Oilfield Review
Autumn 2014
Lost Circulation Control
Perforating Innovations
Real-Time Reservoir Testing
The Shushufindi Giant
m
ow tfor
n
p
la
ap id† p
iew dro
v
Re e An
d
l
h
li fie for t
O le
ab
l
i
va
a
Oilfield Review Apps
The Schlumberger Oilfield Review app for Android† devices is now available free of charge on the Google Play† store. This new app
complements the iPad‡ app, which is available at the Apple‡ iTunes‡ online store. For Android devices, including phones, this is a
stand-alone app; accessing content on the iPad device is done through the Newsstand. An iPhone‡ compatible version is in development and will be available in the near future.
Oilfield Review communicates advances in finding and producing hydrocarbons to oilfield professionals. Articles from the journal
are augmented on the apps with animations and videos, which help explain concepts and theories beyond the capabilities of static
images. The apps also offer access to several years of archived issues in a compact format that retains the high-quality images and
content you’ve come to expect from the print version of Oilfield Review.
To download and install the app, search for “Schlumberger Oilfield Review” in the App Store‡ or Google Play online store or scan
the QR code below, which will take you directly to the device-specific source.
†Android
‡Apple,
and Google Play are marks of Google Inc.
App Store, iPad, iPhone and iTunes are marks of Apple Inc., registered in the US and other countries.
14-OR-0004
Everything We Know, Everywhere You Go
Keeping up with developments in exploration and production technology takes time and effort, but the staff at the
Schlumberger Oilfield Review has tried to make that
task easier for our readers. Now that we have made the
Oilfield Review available on mobile devices, readers can
have the latest articles and access this archive of knowledge more easily than ever in a compact, portable format.
Our mission at the Oilfield Review is to supply today’s oil
and gas industry professionals with information on technical advances they can use to find and produce hydrocarbons. Since its first edition in 1989, Oilfield Review has
published more than 450 articles on topics spanning a
wide range of E&P activities, from seismic surveys, petroleum system modeling and core analysis to bit design, drillstem testing and log interpretation.
In the 25 years since the first edition appeared, the journal
has changed in minor ways—cover design and typeface to
name a few—to improve the reading experience. The latest
innovation is much more ambitious and takes the Oilfield
Review beyond the print realm and into digital formats on the
go; to reach a wider audience, we have created free apps to
give readers access to editions on mobile devices such as
iPad† and Android‡ tablets. Our most recent app versions will
also be available on iPhone† and Android phones. We
designed the apps with the aim of maintaining our high standards of technical accuracy, relevancy and writing quality
while enhancing the reader experience. At the same time, we
hope to entice a new generation of readers and make it easier
for everyone to access all that Oilfield Review has to offer.
In addition to the in-depth coverage and excellent graphics for which Oilfield Review is known, articles available
through the apps now contain animations, videos and
interactive graphics to demonstrate how downhole equipment functions and explain difficult concepts more fully.
Readers can see through-bit logging tools conveyed downhole, seismic volumes interpreted in 3D and quadrupole
waves emitted by a sonic logging tool. The articles in this
edition, which explore controlling lost circulation, well
testing, perforating and permeability, are enhanced in the
apps with videos and animations that illustrate key points.
Articles on general science topics add context to the
physical world in which our industry operates. Recent editions have contained articles on ice core drilling, autonomous ocean monitoring devices, scientific drilling into
earthquake zones, space weather and microbial activity.
Videos and animations bring these topics to life in ways
that words and illustrations alone cannot.
†Apple, App Store, iPad and iPhone are marks of Apple Inc., registered in the US and
other countries.
‡Android
§iOS
and Google Play are marks of Google Inc.
For those interested in exploring topics in greater depth,
the apps have live footnote links to URLs for access to original source references. The Schlumberger Oilfield Glossary is
included with each app and resides on the device, so it can
be accessed at any time to look up unfamiliar terminology.
Readers can search articles for terms and search the entire
archive for articles on specific topics. The archive of articles
in interactive format goes back to 2004, but links to articles
in PDF format are available back to 1998. The Android version will soon feature most of these capabilities.
To make the apps more useful, we continue app development and enhancement based on feedback from you, our
readers. Upcoming releases will give readers the ability to
share articles with colleagues and download collections of
articles on specific topics.
The new Oilfield Review apps appeal to a wide range of
readers: technical experts keeping up to date on recent developments in their domain, new hires learning basics about
their new field and students getting an early lead on topics in
the oil field. The ability to access these articles via mobile
devices allows readers at any experience level to get the information they need at their convenience—anytime, anywhere.
The new apps are available at no cost as downloads from
the Apple† App Store† or Google Play‡ stores. On iOS§ devices,
editions of the journal appear in the Newsstand; on Android
devices, Oilfield Review is accessed through a standalone
app. Alerts are automatically pushed to the apps upon release
of a new issue, and new content can be downloaded as individual articles or full editions.
As the demand for energy increases, so does our need to
understand exploration and production technology. At the
same time, seasoned experts are leaving the oil and gas
industry at an unprecedented rate and taking their knowledge with them. The value of their experience can never
be replicated. But an easily accessed, mobile repository of
knowledge reaching back more than a generation may be
the next best thing.
Lisa Stewart
Executive Editor, Oilfield Review
Lisa Stewart, Executive Editor of the Schlumberger Oilfield Review since
2011, is based in Houston. In addition to managing production of the Oilfield
Review, she has led the initiative to develop the Oilfield Review apps. She
joined the company in 1985 as a research scientist at Schlumberger-Doll
Research in Ridgefield, Connecticut, USA, where she worked on integrated
processing and interpretation of borehole and surface seismic data and early
attempts at hydraulic fracture monitoring. In 1993, she became an editor with
Oilfield Review, where she researched, wrote and edited more than 60 articles
on a variety of topics, managed executive-level seminars and founded the
Russian edition of the journal. Lisa has a bachelor’s degree in geophysics
from the University of California, Berkeley, USA; and a PhD degree in geology
and geophysics from Yale University, New Haven, Connecticut.
is a mark of Cisco in the US and other countries.
1
Schlumberger
Oilfield Review
www.slb.com/oilfieldreview
Executive Editor
Lisa Stewart
Senior Editors
Tony Smithson
Matt Varhaug
Rick von Flatern
Editors
Irene Færgestad
Richard Nolen-Hoeksema
Contributing Editors
Ginger Oppenheimer
Rana Rottenberg
Design/Production
Herring Design
Mike Messinger
Illustration
Chris Lockwood
Mike Messinger
George Stewart
1
Everything We Know, Everywhere You Go
Editorial contributed by Lisa Stewart, Executive Editor, Oilfield Review
4
Sealing Fractures: Advances in
Lost Circulation Control Treatments
Fractured formations create challenging lost circulation
scenarios during the drilling process and may jeopardize
well integrity. Some fiber-based treatments designed to aid
drilling through these formations can be incompatible with
bottomhole assemblies with small bit nozzles. Advances in
fiber technology are making lost circulation treatments
compatible with most bottomhole assemblies, thus providing
operators easy, time-saving and effective treatment options
for bridging and plugging fractured formations.
Printing
RR Donnelley—Wetmore Plant
Curtis Weeks
14 Perforating Innovations—Shooting Holes
in Performance Models
On the cover:
A Schlumberger technician loads a rock
sample into a fixture for testing shaped
charges such as those shown in the
inset. Engineers simulate downhole
pressure conditions with the fixture and
measure charge performance that should
closely replicate downhole results. Data
from tests performed on hundreds of
samples were used to develop a realistic
performance prediction model.
2
Current methods of predicting perforating system performance downhole may yield estimates that are inconsistent
with actual results. New modeling software more accurately
predicts perforation geometry, perforation effectiveness and
system dynamic responses. In addition, engineers have
designed shaped charges that outperform traditional charges
in tests on rocks subjected to stresses representative of
downhole conditions. New safety innovations improve operational efficiencies and provide multiple deployment options.
About Oilfield Review
Oilfield Review, a Schlumberger journal,
communicates technical advances in
finding and producing hydrocarbons to
customers, employees 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 English,
Spanish, Chinese and Russian.
Download the free app.
© 2014 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.
Autumn 2014
Volume 26
Number 3
ISSN 0923-1730
Advisory Panel
32 Step Change in Well Testing Operations
Hani Elshahawi
Shell Exploration and Production
Houston, Texas, USA
Drillstem tests have long been used to gather data that
help engineers predict how individual wells will perform
and how best to complete those wells and develop the field.
An acoustic wireless telemetry system now gives operators
access to these data in real time.
Gretchen M. Gillis
Aramco Services Company
Houston, Texas
Roland Hamp
Woodside Energy Ltd.
Perth, Australia
Dilip M. Kale
ONGC Energy Centre
Delhi, India
42 Shushufindi—Reawakening a Giant
George King
Apache Corporation
Houston, Texas
The Shushufindi mature giant oil field in Ecuador, discovered
in 1969, was in decline from its peak production in 1986.
Starting in 2012, a consortium led by Schlumberger has
revived the field using reservoir characterization, infill drilling, workovers and continuous monitoring of field operations.
Andrew Lodge
Premier Oil plc
London, England
Michael Oristaglio
Yale Climate & Energy Institute
New Haven, Connecticut, USA
59 Contributors
61 Coming in Oilfield Review
62 Books of Note
63 Defining Permeability:
Flow Through Pores
This is the fifteenth in a series of introductory articles describing basic concepts
of the E&P industry.
Editorial correspondence
Oilfield Review
5599 San Felipe
Houston, TX 77056
United States
(1) 713-513-1194
Fax: (1) 713-513-2057
E-mail: editorOilfieldReview@slb.com
Subscriptions
Customer subscriptions can be obtained
through any Schlumberger sales office.
Paid subscriptions are available from
Oilfield Review Services
Pear Tree Cottage, Kelsall Road
Ashton Hayes, Chester CH3 8BH
United Kingdom
E-mail: subscriptions@oilfieldreview.com
Distribution inquiries
Matt Varhaug
Oilfield Review
5599 San Felipe
Houston, TX 77056
United States
(1) 713-513-2634
E-mail: DistributionOR@slb.com
Oilfield Review is pleased to welcome
Michael Oristaglio to its editorial advisory
panel. Michael is Executive Director of
the Yale Climate & Energy Institute, a
center for interdisciplinary research and
teaching on energy use and climate
change at Yale University in New Haven,
Connecticut, USA. His research specialties are seismic imaging, electrical well
logging and carbon management. Before
coming to Yale in 2009, he worked for
nearly 30 years with Schlumberger; his
last position was technology advisor for
Schlumberger Mergers & Acquisitions.
Since 2011, he has been the Program
Manager of the SEG Advanced Modeling,
or SEAM, Phase II consortium for advanced
modeling of land seismic exploration.
Michael has degrees in geology and
geophysics from Yale and a DPhil degree
in geophysics from the University of
Oxford, England. He also authored
A Sixth Sense, a biography of one of the
founders of Schlumberger.
3
Sealing Fractures: Advances in
Lost Circulation Control Treatments
Santiago Pablo Baggini Almagro
Neuquén, Argentina
Of the numerous lost circulation treatments available, some are time-consuming and
Cliff Frates
Dorado E&P Partners,
Denver, Colorado, USA
mitigation and now include self-degradable fibers. These solutions provide stable
Jeremy Garand
Tulsa, Oklahoma
Arnoud Meyer
Clamart, France
Oilfield Review Autumn 2014: 26, no. 3.
Copyright © 2014 Schlumberger.
CemNET, Losseal and PressureNET are marks of
Schlumberger.
BAKER SQUEEZ is a mark of Baker Hughes.
BAROFIBRE and BARO-SEAL are registered trademarks of
Halliburton.
FORM-A-BLOK is a mark of M-I, LLC.
1. Cook J, Growcock F, Guo Q, Hodder M and van Oort E:
“Stabilizing the Wellbore to Prevent Lost Circulation,”
Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35.
2. “Petroleum Engineering Technology Timeline,” Society
of Petroleum Engineers, http://www.spe.org/industry/
history/timeline.php (accessed June 10, 2014).
3. Messenger J: “Technique for Controlling Lost
Circulation,” US Patent No. 3,724,564 (November 12, 1971).
4. Loeppke GE, Glowka DA and Wright EK: “Design and
Evaluation of Lost-Circulation Materials for Severe
Environments,” Journal of Petroleum Technology 42, no. 3
(March 1990): 328–337.
5. A pill is any relatively small quantity—generally less than
32 m3 [200 bbl]—of a special blend of drilling fluid
designed to accomplish a specific task that the regular
drilling fluid is not intended to perform.
6. Jain B, Khattak MA, Mesa AM, Al Kalbani S, Meyer A,
Aghbari S, Al-Salti A, Hennette B, Khaldi M, Al-Yaqoubi A
and Al-Sharji H: “Successful Implementation of
Engineered Fiber Based Loss Circulation Control Solution
to Effectively Cure Losses While Drilling, Cementing and
Work Over Operations in Oman,” paper SPE 166529,
presented at the SPE Annual Technical Conference and
Exhibition, New Orleans, September 30–October 2, 2013.
7. For more on wellbore strengthening: Cook et al,
reference 1.
8. Ghalambor A, Salehi S, Shahri MP and Karimi M:
“Integrated Workflow for Lost Circulation Prediction,”
paper SPE 168123, presented at the SPE International
Symposium and Exhibition on Formation Damage Control,
Lafayette, Louisiana, USA, February 26–28, 2014.
9. Akbar M, Vissapragada B, Alghamdi AH, Allen D,
Herron M, Carnegie A, Dutta D, Olesen J-R,
Chourasiya RD, Logan D, Stief D, Netherwood R,
Russell SD and Saxena K: “A Snapshot of Carbonate
Reservoir Evaluation,” Oilfield Review 12, no. 4
(Winter 2000/2001): 20–41.
4
ineffective. Advances in fiber-based technology permit quick and efficient loss
plugging and reservoir protection during drilling; the plugs then disperse, enabling
production from an undamaged reservoir.
The reduction or loss of fluid returns to the surface can threaten a drilling project. Lost circulation events are not uncommon occurrences and
have a range of consequences, from increasing
well construction costs to jeopardizing well stability. Loss of circulation occurs mainly as a
result of drilling through formations that are
fractured, underpressured, cavernous or highly
permeable. These thief, or lost circulation, zones
can cause drilling crews to lose control of a well
because the thief zones take in drilling fluid and
prevent its return to the surface.
The economic consequences of lost circulation (LC) may be significant, and operators often
add 10% to 20% to their drilling budgets in anticipation of nonproductive time (NPT) attributable
to LC. In addition, uncontrolled loss of fluid to
the formation may damage the reservoir, altering
its characteristics and negatively affecting its
production potential.1
The first recorded use of a fluid other than
water for rotary drilling operations was around
1901 at Spindletop in Texas, USA, when drillers
pumped mud drawn from earthen reserve pits
downhole while drilling the well. No record
exists of the properties of this muddy mixture,
nor were any discussions or information about it
published. The term mud reappeared 13 years
later when a mud-laden fluid—defined as a
10. Cook et al, reference 1.
11. Arshad U, Jain B, Pardawalla H, Gupta N and Meyer A:
“Engineered Fiber-Based Loss Circulation Control Pills
to Successfully Combat Severe Loss Circulation
mixture of water and any clayey material suspended in water for a considerable time—was
used in a cable tool drilling operation in
Oklahoma, USA.2
The history of the first application of lost circulation solutions is as clouded as the history of
early drilling fluids. Almost any solid can be used
to plug a fractured formation given enough
applied pressure and proper particle size or properties. Whether the plug will remain in place
when rotation and circulation are resumed, and
whether it will withstand vibrations and changes
in pressure are different matters. Early lost circulation materials (LCMs) were often chosen
because they were readily available near the
drilling sites and were inexpensive. They included
cottonseed hulls, shredded leather, sawdust,
straw and ground walnut shells.3 Frequently, the
LCMs were made from leftover materials or waste
from manufacturing processes. Today’s more
complex drilling operations have created the
need for specially designed LCMs.4
The characteristics of a formation dictate the
treatment to control lost circulation. Selection of
the correct solution depends on understanding
the formation and identifying the type and cause
of lost circulation. For example, the actions
required to treat fluid losses in naturally fractured rocks differ from those required to treat
Challenges During Drilling and Casing Cementing in
Northern Pakistan,” paper SPE 169343, presented at
the SPE Latin American and Caribbean Petroleum
Engineering Conference, Maracaibo, Venezuela,
May 21–23, 2014.
Oilfield Review
losses into high-porosity and pressure-depleted
formations. Additionally, downhole temperatures
and exposure time to them may limit the range of
suitable treatments.
Typical lost circulation treatments for fractured reservoirs involve LCM mixed into the drilling fluid, either dispersed throughout the fluid or
as a pill.5 These treatments are designed to plug
fractures. However, even though these materials
may provide some level of success, the use of
sized materials alone does not ensure loss mitigation, especially in formations with wide fractures.
Because the aperture of the fractures is often
unknown, the size of the LCM will likely be
wrong. If too small, the particles will flow through
the fractures; if too large, they will not penetrate
the fractures at all. In either case, improperly
sized LCM will leave losses uncured.6
Drilling technology has progressed considerably since the early days at Spindletop; well
construction and drilling operations are more
cost-effective and can be executed more safely
than ever before. As operators target increasingly
remote and geologically complex reservoirs, they
are pushing the limits of modern drilling fluids
and searching for improved technologies to
ensure wellbore integrity. To meet these challenges, the industry continues to introduce
wellbore strengthening solutions to contain
induced fracture growth and prevent uncontrolled LC from the wellbore.7
This article presents several remedies to
combat drilling fluid losses; case studies illustrate the use of treatments. These treatments
are adaptable to a wide range of environments,
including naturally fractured formations,
depleted reservoirs, carbonate zones and other
formations prone to lost circulation problems.
Where Did It Go and What Do We Do Now?
Lost circulation is typically caused by a pressure
imbalance and a pathway for fluid to enter the
formation. Pressure imbalances occur in certain
drilling scenarios. The principal condition for
loss of drilling fluid is mud weight that is too high,
wherein the mud exerts a hydrostatic pressure
that is higher than the formation pressure, which
can lead to fracturing of the formation and subsequent fluid loss into the induced fractures.8
Pathways for fluid loss include caverns, fractures
and unconsolidated formations.
To operate safely in unstable, low-pressure
or naturally fractured intervals—risk zones—
engineers need to identify them, if possible,
prior to drilling. In some types of formations,
risk zones are more difficult to map than in
Autumn 2014
Cavernous formations
Natural fractures
Induced fractures
Highly permeable formations
others. For example, the high degree of heterogeneity of carbonate formations makes reservoir characterization problematic. Carbonate
formations are highly susceptible to dissolution.
This can lead to formation of new pore spaces,
and dissolution along fractures and bedding
planes can produce large caves.9 In considering
any formation type, engineers rely on foreknowledge to plan for preventive and remedial actions
to counter lost circulation events. The most effec-
Type of Loss
tive mitigation is to set protective casing across
problematic zones; however, this solution is
expensive, limits future drilling options and may
compromise logging opportunities.
Lost circulation may be divided into four volumetric loss rate categories: seepage, partial loss,
severe loss and total loss (below).10 As mud loss
severity increases, financial losses mount to
cover costs for additional drilling fluid, lost circulation treatments, rig time and delays.11
Severity of Loss
Seepage
Less than 1.6 m3/h [10 bbl/h]
Partial
1.6 to 16 m3/h [10 to 100 bbl/h]
Severe
More than 16 m3/h
Total
No fluid return to the surface
> Lost circulation classification. Loss is classified based on the rate of fluid
volume lost to the formation.
5
Remediation
Lost circulation management strategies
depend on whether the treatment is applied
before or after the loss. Lost circulation can be
managed through a four-tiered approach (below).
Best drilling practices cover the major types of
drilling fluid losses. They include predrill simulations and calculations in which engineers use
geomechanical models to determine the risk
of lost circulation and wellbore collapse. Best
drilling practices to control losses also include
approaches such as using expandable casing,
managed pressure drilling or casing while drilling. The second tier represents the selection of
drilling fluids with rheological properties that
reduce the risk of lost circulation. The next tier
uses wellbore strengthening materials for loss
management. These are mixtures of particulate
materials formulated and sized to enter and
bridge fractures to isolate them from the wellbore. The top tier includes using LCMs as remedial treatments to correct ongoing lost circulation
problems. This tier may include pills to place
across lost circulation zones.
When drillers anticipate fluid losses, they pretreat drilling fluids by adding wellbore strengthening materials such as ground marble and
synthetic graphite. Pressure tests conducted
before and after such wellbore strengthening
treatments often indicate that these approaches
are successful.12 Adding wellbore strengthening
materials is considered a proactive, or preventive, treatment. Lost circulation materials are, on
the other hand, considered corrective, or remedial, treatments because these materials are usually added to the drilling fluid after losses occur.
Advances in Lost Circulation Solutions
Lost circulation prevention and remediation are
important factors for drilling economically. When
drillers cannot prevent lost circulation, they turn
to mitigation treatments to regain well control
and circulation.
The choice of treatment depends on the targeted geologic formation, the cause of lost circulation and whether a permanent or temporary
solution is required. Prevention and mitigation
practices are largely dictated by the situation;
they take into account parameters such as formation pressure, formation type, drilling fluid
properties, local environmental regulations and
LCM availability.
Service companies offer a variety of LCMs:
They can be flaky, granular, fibrous or acid soluble; they are available in sizes ranging from nano-
Lost
Circulation
Materials
Prevention
Wellbore Strengthening
Materials
Drilling Fluid Selection
Best Drilling Practices
> Lost circulation management program. Some experts address lost circulation
through a tiered approach. The bottom three tiers focus on lost circulation
prevention measures, while the top tier represents remediation measures.
6
meters to millimeters. Mixing different types of
LCMs to improve bridging and plugging performance is a common practice. Many service companies offer lost circulation solutions based on
natural cellulose fiber, shredded cedar
fiber and mineral fiber often combined with
solid particles of various sizes. The Halliburton
BARO-SEAL lost circulation material, a combination of fibers, granules and flakes sized to plug
natural fractures, is one example. The company
also offers the BAROFIBRE material, a natural
cellulose fiber used to seal and bridge depleted
sands and microfractures to reduce seepage loss.
The Baker Hughes BAKER SQUEEZ high fluidloss treatment for partial to severe fluid losses is
designed to dewater and leave a solid plug in
fractures and vugs.
Engineers at Schlumberger have developed
several fiber-based solutions, including the
Losseal family of reinforced composite mat pills
and CemNET and PressureNET treatments.
Although choices are plentiful, and companies
offer a wide array of solutions, the preferred solutions will be those that cost effectively solve lost
circulation problems quickly, safely and with the
least risk.13
Filling the Voids
Scientists at Schlumberger took a customized
treatment approach featuring engineered fibers
and combinations of fibers and solids to obtain
lost circulation solutions that perform consistently. These treatments mitigate loss of drilling
fluid or cementing fluid in many environments,
including formations that have natural fractures,
carbonate zones, rubble zones and pressuredepleted zones. All these treatments may be
placed at the desired depth without pulling the
drillstring out of the hole. This reduces NPT and
associated costs.
Fibrous pill treatment—The Losseal family
of reinforced composite mat pills consists of a
blend of fibers and solids that bridges and plugs
fractured zones during drilling and cementing
(next page, top). The Losseal family comprises
three solutions optimized for microfractures and
fissures, natural fractures and reservoir fractures
(next page, bottom). Fracture plugging using
Losseal treatments for the first two applications—microfractures and natural fractures—
follows a four-step approach: disperse, bridge,
plug and sustain; each step is equally important
Oilfield Review
to achieve optimal treatment performance.
Depending on the application, one particular
step of the four may be the main focus. For
example, when a pill is pumped while drilling, it
is important to maintain the mechanical properties of the recently formed pill in the fracture
while drilling operations continue. The plug must
withstand erosional forces (from changes in pump
rates and fluid velocities), mechanical forces
(from running and rotating pipe) and hydrodynamic forces (from surge and swab). However, in a
cementing spacer application, the main focus is to
seal off the fractures so that cement is not lost into
them. The residual spacer volume is used to displace mud ahead of the cement fluid—the primary purpose of a spacer application.
A Losseal pill creates a strong, impermeable
mesh and prevents the flow of drilling and
cementing fluids into fracture zones. The pill can
seal microfractures and larger natural fractures
in both overburden and reservoir drilling. Within
limits, the plug can withstand additional pressure
from mud density increases as well as future drilling or cementing operations. The Losseal pill is
relatively insensitive to fracture width and may be
used without detailed knowledge of formation
characteristics, whereas the performance of many
lost circulation treatments depends on a known
fixed fracture width. Losseal pills are typically
used for formations that are naturally fractured
and in formations with fissures ranging from 1 to
5 mm [0.04 to 0.2 in.] in width. Engineers can perform a plugging efficiency test on site for each
first-time use of the Losseal system.14 Additional
tests are not needed as long as loss zone conditions remain the same and the same type of particles is used throughout the operation.
Treating microfractures and fissures—
Losseal microfracture lost circulation control
treatment is designed to bridge fractures of
widths ranging from 1 micrometer to 1 mm. The
treatment is compatible with both oil-base and
water-base fluids and can be added directly to
12. Wang H, Sweatman R, Engelman B, Deeg W, Whitfill D,
Soliman M and Towler BF: “Best Practice in
Understanding and Managing Lost Circulation
Challenges,” SPE Drilling & Completion 23, no. 2
(June 2008): 168–175.
13. Alsaba M, Nygaard R, Hareland G and Contreras O:
“Review of Lost Circulation Materials and Treatments
with an Updated Classification,” paper AADE-14FTCE-25, presented at the American Association of
Drilling Engineers Fluids Technical Conference and
Exhibition, Houston, April 15–16, 2014.
14. In a plugging efficiency test, success is based on the
ability of the material to plug a slot similar in width
to the anticipated fracture width. The treatment
plug also needs to hold a similar pressure to the
maximum differential pressure across the thief zone
during operations.
