wellbore or examine the
integrity of the metal casing and its cement.
The first objective of logging in an exploration area is to locate hydrocarbons in a well. Next, the operating company wants to determine if enough
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Oilfield Review