Autumn 2014
> Losseal treatment pill. The Losseal pill blends fibers—both stiff and flexible—and solids that are
pumped through a BHA to bridge fractures. After only about 60 minutes of soaking time, the resulting
pill is able to plug the loss formation. The yellow arrows show the pill flowing up the annulus and into
the formation fractures. The solids and fibers (inset) in the pill form a mesh, which fills and seals the
fractures in the formation.
Challenge
Treatment
Fracture Width, mm
Loss Rate, bbl/h
Microfractures,
fissures
Losseal microfracture
lost circulation control, as a pill
Less than 1
Less than 40
Natural
fractures
Losseal natural fracture
lost circulation control, as a pill
1 to 5
More than 40
Reservoir
fractures
Losseal reservoir fracture
lost circulation control, as a pill
1 to 5
More than 40
While cementing
All
Losseal microfracture
lost circulation control, as a spacer
Less than 1
Less than 40
While cementing
All
Losseal natural fracture
lost circulation control, as a spacer
1 to 5
More than 40
Stage
While drilling
> Losseal solutions and applications. The Losseal family consists of three treatment solutions, some of
which may be applied as either a pill or a spacer. The application type dictates which solution should
be used.
7
> Losseal microfracture material. The Losseal microfracture solution is an engineered fiber treatment,
combining specific fibers (light gray) with solid bridging materials (dark gray).
the drilling fluid in a spacer or as a stand-alone
pill. The Losseal microfracture solution comes as a
single-bag add-on for easy design and preparation
(above). In some cases, the Losseal microfracture
solution has been added to cementing fluids,
bringing the top of cement to the required level.
Pill for natural fractures—The Losseal natural fracture lost circulation control pill is
designed to bridge and plug large fractures of
widths ranging from 1 to 5 mm. The system takes
advantage of a dual fiber combination with a solids package that can be optimized for efficiency.
The system can also be fully tailored to match the
unique needs of the loss zone and required placement, making the performance fit for purpose.
The pill can be pumped through open-ended
drillpipe for efficient plugging of zones. To avoid
premature screenout or plugging, it can be
pumped through the bit nozzles, which may
require changes to the pill formulation such as
reducing total solids, using smaller sized solids
and reducing the amount of fiber. The plugging
performance can be demonstrated via a modified
fluid loss cell, in which the flow performance
through restrictions such as bit nozzles can also
be simulated.
The Schlumberger fibers for lost circulation
control disperse easily in fluids and work by combining an interlocking network of fibers with
sealing material of various sizes. Fiber dispersion
is important to avoid premature bridging and
8
plugging of surface and downhole equipment,
and good dispersion also enhances bridging in
the fractures. The bridge of fibers is still permeable, and the solids fit in the fiber matrix, filling
the pores to create a sealing plug that can withstand differential pressures. The resulting compact, impermeable seal plugs pores and fractures,
mitigating lost circulation risk during drilling,
casing and cementing operations. The Losseal
blend can be added to spacers between cement
application stages, spotted ahead of the cement
or added directly into the cement during pumping operations.15 Use of the material helps operators prevent lost circulation, reestablish
circulation and run casing with limited losses,
and then pump cement to achieve the desired top
of cement level. This solution allows operators to
place treatments precisely in a target zone and
reduce pretreatment loss rate by more than 90%.
The Losseal natural fracture treatment was
applied successfully in the Costero field near
Villahermosa, Mexico, where lost circulation is a
primary cause of NPT. A Schlumberger Integrated
Project Management (IPM) team, operating on
behalf of a client, experienced oil-base mud
(OBM) losses of 2,000 bbl [320 m3] in a 5 5/8-in.
hole in a carbonate formation. The casing was set
at 19,173 ft [5,844 m], and the losses occurred
between 18,963 [5,780 m] and 19,173 ft. The
IPM team responded by reducing the relative
density of the mud from 1.12 to 1.01 [from 9.35 to
8.43 lbm/galUS or from 1,120 to 1,010 kg/m3],
resulting in a kick.16 The well stabilized with mud
at a relative density of 0.97 [8.1 lbm/galUS or
970 kg/m3], but this mud density would not allow
further drilling into the deeper formations.
The IPM team chose to pump a Losseal pill
because OBM is expensive and limited data were
available on fracture width, fracture density and
downhole temperature after the losses. Based on
fluid loss rate and formation temperature, engineers selected the appropriate particle size for
the Costero well—a 90-bbl [14.3-m3] pill, including 2.9 lbm/bbl [8.3 kg/m3] of fibers and a
217-lbm/bbl [620-kg/m3] blend of coarse, medium
and fine solids. The pill was then placed as a balanced plug before a squeeze pressure of 200 psi
[1.4 MPa] was applied.17 Because the system
worked immediately upon pill placement and
stopped static and dynamic losses in a single onehour treatment, no trip was required (next page,
top). The drilling crew increased the mud density
to 1.15 relative density [9.6 lbm/galUS or
1,150 kg/m3] without encountering any losses
and drilled successfully to TD. The team also
completed the cementing operation that followed the Losseal pill without significant losses.
Schlumberger engineers also utilized the
Losseal natural fracture lost circulation solution
for an operator in south Texas. The operator
planned to cement the intermediate section of a
well in a single stage at a depth of 10,000 ft
[3,050 m]. After drilling through the Austin Chalk
and the naturally fractured Buda Limestone formation below it, the driller encountered severe
mud losses and was unable to regain full circulation. The drilling crew attempted to control the
losses by reducing drilling fluid density and by
adding several LCM products, but these efforts
were unsuccessful. Schlumberger engineers then
provided the Losseal natural fracture solution,
enabling the driller to regain full circulation prior
to cementing and to maintain full circulation
throughout the subsequent cementing treatment.
Because the operator had reduced the mud
density, the oil-base drilling fluid could not reliably suspend all fibers during the treatment. The
solution was a high-density fluid that had high
solids content (more than 30%) and exhibited no
dynamic settling of the solids. Plugging efficiency tests performed to optimize Losseal fiber
concentration showed that a 2.0- to 3.0-lbm/bbl
[5.7- to 8.6-kg/m3] concentration could plug slots
up to 0.2 in. [5 mm] across with a differential
pressure of 1,000 psi [6.9 MPa].
Oilfield Review
15. A spacer is viscous fluid used to aid removal of drilling
fluids before a primary cementing operation. The spacer
is prepared with specific fluid characteristics, such as
viscosity and density, and engineered to displace the
drilling fluid while enabling placement of a complete
cement sheath.
16. A kick occurs when the pressure in the wellbore is less
than that of the formation pore pressure. When the mud
weight is too low and the hydrostatic pressure exerted
on the formation by the fluid column is less than the pore
pressure, formation fluid can flow into the wellbore.
17. A balanced plug is a plug of cement or similar material
placed as a slurry in a specific location within the
wellbore to provide a means of pressure isolation.
Autumn 2014
120
6
3,000
2
100
5
40
2,000
Density, g/cm3
60
Pressure, psi
80
1
1,000
20
0
Pump rate, bbl/min
Pumping Losseal pill
Volume pumped, bbl
4
Displacement
3
2
1
0
0
0
18:05:40
18:34:50
19:04:00
19:33:10
Time, h:min:s
> Losseal pill placement. As pumping of the treatment is initiated, density increases (light blue). The
pressure (red) increases on displacement when Losseal fibers are pushed into the formation and
start to bridge and plug the fractures. The pressure drops as the pump rate (green) is reduced and
increases again at constant pump rate, demonstrating the continued bridging and sealing effect of
the Losseal treatment. The black line represents volume pumped.
developers create a plug inside a metal tube connected to a pump. The tube is then placed in an
oven, and a continuous flow of a fluid analogous
to the drilling fluid is applied at high pressure.
The resulting pressure response is monitored
nates the need to pull out of the hole to accommodate pumping of the pill.
The relationship between fiber degradation
and plug stability has been established through
laboratory experiments. In these experiments,
1,750
Measured pressure
1,500
Calculated pressure
1,250
Surface pressure, psi
The Losseal pill was prepared on location
and spotted across the entire suspected thief
zone, from 6,800 to 9,800 ft [2,100 to 3,000 m].
To avoid possible contamination and destabilization of the pill, which could happen should it
come in contact with the drilling fluid, a
weighted spacer was pumped both ahead of and
behind the pill. A soft squeeze, with a low
applied pressure, was then performed to help
initiate the bridging and plugging mechanism of
the LCM particles. A total squeeze pressure of
250 psi [1.7 MPa] was applied and no pressure
reduction was observed, indicating that the
Losseal natural fracture pill had sealed off the
loss zone. The reestablishment of full circulation immediately following the treatment was
another proof of success. Drillers were also able
to maintain full circulation throughout the
cementing treatment by adding this LCM fiber
to all fluids, the weighted spacer and the cement
for the rest of the job. Pressure tests verified
that the measured pressures matched the
design pressures, indicating that the treatment
had worked as expected (below right).
Treatment for reservoir drilling—When lost
circulation occurs while drilling through a reservoir section, operators must stem fluid loss or risk
damaging the zone’s producibility. Schlumberger
engineers have developed a family of reinforced
composite mat pills made of a blend of dissolvable fibers to provide lost circulation mitigation
in naturally fractured reservoirs, carbonate formations and depleted reservoirs; the pills are
designed to plug fractures that have widths from
1 to 5 mm. The pills have three components: viscosifiers, fibers and solids. The combination
remains stable long enough over a broad range of
bottomhole temperatures to allow well completions but then degrades with time, leaving the
formation undamaged. The Losseal reservoir lost
circulation treatment, which can pass through
drillbit nozzles as small as 6.35 mm [0.250 in.]
and through downhole logging equipment, elimi-
1,000
750
500
250
0
0
40
80
120
160
200
240
280
320
Time, min
> Pressure test. The postjob evaluation compares calculated with actual
recorded pressure during a Losseal application in a well in south Texas. A
hydraulic simulation model uses well geometry data, such as hole size and
deviation and casing or drillpipe sizes, taking into account fluid density and
fluid viscosity, to calculate the estimated pressures during pumping. The
model does not simulate possible losses; hence, any trend deviations
between measured and calculated pressure could indicate a lost circulation
event. The curve of the actual measured pressure (blue) follows the same
trend as the curve of the calculated pressure (red), indicating that no fluid is
lost to the formation and that what is pumped in is being circulated. Friction
pressures and annular restrictions cause the offset between calculated and
measured pressures. The pressure buildup after about 200 min indicates the
rising of the denser fluid—the cement—into the annulus.
9
10 5
10 4
10 3
Permeability, mD
Plug degradation
10 2
10
Stable plug
1
10–1
10–2
Time
> Losseal treatment for reservoir drilling. Losseal fibers degrade with time
(top, time increasing to the right). Technicians regulate pill pH levels to
control degradation time and to achieve a wide range of fiber stability
durations, from one day to eight weeks. Here, an accelerant has been added
that causes all fibers to dissolve within a desired time frame. A plot of
system stability (bottom) shows permeability as a function of time.
Permeability through the plug is low, as designed, until the plug disintegrates.
versus time. A sudden pressure drop indicates
that the plug material is starting to degrade and
be cleaned away and that permeability is being
restored (above). Engineers used the results
from these experiments to establish pill formulation guidelines. Factors that affect the performance of this fibrous pill solution include fluid
viscosity, fiber concentration, fiber geometry,
flow rate and fracture width. Engineers are currently working to extend the temperature stabil-
Disperse
Bridge
ity of the Losseal fibers beyond their rating of
85ºC [185ºF], and mid- and high-temperature
fibers are being tested in the field to confirm both
plugging performance and temperature stability
performance up to 150ºC [300ºF].
Unlike other Losseal products, the Losseal
pill for reservoir drilling is designed to degrade
over time (below). The pill disperses into the carrier fluid, leaves the mud to bridge fractures and
plug vugs, is sustained throughout drilling opera-
Plug
Sustain
Degrade
> Losseal solution for reservoir drilling. The Losseal reservoir drilling
treatment is a five-step solution. This treatment disperses in the chosen
fluid; it then bridges and plugs the targeted fractures, remains stable
throughout the operation and finally degrades.
10
tions and then dissolves with time, leaving the
formation undamaged. Plug degradation is catalyzed by downhole temperature and pressure
conditions and can be engineered to match drilling and completion schedules. The pill requires
less than one hour to mix and can be deployed at
temperatures between 40ºC and 150ºC [100ºF
and 300ºF] and at mud densities from 1,030 to
1,440 kg/m3 [8.6 to 12 lbm/galUS]. After the pill is
placed, a soaking time of around 60 min allows
the system to flow into the fractures; pill performance is enhanced by the application of pressure
to help the treatment enter, bridge and plug the
fractures. The pill degradation time is adjustable,
ranging from one day to eight weeks.18
The Losseal treatment for reservoir drilling
was introduced in 2014 and was recently utilized
by an operator in the Middle East to reduce mud
and cement losses during the drilling phase while
avoiding damage to the reservoir. The operator
was drilling two wells as part of a cyclic steam
injection project and experienced total losses at
341 m [1,120 ft] while drilling the 8 1/2-in. section.
The drilling crew continued drilling to the target
depth of 472 m [1,550 ft]; loss rates reached
32 m3/h [200 bbl/h]. Because this was the
intended production and injection zone, ensuring
that any lost circulation treatments would neither inhibit future production nor damage the
formation was crucial.
The operator needed to mitigate losses before
running and cementing the 7-in. casing; the
objectives were to avoid the loss of cementing fluids to the reservoir and to bring cement to the
surface. The operator selected the Losseal treatment for reservoir drilling. The fibers and solids
were mixed on site within an hour and the treatment material was successfully pumped. When
the pill entered the loss zone, a slight rise in
pump pressure indicated that fluids were rising
into the annulus; returns to the surface were
reestablished. After the drillstring was pulled out
of the hole to 61 m [200 ft] above the top of the
pill, the hole was circulated with water, and
returns to the surface were observed again. The
drilling crew then ran the drillpipe into the hole
to the top of the loss zone, and circulation was
reestablished followed by fluid returns to the surface. This treatment was successfully executed
for two wells in this area.
After several months, both wells began production from the treated reservoir zones; no
remedial treatment was necessary. Well testing
confirmed that in both treated wells, the initial production rates, or productivity indexes,
were higher than their predicted rates. These
results indicated that the treatment had dis-
Oilfield Review
18. Soaking time is the time it takes after placing the
Losseal pill at the desired location to achieve the
desired mesh, or grid, that produces the optimal
bridging and plugging effect.
19. A low cement top is produced when the cement slurry
fails to fill the annulus up to the intended level. This
condition can be caused by loss of cement to the
formation. For more on combating lost circulation while
cementing: Daccord G, Craster B, Ladva H, Jones TGJ
and Manescu G: “Cement-Formation Interactions,” in
Nelson EB and Guillot D (eds): Well Cementing 2nd ed.
Houston: Schlumberger (2006): 202–219.
20. A cement line pressure test is conducted by applying
pressure from the cement unit to the cement head or
master valve connected to the well to check for leaks or
any damage in the line. Common practice is to test lines
up to 6.9 MPa [1,000 psi] above the maximum allowed
treating pressure or to the working pressure of the
treating iron system, whichever is lower.
Autumn 2014
> CemNET engineered fiber technology. Dry CemNET fibers (left ) form a sheet-like network when
mixed with water (right ), enabling the network to seal lost circulation zones. CemNET fibers are
dispersible in any cement system and can be added and mixed quickly in a mixing tank.
and then pumped base oil and a spacer followed by
the fiber-laden cement slurry. The base oil and
part of the spacer were displaced without any
returns, indicating continued losses. The drilling
crew started injection at 200 L/min [1.26 bbl/min]
into the loss zone below the liner shoe. The
CemNET slurry immediately plugged the loss zone
upon arrival downhole (below). When the CemNET
slurry reached the open hole, the pressure
increased from 0.1 MPa to 1.4 MPa [14.5 to 203 psi].
Injection was stopped; the driller bled off pressure
through the choke and opened the pipe rams. The
Returns improve as
CemNET slurry cures.
Flow rate in
Flow rate out
Pressure
Flow rate and pressure
solved as designed, leaving the producing reservoir undamaged.
Fiber network—Deploying CemNET fibers—
engineered for use in cementing fluids—is
another method to seal fluid loss zones. The
fibers are inert and entangle to form a resilient
fiber network across a thief zone, allowing the
driller to regain and maintain circulation.
CemNET advanced fiber technology, which can
be deployed in cement slurries across zones
with expected losses, tolerates temperatures up
to 232ºC [450ºF]. The CemNET fibers do not
alter the cement slurry viscosity, thickening
time, tensile strength, shear strength, compressive strength or fluid loss (right). The CemNET
fibers disperse and mix readily in the slurry or
fluid. Application of the CemNET treatment
facilitates cement placement, eliminates excess
cement costs and minimizes remedial cementing operations to repair low cement tops.19
The CemNET treatment was successfully
employed in an operation in the North Sea, where
an operator was experiencing severe losses while
drilling out from the primary cement job in a well
in the Haltenbanken area offshore Kristiansund,
Norway. The cement job was executed according
to plan, and the shoe was pressure tested. The
shoe track, plugs, float and cement were then
drilled out. However, after the rathole was
cleaned out and the driller pulled the BHA out
above the 7-in. liner shoe to circulate, severe
losses occurred. Several LCM pills were pumped,
but losses soon recurred.
After spending 87 hours attempting to control
the losses, the operator decided to try fiber-based
treatments. The driller pulled the BHA out of the
hole and then used the squeeze method to place a
cement slurry containing CemNET LCM fibers.
The cement stinger was placed, and the cement
line was pressure tested successfully.20 Engineers
determined the final injection rate and pressure
Pressure increases as
squeeze is applied.
Pressure decreases
when squeeze stops.
Displacing 0.5 m3 of
cement slurry yields
100% fluid return.
Slurry
exits shoe.
07:37
07:45
07:52
08:00
08:07
08:15
Time, h:min
> CemNET slurry squeeze offshore Norway. The surface mud log recorded
pump-in (green) and flow out (blue) processes. As the CemNET slurry squeeze
exited the shoe and entered the loss zone, pressure (red) built up, and circulation
was reestablished.
11
> PressureNET treatment. PressureNET technology combines the strength and light weight of a lost
circulation material such as vitrified shale particles (left ) with the strength of CemNET fibers (right ).
cement slurry remaining in the stinger was displaced out of the hole by the pump and pull
method.21 Downhole losses were controlled, and
full circulation was reestablished following the
CemNET squeeze. The operator has experienced
similar positive results with the CemNET fiber for
loss control, and this approach has become part of
the operator’s contingency package.
A combination of the CemNET and Losseal
treatments was used in Argentina in 2013. The
drilling crew experienced partial losses when
placing slurry during a cementing operation.
The top of cement (TOC) was 1,100 m [3,600 ft]
below the expected level, and the postjob report
showed a difference between the actual and
simulated pressures, indicating that fluid had
been lost to the formation, which explained the
TOC depth difference.
Engineers designed the cement operation for
the next well based on lessons learned from the
first well. Schlumberger engineers used CemNET
additive in part of the slurry and Losseal microfracture treatment as the spacer. No losses were
experienced while the cement slurry was placed,
and data showed good agreement between calculated and actual pressure curves. The final TOC
was 100 m [300 ft] above the calculated level, and
cement evaluation logs showed a good cement
bond. CemNET and Losseal treatments prevented losses while increasing the equivalent
circulating density (ECD) when the slurry was
being placed.22 When losses occurred, the treatments mitigated them through effective bridging
and plugging mechanisms. As a result, the operator developed a contingency plan using the combination of CemNET fibers and Losseal material
for the remaining wells in the area.
Combination lost circulation solution—The
PressureNET fiber- and solids-based lost circulation solution combines dispersible CemNET fibers
12
with vitrified shale particles to stop lost circulation in shale, dolomite and limestone formations
(above). The combination is capable of bridging
openings up to 3 mm [0.1 in.] in width at pressures up to 5.5 MPa [800 psi]. The particles are
chemically inert in most fluids. The variable-sized
shale particles build up throughout the CemNET
fiber network, creating a base for cement slurry
solids to pack off and plug the lost circulation
zone. The strength of the PressureNET shale particles helps this LCM withstand high differential
pressures across fractures, thereby reducing the
volume of lost drilling fluid and cement. The treatment can be added to cement slurries, spacers
and drilling fluids in batch mixers or mud pits.
The impermeable network created by this treatment can support the hydrostatic pressure of a
cement slurry column and withstand additional
pressure resulting from subsequent primary or
remedial cementing operations.
In early 2013, Apache Corporation suffered
severe losses while cementing production
strings in wells in the Canyon Granite Wash in
Oldham County, Texas. The operator used
foamed cement, but the cement could not be
pumped to the desired height in the annulus in
two-thirds of the wells.23 As a result, Apache was
forced to perform costly and time-consuming
squeeze pressure treatments before the wells
could be put on production.
The Canyon Granite Wash is composed of
arkosic clastic and carbonate sediments that
were eroded from the Amarillo Uplift during the
middle to late Pennsylvanian age. The formation
has been producing since the late 1950s, although
recent activity after a long hiatus introduced
fracture stimulation and acidizing, which have
produced excellent results. However, depleted
zones are encountered when drilling, which
makes the formation prone to breakdown and
more difficult to drill and complete. After the
well experienced lost circulation and cementing
problems, Apache approved the PressureNET
solution for cementing the production casing in
the Bivins Lit well. Following a successful job, as
indicated by an observed pressure increase, per
design, a cement bond log evaluation indicated
that the top of cement met and even exceeded
the required height by several hundred feet.
Based on experience from the Bivins Lit well,
Apache has chosen the PressureNET solution for
several more cement jobs.
Defluidizing lost circulation solution—In
situations of partial or severe losses, the
FORM-A-BLOK high-performance, high-strength
pill may be an option. The pill combines an inert
blend of mineral, synthetic and cellulosic
fibers that are coated to allow the fibers to mix
in freshwater, brine or nonaqueous fluids.24
FORM-A-BLOK pills can treat fluid losses in fractures, caverns or vugs and work in temperatures
up to 177ºC [350ºF]. Standard rig equipment can
be used to mix the pill. The pill does not require
an activator or retarder and does not depend on
temperature to form a plug. The recommended
concentration of FORM-A-BLOK additive is
114 kg/m3 [40 lbm/bbl] for all freshwater, seawater and oil-base or synthetic systems except for
nonaqueous slurries with densities at or above
1,790 kg/m3 [14.9 lbm/galUS], which require a
concentration of 57 kg/m3 [20 lbm/bbl].
In loss situations, this treatment is applied as
a squeeze pill to cure losses rapidly. The driller
pumps the pill into the annulus; the volume
pumped is at least 150% of that of the loss zone.
Squeeze pressure causes the treatment pill to
rapidly lose its carrier fluid to the formation
(next page). The solids left behind pack into
voids and fractures to form a high-strength plug
that seals the loss zone. In addition to handling
partial and severe loss situations, the FORM-A-BLOK
pill can be applied as a quick-acting plug for wellbore strengthening operations, as an openhole
remedial or preventive lost circulation squeeze,
as an aid to improve casing shoe integrity and as
a cased hole squeeze to seal perforations and casing leaks.
After experiencing total lost returns during a
formation integrity test, an operator offshore
Indonesia chose the FORM-A-BLOK pill as the
solution. The integrity test was performed after
drilling out the cement and 20 ft [6 m] of new
formation. The objective was to achieve a
14.0-lbm/galUS [1,680-kg/m3] ECD without fracturing the formation. The operator isolated the
Oilfield Review
placed the well with seawater and pulled the
BHA up to 20 ft above the top of the perforations,
while the rig crew mixed a 40-bbl [6.4-m3]
FORM-A-BLOK pill. A total of 37 bbl [5.9 m3] of
the pill was pumped through the bit at a rate of
3 bbl/min [0.5 m3/min] with no observed pressure on the standpipe, which meant that losses
were not yet controlled. The pill was followed by
58 bbl [9.2 m3] of mud. Afterward, the drilling
crew observed displacement returns, and the
pressure increased to 0.8 MPa [116 psi], indicating that the pill had begun sealing off the perforations. Immediately after spotting the pill, the
crew applied a squeeze pressure, forcing the
pill to release its fluids and leave a malleable,
solid plug in place. The squeeze pressure was
repeated, leaving a total of 15.8 bbl [2.5 m3] of
FORM-A-BLOK material squeezed into the formation. Full circulation was restored, water-base
mud was reestablished as the displacing fluid
without incident, and drilling operations recommenced without further losses.
10 μm
> FORM-A-BLOK high-strength additive. This scanning electron microscope
image (top) shows the fibrous lattice form of a FORM-A-BLOK pill. After the
placement of the pill, pressure is applied, which results in a defluidized
fibrous lattice (bottom).
well with the upper pipe rams and started
increasing the wellbore pressure. A pressure of
4.6 MPa [670 psi] was held for five minutes, after
which the operator attempted to increase the
pressure to 6.9 MPa [1,000 psi]. The formation
broke down at 6.4 MPa [930 psi], and all returns
were lost. Before the pressure test, the operator
had perforated and squeezed a calcium carbon-
ate pill to contain losses in a thief zone. The engineers estimated that the thief zone was located
directly above the casing shoe.
A fluids engineering team from M-I SWACO, a
Schlumberger company, suggested the use of the
FORM-A-BLOK pill to isolate the perforations
and avoid recurring losses of the water-base
drilling fluid. The operator immediately dis-
21. In the pump and pull method, the cement slurry is
pumped through a drillstring equipped with a tailpipe.
During the placement of cement in the borehole, cement
inside the tailpipe is pumped out while the tailpipe is
pulled through the zone. This avoids the risks of
cementing the pipe in place or leaving cement in the
tailpipe after the operation is completed.
22. Equivalent circulating density (ECD) is the effective
density exerted by a circulating fluid against the
formation that takes into account the pressure drop
in the annulus above the point being considered.
23. Foamed cement is a homogeneous, ultralightweight
cement system consisting of base cement slurry, gas
and surfactants. Foamed cements are commonly used to
cement wells that penetrate weak rocks or formations
with low formation fracture gradients.
24. Sanders MW, Scorsone JT and Friedheim JE:
“High-Fluid-Loss, High-Strength Lost Circulation
Treatments,” paper SPE 135472, presented at the
SPE Deepwater Drilling and Completions Conference,
Galveston, Texas, USA, October 5–6, 2010.
Autumn 2014
Flexible Future in Fiber
These lost circulation treatments have been used
in hundreds of jobs around the world. Important
benefits of these solutions include their ease of
use, the time they save by not having to pull out of
the hole and the limited time needed for treatments to have the desired effect.
Because of the diversity in lost circulation
treatments and the variety of loss situations,
drilling experts must work on a case-by-case
basis to match the proper treatment to a specific
loss situation. These treatments have proved to
efficiently mitigate losses in fractured formations. Developments in lost circulation solutions,
such as fiber technology, provide efficient and
resilient treatments while saving rig time. The
hunt for improved, more reliable treatment solutions is not over, and the future of fiber technology promises further advances.
—IMF
13
Perforating Innovations—Shooting Holes
in Performance Models
Carlos Baumann
Alfredo Fayard
Brenden Grove
Jeremy Harvey
Wenbo Yang
Rosharon, Texas, USA
Amit Govil
Tananger, Norway
Andy Martin
Cambridge, England
Roberto Franco Mendez García
Arturo Ramirez Rodriquez
Petróleos Mexicanos (PEMEX)
Agua Dulce, Veracruz, Mexico
Jock Munro
Aberdeen, Scotland
Explosive shaped charges punch holes through the casing of oil and gas wells and
create tunnels to connect the wellbore to the rock beyond the casing. To determine
penetration performance in known conditions, service companies conduct tests at
the surface, firing shaped charges into unstressed concrete targets. After determining
that modeling programs may not correctly predict downhole charge performance,
Schlumberger scientists developed software that accurately computes depth of
penetration, perforation effectiveness and system dynamic responses. They have also
used this knowledge to develop charges that are optimized for perforating stressed rocks.
Perforating with explosive shaped charges is
the primary means of connecting hydrocarbonbearing formations to the wellbore through
casing. Operators have been perforating oil
and gas wells for more than 60 years. For
almost as long, scientists have been working to
create penetration models that link charge
performance in controlled tests to downhole
performance. However, validating charge performance downhole is difficult because of lack
of direct access to the perforations after operations are completed.
Cesar Velez Terrazas
Villahermosa, Tabasco, Mexico
Lang Zhan
Shell Oil Company
Houston, Texas
Oilfield Review Autumn 2014: 26, no. 3.
Copyright © 2014 Schlumberger.
ASFS, CIRP, HSD, PowerJet Nova, PowerJet Omega, PURE,
S.A.F.E., SafeJet, Secure, Secure2, SPAN, SPAN Rock and
TuffTRAC Mono are marks of Schlumberger.
1. Behrmann L, Grove B, Walton I, Zhan L, Graham C,
Atwood D and Harvey J: “A Survey of Industry Models
for Perforator Performance: Suggestions for
Improvements,” paper SPE 125020, presented at the
SPE Annual Technical Conference and Exhibition, New
Orleans, October 4–7, 2009.
2. American Petroleum Institute: RP 19B, Recommended
Practices for Evaluation of Well Perforators, 2nd ed.
Washington, DC: American Petroleum Institute, 2006.
3. For more on dynamic underbalance perforating:
Baxter D, Behrmann L, Grove B, Williams H, Heiland J,
Hong LJ, Khong CK, Martin A, Mishra VK, Munro J,
Pizzolante I, Safiin N and Suppiah RR: “Perforating—
When Failure Is the Objective,” Oilfield Review 21, no. 3
(Autumn 2009): 4–17.
> Concrete targets. A perforating specialist examines a concrete target to
appraise the perforation tunnel geometry produced by deep-penetrating
perforating charges (vertical lines). After the tests, the perforation tunnels
in the concrete targets are oriented horizontally; the concrete target has
been split open and set on its side for stability during examination. The API
RP 19B Section 1 test provides specific procedures for constructing these
concrete targets.
14
Oilfield Review
In recent years, service companies have
introduced perforating charges that penetrate
deeper and create larger perforation tunnels in
concrete test targets than ever before. Research
indicates that the link between tests in concrete and results in rocks subjected to conditions similar to those found downhole may not
be as straightforward as many models suggest.1
The model predictions appear to be too optimistic for depth of penetration, perforation tunnel
geometry and flow effectiveness under downhole conditions.
Charge performance and penetration predictions are traditionally made with data acquired
at the surface that are then corrected for the
downhole environment. The American Petroleum
Institute (API) Recommended Practice (RP) 19B
establishes procedures for qualifying charge performance.2 Testing techniques and procedures in
targets that simulate downhole conditions are
included in API RP 19B; however, shaped-charge
providers most often refer to Section 1 tests—
charges fired into unstressed concrete—when
comparing charges (previous page). Section 1
test results are also the basis of software model-
Autumn 2014
ing programs that predict charge performance
using rock and formation parameters, cement
and casing properties, wellbore completion fluid
effects and temperature and pressure data.
In 2004, Schlumberger opened the oil and
gas industry’s most advanced research laboratory to study perforation sciences. This facility
was an expansion of the industry’s first perforating laboratory, which Schlumberger pioneered
in 1953. At the Schlumberger Rosharon Campus
(SRC), Texas, USA, laboratory specialists conduct shaped-charge testing, including comparisons of laboratory results with predicted
performance from modeling software. Tests can
be performed in rock targets subjected to
stresses that replicate downhole conditions and
thus produce results that are more representative of real operations than those of surface
tests in unstressed concrete.
Research at the SRC laboratory has led to
updates in the understanding of the performance
of shaped charges and perforating systems.
Findings from laboratory testing were incorporated in the SPAN Schlumberger perforating analysis software. This software predicts performance
that more closely matches test results in stressed
rocks than do previous modeling systems. The
updated program has been renamed SPAN Rock
stressed-rock perforating analysis; the updated
software also includes modeling of the PURE clean
perforations and dynamic underbalance (DUB)
perforating systems. The software can predict
dynamic forces produced during perforating and
provide realistic productivity expectations.3
Researchers working to understand charge
performance have also developed charges that
are optimized for real-world conditions. The
PowerJet Nova extradeep-penetrating shaped
charge is an example of an engineered charge
design that incorporates ongoing research. This
is the industry’s first comprehensive charge family optimized specifically for stressed rock.
In addition to enhancing charge performance,
design engineers are developing new technologies to improve perforating safety. The S.A.F.E.
slapper-actuated firing equipment was the first
intrinsically safe perforating system in the oil
and gas industry. It used an exploding foil initiator (EFI) in place of the primary explosives commonly found in blasting caps. The more advanced
15
Penetration Model Results
40
Casing
Gun
28-day concrete
Steel
culvert
Penetration prediction, in.
Test
briquette
Water
35
30
Model 1
Model 2
Model 3
Model 4
SPAN model, concrete
Stressed-rock test
25
20
15
10
5
0
Penetration model
> Industry penetration prediction models. Test results in concrete targets (left) built to API RP 19B
Section 1 specifications are used in industry models to predict perforation performance under downhole
conditions. The concrete is cured for 28 days before testing. Technicians use a test briquette made with
the same batch of concrete to confirm the mechanical properties of the target. Researchers at
Schlumberger compared several models (right) to predict charge penetration using the same type of
charge under identical conditions. The traditional concrete-based SPAN model (light blue) predicted the
shallowest depth of penetration (DoP). For further validation, a test was performed on a stressed-rock
sample; the properties were input in the various models. All the model predictions were overly optimistic
compared with the actual DoP in the stressed-rock sample. (Adapted from Harvey et al, reference 14.)
SafeJet perforating gun system was recently
introduced. It includes added safety features
such as electronic initiators that enable selective
firing of multiple individual charges or charge
clusters. SafeJet technology improves efficiency
in selective firing operations commonly used in
fracture stimulation programs.
This article describes ongoing shaped-charge
research and outlines recent developments in
penetration and performance modeling software.
Operators in Mexico and the North Sea took
advantage of advances in modeling and shapedcharge design to enhance well productivity. An
additional North Sea example demonstrates the
benefits and operational efficiencies of SafeJet
perforating technology.
Setting New Standards
Engineers and scientists have been conducting
shaped-charge experiments since the 1950s.
Most of the experimentation was focused on
determining depth of penetration (DoP) because
well productivity of natural completions—those
that do not require stimulation—depends on the
degree to which perforation tunnels extend
beyond drilling-induced damage in the near-wellbore region.4 Recently, researchers compared the
penetration performance of modern shaped
charges under simulated downhole conditions
16
with penetration predictions from models commonly used in the industry—most of which were
developed before the 1990s. Test results indicate
that the accuracy of performance predictions has
not kept up with changes in charge design.5 In
addition, when the same perforating system is
evaluated under identical simulated conditions,
large discrepancies exist in performance predictions between models (above).
Surface testing of charges forms the basis of
performance predictions. Standards for testing
perforation charges were developed by the API
and described in RP 43 Section 1 concrete tests.
These standards were first published in 1962. Over
time, they evolved to include four test procedures:
• Section 1: System tests in concrete at ambient
temperature and pressure
• Section 2: Single-shot tests in stressed Berea
sandstone (3,000 psi [20.7 MPa]) at ambient
temperature
• Section 3: System tests in steel at elevated
temperature
• Section 4: Single-shot, flow performance tests
in stressed Berea sandstone samples (3,000 psi)
at ambient temperature.
To predict downhole DoP, early penetration
models started with API RP 43 Section 1 penetration data and applied a series of corrections (next
page, top). The sequential process for converting
Section 1 test results to downhole DoP in predictive models generally follows these five steps:
• Perform API RP 43 Section 1 concrete tests to
standards.
• Normalize these results for Berea sandstone
with unconfined compressive strength (UCS)
of 7,000 psi [48.3 MPa].
• Normalize corrected Berea sandstone data for
other unstressed rock types.
• Correct unstressed rock penetration data for
effective stress.
• Apply the effects of cement, casing and wellbore fluid to provide the final product.6
In 2001, API RP 19B, Recommended Practices
for Evaluation of Well Perforators, replaced API
RP 43; it was updated in 2006.7 The most significant change introduced by the new standards was
strict specifications for concrete aggregate targets used to evaluate charge penetration in
Section 1 tests.8 These updated practices included
narrow tolerances that ensured comparisons
between shaped charges from various charge providers were based on results from identical targets. However, API RP 19B surface tests may not
directly correlate with downhole charge performance predictions because most penetration
models were developed from the outdated DoP
data acquired using API RP 43 practices.
From extensive laboratory testing, SRC
researchers discovered that the common practice of sequentially applying corrections to API
RP 19B Section 1 DoP data results in overly optimistic downhole performance predictions that
are not representative of results observed in
stressed-rock tests. The discrepancies between
predicted performance and laboratory results are
attributed to the following:
• excessive reliance on API RP 19B Section 1
results in unstressed rocks
• lack of research using modern charges
• unrealistic treatment of in situ stress effects in
modeling programs.9
4. McDowell JM and Muskat M: “The Effect on Well
Productivity of Formation Penetration Beyond Perforated
Casing,” Transactions of the AIME 189 (1950): 309–312.
5. Behrman et al, reference 1.
6. Harvey J, Grove B, Zhan L and Behrmann L: “New
Predictive Model of Penetration Depth for OilwellPerforating Shaped Charges,” paper SPE 127920,
presented at the SPE International Symposium and
Exhibition on Formation Damage Control, Lafayette,
Louisiana, USA, February 10–12, 2010.
7. American Petroleum Institute, reference 2.
8. For more on concrete aggregate effects on testing:
Brooks JE, Yang W and Behrmann LA: “Effect of
Sand-Grain Size on Perforator Performance,” paper
SPE 39457, presented at the SPE International
Symposium on Formation Damage Control, Lafayette,
Louisiana, February 18–19, 1998.
9. Harvey et al, reference 6.
Oilfield Review
Basis of Industry Models
Section 1 Concrete Tests
Tests in 7,000-psi Berea Sandstone
Fluid inlet
Core vent
Casing
Other rock types
Gun
Section 1 concrete
Water
Test
briquette
28-day concrete
4- or 7-in.
diameter core
24
22
Sandstone
Limestone
Rubber sleeve
20
Steel
culvert
Target plate
Rock penetration, in.
18
Shaped charge
Annulus fluid
16
14
12
10
8
6
Brine
Cement
Damage zone
Formation
0
60
120
180
240
300
Average
3.38
2.17
0.48
0.00
0.48
2.17
1.45
14.89
17.64
19.99
19.22
19.99
17.64
18.23
13.73
16.49
18.83
18.07
18.83
16.49
17.07
0.43
0.52
0.93
0.78
0.93
0.52
0.71
Open Flow
Area, in.2/ft
0.20
0.25
0.43
0.36
0.43
0.25
0.32
0.48547 at
6 shots per ft
1.0
Downhole conditions
Fraction of surface penetration
Entrance Hole
Phase Clearance,
Formation
Total
Formation
Angle, °
in.
Penetration, in. Penetration, in. Diameter, in. Diameter, in.
System 1
System 2
System 3
System 4
0.9
4
2,000
6,000
10,000
14,000
18,000
22,000
Measured axial strength, psi
0.8
0.7
Effective stress
0.6
0.5
0
2,000
4,000
6,000
8,000
Applied effective stress, psi
> Sequential modeling. Most predictive penetration modeling software used in the industry follows a sequential path: API RP 19B Section I test data in
concrete (top left) are corrected for 7,000-psi [48.3-MPa] UCS Berea sandstone (top middle), corrected for rock type (right) and effective stress (bottom
right) and then corrected for downhole conditions, including casing size and type, fluid properties and gun geometry. The result is often presented as a 2D
model of DoP (bottom left). For the final results using the sequential model, the interaction of the various parameters with each other is given little
consideration. (Adapted from Martin et al, reference 13.)
Newer shaped charges penetrate much
deeper into test targets than did older generation
charges, and simple extrapolations of test data
often yield incorrect results. Compared with
those from older perforating systems, modern
shaped charges used in similar environments
may exceed penetration performance by 100% or
more. This greatly compounds the effects of
model uncertainty (right). Tests in unstressed
concrete targets may introduce large uncertainties in predicting actual penetration, even though
the tests are conducted in targets that adhere to
the stricter standards of API RP 19B Section 1.
Using industry models, engineers found a wide
variability in charge performance predictions.
These models begin with data from API RP 19B
Section 1 performance in concrete followed by
sequential applications of corrections for rock
type, downhole stress and environmental conditions. Modern charges far exceed the penetration
of older generation charges, although engineers
Autumn 2014
API RP 43 Section 2
Berea sandstone penetration, in.
40
30
Area of uncertainty
20
Modern charge
performance
10
0
0
10
20
30
40
50
60
API RP 43 Section 1 concrete penetration, in.
> Historical penetration data used in penetration prediction models. Historical data, based on API RP 43
guidelines (blue shading), were used to develop many penetration prediction models in use today. The
DoP values (black dots) on which these models are based were all less than 30 in. [76 cm]; modern
deep-penetrating charges, unavailable when most of these models were created, can exceed 60-in.
[152-cm] DoP. Researchers at Schlumberger observed that the assumption of a linear relationship
(black line) between DoP from tests in concrete and those in Berea sandstone does not hold true for
these deep-penetrating charges. The relationship may be asymptotic (red). Because of the difference
between historical and current penetration depths, small errors in the model can introduce a large
uncertainty in predicting DoP in rock samples (pink shading). (Adapted from Martin et al, reference 13.)
17
DoP = DoP in the producing formation.
In
DoP
DoPref
DoPref = DoP in a reference formation using F BI ref
at 10,000 psi.
αo = Exponential charge coefficient.
= αo F BI ref – F BI .
(
(
FBI = UCS + b × Peff .
FBI = Ballistic indicator function of producing
formation, psi.
Peff = Pc – a × Pp .
FBI ref = Ballistic indicator function in a reference
formation at 10,000 psi.
UCS = UCS of producing formation, psi.
a φ = 0.0967 × φ 0.428.
()
b=
Peff = Ballistic effective stress, psi.
0.7336 – 1.813 × 10 –5 × UCS, UCS < 30,000 psi.
3.33 × e –9.55 × 10 –5 × UCS, UCS >– 30,000 psi.
Pc = Confining stress, psi.
Pp = Pore pressure, psi.
a = Ballistic pore pressure coefficient.
b = Stress influence coefficient.
φ = Porosity, %.
35
αo = 8 × 10 –5
αo = 7 × 10 –5
αo = 6 × 10 –5
αo = 5 × 10 –5
αo = 4 × 10 –5
30
DoP, in.
25
20
15
10
5
0
0
5,000
10,000
15,000
20,000
FBI , psi
> Predicting DoP using the ballistic indicator function. After performing hundreds of sample test shots,
researchers at Schlumberger developed a realistic model for predicting DoP (top); the new model
includes data from modern deep-penetrating charges. This method includes a ballistic indicator
function (FBI ), which is computed from UCS and ballistic effective stress, Peff . The Peff is determined
from the confining stress, Pc, pore pressure, Pp, and a ballistic pore pressure coefficient, a. The
ballistic pore pressure coefficient is computed from porosity. The stress influence coefficient, b, is a
function of the UCS. The unitless exponential charge coefficient, α0, must be determined empirically
for each shaped charge. For the exponential charge coefficient, a fixed value of 8 × 10–5 (bottom, dark
blue) can be used, but an accurate choice of this parameter gives more representative predictions,
especially in weaker rocks. The various parameters are then incorporated in an equation that includes
two reference values, FBI ref and DoPref , which were determined from tests conducted in 69-MPa
[10,000-psi] UCS rock. Since the introduction of this model, engineers have validated the results with
thousands of tests. (Adapted from Harvey et al, reference 6.)
determined that performance of these charges
is more affected by in situ stress than were the
older generation charges. Researchers at SRC
concluded that the simplistic approach of
sequential corrections in prediction models produces misleading results for modern charges.
They also noted that effective stress has a
greater effect on DoP and perforation tunnel
geometry than previously believed, and modeling programs do not fully account for these
18
effects. Penetration performance downhole can
be overestimated by as much as 240% compared
with traditional model predictions.10
Stressed-Rock Penetration Correlation
Most modeling software applies rock-strength
effects on DoP predictions based on research
conducted in the early 1960s.11 These models
treat rock strength and downhole stress conditions separately without regard to how these
conditions interact with each other. Researchers
at that time developed a simple logarithmic formula that computes DoP from expected downhole UCS.12 The relationship is based on the
following assumptions:
• Penetration performance across multiple targets can be characterized from a measurement
in a single target.
• Charges cannot be optimized for a given target
strength.
• The correction for UCS is the same regardless
of rock type.
• The performance trends in unstressed targets such
as those in API RP 19B (or 43B) Section 1 tests will
be the same as those in stressed targets.
Tests of state-of-the-art perforating gun systems
have demonstrated that some of these assumptions result in discrepancies between actual performance and model results.13
To address these discrepancies, Schlumberger
researchers developed a new parameter—the
ballistic indicator function, FBI. This function
combines formation intrinsic properties (UCS
and porosity) and extrinsic properties (overburden stress and pore pressure) to more accurately
predict shot performance in downhole conditions
(left). The parameter was defined after researchers conducted more than 200 experiments using
four charge types and targets with UCS values
ranging from 11 to 110 MPa [1,600 to 16,000 psi].14
Based on the results of their experiments, the
researchers developed and introduced a new DoP
computation model. Previous models often used a
simple equation to determine downhole DoP.
Section 1 test results for DoP in concrete were
adjusted using only the difference between test
target UCS and the estimated downhole UCS. The
new model requires six parameters: two shaped
charge–specific parameters and four formation10. Harvey et al, reference 6.
11. Thompson GD: “Effects of Formation Compressive
Strength on Perforator Performance,” paper API-62-191,
presented at the Drilling and Production Practice
Conference, New York City, January 1, 1962.
12. Unconfined compressive strength, a measure of rock
strength, is the maximum uniaxial compressive stress
that a material can withstand under the condition of
no confining stress.
13. Martin A, Grove B, Harvey J, Zhan L and Atwood D:
“A New Direction for Predicting Perforating Gun
Performance,” paper MENAPS-11-12, presented at the
Middle East and North Africa Perforating Symposium,
Abu Dhabi, UAE, November 28–30, 2011.
14. Harvey J, Grove B and Zhan L: “Stressed Rock
Penetration Depth Correlation,” paper SPE 151846,
presented at the SPE International Symposium and
Exhibition on Formation Damage Control, Lafayette,
Louisiana, February 15–17, 2012.
15. Grove B, Harvey J and Zhan L: “Perforation
Cleanup by Means of Dynamic Underbalance: New
Understanding,” SPE Drilling & Completion 28, no. 1
(March 2013): 11–20.
16. For more on the perforation process, damage zones and
tunnel debris: Baxter et al, reference 3.
Oilfield Review
25
A
20
B
40
DoP, in.
15
35
C
10
D
Sandstone
Carbonate
30
DoP, in.
25
5
20
15
0
0
5,000
10,000
15,000
20,000
25,000
10
FBI, psi
5
Formation
DoP, in.
FBI , psi
UCS, psi
Pc, psi
Pp, psi
A
Castlegate
20.8
4,500
1,600
4,000
0
B
Berea
16.5
10,400
8,000
4,000
0
C
Nugget
9.0
17,800
16,000
4,000
0
D
Berea
8.5
19,800
8,000
20,000
0
0
0
5,000
10,000
15,000
20,000
25,000
30,000
FBI, psi
> Logarithmic response and rock-specific corrections. Penetration tests, conducted in sandstone cores of varying applied stress and UCS (bottom left),
indicate that the relationship between the FBI and DoP is logarithmic (top left). In addition, the plot of DoP versus FBI (right) indicates that performance is
rock dependent. Using the same type of charge, technicians performed tests in sandstone (blue diamonds) and carbonate (red squares) cores; curves fit
to the data—sandstone (blue) and carbonate (red)—indicate that the DoP in sandstone is greater than the DoP in carbonate. The difference in DoP is
more pronounced in weaker rocks. The SPAN Rock program includes corrections for both rock strength and type. These tests further validate the
ballistic indicator function model.
specific parameters (UCS, porosity, confining
pressure and pore pressure). A reference FBI was
chosen using a 69-MPa [10,000-psi] baseline,
which represents the center of the dataset.
Replacing one charge-specific parameter with
two means that engineers can optimize perforation designs for specific targets: for example,
hard versus soft formations. Following the introduction of the six-parameter model, hundreds of
additional tests have been conducted to confirm
the validity of the method (above). However, DoP
is only part of the overall picture of perforation
performance; researchers also looked at the flow
effectiveness of the perforation tunnels.15
Effective Perforations
Perforating opens holes in solid steel casing and
then creates perforation tunnels that are usually
filled with debris and lined with a layer of shockdamaged rock (below).16 The damaged rock and
debris impede fluid flow. The effects can be quantified in the term skin, which includes formation
Unrealistic Model
Assumed Condition
After Conventional Treatment
Conventional Perforating
Perforating debris
Uniform damage
Ineffective Flow
Likely Condition After Treatment
1 in.
Perforating debris
Nonuniform damage
> Tunnel cleanup following traditional perforating. Tunnels produced by traditional perforating techniques may be plugged
with flow-impeding debris (left). The walls of the tunnels are lined with damaged rock that may also act as an impediment
to flow (middle top). Methods for predicting flow effectiveness into the wellbore assume uniform flow from the formation
into the perforation tunnels (top right). Because the tunnels have nonuniform damage along the tunnel walls and varying
degrees of plugging (middle bottom), uniform flow is atypical, and in reality, flow into perforation tunnels using
conventional methods is restricted (bottom right). (Adapted from Grove et al, reference 15.)
Autumn 2014
19
Computed Productivity Ratios
PURE DUB Perforating, Effective Flow
1.2
1.0
Productivity ratio
0.8
0.6
Conventional Perforating, Ineffective Flow
0.4
0.2
0
Case A
Conventional perforating,
new model
Case B
Conventional perforating,
traditional model
Case C
PURE DUB perforating,
new model
> Improving productivity ratios with dynamic underbalance perforating. In
conventional perforating, even in underbalanced conditions, damaged rock
along the tunnel wall and debris may decrease the productivity ratio (PR)
substantially (left). Some perforation debris can be removed by flowing the
well, although the tunnels with the best flow characteristics will contribute
most of the flow, and plugged perforations may not flow at all. The total well
flow performance of three perforating scenarios illustrates the effects of
perforation damage and the application of the new flow model. Case A
shows a PR computed from the realistic treatment of a conventionally
perforated well analyzed using the new model. The model recognizes that in
the absence of PURE DUB perforating, inflow may be restricted to only a
small portion of each perforation tunnel. Case B shows the overly optimistic
PR computed with a conventional model of perforation damage. This model
damage caused by drilling, completion and perforation practices.17 Although DoP is often considered the most crucial component in production
efficiency, in practice, the condition and geometry
of the perforation tunnel have as much to do with
the effectiveness of perforating as does DoP.18
One conventional predictor of perforation
effectiveness is core flow efficiency (CFE), which
is the ratio of measured productivity to theoretical productivity of a laboratory-perforated core.
The CFE of an ideal undamaged perforation tunnel is 1.0; anything less than 1.0 indicates damage caused during perforating. A CFE greater
than 1.0 indicates stimulation.
A CFE computed from the ratio of measured
to theoretical productivity raises many questions
because of assumptions made in the method.19
Traditional CFE computation assumes 1D radial
flow into perforation tunnels with a constant tunnel diameter, which is not usually the case. The
models for predicting CFE also assume that the
crushed zone, the damaged rock along the tunnel
wall, is the only contributor to reduced flow,
20
assumes inflow restricted by a uniform crushed zone of reduced
permeability along the full length of each perforation tunnel. Case C shows
the PR computed for a well with PURE DUB perforations. Because all
perforations are clean and unrestricted to reservoir inflow, this method
maximizes inflow performance. Engineers have proved this by comparing
flow of fluorescent dye into the tunnel of a PURE DUB perforated core
sample (top right) with flow into the tunnel of a conventional perforation
core sample (bottom right). The fluorescent dye (light blue) enters along the
full length of the PURE DUB perforation tunnel. However, the dye flows only
into a small portion of the conventional tunnel because the majority of the
tunnel is plugged with debris and damaged rock. The benefit of PURE DUB
perforating is more accurately reflected by comparing Case C with Case A,
rather than with Case B.
ignoring perforation debris in the tunnels.20 In
addition, a permeability-impaired crushed zone
of constant thickness is assumed for the length of
the tunnel, although the thickness and permeability are known to vary along the length of the
tunnel. Another assumption used to develop the
CFE computation is that cleanup during flowback
can improve crushed zone permeability, which
may not be true for all perforation tunnels. One
last crucial assumption is that CFE is the ratio of
the damaged perforation tunnel productivity to
that of a theoretical undamaged tunnel; however,
undamaged perforation tunnel productivity may
be difficult to quantify.
Many wells are allowed to flow after they have
been perforated to remove damaged rock and perforation debris. One common method used by
operators to initiate flow immediately after perforating is static underbalanced perforating—an
operation in which the pressure in the wellbore
prior to punching holes in the casing is maintained below that of the formation pore pressure.
The effectiveness of perforation cleanup using
the static underbalanced technique depends on
individual perforation flow efficiency and the
effectiveness of flow from the reservoir into the
perforations. One problem with this method is
that the perforations with the best flow characteristics contribute the majority of the flow, and
those that would benefit the most from cleanup
remain debris filled and damaged.
An alternative to static underbalanced perforating is the PURE DUB perforating technique, a proven method of improving flow
efficiency of perforation tunnels as measured by
the productivity ratio of the well (above).21 The
technique removes damaged rock from the walls
of the perforation tunnels and flow-restricting
debris from the tunnels.22 In addition to improving well performance, PURE DUB perforating
offers operational and safety advantages; for
example, PURE DUB perforating can be
achieved even under conditions in which a well
cannot maintain a static underbalanced state
prior to perforating, such as when open perforations are present, or when static overbalance is
required for well control.
Oilfield Review
The concept of DUB perforating grew out of
studies performed at the SRC laboratory. The perforation cleanup process is controlled primarily
by formation properties and wellbore pressure
transients created by a gun system (below). For
cleanup, PURE DUB perforating is more effective
than flowing the well or perforating underbalanced. Recent research is shedding light on the
technique and has demonstrated that wells perforated with PURE DUB systems experience significant improvements in flow efficiency.
A feature of the SPAN Rock program is the
introduction of an updated flow model that overcomes limitations of the conventional CFE
method and more accurately predicts DUB perforating results. The model developed at the SRC
laboratory is based on multiple experiments,
incorporates realistic flow modeling and is consistent with the actual mechanisms of perforation cleanup.23
The processes involved in DUB perforating
are complex, although modeling software to
predict the effectiveness of a perforating system has been developed that accounts for well-
Dynamic Underbalance
bore pressure transients, formation properties
and inflow simulation.24 The workflow and
modeling are integral parts of the SPAN Rock
software program.
SPAN Rock Software
The SPAN Schlumberger perforating analysis
program was introduced in the 1980s. The program computed DoP from concrete target test
results and predicted perforation geometry for
any Schlumberger gun combination and charge
type in any casing size, including multiple casing strings. A productivity module was included
in the program to evaluate perforation effectiveness and efficiency. A graphic interface allowed
visual comparisons of the performance of various gun systems.
The SPAN software has undergone many
updates since its introduction. In the current version, the newly developed, stressed rock–based
penetration model replaces the original concrete-based model.25 The updated name of the
SPAN Rock program reflects this change. The
penetration model is not the only addition to the
Pressure, psi
Uniform Flow
PURE Dynamic Underbalance Perforating Results
6,000
software; several major functionality enhancements have been included.
The SPAN Rock program features the industry’s first DUB perforation cleanup model.26 The
model calculates perforation cleanup as a function of wellbore pressure dynamics and formation characteristics. Based on the current
published and peer-reviewed research, the new
model allows users to predict cleanup in either
the conventional “crushed zone” (kc/k) framework, or the newly published “effective flowing
length” (Lc/L) framework.27 The combination of
more-accurate models for both DoP and cleanup
translates to much more reliable predictions of
well performance.
Along with the perforation crushed zone
model described by the SPAN Rock software, new
algorithms have been developed to estimate the
effects of rock strength. These estimates compute productivity for both oil and gas wells. If
petrophysical logs are available to construct a
mechanical earth model, these data can be
imported directly into the software and used to
compute realistic penetration and production
Clean Tunnel
4,000
2,000
1 in.
0
0
2
4
Time, s
> PURE dynamic underbalance (DUB) perforating model. Dynamic underbalance perforating systems create transient pressure differentials (left) at the
perforation tunnel. The perforation debris and damaged rock along the tunnel surface have been swept from the tunnel (middle left). These fully cleaned
perforation tunnels provide effective flow along the length of the tunnel (middle right). Flow from the formation enters each perforation tunnel and then
flows into the wellbore (right), a situation that improves productivity compared with that from conventional techniques.
17. Skin is a term used in reservoir engineering theory to
describe the restriction to fluid flow in a geologic
formation or well. Positive skin values quantify flow
restriction, whereas negative skin values quantify flow
enhancements, typically created by artificial stimulation
operations such as acidizing and hydraulic fracturing.
18. Grove et al, reference 15.
19. Harvey J, Grove B, Walton I and Atwood D: “Flow
Measurements in the Perforation Laboratory:
Re-Thinking Core Flow Efficiency (CFE),” paper
IPS-10-015, presented at the International Perforating
Symposium, The Woodlands, Texas, USA, May 5–7, 2010.
Grove B, Harvey J, Zhan L and Atwood D: “An Improved
Technique for Interpreting Perforating-Flow-Laboratory
Results: Honoring Observed Cleanup Mechanisms,”
SPE Drilling & Completion 27, no. 2 (June 2012): 233–240.
20. The crushed zone refers to damaged rock along the
tunnel wall after perforating.
Autumn 2014
21. The productivity ratio is defined as the measured
productivity index of a well, which includes completion
and near-wellbore influences, divided by the theoretical
ideal productivity index of an openhole well. For more on
productivity ratio: Behrmann L, Brooks JE, Farrant S,
Fayard A, Venkitaraman A, Brown A, Michel C,
Noordermeer A, Smith P and Underdown D: “Perforating
Practices That Optimize Productivity,” Oilfield Review 12,
no. 1 (Spring 2000): 52–74.
22. For more on dynamic underbalance perforating:
Baxter et al, reference 3.
23. Grove et al, reference 15.
24. For more on the implementation of the modeling in the
SPAN Rock software: Zhan L, Doornbosch F, Martin A,
Harvey J and Grove B: “Perforated Completion
Optimization Using a New, Enhanced and Integrated
Perforating Job Design Tool,” paper SPE 151800,
presented at the SPE International Symposium and
Exhibition on Formation Damage Control, Lafayette,
Louisiana, February 15–17, 2012.
25. A concrete-based DoP model is an available option in
the software.
26. Harvey J, Grove B and Zhan L: “A Laboratory Correlation
for Dynamic Underbalance Core Flow Efficiency,“ paper
IPS-12-26, presented at the International Perforating
Symposium, The Woodlands, Texas, April 26–28, 2012.
27. The ratio of the permeability of the damaged layer (kd )
and the permeability of the undisturbed rock (k) is a
measure of flow impairment. Because DUB perforating
can remove the disturbed rock over a portion of the
tunnel, a new model for computing effective flow was
developed that is the ratio of the length of perforation
tunnel cleaned (Lc) and the total DoP (L).
21
Reservoir Properties
• Rock mechanical properties
• Stress condition
• Rock type
• Formation permeability
• Formation porosity
• Formation anisotropy
• Formation heterogeneity
• Formation fluid properties
(viscosity, reservoir
pressure, temperature
and others)
Near-Wellbore
Formation and Flow
Condition
• Drilling fluid invasion
and particle migration
(near-wellbore
formation damage
radius and severity)
• Near-wellbore fluid
flow condition
(laminar or
turbulent flow)
Well and Wellbore
Condition
• Wellbore geometry
• Tubing and cement
specifications
• Wellbore fluid properties
• Wellbore orientation
and deviation
• Wellbore fluid pressure
condition with respect to
reservoir fluid pressure
• Gravel packing
• Screen properties
Charge, Gun and
Toolstring System
• Charge type and size
• Gun type and size
• Charge loading pattern
(phasing and shot
density)
• Other tools in the string
• Toolstring setup condition
(centered or eccentered
and detailed geometries)
Data collection
New rock-based
penetration model
Transient wellbore
pressure prediction
simulator
Perforation depth, entrance
hole size and perforation
diameter estimation
Perforation depth, entrance hole
and initial perforation
diameter values
Perforation tunnel
condition
assessment
DUB properties, crushed zone
damage, tunnel fill, clean-tunnel
length and refined tunnel diameter
Well productivity
calculation and gun
performance evaluation
Productivity ratio, productivity
index, production rate, total skin
and all skin components and
sensitivity analysis results
Accurate perforation
skin model
Improved well
skin model
Change input data
or gun system
parameters?
Yes
No
Select optimal
gun system
> New workflow for gun and charge selection. The SPAN Rock software provides realistic predictions of shaped-charge
penetration using data from multiple sources. The new rock-based penetration model is the default output, although
traditional concrete-based penetration predictions can be performed. Engineers can also model gun systems that utilize
PURE DUB perforating techniques. Well productivity that reflects perforation tunnel conditions and skin are also available.
This workflow can be used iteratively to maximize perforating performance; the results are directly linked to performance
in stressed rocks.
predictions versus depth. The effects of gravel
packing, reservoir boundaries and partial completions can be included in the productivity
analysis (above).
22
Engineered Gun System Designs
One of the benefits of the SPAN Rock program is
that an engineer can optimize a perforating strategy by performing a sensitivity analysis simulating
different gun systems and perforating charges. In
an example well with relatively deep formation
damage, a PURE DUB design—Gun System 1—
used a 4 1/2-in. carrier loaded with deep-penetrating
charges at 5 shots per ft (spf). For the analysis,
1 out of 10 charges was replaced with a DUB
puncher charge, leading to an effective 4.5 spf
(next page). Puncher charges allow wellbore and
Oilfield Review
Shock, the Enemy
Most shaped-charge testing and characterization
focus on the performance of individual charges
with little regard to system dynamics. The transient interactions that occur during and just after
detonation are difficult to reproduce using surface testing systems; however, because of deeper
understanding of perforation shock physics and
advances in computational power, modeling software is now able to simulate gun shock loads.
These dynamic forces are sensitive to casing and
tubing geometry, gun hardware, shaped-charge
variations, perforating gun shot density and fluid
effects. By controlling the effects of gun shock,
operators can improve perforating performance
and avoid costly damage to downhole hardware.
During a typical casing gun operation, complex interactions occur in the wellbore and in the
gun system when perforating jets exit the gun
carrier. The wellbore hydrodynamics are affected
primarily by by three conditions: detonation gas
pressure inside the guns, wellbore fluid pressure
and formation pore pressure.29 Liquid wellbore
fluids typically have high density and low compressibility compared with the air initially inside
the gun system and gases generated during perforating. The pressure differential created between
the pressure inside the guns and the hydrostatic
wellbore pressure during detonation results in
Autumn 2014
Gun System 1
Parameter
Gun System 2
Gun System 3
4 1/2-in. HSD gun, DUB, Charge 1 4 1/2-in. HSD gun, no DUB, Charge 2 4 1/2-in. HSD gun, DUB, Charge 2
Gun type
Charge type
PowerJet Omega charge, HMX
DP, HMX
Standard charge (spf)
4.5
12
8
DUB puncher charge (spf)
0.5
0
0.5
Gun position
Eccentered
Eccentered
Eccentered
Explosive weight, g
38.8
22
22
API penetration, in.
59.2
34
34
1.2
1.20
1.1
1.18
Productivity ratio
Productivity ratio
formation fluids to rapidly enter the gun carrier,
which creates a dynamic underbalance condition.
The permeability of the formation was high, a
condition that can lead to non-Darcy skin effects
for low-spf gun systems.28 Gun System 2 was
loaded at 12 spf in a 4 1/2-in. carrier. This system
had the potential to overcome the non-Darcy skin
because of the increased flow area compared
with that of the 4.5-spf system. However, the
12-spf gun includes trade-offs: The DoP is reduced
because the gun must use smaller charges, and
the DUB perforating effects do not occur because
the gun included no DUB puncher charges.
After running the scenarios in the SPAN Rock
program, the design engineer quantifiably demonstrated that Gun System 1 delivered a substantially higher productivity than did Gun System 2.
A third gun system that used charges similar to
those in Gun System 2 but that was loaded at
8 spf was modeled; Gun System 3 included DUB
puncher charges. This gun system had a higher
shot density than that of Gun System 1 to reduce
non-Darcy skin, and DUB effects were generated
with the puncher charges. Because deep-penetrating PowerJet Omega charges in Gun System 1
penetrated beyond drilling-induced damage, Gun
System 1 still outperformed Gun System 3.
1.0
0.9
Gun System 1
Gun System 3
0.8
DP, HMX
1.16
1.14
Gun System 1
Gun System 3
1.12
0.7
1.10
0
4
8
12
16
20
Drilling damage zone, in.
0
0.2
0.4
0.6
0.8
1.0
Damage zone permeability impairment, kd /k
> Designing a perforating program. Engineers modeled three gun systems (top) to perforate a well, in
which the operator expected severe drilling-induced formation damage. It might seem that wells
perforated with higher shot density should produce more effectively than those perforated with lower
shot density because the inflow area of the open perforations is greater. However, a SPAN Rock model
indicated that a deep-penetrating (DP), high-temperature explosive (HMX), 4.5-spf PURE DUB Gun
System 1 (bottom left, blue) had a higher productivity ratio than a 12-spf non-DUB Gun System 2 (not
shown) and an 8-spf DUB Gun System 3 (red) because skin from deep drilling-induced damage has a
greater effect on Gun System 3 productivity than on that of Gun System 1. In addition, the DUB
perforating of Gun System 1 not only penetrates beyond the drilling-induced damage zone, it also
produces longer perforation tunnels with less damage zone thickness than does Gun System 3, as
indicated by the ratio of the perforation tunnel damage zone permeability (kd) and the permeability (k)
of undamaged rock. Consequently, Gun System 1 (bottom right, blue) delivers a higher productivity
ratio than does Gun System 3 (red) based on the comparison of perforation tunnel permeability
impairment.
transient pressure waves within the wellbore
fluid that propagate radially and axially up and
down the wellbore. These pressure waves travel
through the wellbore at the fluid’s speed of
sound, approximately 1,500 m/s [4,900 ft/s].
Predicting the hydrodynamic effects caused
by these pressure waves and the structural loads
they impose on gun systems, tubulars, downhole
hardware, cables (for wireline-conveyed systems)
and other well components requires knowledge
of gun system dynamics, wellbore dynamics and
reservoir pore pressure conditions. PURE planner software developed to predict and optimize
DUB perforating also enables engineers to evaluate gun-shock loads and structural dynamic
response on completion hardware.
The value of this modeling capability was
recently demonstrated in a tubing-conveyed perforating (TCP) operation that used a 7-in. HSD
high shot density perforating gun system. The
guns covered a 50-m [164-ft] net interval and
were loaded at 39 shots per m (spm) with deeppenetrating charges. Initial wellbore pressure
was expected to be 37.9 MPa [5,500 psi], and the
brine completion fluid density was 1,102 kg/m3
[9.2 lbm/galUS]. The expected reservoir pore
pressure was 44.8 MPa [6,500 psi]—6.9 MPa
[1,000 psi] higher than the wellbore pressure,
28. Darcy’s law assumes laminar flow. Non-Darcy skin
results from restricted fluid flow typically observed in
high-rate gas wells when the flow converging on the
wellbore attains high velocity and reaches turbulent
flow. Since most of the turbulent flow takes place near
the wellbore in producing formations, the effect of
non-Darcy flow is a rate-dependent skin effect.
29. Baumann C, Dutertre A, Khaira K, Williams H and
Mohamed HNH: “Risk Minimization when Perforating
with Automatic Gun Release Systems,” paper
SPE 156967, presented at the SPE Trinidad and Tobago
Energy Conference and Exhibition, Port of Spain,
Trinidad and Tobago, June 11–13, 2012.
23
F
A
Loaded
Packer
Unloaded
Gun 8
Gun length, 6 m
Gun 6
Gun 4
Gun 2
Tubing
Firing head
Gun 9
Gun 7
Gun 5
Gun 3
Automatic
gun release
Gun 1
Safety
spacer
HSD guns
Bullnose
C
Wellbore Pressure
D
Gun Movement
13,700
− 50
− 2.0
14,000
14,100
14,200
−1.4
−1.2
−1.0
− 0.8
− 0.6
14,300
20
− 40
−1.6
Force, 1,000 lbf
Displacement, in.
Measured depth, ft
−1.8
13,900
40
− 30
− 20
− 0.2
14,500
0
0.2
2,000
3,000
4,000
5,000
6,000
Pressure, psi
60
80
100
−10
120
− 0.4
14,400
Packer Annulus and Tubing
0
− 2.2
13,800
E
Tubing Axial Load
− 60
− 2.4
Force, 1,000 lbf
B
13,600
0
140
10
0
0.02
0.04
0.06
Time, s
0.08
0.10
160
0
0.02
0.04
0.06
Time, s
0.08
0.10
0
0.02
0.04
0.06
0.08
0.10
Time, s
> Initial perforating design. PURE planner software can predict dynamic effects such as forces on downhole hardware. The operator planned to perforate
a single interval (B, dashed lines) using nine guns; Gun 9 acted as a spacer with no charges, and approximately 1.5 m of Gun 8 was left unloaded (A). The
model indicates that upon charge detonation, this design would generate a series of pressure pulses over the first 0.10 s (B). The data, color coded based
on time from detonation, with dark blue starting at time zero and red ending at 0.10 s, indicate that the gun string would move upward 2.4 in. [6.1 cm] (C), the
tubing would be subjected to a 58,000-lbf [258-kN] axial load (D) and the packer and annulus would receive a maximum force of almost 160,000 lbf [712 kN] (E),
enough to damage the automatic gun release and probably unseat the packer (F).
thus creating a static underbalanced perforating condition. The distance from the top of the
gun to the packer was 35 m [115 ft], and the
distance to TD was about 182 m [597 ft] (above).
An automatic gun release was included in the
string to drop the guns to the bottom of the well
after perforating. Gun release allows immediate
access to the perforations below the packer
assembly for testing, flowback or production
24
through open tubing. The gun assembly is typically fished from the hole after the tubing is
retrieved; however, some operators use this
design to begin immediate production and leave
the spent guns in the well.
The initial gun design included nine 6-m
[20-ft] carriers; a 1.5-m [4.9-ft] portion of Gun 8
and all of Gun 9 were unloaded and acted as a
spacer. The other seven guns were fully loaded.
Detonation pressure waves inside the guns
travel at 6,100 m/s [20,000 ft/s]. In the wellbore,
the fluid pressure waves resulting from the detonation travel at 1,500 m/s [4,900 ft/s]. The velocity difference produces a pressure differential
between the bottom and top of the gun string.
The net effect is a large upward force, followed by
oscillations from stress waves transmitted and
reflected at each change in gun string cross-
Oilfield Review
A
Loaded
Unloaded
Gun length, 6 m
Gun 9
B
Gun 8
Gun 6
Gun 4
Gun 2
Gun 7
Gun 5
Gun 3
Gun 1
C
Wellbore Pressure
D
Gun Movement
13,600
0
13,700
0.5
E
Tubing Axial Load
Packer Annulus and Tubing
0
0
10
1.0
13,800
1
20
14,100
14,200
2.5
3.0
3.5
30
2
Force, 1,000 lbf
14,000
2.0
Force, 1,000 lbf
Displacement, in.
Measured depth, ft
1.5
13,900
3
4
40
50
60
70
4.0
14,300
80
5
4.5
14,400
90
5.0
14,500
6
100
5.5
3,000
4,000
5,000
6,000
Pressure, psi
0
0.02
0.04
0.06
Time, s
0.08
0.10
0
0.02
0.04
0.06
Time, s
0.08
0.10
0
0.02
0.04
0.06
0.08
0.10
Time, s
> Modified perforating program. In the original gun loading design, Gun 9 and the top 1.5 m of Gun 8 were not loaded. This design would have applied
a large upward force on the packer and the gun release. A slight change in the loading program produced much different results. In this scenario (A),
the lower 1.5 m of Gun 1 was left unloaded, Gun 8 was fully loaded and Gun 9 was left unloaded. The model predicts the pressure pulses that are
generated over the first 0.10 s (B), and each plot is color coded based on time from detonation. The gunstring moves downhole immediately after gun
detonation using this design (C) , the axial load on the tubing is greatly reduced (D) and the maximum force on the packer is 100,000 lbf (E), which is less
likely to damage the release mechanism or the packer.
sectional area. The model showed that upon detonation, this gun system would move upward
forcefully, potentially damaging the hardware
and negating the intended action of the gun dropping mechanism.
The engineers next modeled a gun system
with a fairly simple reconfiguration. Gun 1 was
partially loaded, leaving the bottom 1.5-m section unloaded, Gun 8 was fully loaded and Gun 9
Autumn 2014
remained unloaded (above). The load experienced by the gun release system in the original
configuration would have been around 258 kN
[58,000 lbf], which most likely would have damaged the equipment, even to the point of causing
failure to release. The second option subjected
the release mechanism to only 4.4 kN [1,000 lbf],
eliminating the damage potential. The original
design exposed the packer to a 712-kN [160,000-lbf]
upward force. The new configuration resulted in
a net downward force on the packer of 445 kN
[100,000 lbf], which was unlikely to unseat the
packer. The iterative process of modeling
dynamic forces showed operators how even simple changes affect gun system dynamics. The second gun system was successfully deployed with
no negative operational consequences.
25
Field A
Field B
160
120
110
Production, bbl/d
Production, bbl/d
150
140
130
120
100
90
80
110
100
70
PowerJet Nova average
Field average
> Production increase with PowerJet Nova charges. To achieve deep
penetration past drilling-induced damage, PEMEX traditionally perforated
with guns that used exposed shaped charges to maximize charge size. The
PowerJet Nova charges, deployed inside sealed casing gun carriers,
delivered increased production compared with traditional perforation
methods, even though they are physically smaller than charges used in
exposed guns. The average production from five wells in Field A increased
by 13% (left), and four wells in Field B improved by 23% (right) compared
with production achieved using previous gun systems.
Perforating Strategy
The concrete target characterization defined in
API RP 19B Section 1 was an attempt to simplify
decision making during perforation program
design, but it may actually confuse matters by
providing unrealistic expectations. Contrary to a
common perception, developing an optimal perforating strategy is often neither simple nor
straightforward. On many occasions, changing
perforation methodologies can result in significant production increases.
Petróleos Mexicanos (PEMEX) traditionally
perforated wells in two fields in southern
Mexico with exposed-charge expendable guns.
Exposed-charge guns often use larger and
deeper penetrating charges than those used in
hollow carrier casing guns, but they leave debris
from spent charges in the wellbore after shooting. Other operational concerns are vulnerability of exposed charges to damage during
deployment and limitations on the type of conveyance methods that may be used. Exposedcharge guns are usually run on wireline and are
rarely run in horizontal completions. Unlike
stiff, hollow carrier guns, pushing these types of
guns downhole is difficult because of the flexibility of the gun string. The benefits from deeper
penetration and the associated higher productivity ratio made possible by the larger exposed
charges must be weighed against debris, gun
vulnerability and operational concerns.
26
PowerJet Nova charges are designed for maximal penetration in stressed-rock conditions (see
“Optimizing Charges for Stressed Rocks,” page 28).
Modeling of charge performance under the
expected conditions predicted up to 30% DoP
increase compared with that from previous-generation shaped charges. This improved penetration
was achieved even though the PowerJet Nova
charges, which were first available only in hollow
carrier systems, were smaller than those used with
the exposed-carrier guns. PEMEX opted to test the
new charge and compare well performance with
that of existing wells in the fields.
The average production from five wells in
Field A perforated with the new charge was
157 bbl/d [24.9 m3/d], a 13% improvement over the
field average of 139 bbl/d [22.1 m3/d].30 Four wells in
Field B averaged 119 bbl/d [18.9 m3/d], a 23%
improvement over the 97-bbl/d [15.4-m3/d] average
from wells perforated with the exposed-charge perforation systems (above). Because PowerJet Nova
charges were able to penetrate beyond drillinginduced damage, the use of these charges helped
increase productivity. The selection of hollow carrier guns also improved efficiency, provided conveyance option alternatives and reduced risks
associated with exposed charges.
In another example, a North Sea operator producing from a high-pressure, high-temperature
(HPHT) condensate field sought an engineered
solution to improve well performance. From experience, the operator understood the reliability and
performance challenges related to high-temperature shaped-charge technologies. The operator’s
objective was to achieve maximal reservoir contact
in undamaged rock by penetrating beyond drillinginduced formation damage. Alternatives were
investigated to improve performance, which the
operator would quantify by comparing the productivity index (PI) of the engineered system with
that of previous methods.31
Because of the expected high reservoir pressure, the operator needed to maintain strict
safety requirements, which was made more difficult by the long perforation intervals and long
gun strings. The perforating design team collaborated with Schlumberger engineers to customize a solution to meet both productivity and
safety objectives.
The gun system design included charges that
were suitable for high-temperature operations and
maximized the probability that penetration would
extend beyond the damage zone. The client’s process included API RP 19B Section 4 testing to measure cleanup efficiency and determine damage
caused by wellbore fluids and Section 2 stressedrock testing to validate DoP predictions.
API RP 19B Section 4 tests were performed on
quarried Cretaceous-age Carbon Tan sandstone
core samples, whose properties are analogous to
those of the rock found in the deeper regions of the
reservoir. Tests, conducted under downhole stress
conditions, validated the PURE DUB predictions
from the SPAN Rock program that included
enhanced models for determining DUB effects and
tunnel cleanup. Section 4 tests demonstrated that
PURE DUB perforating could remove significant
portions of the damaged rock in the crushed zone
and deliver an associated high PI, even when the
perforation tests were conducted with drilling
mud in the wellbore. Tests with static underbalance without DUB conditions were significantly
30. Garcia RFM and Fayard AJ: “Nuevos desarrollos en
tecnología de disparos incrementan la seguridad y
producción—aplicaciones en la región sur,” presented at
the meeting of the Asociación de Ingenieros Petroleros
de México and Colegio de Ingenieros Petroleros de
México, Coatzacoalcos, Mexico, October 25, 2013.
31. Procyk AD, Burton RC, Atwood DC and Grove BM:
“Optimized Cased and Perforated Completion Designs
Through the Use of API RP-19B Laboratory Testing to
Maximize Well Productivity,” paper SPE 159920,
presented at the SPE Annual Technical Conference and
Exhibition, San Antonio, Texas, October 8–10, 2012.
32. Procyk et al, reference 31.
33. Huber KB and Pease JM: “Safe Perforating Unaffected
by Radio and Electric Power,” paper SPE 20635,
presented at the 65th SPE Annual Technical Conference
and Exhibition, New Orleans, September 23–26, 1990.
Oilfield Review
Autumn 2014
13,500
13,000
12,500
Downhole data
Wellbore pressure, psi
less effective in removing crushed zone damage,
and tests conducted in drilling mud in the wellbore yielded poor productivity.32 Following the
Section 4 testing, which confirmed the effectiveness of PURE DUB perforating at cleaning the perforations in the reservoir’s more challenging
zones, a series of Section 2 penetration tests was
conducted. The Section 2 experiments included
Early Mississippian-age Berea Buff sandstone,
which was analogous to the reservoir’s shallower—lower strength, higher porosity—regions.
Based on the test results, the team selected
HPHT PowerJet Nova charges, which had a penetration improvement of 25% compared with
previous-generation charges and resulted in a
50% increase in formation contact. The perforating string included pressure gauges to confirm
that predicted DUB conditions were actually
achieved by the design (right).
To minimize formation damage from solids in
the mud system, the wells were perforated in base
oil, which was similar to the mud system fluid
minus solids and weighting materials. Extensive
laboratory testing and results from completions in
offset wells influenced this decision. For the completion program, six wells with a combined total of
2,450 m [8,038 ft] were perforated. Analysis of production data indicates the HPHT PowerJet Nova
charges with PURE DUB perforating delivered
clean perforations and the fully engineered solution provided low-skin completions.
In addition to the engineered perforating and
completion program, another solution was implemented in the operating procedure. Retrieving
long TCP guns—the longest was 514 m [1,686 ft]—
usually necessitates killing the well, which may
allow fluids and solids from the kill fluids to flow
into newly opened perforations. This invasion
process can increase skin and lower PI. After
each interval was perforated, the completion
team expected 41.3-MPa [6,000-psi] surface pressure. Rather than kill the well, engineers successfully deployed a 5 1/8-in. ID CIRP completion
insertion and removal under pressure system; a
remotely activated 103.4-MPa [15,000-psi] gate
valve was installed above the tree. The crew was
able to retrieve the guns safely with the primary
pressure control—a downhole lubricator valve.
In the event surface pressure control was
required, the CIRP system could allow retrieval
of the guns without killing the well. The operations were performed without incident, the well
did not have to be killed and production performance was not needlessly compromised.
12,073 psi
12,000
11,500
11,000
10,500
Gun 72
Gun 59
Gun 46
Gun 33
10,000
9,500
Gun 20
Gun 1
Top gauge
Bottom gauge
9,000
0
0.5
1.0
1.5
2.0
2.5
Time, s
> PURE dynamic underbalance (DUB) perforating predictions versus
downhole performance. Perforating design engineers used PURE planner
software to predict DUB pressure for several PURE gun systems. The
estimated pressure drop is around 2,000 psi [13.8 MPa] below the predicted
reservoir pressure, which was measured at 12,073 psi [83.24 MPa] after
perforating. Because gauges cannot be located at the point of gun
detonation, PURE planner software simulates pressure responses at
locations above the gun string, as a top gauge (gray), and below the gun
string, as a bottom gauge (orange). Data from a high-speed downhole
pressure gauge placed above the gun string (black), indicated an
underbalance of approximately 2,000 psi after the guns fired, confirming the
drawdown predictions from the PURE planner software.
Safety is always a priority for operators and
service companies when personnel handle explosives, but innovations such as the CIRP system
improve both performance and safety. More
safety innovations have been developed recently
and are available for perforating operations.
Intrinsically Safe Perforating
A number of industries use blasting cap detonators
to initiate explosive devices. Only trained personnel are allowed to handle explosives, including
blasting caps, and specific procedures have been
developed to ensure safe operations. Blasting caps
use a small, sensitive primary explosive to detonate larger, less sensitive explosives.
The use of conventional blasting caps is precluded in situations that include the presence of
strong electromagnetic fields from radio-frequency (RF) transmissions, stray currents from
cathodic protection and welding, induced currents
from high-voltage power lines and lightning from
thunderstorms. Today, many operators rely on constant RF-based communications between the wellsite and the office, especially for offshore
operations, and are reluctant to shut off data
transmissions, even for the short time that guns
are being armed at the surface. This, along with
other considerations, led to the development of an
intrinsically safe detonator based on an exploding
foil initiator (EFI) principle—the S.A.F.E. slapperactuated firing equipment, which was introduced
in 1991.33 The device offers RF immunity along
with protection from stray and induced current.
Several iterations of the S.A.F.E. system have
been introduced; the first- and second-generation systems were replaced by Secure and
Secure2 electronic detonators—small drop-in
devices that substitute for conventional blasting
cap detonators. The most recent introduction,
the SafeJet perforating gun system, offers the
intrinsic safety of EFI devices with the flexibility
and scalability of traditional selective perforating
operations. The ASFS addressable-switch firing
system, which is part of the SafeJet system, is
suitable for selective perforating operations.
The perforating approach in many conventional reservoirs emphasizes high shot density,
deep penetration and zonal coverage. For production from formations that benefit from limited perforations, including unconventional
reservoirs that are hydraulically stimulated,
operators do not take this approach. Selective
perforating in these wells focuses on placing a
(continued on page 30)
27
Optimizing Charges for Stressed Rocks
The relationship between shaped-charge DoP
and rock strength is inversely proportional—
penetration in a weak rock is greater than
penetration of the same charge in a stronger
rock. Recent research has demonstrated that
charges optimized for weak, moderately
stressed rocks will not perform as well in
stronger, highly stressed rock.
It might seem that improving charge performance in one target would mean simultaneously improving performance for all other
targets, but this is not always the case. A
look at the underlying physics of shapedcharge penetration can help explain why.
A perforating shaped charge consists of
three primary parts: a small primer igniter,
a conical liner and a main explosive charge
(next page, top). The liner, which controls
the formation of the perforating jet, is typically made from a pressed blend of metal
powders. An outer case provides containment and confinement. In a loaded gun, the
primer region of each charge is in contact
with explosive detonator cord.
The systematic process of charge detonation and the resulting jet formation happen in
a few microseconds. Detonator cord is initiated, usually by some type of blasting cap,
which generates a detonation front that
passes each charge in a perforating gun. The
primer, which is in contact with the detonator
cord, is located at the back of each charge;
the primer detonates and causes the main
explosive of the shaped charge to detonate.
The pressure generated by this reaction
causes the liner to collapse inward onto the
charge centerline, and a jet forms with an
extremely high velocity, exceeding 7,000 m/s
[23,000 ft/s]. This forward moving jet of liner
material penetrates the gun, well fluids, casing, cement and formation (right).
As the detonation continues and the liner
collapses further, the jet continues to form but
with lower and lower velocities. The front of
the jet, or tip, may be traveling at 7,000 m/s
but the tail, the end of the jet, is typically traveling at 1,000 to 2,000 m/s [3,300 to 6,600 ft/s].
28
Time-Lapse Detonation and Penetration
Perforating gun
Detonator cord
Liner
Primer igniter
1 μs
Explosive
Detonation front
10 μs
Jet tip (7,000 m/s)
Jet tail (1,000 m/s)
30 μs
Jet tip pressure
(30 GPa)
50 μs
Tail particles
100 μs
> Perforator progression. To perforate a well, the engineer sends power downhole to set off a
ballistic detonator, which initiates a rapid chain of events. The detonator explodes and transfers
energy to the attached detonator cord that then propagates an explosive force through the gun to
each shaped charge. A primer igniter at the back of the shaped charge (top right) is in contact
with the detonator cord. The igniter detonates and initiates the main explosive in the charge. The
force of the explosion causes the conical liner to collapse upon itself, forming a jet whose tip is
traveling up to 7,000 m/s [23,000 ft/s]. The ultrahigh-velocity jet elongates as the liner continues to
collapse, and the pressure at the tip may exceed 30 GPa [4.4 million psi]. The tail of the jet travels
at 1,000 to 2,000 m/s [3,300 to 6,600 ft/s] or less. The velocity gradient is large enough that the tip
has expended its energy in the target by the time the tail forms (left).
The velocity gradient along the jet gives rise to
its length: A large spread between tip and tail
velocities creates a longer jet. Reactions during
this process happen so fast, and the differences
in velocity are great enough, that the tail is
still forming as the energy of the tip is being
consumed by whatever materials lie in front of
the jet during formation of the perforation
Oilfield Review
Liner
Detonating
cord
Liner powder
Main
explosive charge
Case
Primer
Primer
explosive
Loaded
charge
Main explosive
Conical liner
Case
Case
Gun body
Liner
powder
Casing
Liner variations
> Components of a shaped charge. A perforating shaped charge (left) is composed of a small
primer igniter, a conical liner and the main explosive charge. The parts are placed in a protective
case. Detonating cord runs the length of the gun and connects to each charge. The raw materials
used to manufacture shaped charges (top right) begin as powders. Liners (bottom right) are
usually formed from compressed powdered metal.
tunnel. It is the tremendous pressure created
by the hypervelocity jet that forms the perforation tunnel.
The impact pressure of the jet is proportional to the target density, jet density and jet
velocity squared. Impact pressures can exceed
30 GPa, which cause the material in front of
the jet to flow like a fluid, although the pressure does not necessarily melt the material.
Because the impact pressure is proportional
to the square of the velocity, in later stages of
penetration when the jet velocity rapidly
Charge redesigned to move wasted
energy to where it will be useful
Jet velocity
Jet energy wasted
on strong target
Threshold region for strong rocks
Threshold region for weak rocks
decreases, the impact pressure is significantly
reduced.
Jet length is a main factor in determining
DoP for a given target. The effective length of
the jet is the portion of the jet traveling fast
enough to create impact pressures sufficient
to extend the perforation farther into the target. A charge with a long jet and relatively
slow tail will be effective in perforating a weak
target. This jet will be less effective in a stronger target because the tail will create insufficient impact pressure to continue penetrating
and be essentially wasted energy. Therefore,
the tail portion of certain jets can be wasted
for strong targets.
A charge can be designed, however, that
relocates its energy in the early part of the
jet and more effectively penetrates a strong
target (below left). Because of energy constraints, this new design generates a shorter
jet than that of earlier designs; more of the
liner material has to be used in the early
stages, reducing what is available later in the
detonation for jet formation. Understanding
and applying the physics of perforating have
helped Schlumberger scientists and engineers design charges optimized for specific
targets. This short-jet design can be used to
manufacture a charge optimized for strong
targets; the long-jet design can be optimized
for weak targets.
A charge that will penetrate deeply into
stressed rocks requires a high-velocity, highdensity jet that is as long as possible but without wasted energy at the tail. This was the
methodology used by engineers to develop the
PowerJet Nova charge—a charge that has
been optimized for a broad range of real
reservoir conditions, including hard rocks.
Jet position
> Designing perforators for strong rocks. In weak rocks, the tip and tail of a
charge may have sufficient velocity to tunnel deeply into the rock once the
threshold of the rock strength is exceeded. For strong rocks, the initial
penetration threshold is high, and the tail energy may be insufficient to
overcome the rock strength; therefore, the tail energy is wasted. Charge
designers discovered that relocating energy closer to the tip region of the
charge, which is the basic concept of the PowerJet Nova charge, increases
DoP in hard rocks.
Autumn 2014
29
Gun 4
Type 1
switch
Gun 3
Type 2
switch
Type 1
switch
Gun 2
Gun 1
Diode
Detonator
Detonator
Detonator
Detonator
Switch
> Diode pressure switches. Multiple guns can be shot on a single run using traditional diode pressure
switches (top). The engineer fires Gun 1 with positive polarity direct current (DC); the Type 1 switch
connects the circuit to a reversed diode, which allows only negative polarity DC to pass. The engineer
then shoots Gun 2 using negative DC; the switch completes the circuit in the Type 2 switch, and Gun 3
can now be shot using positive DC. This process is repeated until all the guns are fired. Should any gun
fail to fire, or if the pressure-activated switch does not engage, subsequent firing cannot take place.
Using this type of switch is complicated by the number of wire connections (bottom, five pairs of wires)
that can be connected only at the wellsite. Confirming the switch connections prior to perforating is not
possible because sending current through an armed gun at the surface is not permitted.
few shots in clusters or widely spaced single
shots over long intervals. Perforation clusters are
commonly used in multistage hydraulic fracture
stimulations. The clusters may be geometrically
spaced or concentrated in zones identified as
having optimal reservoir and completion quality
characteristics.34 Only a few holes are necessary
in each cluster, and operators typically use multiple clusters for each stimulation stage.
Traditional selective perforating techniques
use multiple shaped-charge carriers that have
explosive detonators for each gun. The surface
units used for perforating send DC current to initiate the detonator and fire the gun. Guns are
fired sequentially in a daisy-chain fashion using
positive or negative polarity and diode switches
to control the polarity of current that can pass
(above). The diode switch is activated by pressure created in the carrier upon detonation.
Although pressure-activated diode switches have
proved reliable, should a switch fail to engage,
the next gun cannot be fired, and the remaining
unspent guns must be retrieved from the well.
30
A diode switch failing to engage is a real possibility in selective perforating because the limited
number of charges used for clusters, which may
be a single charge, may not generate the force
necessary to activate the switch.
SafeJet technology, which incorporates
intrinsically safe features introduced in S.A.F.E.
and Secure systems, includes a small ASFS
microprocessor-controlled addressable switch on
a circuit board for each detonator (next page).
Each switch has a unique address and is directly
accessed from the surface. The switches are connected using a single wire, which greatly simplifies assembly; this replaces the five wire
connections that must be made to properly connect traditional switches. Arming a 10-gun traditional system would require the engineer to make
50 connections, all of which must be completed
on location to comply with safety guidelines. The
single-wire connections of the SafeJet system
add efficiency while greatly reducing the chance
for human error.
To initiate detonation, the engineer at the
surface sends a command to an addressable
switch. Two-way communication between the
surface and the microprocessor is required to
proceed. Surface power is then directed to the
detonator with the specific address. Should a gun
or detonator fail to fire, the engineer can skip the
misfired gun and continue to the next carrier in
the string. This flexibility is not possible with traditional diode switches. In addition, the guns can
arrive at the field location loaded and ready for
deployment, which eliminates time-consuming
onsite arming procedures.
In a recent North Sea well, an operator
used the SafeJet system to perforate a 4,100-ft
[1,250-m] horizontal interval. The perforating
program called for two stages with 90 holes per
stage, totaling 180 single shots. The plan was to
perforate with a single shot every 23 ft [7 m]
along the horizontal section. A TuffTRAC Mono
cased hole services tractor conveyed the gun system in the horizontal well.
Oilfield Review
Carrier housing
Loading tube
Shaped charge
Addressable switch
and detonator
Detonator cord
Single-wire
connectivity
> Talking to perforating guns. The SafeJet system includes intrinsically safe detonators with
addressable switches (top right) that are connected by a single-wire system (bottom right). The
engineer fires each gun in sequence by sending commands to the addressable switch. Should a gun
fail to fire, the engineer can skip it and fire the next gun in line. The SafeJet detonators are immune to
induced current and cannot be set off by RF emissions. Prior to the job, technicians load shaped
charges and detonator cord into the loading tubes (middle) and insert them into the carrier housing
(top left). Up to 33 of these guns could be run in a single trip. Only one charge is shown loaded in the
approximately 0.3-m [1-ft] carrier, although longer housings are available to accommodate more
charges. Because this system uses no primary explosives, unlike traditional blasting caps, the guns
can be fully prepared at the operations base, shipped directly to the rig and connected on location.
The first 90-shot stage was limited by well trajectory and downhole conditions to 20 guns per
run and was perforated in five runs. The second
stage required only three gun runs because well
conditions allowed the combination of 33 guns
per descent. No field wiring was required, which
greatly improved wellsite efficiency. Service quality was enhanced because the loading system had
integrated electronics, switches and polarity that
did not have to be confirmed, dual conductor connections, field tester verification and built-in
redundancy. Each gun was assigned its own
address and the firing was controlled from the
surface. Of the 181 shots attempted, 180 fired.
System flexibility and redundancy allowed the
engineer to include backup guns in the string;
thus, all 180 depths from the original program
were covered during the perforating operation.
34. For more on optimizing completion design based on
reservoir characteristics: Glaser KS, Miller CK,
Johnson GM, Toelle B, Kleinberg RL, Miller P and
Pennington WD: “Seeking the Sweet Spot: Reservoir
and Completion Quality in Organic Shales,”
Oilfield Review 25, no. 4 (Winter 2013/2014): 16–29.
Autumn 2014
Testing Methodology Update Needed
Research clearly indicates that traditional
shaped-charge characterization tests of deeppenetrating charges produce unrealistic results.
Qualification testing in stressed-rock samples
more accurately represents downhole performance. Unfortunately, running tests on representative core samples using the many charge options
available can be prohibitively expensive for most
operators. However, predictive modeling software
developed by Schlumberger scientists includes
the ballistic indicator function, and this method
of DoP and performance prediction has proved to
more closely match results from rock samples in a
stressed state similar to downhole conditions.
Until all shaped-charge providers update predictive penetration modeling, results from surface testing and actual downhole results may
continue to show discrepancies. The ultimate
test for charge performance is production.
Drilling and completing deepwater prospects are
expensive. Effective perforating in unconventional rocks to ensure successful hydraulic stimu-
lations is essential. Because of these and other
factors, understanding what actually happens
downhole during perforation is more important
than ever.
Although the industry has been perforating
wells for more than 60 years, operators and service companies continue to improve perforating
methods and techniques. Regardless of charge
improvements and the accuracy of predictive
software, safety is of paramount importance. New
technologies like the SafeJet system enhance
safety while increasing operational efficiency.
The ultimate goal is to connect the reservoir to
the wellbore and produce hydrocarbons as efficiently, effectively and safely as possible. Recent
advances in perforating science are helping to do
exactly that.
—TS
31
Step Change in Well Testing Operations
In exploration and appraisal environments, one way to gather data for well
productivity and reservoir characterization is through well or drillstem testing.
The acquisition of downhole well test data has recently been enhanced by the
development of an acoustic wireless telemetry system that gives operators access
to these data in real time.
Amine Ennaifer
Palma Giordano
Stephane Vannuffelen
Clamart, France
Bengt Arne Nilssen
Houston, Texas, USA
Ifeanyi Nwagbogu
Lagos, Nigeria
Andy Sooklal
Carl Walden
Maersk Oil Angola AS
Luanda, Angola
Oilfield Review Autumn 2014: 26, no. 3.
Copyright © 2014 Schlumberger.
For help in preparation of this article, thanks to
Michelle Parker Fitzpatrick, Houston; and David Harrison,
Luanda, Angola.
CERTIS, CQG, InterACT, IRDV, Muzic, Quartet,
RT Certain, SCAR, Signature and StethoScope are
marks of Schlumberger.
1. Skin is a term used in reservoir engineering theory to
describe the restriction of fluid flow from a geologic
formation to a well. Positive skin values quantify flow
restriction, whereas negative skin values quantify flow
enhancements, typically created by artificial stimulation
operations such as acidizing and hydraulic fracturing.
2. Al-Nahdi AH, Gill HS, Kumar V, Sid I, Karunakaran P and
Azem W: “Innovative Positioning of Downhole Pressure
Gauges Close to Perforations in HPHT Slim Well
During a Drillstem Test,” paper OTC 25207, presented
at the Offshore Technology Conference, Houston,
May 5–8, 2014.
3. Kuchuk FJ, Onur M and Hollaender F: Pressure Transient
Formation and Well Testing: Convolution, Deconvolution
and Nonlinear Estimation. Amsterdam: Elsevier,
Developments in Petroleum Science 57, 2010.
32
By the time Edgar and Mordica Johnston performed the first commercial drillstem test in
1926, more than two dozen formation tester patents had been issued. Before the Johnston brothers introduced their innovative methods, if oil did
not flow to the surface, exploration wells were
tested through bailing—lowering a hollow tube
on a cable to capture a formation fluid sample—
after casing had been set and cemented above
the zone of interest. The brothers’ success led to
the creation of the Johnston Formation Testing
Company, which Schlumberger acquired in 1956.
Today, the most common drillstem tests
(DSTs) are temporary well completions through
which operators produce formation fluids while
the drilling unit is on location. During DSTs, formation fluids are typically produced through
drillpipe or tubing to a test separator or other
temporary surface processing facility, where the
fluids are metered, sampled and analyzed.
Drillstem tests focus on acquiring various
types of data. A descriptive test may concentrate
on acquiring downhole reservoir fluid samples
and pressure data from a shut-in well; a productivity test may focus on identifying maximum flow
rates or determining reservoir extent. In exploration and appraisal wells, the primary well test
objectives focus on well deliverability, skin,
fluid sampling, reservoir characteristics and
identification of reservoir extent and faults.1 In
development wells, the objectives are typically
linked to measurements of the average reservoir
pressure and skin and determination of reservoir
characteristics.
Well test operations comprise cycles of well
flow and shut-in while bottomhole pressures
(BHPs) are monitored. Reservoir engineers apply
these data to make early predictions about reservoir potential through a process known as
pressure transient analysis, in which the rate of
pressure change versus time during a shut-in
and drawdown cycle is plotted on a logarithmic
scale. The resulting plots indicate reservoir
response patterns that can be associated with
specific reservoir models using generalized type
curves; the curves help determine reservoir
characteristics such as skin, permeability and
half-length of induced fractures.
The shut-in mechanism must be as close as
possible to the point at which formation fluids
enter the wellbore to eliminate the influence of
wellbore storage on the downhole data. Wellbore
storage refers to the volume of fluid in the wellbore that may be compressed or expanded, or
to a moving fluid/gas interface as a result of a
production rate change. Wellbore storage may
exhibit complex behavior below the point of
shut-in, such as phase segregation, which can
hinder true reservoir response by mixing with or
masking reservoir pressure transients.2 A crucial
part of the pressure transient analysis is distinguishing between the effects of wellbore storage
and the interpretable reservoir response in the
early stages of the test.
At various points during the test, technicians
may capture representative samples of formation
fluids through the test string; fluid capture may
be performed using dedicated inline sample carriers equipped with trigger systems or by deploying through-tubing wireline-conveyed samplers.
The samples are then sent to a laboratory for
detailed PVT analysis in a process that may take
several months.
Oilfield Review
By deploying logging-while-drilling tools such
as the StethoScope formation pressure-whiledrilling service, engineers may ascertain initial
information about reservoir properties, formation
fluid types and producibility. This information is
often coupled with wireline log analysis and formation pressure and sampling data after the well
has been drilled through the section of interest.
In exploration and appraisal wells, these estimates may be associated with some uncertainty,
and the reservoir parameters can be confirmed
only by monitoring the reservoir under dynamic
conditions such as is done with DSTs.
Drillstem tests provide complementary data
for reservoir and formation fluid characterization
and for predicting the reservoir’s ability to produce. Of all the data that operators depend on to
design well completions, these data include the
least amount of uncertainty and the deepest
radius of investigation.3 The duration, producing
time and flow rate of a DST provide a deeper
investigation into a reservoir than do other reservoir evaluation techniques. As a consequence,
well testing provides the bulk of the information
engineers need to design well completions and
production facilities.
Although more efficient, reliable and robust,
the primary components of DST assemblies
today are similar to those deployed by the
Johnston Formation Testing Company in the
1930s. These components consist primarily of
four types of devices:
• packers to provide zonal isolation
• downhole valves to control fluid flow
• pressure recorders to facilitate analysis
• devices to capture representative samples.
Changes to test systems over time have been
confined mainly to the addition of auxiliary
components such as circulating valves, jars,
safety joints and other devices aimed at reducing the time required to recover from a stuck
testing string or to provide options for killing a
well. In recent years, service companies have
done much to reduce uncertainty and costs
associated with well testing while increasing
safety and efficiency. A significant step in this
progression includes the Quartet downhole reservoir testing system.
The Quartet testing tool allows operators to
perform the four essential functions of a DST
assembly—isolate, control, measure and sample—in a single run. The system includes the
CERTIS high-integrity reservoir test isolation system, the IRDV intelligent remote dual valve,
Signature quartz gauges and the SCAR inline
independent reservoir fluid sampling tool.
Autumn 2014
33
The CERTIS isolation system provides production-level isolation with single-trip retrievability. It includes a floating seal assembly to
compensate for tubing movement during well
testing and eliminates the need for slip joints and
drill collars (below). The IRDV dual valve is an
intelligent remotely operated tool that allows
operators independent control of the tester and
circulating valve via commands transmitted by
low-pressure annular pulses (below). Signature
gauges that have ceramic electronics boards
provide high-quality pressure and temperature
Circulating
valve (closed)
Stinger
Stinger release
Rupture disc
Hydraulic
setting mechanism
Test valve (open)
Ratchet lock
Seal element
Bypass
Slips
Release ring
Atmospheric
chamber
Sealbore
Stinger seal
Hydrostatic
chamber
Pressure sensor
+
+
+
-
Battery
Perforating guns
> Isolation system. The CERTIS system’s
hydraulic setting mechanism is activated by
applying pressure to a rupture disc; setting does
not require string rotation or mechanical
movement. To unset the system, an upward force
disengages the ratchet lock and shears the
retaining pins in the release ring, which allows
the slips to relax and release the system.
Continued pulling reopens the bypass, which
eliminates swabbing while pulling the packer out
of the hole. The stinger floats inside the sealbore,
which compensates for string movements
caused by temperature changes. The system
allows gauges to be positioned below it in the
test string. Tubing-conveyed perforating guns
can be suspended below the body.
34
>Remote dual valve. The IRDV intelligent remote
dual valve combines a test valve and a circulating
valve that may be cycled independently or in
sequence. The test valve, the primary barrier
during the well test buildup period, is activated
through wireless commands or low-pressure
pulses. Wireless commands facilitate the
independent operation of both valves without
interfering with the operation of other tools in the
test string. In the open position, the circulating
valve allows flow between the tubing and
annulus. Low-pressure pulses are detected by the
pressure sensor, and the electronics confirm the
received command by comparing it with those in
a library stored in the tool memory. The IRDV
valve may be configured to provide wireless
feedback, confirming command reception. The
activation of both valves is initiated by battery
power, which is augmented by a hydraulic fluid
circuit that discharges fluid from the atmospheric
chamber into the hydrostatic chamber when the
valve is operated.
measurements at the reservoir (next page, top
left).4 The SCAR inline independent reservoir
fluid sampling tool collects representative reservoir fluid samples from the flow stream (next
page, top right).
The accuracy of reservoir property analysis
and the degree of reservoir understanding are
heavily dependent on the quality of pressure
measurements acquired downhole; obtaining
accurate measurements hinges on metrology and
its parameters.
Cornerstone of Pressure Transient Analysis
Metrology is the science of measurements based
on physics. Technicians use the methods of
metrology to ascertain that sensors are properly
calibrated to specified or technical parameters
(next page, bottom). In the case of pressure gauge
metrology, static parameters include the following:
• Accuracy is the algebraic sum of all the errors
that influence the pressure measurement.
• Resolution is the minimum pressure change
that can be detected by the sensor and is equal
to the sum of sensor resolution, digitizer resolution and electronic noise induced by the amplification chain. Therefore, when determining
gauge resolution, engineers must consider the
associated electronics and specific sampling
time. The resolution of the interpreted range
of investigation, or transient drainage radius,
depends on the resolution of the gauge. Gauge
metrology could impact important decisions
operators make in evaluating reservoir size
and extent, which is a key objective of well
testing interpretation.5
• Stability is the ability of a sensor to retain its
performance characteristics for a relatively
long period of time and is the sensor mean drift
in psi/d at a specified pressure and temperature. The levels of stability include short-term
stability for the first day of a test, medium-term
stability for the following six days and longterm stability for a minimum of one month.
• Sensitivity—the ratio of the transducer output
variation induced by a change of pressure to that
change of pressure—is the slope of the transducer output curve plotted versus pressure.
Dynamic parameters include the following:
• Transient response during pressure changes
is the sensor response recorded before and
after a pressure variation while the temperature is kept constant.
• Transient response during temperature
changes is the sensor response monitored under
dynamic temperature conditions while the
applied pressure is kept constant. This param-
Oilfield Review
Battery
Rupture disc
trigger
Buffer fluid
Single-phase
reservoir
sampler
Pressure
compensation
fluid
Reservoir
fluid
Pressure
compensation
fluid
Electronics
Sensor
> The Signature quartz gauge. The Signature
gauge consists of a sensor, electronics section
and battery. The sensor includes a multichip
ceramic module (not shown).
eter provides the stabilization time required
for a reliable pressure measurement for a given
temperature variation.
• Dynamic response during pressure and temperature changes is the sensor response
recorded before and after a change in both
pressure and temperature.
Pressure data help engineers develop information about the size and shape of the reservoir
Nitrogen
> Downhole fluid sampler. The SCAR inline independent reservoir fluid
sampling tool (left ) captures representative, contaminant-free, single-phase
fluid samples directly from the flow stream close to the reservoir. The tool
houses the single-phase reservoir sampler (right ). Using a rupture disc
triggering mechanism, initiated by applied annular pressure or through
wireless command, the sampler can be activated to open a flow channel to
capture a sample. The single-phase reservoir sampler has an independent
nitrogen charge to ensure each sample remains at or above reservoir
pressure. When the triggering mechanism is activated, reservoir fluid is
channeled to fill a sample chamber bounded by pressure compensation fluid.
The compensation assembly comprises the nitrogen precharge, pressure
compensation fluid and buffer fluid, which ensure that the sample chamber
slowly provides enough volume to capture the reservoir fluid without altering
its properties.
and its ability to produce fluids. Pressure transient analysis is the process engineers use to
convert these data to useful information. During
this process, they analyze pressure changes over
time, particularly those changes that are associated with small variations in fluid volume.
During a typical well test, a limited amount of
fluid is allowed to flow from the formation while
the pressure measurement at the sandface is
acquired along with downhole and surface flow
rate measurements. After the production period,
the well is shut in while downhole pressure data
acquisition continues during the buildup.
Gauge Metrology Parameters
Static
Accuracy
Resolution
Stability
4. For more on Signature gauges: Avant C, Daungkaew S,
Behera BK, Danpanich S, Laprabang W, De Santo I,
Heath G, Osman K, Khan ZA, Russell J, Sims P, Slapal M
and Tevis C: “Testing the Limits in Extreme Well
Conditions,” Oilfield Review 24, no. 3 (Autumn 2012): 4–19.
5. Kuchuk FJ: “Radius of Investigation for Reserve
Estimation from Pressure Transient Well Tests,” paper
SPE 120515, presented at the SPE Middle East Oil and
Gas Show and Conference, Bahrain, March 15–18, 2009.
Autumn 2014
Sensitivity
Dynamic
Transient response during pressure changes
Transient response during temperature changes
Dynamic response during simultaneous pressure and temperature changes
> Gauge metrology parameters.
35
Pressure, psi
0.04
0.03
0.02
0.01
0
0
10
20
30
40
50
60
70
80
90
100
110
120
Time, s
Pressure, psi
10,000
1,000
0
0.0001
0.001
0.01
0.1
1
10
100
1
10
100
Time, h
100
Pressure, psi
10
1
0.1
0.01
0.001
0.0001
0.001
0.01
0.1
Time, h
>The impact of high resolution on data quality. Analysts can use high-resolution
measurements (top ) acquired using a Signature gauge to deliver a clear
interpretation of the pressure data. High-quality pressure data (middle, green)
result in a pressure derivative curve (red) that is easily discernable and
from which reservoir engineers can identify various pressure regimes
during buildup. A low-resolution measurement (bottom) may deliver an
uninterpretable dataset.
The downhole gauges that capture the reservoir response during the well test must be highly
accurate, but high accuracy is difficult to achieve
because of the complex wellbore environment.
During well tests, fluid dynamics and thermal and
mechanical string effects impact tool response.
The technology used to capture pressure data
has evolved considerably over time. In the 1930s,
operators deployed mechanical gauges, which
provided resolution of about 35 kPa [5.1 psi].
36
These gauges operated by recording the displacement of a pressure sensing element on a sensitive
surface, which was rotated by a mechanical
clock, thus providing a pressure versus time measurement. The data were digitized manually from
the pressure-time chart.
Following improvements in electronics design
and reliability led by the Hewlett-Packard
Company, electronic gauges were introduced to
the oil industry in the 1970s. Development of stable electronic gauges with higher levels of accu-
racy progressed rapidly, and by the turn of the
century, two main types dominated the industry.
Strain gauges were the first electronic gauges
used widely in the oil industry. They operated on
the principle of a resistance circuit placed on a
pressure sensitive diaphragm. The change in
length of the diaphragm in response to pressure
altered the balance of a Wheatstone bridge circuit. These strain gauges were capable of 0.7-kPa
[0.1-psi] resolution, which may not be sufficient
to resolve reservoir properties.
Vibrating quartz pressure sensors, developed
in the 1970s, signaled a significant shift in the
quality of downhole measurements in terms of
metrology. Because of their superior metrological
characteristics, quartz gauges have become the
standard for downhole pressure and temperature
acquisition although their accuracy may be
affected by sudden changes in downhole temperature and pressure. Quartz sensors use the piezoelectric effect to measure the strain caused by
pressure imposed upon the sensing mechanism.
The frequency of vibration in relation to pressure
changes is measured and converted to digital
pressure measurements. The high frequencies of
quartz sensors enable measurement of highresolution pressure changes and rapid sensor
response. Typical resolution of quartz gauges is
0.07 kPa [0.01 psi]. Today, the Schlumberger
Signature CQG gauge, using a proprietary compensated quartz gauge—the CQG crystal—is
able to distinguish pressure measurements as
small as 0.021 kPa [0.003 psi] (left).
Signature gauges may be deployed in reservoir tests at temperatures up to 210°C [410°F]
and pressures reaching 200 MPa [29,000 psi].
They may be deployed in real-time or memory
mode as part of the test string and are contained
within gauge carrier mandrels able to hold up to
four gauges each. Numerous carriers can be
placed in the test string above and below the
CERTIS isolation system.
The challenge of downhole measurements is
not limited to the harshness of ambient conditions; three major sources of uncertainty affect
downhole pressure measurements during well
testing. Uncertainties in gauge resolution and
accuracy, which are typically characterized as
functions of the magnitude of pressure and temperature changes downhole, may introduce
errors. In addition, uncertainty in the condition
of the environment may induce error.6 For example, during the test flowing period, a gas bubble
close to the gauge may burst and create high-frequency noise that is of the same order of magnitude as the gauge accuracy and several times
larger than the gauge resolution. If the pressure
Oilfield Review
Flowhead
Type of Test
Test Objectives
Acquired Data
Descriptive
Well characteristics
Bottomhole pressure and temperature
Reservoir characteristics (average reservoir
pressure, permeability thickness, storativity ratio
and interporosity flow coefficient)
Surface flow rate
Surface PC
Reeler
Communication between wells and reservoirs
(interference and multizone tests)
Interface box
Productivity
1
Hanger
Seabed
2
3
Reservoir extent and drive mechanism
Bottomhole pressure and temperature
Inflow performance ratio (combined well and reservoir)
Surface flow rate
> Types of well tests, test objectives and acquired data. Two types of tests—descriptive and
productivity—provide a variety of downhole data. Descriptive tests seek information about well and
reservoir characteristics, whereas engineers typically use productivity tests to understand the
producing capacity, extent and drive mechanism of a reservoir. Both types require bottomhole
pressure, bottomhole temperature and surface flow rates. Sequence and duration of individual flow
periods differentiate the test types.
4
5
6
7
Tubing
8
9
Repeaters
10
11
12
13
14
15
16
Gauge carrier,
Muzic wireless
system with
Signature gauges
17
18
IRDV valve
SCAR sampler
CERTIS
isolation system
19
20
21
Gauge carrier,
Muzic wireless
system with
Signature gauges
> A downhole reservoir testing system enabled
by Muzic wireless telemetry. A network of
acoustic repeaters, attached to the tubing using
a system of clamps, enables remote interrogation
of downhole gauges or tools with feedback via
computer terminal at the rig. Two repeaters
installed in each numbered node supply
horizontal redundancy; one repeater is always on
standby. Vertical redundancy is provided by
repeaters able to communicate across twice the
normal spacing between repeaters, which is
usually 305 m [1,000 ft].
Autumn 2014
changes quickly, and the sampling rate is relatively slow when this occurs, separating high-frequency noise from measurements is difficult. A
similar situation arises if phase segregation of
small quantities of water and gas in the well effluent occurs.
With the introduction of quartz gauges, the
parameters of pressure gauge metrology were
improved significantly. However, experts recognized that the value of well tests was often
impacted by the fact that data were inaccessible
until after the tests were complete. To address
this shortcoming, they developed a system that
allows operators to monitor the progress of a well
test as the test proceeds by delivering the downhole pressure and temperature data to the surface in real time. With insights provided by these
data, coupled with real-time downhole control,
operators would then be able to alter ongoing
tests to meet their objectives.
Real-Time Data, Real-Time Decisions
To reduce the uncertainty associated with some
well and reservoir parameters, engineers typically begin a well test design by defining the
objectives of the test (above). The acquisition of
wireless real-time bottomhole pressure and temperature data gives operators the ability to manage both the well and reservoir uncertainties,
make adjustments during the test and exercise a
measure of control over operational and cost
challenges associated with traditional DSTs.
The sequence and duration of well test operations are based on initial data obtained from various sources, including petrophysical logs and
core analysis. Historically, well tests are based on
a design-execute-evaluate cycle, in which technicians design and execute the tests to acquire
downhole data for evaluation and capture fluid
samples for laboratory analysis.
Downhole data are most frequently acquired
using electronic gauges in memory mode, which
do not provide operators with real-time feedback
to validate pretest assumptions, to verify that
objectives are being achieved or to modify the
tests during execution. As a consequence, technicians typically execute the well test program
regardless of reservoir response. This can result
in unnecessary steps, prolonged tests, missed
opportunities and even damage to the reservoir.
That the pretest assumptions are wrong or the
test is failing to meet objectives is often realized
only after the test has been concluded and the
memory data have been analyzed.
The industry has made attempts to correct
this shortcoming by using surface readout (SRO)
systems. These SRO systems deploy electric line
tools to recover downhole data from electronic
memory gauges that are run as part of the DST
toolstring. The data download is typically performed toward the end of the test, which limits
any modification of the operation to managing
the remainder of the well test operation and does
little to improve the overall operational sequence.
The practice of deploying electric line tools
has become increasingly unpopular with operators in expensive deepwater projects. Operators
are concerned that the electric line cable may
become snagged or part when it crosses valves.
The efficiency of managing well test operations
through electric line data acquisition is also limited because it is typically performed only during
nonflowing periods; electric line toolstrings are
at risk of being forced up the hole when the well
is flowing.
To address these limitations, Schlumberger
engineers developed the Muzic downhole wireless system (left). The Muzic system is designed
6. Onur M and Kuchuk FJ: “Nonlinear Regression Analysis
of Well-Test Pressure Data with Uncertain Variance,”
paper SPE 62918, presented at the SPE Annual Technical
Conference and Exhibition, Dallas, October 1–4, 2000.
37
S
R
R
R
R
R
R
R
R
R
R
Clamp
R
R
Acoustic message
R
R
Piezoelectric
transducer
E
E
E
Production
tubing
E
E
R
R
R
R
R
R
R
R
S Surface repeater
R Repeater
E
E
E
E
End node
Bidirectional
acoustic message
E
>Network architecture of the Muzic wireless system. The Muzic wireless
network is based on acoustic clamp-on style repeaters (left ) attached to
tubing. The transducer generates an acoustic signal (red) encoded with digital
information. Bidirectional acoustic energy travels the length of the pipe and
is transmitted from each repeater to adjacent repeaters until the signal
reaches the user at the surface. With such a series of repeaters, a network
architecture (right ) can be established in which transmitting nodes (R) send
and receive information from transmitting hubs and sensing or actuating
end nodes (E). End nodes are points of interest for the surface user and
include sensors to acquire measurements or actuators to control devices.
Memory
Real time
Pressure and pressure derivative
Pressure
Pressure
derivative
Time
>Comparing Signature gauge real-time data with memory data. Pressure data
obtained by a Signature quartz gauge and transmitted wirelessly in real time are
a nearly perfect match with data downloaded from memory during a pressure
transient well test offshore Indonesia for Total E&P. The quartz gauges
transmitted real-time bottomhole pressure and temperature data to the surface
without interruption for almost seven days. These data allowed pressure
transient analysis to be performed in real time and facilitated the validation of
the ongoing well test operations versus the Total E&P Indonesia test objectives.
38
to be embedded into the Quartet DST string. The
system interfaces with the Quartet reservoir testing system to facilitate interactive well testing
operations in which the operator has direct
access to downhole data in real time and is able
to control downhole tools through wireless commands. The distributed digital wireless telemetry
system uses an acoustic wave generated in the
test string to transmit information.
The acoustic network is composed of a series of
tools clamped on the outside of downhole test tubing (left). Each tool acts as a repeater and can
transmit or receive an acoustic signal as well as
allow control of downhole tools through wireless
commands. By initiating real-time changes to the
proposed testing program, operators can derive
the maximum value from each testing operation.
Digital data are relayed from one repeater to
the next in either direction on their way to their
final destination. In the bottomhole assembly,
the network interfaces either with downhole
pressure gauges for data acquisition or with
downhole tester tools (tester valve, circulating
valve and sampler) to issue commands and verify
tool status. This interactive platform also opens
the possibility to expand the scope of reservoir
testing to access previously inaccessible parts of
the well for instrumentation and tool control.
The signal processing techniques used for
downhole digital data transmission are similar to
methods employed in other wireless communications. However, successful wireless transmission
is affected by many things, including pipe or tubing effects, ambient noise and electronics and
battery limitations.
For acoustic propagation, tubing is a complex
medium; its effectiveness in propagating acoustic
waves is hampered by noise, attenuation and distortion. For example, each time an acoustic wave
goes through a tubing connection, it generates an
echo. The series of echoes generated by crossing
multiple joints are canceled by advanced signal
processing techniques to achieve point-to-point
communication. In addition, because the wireless
telemetry system relies on acoustic propagation,
any increase in ambient noise conditions downhole can adversely impact transmission.
Additional engineering challenges arise from
the low-power electronics required for long duration battery operation. This low-power requirement limits the choice of downhole processors
and impacts the available processing power. To
address these challenges, a specific network protocol was developed that manages and optimizes
communication through a repeater network.
Oilfield Review
8,000
2
Memory gauge
Real-time pressure
7,000
6,000
Pressure, psi
The Muzic system makes possible a new workflow for real-time testing operations. A decision
tree within this workflow includes risk assessment, test planning, data validation, quality
assurance and quicklook validation of data during the execution phase. This process allows realtime decisions and adjustments to the testing
plan while the test is underway.
5,000
4,000
1
3,000
4
5
3
4
3
2,000
Autumn 2014
1,000
0
Rate, bbl/d
A Real-Time Interpretation Workflow
In traditional well testing operations, engineers
design, prepare and execute the test and interpret the acquired data in sequence. In this “postmortem” approach to reservoir characterization,
insight obtained during data analysis does not
impact the original design or execution phases,
and the interpretation usually takes place after
operations are concluded.
The availability of downhole data and tool status information in real time from technologies
such as Muzic wireless telemetry represents a
significant shift from the sequential approach.
Feedback from the reservoir is immediate and
available during the execution phase, allowing
the operator to modify the test sequence and
operation while the test string is still in the well.
Real-time information about the condition of the
wellbore and status of downhole tools considerably impacts operational efficiency and gives the
operator confidence in the validity of the measurements (above right).
Introduction of real-time monitoring into the
standard well test workflow reduces overall costs
and rig time because the process is driven by
actual reservoir responses and not by generally
accepted practices and estimates (right). Any
erroneous operational steps can be immediately
identified and remedied, eliminating uncertainties and the costs of repeat operations as a result
of inconclusive operational data.
Total E&P planned an exploration test of a 45°
deviated well offshore East Kalimantan, Indonesia.
The target zone was at 3,200 m [10,500 ft] MD with
a bottomhole pressure of 25,000 kPa [3,600 psi]
and a bottomhole temperature of 118°C [244°F].
The operator’s test objectives were to analyze
the downhole pressure transient data and obtain
initial estimates of key reservoir properties such
as pressure, skin, permeability thickness and
boundaries. A solution was designed around
Muzic wireless telemetry interfacing with highresolution Signature pressure gauges. The gauges,
which proved to provide data that matched nearly
perfectly with data gathered using memory
gauges, transmitted downhole pressure and temperature for almost seven days (previous page,
bottom). This continuous flow of data allowed
2,500
1,250
0
0
1
2
5
6
7
8
9
Time, d
> A real-time dataset overlaid on a memory dataset. In this example, data captured in memory mode
(green) and real-time data (red) track perfectly. Data captured in memory mode can be accessed only
when they are downloaded after the test is ended. Wireless-enabled reservoir testing, however, allows
operators to observe pressures in real time and make decisions accordingly. Information that operators
may derive from real-time test data and use to make decisions include tubing conditions while running
in the hole (1), underbalance before perforation (2), connectivity after perforation (3), progress of
cleanup and flowing periods (4) and buildup (5, blue shading). The flow rate (blue curve) is visible in
real time throughout the test. Real-time measurements ceased when the operator began to pull out of
the hole after almost seven days.
engineers to optimize flow and maintain reservoir
conditions below depletion during testing. The
reservoir engineer was also able to perform realtime interpretations of pressure transient data
and thus validate that test objectives were being
1
Geologic model
met. Because the engineers were able to determine the test objectives had been achieved as the
test was proceeding, they could shorten the flowing period without fear of losing valuable pressure
transient data.
Final interpretation and
validation model, verification
and uncertainty
Operation and
data acquisition
2
Hardware
selection
4
6
3
Test design
5
Real-time wellsite or remote-site interpretation
> A workflow for integrating the test design, execution and interpretation sequence in real time. Muzic
wireless telemetry and InterACT collaboration software enable real-time interpretation and analysis for
use in updating the geologic model and refining the transient analysis and eventual final reservoir
model. The integration process includes information from the geologic model (1) used in test equipment
selection (2) and test design (3). Because real-time bottomhole data are available during the test (4),
the test results are continuously compared with the initial design expectation, and this output (5) helps
in refining the final interpretation (6). This process continues iteratively for each flow period and results
in a model with least uncertainty for the reservoir engineer. (Adapted from Kuchuk et al, reference 3.)
39
First
flow
Cleanup
0
1
2
First
buildup
3
Choke size
Second
buildup
Second flow
4
Production
logging
tool
rigup
5
6
7
Choke size
Productivity index
Real-time productivity index
Third flow
8
9
Time, d
> Real-time productivity index mapping during well testing. Using the Muzic system, the operator
tracked the productivity index during flow on several choke sizes.
Memory annulus pressure
Real-time bottomhole temperature
Memory bottomhole temperature
BHP
Real-time bottomhole pressure
Memory bottomhole pressure
Real-time annulus pressure
Time
Tubing-conveyed perforating (TCP)
gun detonation
Main pressure transient test
> Obtaining critical data in real time. The overlap of real-time and memory data
demonstrates the accuracy of real-time data and their capability to provide
sufficient insight into operational events, even though the real-time data
sampling is less dense than memory mode sampling. An inset from a separate
test shows TCP gun detonation data (left ); the sharp decrease followed by a
sharp increase in pressure confirms in real time the postperforation flow of
reservoir fluid into the wellbore. An inset from a separate test showing
pressure response during the main pressure transient test (right )
demonstrates that the volume of data captured is adequate for detailed
analysis, such as productivity index determination and pressure transient
analysis, during flow and buildup periods.
40
10
Petrobras engineers working in a presalt environment in the Santos basin offshore Brazil
sought to obtain real-time data at the surface
during a deepwater well test and to eliminate the
wireline run typically required to acquire such
data. Schlumberger and Petrobras engineers
chose to deploy wireless-enabled Signature
gauges in the well, which is in 2,000 m [6,600 ft]
of water 250 km [155 mi] off the coast of Brazil.
The Muzic wireless telemetry system and pressure and temperature gauges enabled for wireless communication were run in the well. This
configuration permitted engineers to receive
data during flow and shut-in periods, to monitor
cleanup efficiency in real time and to obtain key
reservoir information before the end of the test
(left). As a consequence, reservoir engineers
were able to observe the pressure transient after
perforation gun detonation to confirm dynamic
underbalance.
Petrobras and Schlumberger engineers were
also able to confirm downhole valve status, compute productivity as the well was flowing, confirm
that sufficient data were acquired during the initial and main buildup periods, eliminate a wireline run and establish the reservoir pressure
after the initial postperforating flow period
(below left).
A common challenge in well test operations is
managing the duration of the buildup period. Test
operators often calculate a buildup period as an
integer multiple of the flowing period duration.
By accessing the actual downhole pressure
response in real time during the buildup period,
engineers are able to determine that the desired
reservoir response has been achieved and validated sooner than would be the case using the
multiple, thus saving the operator hours of rig
time. Conversely, if the reservoir response objective has not been met, the test can be extended.
The overall efficiency of the operation is
improved because downhole tool status can be
verified at each step of the program. Important
decisions about the progress of the test can be
made with clear understanding of the reservoir
response from downhole pressure conditions,
which makes the overall operation safer. Using
wireless tool activation also takes less time and
requires fewer operational steps than do traditional pressure activation methods. Real-time
data are important for characterizing the reservoir with the least possible uncertainty. The
Muzic system enables remote interpretation
through data sharing and collaboration software.
Based on a geologic model, the well test is
designed and gauges and DST tools are selected to
meet certain operational and acquisition criteria.
Oilfield Review
Plan
Pressure
Initial
flow
Sampling
flow
Initial
buildup
Second
buildup
Main flow
Main buildup
Rate
Cleanup
0
1
2
3
4
5
Time, d
Actual
Sampling
flow
Pressure
28 hours saved
Initial
flow
Initial
buildup
Second
buildup
Main flow
Main buildup
Rate
Cleanup
0
1
2
3
4
5
Time, d
Flow Period
Initial flow
Initial buildup
Cleanup flow
Second buildup
Main flow
Main buildup
Sampling flow
Total
Plan, h
0.5
2
12
12
24
48
8
106.5
Actual, h
0.5
2.4
9.9
10.5
21.7
22.7
10.8
78.5
> Real-time decision making. A well test, as planned, would have taken nearly five days (top). Using
the wireless-enabled downhole reservoir testing system, engineers at Maersk Oil were able to monitor
reservoir parameters and make decisions in real time, which shortened the well test by more than a
day. Real-time data (middle) allowed the operator to obtain necessary downhole information with which
to characterize the reservoir and meet its test objectives in 28 fewer hours than was called for in the
original test plan (bottom).
During the operation, the downhole pressure and
surface rate data acquired by the system are validated in real time, and QA/QC can be performed
immediately. Engineers can use these data for
quicklook interpretations and to determine well
and reservoir parameters. The initial reservoir
model may then be updated in real time with the
information from the well test to generate a new
interpretation model, verified with less uncer-
Autumn 2014
the primary target was at a depth of approximately 5,000 m [16,000 ft] in water depth of
1,462 m [4,797 ft].
Downhole gauges enabled by Muzic wireless
telemetry transmitted data successfully throughout the test. The operator was able to verify the
underbalance prior to perforating, establish initial
reservoir pressure after perforating, verify the status of the downhole tools during the test, optimize
the cleanup period by monitoring sandface pressure, reduce duration of buildup and confirm that
samples were being taken in ideal conditions.
The RT Certain real-time test collaboration
service brought reservoir experts at the rig in
Luanda and in Copenhagen, Denmark, together
in a virtual environment. A software platform
enabled wellsite data transmission and interpretation tools that allowed experts to make the right
decisions on site and from remote locations. This
integrated system also helped ensure sufficient
data were collected to complete a successful pressure transient well test.
The wireless downhole testing system saved
28 hours of rig time, about US$ 1.5 million in rig
spread costs, while acquiring sufficient data for
key reservoir property estimation (left). A comparison of memory data from the gauges retrieved
at the surface with the real-time data used for
interpretation during the test validated the decisions made during the operation.
tainty. The process is multidisciplinary and
dynamic; results from interpretation and analysis
can be used to modify earlier assumptions in an
iterative fashion and continuously generate a
clearer picture of the reservoir.
Maersk Oil drilled an exploration well offshore
Luanda to acquire data that would confirm the
presence of hydrocarbons in the target formation.
The well was drilled into oil-bearing sandstones;
The Future of Well Testing
Engineers have long recognized the value of DSTs
but in certain circumstances have had to make
compromises between quality data, costs and
risk. Real-time wireless telemetry addresses
those compromises by providing a means to capture real-time data throughout the test, remotely
activate downhole tools and isolate zones of
interest efficiently without permanent packers
and the need to collect reservoir fluid samples at
specified times. Most importantly, unlike in the
past, engineers can be certain they have achieved
test objectives before the test is ended.
The future of real-time well testing goes
beyond transmitting data to include the actuation
of multiple devices in the DST string using this
same wireless backbone. The immediate reward
for these expanded capabilities will be measured
in saved time, saved capital and improved ultimate hydrocarbon recovery as a result of development designs and production schedules informed
by high-quality data and accurate knowledge of
reservoir characteristics.
—RvF
41
Shushufindi—Reawakening a Giant
Daniel F. Biedma
Tecpetrol SA
Quito, Ecuador
Chip Corbett
Houston, Texas, USA
Francisco Giraldo
Jean-Paul Lafournère
Gustavo Ariel Marín
Pedro R. Navarre
Andreas Suter
Guillermo Villanueva
Quito, Ecuador
In less than three years, a consortium led by Schlumberger has resuscitated the ailing
giant Shushufindi oil field in Ecuador. The consortium’s team assimilated what was
known about the field and made recommendations to remedy problems and stimulate
production. Soon after a contract was signed, the consortium was performing
workovers, drilling new wells and continuously monitoring all field operations. As a
result, oil production has increased by more than 60% over rates from three years ago.
Ivan Vela
Petroamazonas EP
Quito, Ecuador
Oilfield Review Autumn 2014: 26, no. 3.
Copyright © 2014 Schlumberger.
For help in preparation of this article, thanks to Joe
Amezcua, Jean-Pierre Bourge, Jorge Bolanos Burbano,
Juan Carlos Rodriguez, Adriana Rodriguez Zaidiza, Luis
Miguel Sandoval Neira and Jorge Vega Torres, Quito,
Ecuador; Austin Boyd, Rio de Janeiro; Fausto Caretta,
London; Joao Felix and Christopher Hopkins, Houston; and
Pablo Luna, Petroamazonas EP, Quito, Ecuador.
Avocet, CMR, CMR-Plus, Dielectric Scanner, ECLIPSE, FMI,
i-DRILL, IntelliZone Compact, LiftWatcher, NOVA, P3, Petrel,
Platform Express, PowerDrive Orbit, PowerDrive vorteX,
PURE, Techlog and Vx and are marks of Schlumberger.
CLEANPERF and FLO-PRO are marks of M-I SWACO, LLC.
CIPHER is a joint development by Saudi Aramco and
Schlumberger.
1. Alvaro M: “Companies Look to Boost Production at
Mature Oil Fields in Ecuador,” The Wall Street Journal
(February 1, 2012), http://online.wsj.com/article/
BT-CO-20120201-713643.html (accessed August 1, 2014).
2. A horst and graben system develops in an extensional or
rifting tectonic regime, in which normal faults are the
most abundant type of fault. A horst is a relatively
high-standing block bounded on both sides by normal
faults that dip away from each other. A graben is a
relatively low-standing block—trough or basin—
bounded on both sides by normal faults that dip toward
each other. A horst and graben system is formed by
alternating high- and low-standing blocks.
42
Oilfield Review
O
an
COLOMBIA
Pac
ifi
c
ce
Sucumbíos
province
Putumayo basin
ShushufindiAguarico field
Nueva Loja
Quito
Napo
province
ECUADOR
Oriente basin
Marañón basin
PERU
0
0
km
200
mi
N
200
> Shushufindi location. The Shushufindi-Aguarico oil field (center) is located in the Oriente basin, in the Sucumbíos and Napo provinces in northeast
Ecuador (left). The gray shading indicates the Putumayo, Oriente and Marañón basins in eastern Colombia, Ecuador and Peru along the eastern front of the
Andes Mountains (dashed black line). The field was discovered in January 1969, and its first oil was produced in 1972. The Shushufindi-Aguarico anticline
(right) trends north to south and is 40 km [25 mi] long, 10 km [6 mi] wide and bounded on its east by a N–S reverse fault.
The Shushufindi-Aguarico field (collectively
known as Shushufindi) is a mature giant field
responsible for more than 10% of the total hydrocarbon production of Ecuador. Discovered in
1969 with an estimated 3.7 billion bbl [590 million m3] of oil originally in place, it achieved a
maximum production rate of about 125,000 bbl/d
[19,900 m3/d] of oil in 1986. Since then, the field
has been in decline; the field produced less than
40,000 bbl/d [6,360 m3/d] of oil in 2011.
In 2010, the government of Ecuador, concerned
about declining oil revenues from existing oil
fields in the country, actively sought partnership
with a service company to reverse this trend. In
late January 2012, the state-owned oil company
Empresa Pública de Hidrocarburos del Ecuador
(EP Petroecuador) signed a 15-year contract with
the integrated services joint venture (JV)
Consortium Shushufindi SA (CSSFD), led by
Schlumberger, to manage production from
Shushufindi.1 The objectives were to optimize production, accelerate the development of proven
reserves and evaluate secondary and tertiary
recovery potential. In just a few years, the consortium has resuscitated the ailing giant, restoring oil
production to 75,000 bbl/d [11,900 m3/d].
Autumn 2014
As of August 2014, the consortium has
increased oil production by more than 60%,
drilled 70 wells, completed 60 workovers and
built a state-of-the-art water treatment facility
for a 40,000-bbl/d water-injection pilot project.
Currently, production from Shushufindi has
reached the limits of the available facilities.
This article, which explains how the CSSFD JV
revitalized production from the giant ShushufindiAguarico field, begins with the field’s structure,
discovery, early oil production and subsequent faltering production. It discusses the consortium’s
early interventions to increase production, simultaneous and parallel studies to understand the
field’s architecture, building of a digital oilfield
operations center, efforts to maximize production
through well construction and interventions and
development of pilot programs to test production
through waterflood secondary recovery.
The Rise and Fall of a Giant
The Shushufindi field is located in the Oriente
basin in northeast Ecuador (above). Covering an
area of 400 km2 [150 mi2], it is Ecuador’s largest
oil field: a giant estimated to contain 3.7 billion
bbl of original oil in place (OOIP). As of January
2014, about 1.2 billion bbl [190 million m3] of oil
have been produced from the field.
The Ecuadorian Oriente basin is part of a
Mesozoic-Cenozoic back-arc basin that formed in
conjunction with the tectonic activity that created
the Andes Mountains during the Cretaceous to
Tertiary ages. Present-day structural traps were created by the compressional deformation and rejuvenation of pre-Cretaceous basement structures. The
traps consist primarily of faulted anticlines or
drapes over uplifted basement structures.
The Cretaceous Shushufindi-Aguarico reservoir structure consists of a low-relief, asymmetric
anticline; the western limb dips 1° to 2° to the
west. The field is about 40 km [25 mi] long and 10
km [6 mi] wide and has a structural closure of
around 67 m [220 ft] in relief. The structure is
closed to the east by a discontinuous north-south
reverse fault, which has a minor component of
strike-slip movement. Geoscientists believe this
fault is sealing in some locations but partially
sealing or nonsealing in others. The pre-Cretaceous basement is dominated by a horst and graben system, which has a direct influence on the
Cretaceous sedimentary sequence and depositional environment.2
43
Production rate, 1,000 bbl/d
160
Combined
Oil
Water
120
80
40
0
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
Year
100
Number of active wells
Total number of active wells
80
60
40
20
0
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
Year
> Production history. Since production (top) began in 1972, the Shushufindi field’s oil production decreased as its water production increased. After 1986, the
trend was independent of the number of active wells in the field (bottom).
In the Oriente basin, the primary reservoir
targets are the Cretaceous Hollin and Napo formations. Six clastic intervals form reservoirs;
from the oldest to the youngest, they are the
Hollin Formation, the T, U, M2 and M1 members
of the Napo Formation and the basal member of
the Tena Formation.3 These formations were
deposited in a transgressive-regressive sedimentary setting that occurred in response to global
sea-level fluctuations.4 The reservoirs are found
within successions of fluvial, estuarine and deltaic deposits of sediments that flowed in from the
east and prograded, or built up, successively seaward, first as shoreline and then as shallowmarine shelf deposits.
Shushufindi oil production comes from the
T and U members of the Napo Formation and the
basal Tena reservoirs. The thick and homogeneous sands of the Hollin Formation are present
in the area but are water saturated. The Napo T
and Napo U members are represented by estuarine to shallow-marine deposits; they are subdivided into the T Inferior (lower T), T Superior
(upper T), U Inferior (lower U) and U Superior
Oil production rate, 1,000 bbl/d
80
60
Incremental production
40
20
0
Feb 2012
Production baseline
Aug 2012
Feb 2013
Aug 2013
Feb 2014
Aug 2014
Date
> Incremental oil production. Since the Consortium Shushufindi contract was signed in late January
2012, oil production has increased to more than 75,000 bbl/d, which includes incremental oil production
of more than 30,000 bbl/d above the baseline production. The calculation of baseline production is
based on the assumption of no further action, and production from Shushufindi would be allowed to
decline naturally.
44
(upper U) submembers. The lower submembers
are the main reservoirs in the field; they are
formed from massive tidal and estuary sands and
contain 90% of the OOIP of Shushufindi. The
upper submembers are interbedded sandstones
and mudstones that were deposited in a shallow
marine environment. These reservoir intervals
have little aquifer pressure support.
A Texaco-Gulf consortium (both companies
are now part of Chevron) discovered the
Shushufindi oil field in 1969. Initial tests in the
discovery well yielded oil flow rates of 2,496 bbl/d
[396.8 m3/d] from the Napo U member and
2,621 bbl/d [416.7 m3/d] from the Napo T member. During early production, the oil from these
units was commingled. Lateral aquifer support to
the reservoir units from the west provided the
primary hydrocarbon drive mechanism.
Production from the Shushufindi field started
in 1972 at a rate of 19,200 bbl/d [3,050 m3/d] of
oil with no water production. It peaked about
1977 at 120,000 bbl/d [19,100 m3/d] with a
low water cut (above). As formation pressure
declined, the aquifer encroached upon the reservoir and the fault on the structure’s east side
leaked water into the reservoir. By 1994, oil production was 100,000 bbl/d [15,900 m3/d] and
water production was 40,000 bbl/d. Thereafter,
total liquid production remained stable at
roughly 130,000 bbl/d [20,700 m3/d], although oil
production gradually declined while water production increased proportionally.
By 2010, oil production was roughly 35% of
total liquid production. To counter the declining
Oilfield Review
True Vertical Napo
Depth
Formation
Measured
Zones
Depth, ft Subsea, ft
Completions
Sand
Producing
Interval
Shale
Isolated
Interval
0
Gamma Ray
gAPI
150 0
Shale Volume
Fraction
Sand
Effective Porosity
Shale
Bound-Fluid Porosity
Neutron Porosity
Effective Porosity
0.45 Fraction –0.15 0.5
Fraction
0
1 1.95
Density
g/cm3
Total Porosity
2.95 0.5
Fraction
Permeability
Spontaneous Potential
–121
mV
–9
Permeability
Deep Resistivity
0 0.01
mD
10,000 0.2
ohm.m
200 1
Water Saturation
Water Saturation
Fraction
0
Sand
Reservoir
Pay Zone
X,900
Upper U
X,925
X,950
Lower U
X,975
Y,300
Y,000
Y,025
Y,050
Middle
Shale
Y,075
Y,400
Y,100
Y,125
Limestone
B
Y,150
Upper T
Y,175
Y,500
Y,200
Y,225
Y,250
Lower T
Y,275
Y,600
Y,300
Lower Shale
> Single-well display output from Techlog well log software. Analysts interpret every well in the field, and results are presented and available in a simple,
comprehensive format, accessible to all personnel in subsurface, engineering production, drilling and workover teams. This single-well layout is used for all
completions and recompletion and workover proposals.
oil-production trend, the government of Ecuador
invited proposals from companies to revitalize
the Shushufindi field. Schlumberger formed
Consortium Shushufindi SA (CSSFD) with the
Argentine E&P company Tecpetrol SA (25%) and
the multinational private equity firm Kohlberg
Kravis Roberts & Co. LP (10%).
3. A clastic sedimentary rock consists of broken or eroded
fragments derived from preexisting rocks, transported
elsewhere and redeposited before forming another rock.
Examples of common clastic sedimentary rocks are
conglomerate, sandstone, siltstone, mudstone and shale.
Carbonate rocks can also be broken and reworked to
form clastic sedimentary rocks.
4. In sequence stratigraphy, a transgressive-regressive
sedimentary package is a unit of related sequential
layers of sediments formed during a cycle of sea-level
rise and fall. Transgressive sediments are deposited
during rising sea level as water advances over land.
Regressive sediments are deposited during falling sea
level as water retreats from the land.
5. Alvaro, reference 1.
6. Lafournere J-P, Dutan J, Naranjo M, Bringer F, Suter A,
Vega J and Bolaños J: “Unveiling Reservoir Characteristics
of a Vintage Field, Shushufindi Project, Ecuador,” paper SPE
171389, presented at the SPE Western Venezuela Petroleum
Section Second South American Oil and Gas Congress,
Porlamar, Venezuela, October 22–25, 2013.
7. A static model describes a single moment in time. Geologic
models are static because on the human timescale, geologic
characteristics, for the most part, vary imperceptibly. In
contrast, a dynamic model describes events as they
evolve through time. Reservoir models are dynamic
because they account for the behavior of time-dependent
properties—temperature, pressure, flow rate, volume,
saturation, compressibility and others—that vary during
the operating life of a reservoir.
Autumn 2014
In January 2012, the consortium signed a
15-year contract with EP Petroecuador, the
national oil company of Ecuador, to form an integrated service JV to manage production from
Shushufindi.5 Subsurface studies and capital
investment activities for the JV contract are managed by CSSFD. In February 2013, the upstream
division of EP Petroecuador was merged with
Petroamazonas Ecuador SA to become
Petroamazonas EP, or PAM. As a result, PAM
assumed responsibility as operator and as the
CSSFD JV customer partner in the Shushufindi
asset. At the time of contract signing, about 100
active wells were collectively producing
45,000 bbl/d [7,150 m3/d] of oil.6
Production has since increased by more than
60% to about 75,000 bbl/d or about 30,000 bbl/d
[4,770 m3/d] more oil than when the contract
started in January 2012 (previous page, bottom).
Precontract Intervention
In October 2011, four months before the contract
was signed, CSSFD introduced a team of technical
and operations professionals dedicated to studying the field and proposing specific actions to be
taken immediately after contract execution. In
less than four months, the team designed the
annual work plan (AWP) for 2012, which included
drilling 22 wells and conducting 25 workovers.
The team developed strategies for reviewing existing surface facilities—looking for and addressing
bottlenecks in the system—to improve the
throughput at the facility.
Within four months of starting work, the team
had assembled a comprehensive database of
existing wells and developed a reliable static geologic model and a realistic dynamic reservoir
model for Shushufindi.7 In addition, the team had
recommendations for 35 new well locations and
29 workovers. The team also devised plans for
continuous monitoring and streamlining of facilities and production operations to minimize nonproductive time and deferred production. Six
weeks into the contract, the asset team was operating one drilling rig and two workover rigs in the
field. By the end of 2012, the number of drilling
and workover rigs grew to four and three, respectively, and the CSSFD JV had completed the new
wells and workovers from the 2012 AWP and had
opened a computerized, state-of-the-art operations center.
Within two months after the contract had
been signed, the team had evaluated 152 wells
using the Techlog wellbore software platform.
The results for each well were compiled and presented in a single format (above). In addition,
45
Effective Porosity
Bound-Fluid Porosity
Completions
Napo
Measured Formation
Zones
Depth, ft
A
Producing
Interval
Isolated
Interval
Shale Volume
0
Fraction
0.5
1 0.5
B
Effective Porosity
Spontaneous Potential
Fraction
0 –121
mV
–9
Total Porosity
Fraction
0 0.2
Deep Resistivity
ohm.m
200
Sand
Reservoir
C
Pay Zone
D
Thickness
E
B
D
C
A
E
> Multiwell “M” section output from Techlog well log software. For each well, the tracks are from left to right: measured depth; Napo Formation zones
(Track 1); completion information (Track 2); shale volume (Track 3); porosity (Track 4); deep resistivity and spontaneous potential (Track 5); lithology (Track 6);
reservoir (Track 7); pay zone (Track 8); and pay zone thickness (Track 9). Each well in the field is correlated with its immediate neighbors.
each well was correlated to the four closest offset
wells; each correlation cross section formed an
“M” pattern with the well of interest in the center
(above). Because these displays had simple formats, the subsurface, engineering production,
drilling and workover teams could easily plan
well interventions. In addition, the displays facilitated picking locations for drilling new infill
wells. Focus was initially on characterizing the
lower T and lower U Napo sandstones, which are
the principal reservoir units within Shushufindi.
The team developed a well-history card—a digital record—for each well, listing production and
Napo Upper Shale–Limestone M2
pressure data and estimated remaining reserves
along with significant events such as completions
and workovers. The records allowed the team to
perform a methodical review of all well characteristics, prioritize workovers and select locations for new wells.
Reservoir Architecture and
Field Redevelopment Strategy
In a parallel effort to understand the reservoir
architecture and prepare a fieldwide redevelopment strategy, the team designed and implemented
a comprehensive data acquisition campaign. The
campaign included core analysis, comprehensive
suites of logs, fluid analysis and seismic reprocessing to reduce reservoir uncertainty and build
a database for updating the static model; such
data were based on improved understanding of
the reservoir architecture and dynamic behavior
of the field. From 2012 to 2013, geologists, geophysicists, petrophysicists and reservoir engineers worked closely with drilling, completions
and facilities engineers to build a long-term field
development strategy.
Structural framework—The Shushufindi
structure is a large asymmetric anticline closed
Lower U has stratigraphic and lateral compartmentalization.
Upper U
Lower U
Upper T
Lower T
656 ft
200 m
Napo Middle Shale–Limestone B
2 km
Upper T and U have discontinuous sand lenses.
1.2 mi
> Reservoir architecture. In the Napo Formation and its members, blue indicates low-permeability shale and limestone units, yellow indicates good quality
sands, orange indicates low-quality sands and green indicates shales. The lower T submember, the main reservoir, is continuous and massive across the
field and results from coalescing sands piled vertically. The lower U submember reservoir is also continuous across the field but has a higher degree of
stratigraphic variation than the lower T submember. The upper T and U submembers contain secondary reservoirs that have little lateral continuity and occur
mostly as localized lenses.
46
Oilfield Review
SW
NE
10 km
0.6 mi
1 km
6.2 mi
Shushufindi-Aguarico field
Sacha field
Reverse fault
Pre-Cretaceous paleo structure
(horst and graben system)
> Structural framework from seismic data. The Sacha and Shushufindi-Aguarico oil fields are low-relief asymmetric anticlines. The Cretaceous-age Hollin,
Napo T and Napo U reservoir sequences (yellow reflectors) drape over the pre-Cretaceous basement, which is dominated by a horst and graben system
(red reflectors). The Shushufindi-Aguarico structure is bounded on its east by a reverse fault. Blue vertical lines are intersections with other seismic lines.
on the east by a reverse fault (above). The structure is flat and has a vertical closure of only
67 m from crest to flank over a distance of 7 km
[4 mi]. In addition, the eastern fault is patchy
and discontinuous in its sealing effect and
locally allows a strong influx of water from the
east (below).
The architecture of the Napo Formation is
varied. The lower T submember is characterized
by continuous, high-quality sands with little com-
partmentalization, whereas the lower U submember exhibits both stratigraphic discontinuities
and compartmentalization. The upper T and U
submembers are characterized by discontinuous
and isolated sand lenses (previous page, bottom).
August 1, 1972
January 1, 1976
January 1, 1980
January 1, 1984
January 1, 1988
January 1, 1996
January 1, 2000
January 1, 2004
January 1, 2008
June 1, 2011
January 1, 1992
N
> Water encroachment. Bubble maps show the active wells (circles) and their liquid production; green indicates oil, blue indicates water and both colors
indicate commingled liquid. The progression, mapped about every four years, shows water encroaching into the field as a result of oil production and
declining reservoir pressure.
Autumn 2014
47
Fluvial channel
Marsh
Sandbar
Shoreface sand
Shallow-marine environment
Tide-Dominated
estuary
> Present-day analog for depositional environment. A large, flat and tidally dominated estuary that invades into a shallow
carbonate platform is the general sedimentological model for the Ecuador Cretaceous basin that holds the Shushufindi field.
This photograph, from the eastern Australia coast, is of a depositional environment similar to those found in many other
parts of the world.
The fault’s irregular sealing and the reservoirs’ architecture are important in understanding today’s reservoir fluid distribution, which is
controlled mainly by variations of rock properties
and facies in reservoir zones. In addition, engineers consider the distribution of cumulative oil
and water production, and each well’s contribution to it, when selecting locations for new infill
wells within the structure’s flank.
Geologic framework and sedimentology—
The sediments that formed the Shushufindi oil
field are near-shore to shallow-marine deposits of
Late Cretaceous age. The depositional setting is
characterized by features such as sand bars,
beaches, tidal channels, estuaries, shallow
lagoons, marshes and streams (above).8
The Napo T and U sands were deposited in
shallow water.9 After deposition of each sand unit,
2.54 cm
1 in.
> Cores from the Shushufindi field. Fine layers of coal and amber intercalate between clean siltstone mixed with shale (left). These dipping layers are
preserved at the base of the sand bedsets and are typical of tidally dominated sediments. A photomicrograph (right) shows amber within coal. The
preservation of amber is indicative of a quiet, low-energy sedimentary environment.
48
Oilfield Review
0.5
Sand
Shale
Napo
Measured Formation
Zones 0
Depth, ft
Core Porosity
Fraction
Sand
Effective Porosity
Shale
Bound-Fluid Porosity
0
Neutron Porosity
Effective Porosity
0.45 Fraction –0.15 0.5
Fraction
0
Gamma Ray
gAPI
150 1.95
Density
g/cm3
2.95 0.5
Total Porosity
Fraction
0.01
Core kv
mD
10,000
0.01
Core kh
mD
10,000
Permeability
0 0.01
Lithology and
Production Data
Spontaneous Potential
–121
mV
–9
Permeability
Deep Resistivity
mD
10,000 0.2
ohm.m
200 1
Sand
Water Saturation
Water Saturation
Fraction
Reservoir
0
Pay Zone
X,605 ft
X,608 ft
X,611 ft
X,614 ft
X,606 ft
X,609 ft
X,612 ft
X,615 ft
X,607 ft
X,610 ft
X,613 ft
X,616 ft
X,500
Upper U
X,475
X,525
X,550
Lower U
X,575
X,600
X,625
> Well interpretation. The Techlog well data display (left) shows the upper and lower U submembers of the Napo Formation. It includes data from the core
interval in the lower U submember. The log tracks are from left to right: measured depth; Napo Formation zones (Track 1); gamma ray (Track 2); neutron
porosity and density (Track 3); effective, total and core porosity (Track 4); NMR and core permeabilities (Track 5); deep resistivity and spontaneous potential
(Track 6); Archie water saturation and core water and oil saturation (Track 7); lithology (Track 8); reservoir (Track 9); pay zone (Track 10); and pay zone thickness
(Track 11). The core (right) shows thin horizontal layers—streaks of quartz, lignite and amber—which form barriers to vertical flow and may be correlated
over large areas. These thin layers do not appear in the well logs, which show the interval as a massive, homogeneous sandstone reservoir.
sea level rose—as evidenced by repeated cycles of
an upward succession of shallow-shelf carbonates
and marine shales deposited on top of the sands.
Examination of core cut through the Napo T and U
sandstones suggested that the sands were deposited in low-energy environments that supported
various types of wetlands such as marsh and forest wetlands.10 Within the core were thin layers of
fine-grained, quartz-rich, tightly cemented and
impermeable siltstones and thin layers of coal
(above). Both types of thin layers contain
amber—fossilized resin from coniferous trees—
which is typically preserved in low-energy environments (previous page, bottom).11 These thin
siltstones and coals are traceable in cores from
well to well and extend over large areas; therefore
they are potential barriers or baffles to the vertical migration of fluid.
Although geoscientists surmise that layering
is the fabric controlling fluid migration, some
zones contain coalescing sands, which are sand
units deposited one on top of another to produce
a sand body that is effectively continuous.
When present, coalescing sands can aid vertical
fluid flow.
Both fabrics—laterally extensive impermeable layers and locally coalescing sand bodies—
affect original fluid migration and the behavior
of the natural water drive, secondary waterflood
and tertiary recovery operations. Production
8. White HJ, Skopec RA, Ramirez FA, Rodas JA and
Bonilla G: “Reservoir Characterization of the Hollin and
Napo Formations, Western Oriente Basin, Ecuador,”
in Tankard AJ, Suárez Soruco R and Welsink HJ (eds):
Petroleum Basins of South America. Tulsa: American
Association of Petroleum Geologists, Memoir 62 (1995):
573–596.
9. Corbett C, Lafournere J-P, Bolanos J, Bolanos MJ,
Frorup M and Marin G: “The Impact of Layering on
Production Predictions from Observed Production
Signatures, Shushufindi Project, Ecuador,” paper
SPE 171387, presented at the SPE Western Venezuela
Petroleum Section Second South American Oil and Gas
Congress, Porlamar, Venezuela, October 22–25, 2013.
10. Greb SF, DiMichele WA and Gastaldo RA: “Evolution and
Importance of Wetlands in Earth History,” in Greb SF and
DiMichele WA (eds): Wetlands Through Time. Boulder,
Colorado, USA: The Geological Society of America
Special Paper 399 (2006): 1–40.
11. Lafournere et al, reference 6.
The presence of amber indicates that a low-energy
environment existed at the time of its deposition.
Coniferous trees grew in the wetlands and dropped
resin, which was not washed away and remained in
place long enough to be preserved as amber.
Autumn 2014
49
9
8
7
Vertical flow
Highly layered flow
Well water/oil ratio
6
5
4
3
Measured data, Well SSF-128D
Measured data, Well SSF-127D
Measured data, Well SSF-094
2
Fit to data, Well SSF-127D
Fit to data, Well SSF-094
1
0
0
2
4
6
8
10
12
14
16
18
Well liquid production totals, million bbl
> Production signatures. A typical water/oil ratio (WOR) is charted versus cumulative liquid (oil and water) production for wells drilled through a highly
layered reservoir (blue) and through a reservoir with more vertical flow (red). The circles are WORs from wells in the Shushufindi field. The lines are best
linear fits to the early production. In comparison to that in wells with a dominantly vertical flow component, the rise in WOR from a highly layered reservoir
is more gradual.
profiles from many Shushufindi wells indicate a
steady increase in water production caused by
lateral aquifer encroachment; these characteristics confirm the presence of a dominant layered system (above).12
The CSSFD geoscientists and engineers demonstrated this interpretation to be incomplete.
After establishing the geologic framework, the
team used the ECLIPSE reservoir simulator to
incorporate more knowledge of the geology to
model the water cut. Numerical reservoir simulators use various parameters to account for
unusual reservoir behavior. To model layered geologic strata in which fluid migration is primarily
horizontal, reservoir simulators have a parameter
called the vertical transmissibility multiplier
(MULTZ) that represents vertical communication between geologic layers; MULTZ varies from
zero to one, and when it is set to zero, a permeability barrier blocks vertical flow between layers.
Setting MULTZ to zero for the top horizon of each
layer creates a permeability barrier and results
in a gradual rise in the water cut from a well,
somewhat similar to what is observed. However,
the modeled water cut exhibits a series of pulses
as water from individual layers breaks through at
the well. The pulses were not observed in the
Shushufindi field data.
The CSSFD team then used a Petrel E&P software platform workflow to modify the vertical
transmissibility multiplier.13 The asset team mod-
50
eled the horizons between layers as baffles, or
broken and leaking barriers, representing
amounts of sand coalescence. For 80% of the grid
cells making up a layer, flow was horizontal only;
the top grid-cell faces were “no flow,” or zero permeability, barriers. For the rest of the grid cells,
vertical flow occurred in accordance with the
permeability and fluid transmissibility properties
across layer boundaries.14 The result of this model
more closely matched the water cut history. The
modeled water production increased gradually
and did not exhibit the pulsing caused by layerby-layer water breakthrough.
Understanding the reservoir architecture of
the Shushufindi field is important for planning
infill drilling and completions programs. The
CSSFD team plans to increase the well density
from nominally 125-acre [0.506-km2] spacing to
approximately 60-acre [0.243-km2] spacing;
these spacings correspond to well-to-well distances of about 2,630 ft [802 m] and 1,820 ft
[555 m], respectively.
Characterization of the porous media—The
CSSFD team wanted to perform reservoir characterization by establishing sequential objectives.
The immediate objective for the contract was to
rejuvenate recovery from the primary reservoir
zones. Therefore, the AWPs for 2012 and 2013
focused on the reservoirs in the lower Napo
T and U submembers.
After recovery from the primary reservoirs is
rejuvenated, analysis will focus increasingly on
providing results for the field development plan,
which includes planning for secondary and tertiary recovery phases, a waterflooding pilot and,
possibly, an enhanced oil recovery (EOR) pilot. In
addition, the reservoir characterization effort
will produce a quantitative evaluation of OOIP in
the highly laminated secondary reservoirs of the
upper Napo T and U submembers.15
To characterize porous media, the CSSFD
team made extensive use of routine and advanced
core studies, high-resolution magnetic resonance
data, advanced processing of CMR-Plus combinable magnetic resonance tool data and, to a
lesser extent, Dielectric Scanner multifrequency
dielectric dispersion service data.16 The objective
was to characterize grain size, pore size, pore
throat size and in situ residual oil saturation at
reservoir conditions. Results allowed the CSSFD
team to define four rock types based on advanced
CIPHER processing of pore size, pore throat, productivity index, permeability and hydraulic
behavior (next page).17
The CSSFD team used the rock typing data to
choose reservoir intervals for completions, optimize electric submersible pump (ESP) operating
parameters within completion zones and assess
particle sizing for drilling and completion fluids
to prevent and mitigate formation damage.
Oilfield Review
CIPHER
Core MICP and SEM
Neutron-Density Log and CMR Log
Porosity,
%
Rock type
1
Core NMR
Permeability,
mD
Average grain Median pore throat
diameter, μm
diameter, μm
Greater than 17 Greater than 800 Greater than 30
2
3
4
14 to 17
12 to 16
Less than 12
400 to 800
150 to 250
Less than 10
25
5 to 10
Less than 5
CMR Log
Production Tests and
Nodal Analysis
Median pore body
diameter, μm
Primary CIPHER
pore description
CMR porosity
bin number
Average productivity,
bbl/ft/d [m3/m/d]
Greater than 20
Greater than 120
Macropores
7 to 8
10 to 20
2 to 10
Less than 2
40 to 80
8 to 40
Less than 8
Mesopores to Macropores
Mesopores
Micropores
6 to 7
3 to 5
1 to 2
Greater than 160 up to 400
[Greater than 63.5 up to 209]
68 [35.5]
28 [14.6]
No flow
CIPHER Results
CMR-Plus Data
Micropores
T2 Distribution
Mesopores
T2 Cutoff
0.3
Measured
Depth, ft 0.3
ms
Macropores
5,000
T2, Log Mean
ms
Measured
Depth, ft
5,000
T2 relaxation time, ms
Time, ms
X,000
Echo amplitude
NMR signal amplitude
X,000
T2 Distribution
X,025
X,025
CIPHER
> Rock typing. The Consortium Shushufindi team used a variety of data sources (top) to define four rock types. Rock-type classifications integrated core
analysis results (green) from mercury injection capillary pressure (MICP) porosimetry, scanning electron microscopy (SEM) and nuclear magnetic
resonance (NMR); well log results from neutron, density and CMR combinable magnetic resonance logs; and processing results from CIPHER software
(blue); and production data and nodal analysis (orange). The rock types are defined by their respective porosity, permeability, grain size, pore throat size,
pore diameter, pore families, CMR porosity bin families and productivity ranges based on advanced CIPHER processing (bottom). CMR-Plus data (left) are
processed using CIPHER software (middle) to quantify pore dimensions and associated pore volume (right). The CIPHER window shows a decay spectrum,
or transverse relaxation time (T2) distribution, on the left and an NMR echo amplitude decay plot on the right; through mathematical inversion, the decay
plot on the right is converted to the T2 distribution on the left. The T2 distribution directly relates to the capillary properties of pore size distribution. The T2
cutoff is an empirical fixed T2 value—typically 33 ms in sandstones—that relates to the capillary properties of fluids in pores; it separates pores into those
that are large enough for free fluid flow from those that are too small for free fluid flow; in the latter case, fluid is bound, or trapped, by capillary forces.
12. For more on characteristic charts of water
complications: Chan KS: “Water Control Diagnostic
Plots,” paper SPE 30775, presented at the SPE Annual
Technical Conference and Exhibition, Dallas,
October 22–25, 1995.
For more on water-control problems and solutions:
Bailey B, Crabtree M, Tyrie J, Elphick J, Kuchuk F,
Romano C and Roodhart L: “Water Control,”
Oilfield Review 12, no. 1 (Spring 2000): 30–51.
13. Hoffman DR: “Petrel Workflow for Adjusting Geomodel
Properties for Simulation,” paper SPE 164420, presented
at the SPE Middle East Oil and Gas Show and
Conference, Manama, Bahrain, March 10–13, 2013.
14. Corbett et al, reference 9.
Autumn 2014
15. Gozalbo E, Bourge JP, Vargas A, Lafournere JP and
Corbett C: “Geomodel Validation Through Pressure
Transient Analysis (PTA) and Simulation in the
Shushufindi Field, Ecuador,” paper GEO-DE-EG-04-E,
presented at VIII INGEPET, Lima, Peru, November 3–7, 2014.
16. Lafournère J-P, Dutan J, Hurtado J, Suter A, Bringer F,
Naranjo M, Bourge J-P and Gozalbo E: “Selection of
Optimum Completion Intervals Based on NMR Calibrated
Lithofacies,” paper SPE 169372, presented at the SPE
Latin America and Caribbean Engineering Conference,
Maracaibo, Venezuela, May 21–23, 2014.
For more on CMR logging: Allen D, Flaum C,
Ramakrishnan TS, Bedford J, Castelijns K, Fairhurst D,
Gubelin G, Heaton N, Minh CC, Norville MA, Seim MR,
Pritchard T and Ramamoorthy R: “Trends in NMR
Logging,” Oilfield Review 12, no. 3 (Autumn 2000): 2–19.
For more on the Dielectric Scanner service: Carmona R,
Decoster E, Hemingway J, Hizem M, Mossé L, Rizk T,
Julander D, Little J, McDonald T, Mude J and
Seleznev N: “Zapping Rocks,” Oilfield Review 23, no. 1
(Spring 2011): 36–52.
17. For more on the CIPHER software: Clerke EA, Allen DF,
Crary SC, Srivastava A, Ramamoorthy R, Saldungaray P,
Savundararaj P, Heliot D, Goswami J and Bordakov G:
“Wireline Spectral Porosity Analysis of the Arab
Limestone—From Rosetta Stone to CIPHER,”
Transactions of the SPWLA 55th Annual Logging
Symposium, Abu Dhabi, UAE, May 18–22, 2014.
51
Field redevelopment strategy—The revival
of Shushufindi is a result of the integration of disciplines, expertise and more than 50 specialized
technologies used in this field (below).
Consortium Shushufindi leads the contract’s
production management team. Various groups
from CSSFD and PAM were assigned specific
responsibilities.18 The subsurface teams included
geophysicists, petrophysicists, geologists, geologic modelers and reservoir engineers. Their
purview included short-term events such as
determining casing points and completion intervals on new wells and a responsibility to longer
term deadlines that resulted in annual work
Seismic reprocessing
plans and defining the field development plan;
the latter was based on a detailed reservoir characterization that identified remaining reserves
and areas for drilling delineation wells and intervention opportunities.
In 2012, the CSSFD team developed a field
redevelopment strategy for each production area
Advanced core analysis
CMR pore throat size and bound fluid
9612
9606
Supervisory control and
data acquisition system
9616
9610
Calibration using petrophysics
Seismic Methods
gy
olo
Ge
Prod
ucti
on
Mo
nit
or
in
g
Residual oil saturation estimation
using Dielectric Scanner service
Asset Integrated Management Center
Vertical heterogeneities using FMI log,
dielectric log and high-resolution
Platform Express wireline tool
LiftWatcher surveillance service
Reservoir simulation
mp
ir E
Co
n gi
nee
ll
We
IntelliZone Compact completion
ri n g
Vx multiphase well testing
Re
n
se
io
rvo
l et
Well Construction
Hydraulic fracturing
Improved drilling performance
PowerDrive vorteX
powered rotary steerable system
Reduced reservoir damage
MAXR anchors, PURE perforations system
and NOVA valves
> Multidisciplinary integration. The asset integrated management (AIM) center coordinates collaboration and flow of information from the various
Shushufindi teams: seismic, geology, reservoir engineering, well construction, well completion and production monitoring.
52
Oilfield Review
Advanced well drilled into
offset structure (AGU-29)
N
Faults
AGU-29
Marginal production; well
AGU-19 converted to a
cuttings disposal well
Excellent delineation well,
AGU-29; accelerate primary
development in area
AGU-19
AGU-29
1
Primary development
strategy for Aguarico
and north Shushufindi
Development area boundary
Good production from
development well; accelerate
drilling infill wells in the area
3
2
4
Development area boundary
Waterflooding pilot area
pattern construction through
drilling of infill wells
Field
extent
Infill drilling to reduce well
spacing to about 450 m
Excellent
Good to very good
Medium to low
Poor to noneconomic
Injector
Field
extent
Mixed production caused by
stratigraphic and structural
boundaries; slowed
development in area
5
Good potential for production
from lower T and U; low pressure
in lower U; target lower U for
waterflood expansion
6
Development area boundary
Development area boundary
Crest of structure swept by
water inflow through fault
Infill drilling to reduce well
spacing to about 450 m
8
7
Shift focus for drilling
infill wells to western
flank of structure
Faults
Development area boundary
Development area boundary
10
Reservoir delineation of
south and southwest
development areas
Drilling activity
2013 to 2014
0
0
N
m
5,000
ft
9
Drilling activity
2014 to 2015
0
20,000
0
m
Good production from U sands
in south development area;
delay drilling infill wells until
2016 because of low facilities
capability
5,000
ft
20,000
> Field development strategy. These maps summarize the development plans from the second half (H2) of 2013 through the first half (H1) of 2015. In the
H2 2013 through H1 2014 plan (left), the Shushufindi-Aguarico field is divided into five development areas; from the north, these areas are the Aguarico and
north, central, south and southwest Shushufindi. New wells (colored circles) are classified according to their production. The dashed ovals indicate areas
of drilling activity in the field; their colors indicate the activity described in the corresponding colored rectangles. For the H2 2014 through H1 2015 plan
(right), the field was subdivided into 10 areas of development and drilling activity (dashed outlined areas and numbers). The outlines are colored according
to risk and production potential; green indicates low risk, good production and accelerated development; yellow indicates medium risk, moderate
production and slowed development; red indicates high risk, poor production and stopped development; blue indicates waterflood expansion; and black
indicates drilling activity. New wells are colored and rated as they are on the left. The CSSFD field development program is dynamic and can change over
time to adapt to new data and situations, as these maps illustrate.
of Shushufindi for the first half of 2013 through
the first half of 2014 (above). The plan included
drilling low-risk development wells on the
flanks of the structure to add oil reserves and
reducing well spacing to reach bypassed oil that
had good pressure support. This strategy relied
on characterization of the pressure depleted
areas, in which secondary recovery will take
place with a waterflooding pilot program. In
addition, the plan contained high-risk, step-out
delineation wells on the periphery of the main
structure. New results and lessons learned dur-
Autumn 2014
ing this period allowed the CSSFD team to formulate a drilling and development strategy with
specific objectives for each area of the field for
the period from the second half of 2014 through
the first half of 2015.
Asset Integrated Management Center
The economic success of the field is measured by
incremental production above the baseline production, which assumed a no-further-action scenario. The Shushufindi contract also obligates
CSSFD to make direct investments in capital
expenditures (capex).
The CSSFD JV hired Schlumberger Production
Management to design and build a digital oilfield
operations center to acquire data, monitor activities and manage the Shushufindi oil field. In
December 2012, CSSFD opened its Centro de
Manejo Integrado del Activo (Centro MIA), or
18. Marin G, Paladines A, Suter A, Corbett C, Ponce G and
Vela I: “The Shushufindi Adventure,” paper SPE 173486,
presented at the SPE Western Venezuela Petroleum
Section Second South American Oil and Gas Congress,
Porlamar, Venezuela, October 22–25, 2013.
53
> Asset integrated management (AIM) center. The CSSFD team continuously monitors drilling, workover and production operations to improve efficiency at
the field. Whenever there is an outage such as equipment failure, center staff alerts the field to minimize nonproductive time and deferred production. All
field activities are monitored from the AIM center in Quito to optimize production and reduce operating costs.
asset integrated management (AIM) center.19
The CSSFD JV decision processes consist of multidisciplinary integration of drilling, completions,
workover, production and surface facilities data
and include extensive use of real-time data from
the AIM center. Fit-for-purpose software applications on a common platform, state-of-the-art visualization technologies and revisions to the
traditional decision-process loop have made data
integration possible.
The AIM center operates on three time loops—
fast, intermediate and slow. The fast loop encompasses daily real-time surveillance and monitoring
of activities related to well status, ESPs, well tests,
drilling, completions and workovers.
The intermediate loop covers activities that
occur in 1 to 90 days and addresses optimization
activities, in which the AIM center plays a key role
as enabler for collaboration between all CSSFD
teams in the field and Quito, Ecuador, offices.
These activities include scheduling daily and
weekly ESP operations and maintenance, monitoring and follow-up of special completion operations
such as hydraulic fracturing or overbalanced perforating, managing deferred and lost production
and administering surface facilities.
54
The slow loop focuses on reservoir management. The AIM center provides the daily, weekly
and monthly data to the subsurface team
experts, who integrate them with results from
reservoir, facilities and economic models to plan
field development, infill drilling and annual
workflow operations.
Continuous monitoring at the AIM center is
well on its way to becoming a reality (above).
Monitoring and surveillance hardware have been
installed in the field; these devices include downhole pressure gauges, inflow control valves, compact intelligent completion equipment and
distributed pressure and temperature monitoring
sensors. The status of every operation in the field is
summarized daily and displayed on the video walls
in a format that is easy to understand at a glance.
The Shushufindi field relies on artificial lift,
and 99% of the wells in the field are equipped with
ESPs.20 To maximize run life of the pumps and
minimize deferred production, the AIM center
monitors every ESP well with an array of sensors
that measure downhole pressure, temperature,
ESP functions and wellhead parameters such as
pressure, temperature and flow rates. These data
are compiled to determine whether the pumps
are on or off and how this status compares with a
schedule of planned shutdowns and well testing.
For both scheduled and unscheduled shutdowns,
the center alerts the field and records the shutdown time and lost production until the well
comes back online.21 The ultimate objective is to
have no unscheduled downtime or unscheduled
lost production (next page, top).
During well construction, the objective of the
AIM center team is to minimize nonproductive
time and capex. The team continuously monitors
critical drilling parameters such as weight on bit,
rate of penetration (ROP), torque, drillstring
depth and pressure. If drilling parameters deviate from acceptable ranges, AIM experts alert
the onsite drilling team. Completion and workover operations follow a similar process.
Enabling an ideal collaborative environment
is another key objective for the AIM center.
Collaboration rooms with visual aid and communication devices make this possible. For example,
during the design and selection of multizone
intelligent completions, multidisciplinary teams
from the field, Quito offices and Houston technical support staff shared information in real time
to facilitate and speed the decision process workflow (next page, bottom).
Oilfield Review
Well Construction Solutions
Drilling new wells is an activity that consumes
the attention of a project team. The CSSFD JV
formed a drilling team that evaluated the geomechanical aspects and trajectory of each well. The
drilling team modified several drilling practices
to reduce risk, drilling costs and formation damage and improve well integrity. For example, to
minimize environmental impacts to this sensitive
Amazon region, every well is drilled from a multiwell pad.
The team used technologies designed to
increase hole quality. The PowerDrive Orbit motorized rotary steerable system (RSS) achieved good
hole cleaning, which resulted in reduced circulation and tripping times. The PowerDrive vorteX
powered RSS effectively converted mud hydraulic
power to additional mechanical power for
improved ROP.22 Bottomhole assembly designs
from the i-DRILL engineered drilling system
design software contributed to higher ROP,
decreased drillstring vibration and increased bit
footage in heterogeneous reservoir sections.23
Drilling fluids were designed to be compatible
with the formation and the in situ stress regime,
ensuring chemical and mechanical stability in the
wellbore. Thanks to the combination of RSSs, suitable bits and the appropriate drilling fluids, the
occurrence of stuck pipe was less frequent and
less severe than in previous drilling campaigns
elsewhere in the field.
19. Rodriguez JC, Biedma D, Goyes J, Tortolero MA, Vivas P,
Navarre P, Gozalbo E, Agostini D and Suter A: “Improving
Reservoir Performance Using Integrated Asset
Management in Shushufindi Asset,” paper SPE 167835,
presented at the SPE Intelligent Energy Conference and
Exhibition, Utrecht, The Netherlands, April 1–3, 2014.
For more on integrated asset management: Bouleau C,
Gehin H, Gutierrez F, Landgren K, Miller G, Peterson R,
Sperandio U, Trabouley I and Bravo da Silva L:
“The Big Picture: Integrated Asset Management,”
Oilfield Review 19, no. 4 (Winter 2007/2008): 34–48.
20. For more on electric submersible pumps: Bremner C,
Harris G, Kosmala A, Nicholson B, Ollre A, Pearcy M,
Salmas CJ and Solanki SC: “Evolving Technologies:
Electrical Submersible Pumps,” Oilfield Review 18, no. 4
(Winter 2006/2007): 30–43.
21. Goyes J, Biedma D, Suter A, Navarre P, Tortolero M,
Ostos M, Vargas J, Vivas P, Sena J and Escalona C:
“A Real Case Study: ‘Well Monitoring System and
Integration Data for Loss Production Management’
Consorcio Shushufindi,” paper SPE 167494, presented at
the SPE Middle East Intelligent Energy Conference and
Exhibition, Dubai, October 28–30, 2013.
22. For more on the PowerDrive vorteX powered rotary
steerable system: Copercini P, Soliman F, El Gamal M,
Longstreet W, Rodd J, Sarssam M, McCourt I, Persad B
and Williams M: “Powering Up to Drill Down,”
Oilfield Review 16, no. 4 (Winter 2004/2005): 4–9.
23. For more on the i-DRILL engineered drilling system:
Centala P, Challa V, Durairajan B, Meehan R, Paez L,
Partin U, Segal S, Wu S, Garrett I, Teggart B and
Tetley N: “Bit Design—Top to Bottom,”
Oilfield Review 23, no. 2 (Summer 2011): 4–17.
Autumn 2014
> Daily well monitoring status report. For each production area in the Shushufindi-Aguarico oil field—
Aguarico, north, central, south and southwest—a panel contains four columns of the well status data,
unscheduled downtime, lost production and latest well test flow rate. The circles on the left of each
panel are color coded for the well status: normal (green), shutdown for well test (blue), scheduled
shutdown (yellow), unscheduled shutdown (red), no signal from monitoring equipment (black) and not
monitoring (white). At the bottom of each panel is the total unscheduled lost production for the area.
The summary below the panels gives the cumulative production lost for the day, the number of shut-in
wells and the production lost from unscheduled shutdowns and scheduled shutdowns.
> Collaboration rooms. At the AIM center, a multidisciplinary team makes final adjustments on the
design of a multizone intelligent completion. Using state-of-the-art visualization and communication
capabilities, engineers are able to display reservoir attributes, mechanical design and key performance
indicators on the video wall and collaborate with the Houston support center via video conferencing.
55
ESP
Capsule
Packer
Zone 1
Perforations
Packer
Zone 2
Perforations
Multidrop module
FCV and sensors
Multidrop module
FCV and sensors
> Intelligent completions. In this configuration, the electric submersible pump
(ESP) is encapsulated for easy maintenance and replacement. Using
multidrop modules at each zone gives engineers remote control of downhole
flow control valves (FCVs) and the ability to monitor downhole sensors that
record flowing bottomhole pressure and temperature, reservoir pressure and
temperature, and tool position. This setup gives the Shushufindi AIM center
flexibility to monitor simultaneous production, calculate liquid production with
intelligent FCVs and isolate zones for three-phase metering, stimulation work,
rigless mechanical cleaning or well tests.
To minimize formation skin, engineers used
fluids with relatively low solids content such as
the M-I SWACO FLO-PRO reservoir drilling fluid
systems to drill the reservoir section.24 Using a
permeability plugging tester, laboratory analysts
tested cores for mudcake competency.25 These
results were used to design an efficient sealing
fluid with minimal damage for objective sands.
These new drilling technologies, in combination,
allowed the drilling times for each well in this
field to go from an average of 30 days per well in
2011 to 22 days in 2014.
Separate teams have been created for the
construction of new well completions and for
well interventions. The well completions team
investigated intelligent completion technologies and, specifically, compact concentric intelligent completions.
56
The success of this operation relies on the
accuracy of drilling targets defined by the subsurface team. Engineers log the wells with LWD and
wireline tools. A rapid turnaround of petrophysical evaluation provides engineers with the necessary data to quickly design the casing program
and to choose perforation depths.
The CSSFD JV also applies advanced completion technologies to reduce formation damage by
designing completion fluids according to core
flow tests, mineralogy and compatibility with the
reservoir. For example, the completion team has
applied perforating techniques such as the
PURE clean perforations system, CLEANPERF
noninvasive perforating fluid and P3 PURE postperforating controlled implosions to clean out
perforations.26 Application of these techniques
and tools helped reduce formation damage from
a skin factor of 6 to that of 1 (see “Perforating
Innovations—Shooting Holes in Performance
Models,” page 14). Hydraulic fracturing has been
used successfully in some of the wells completed
in the upper Napo U submember to enhance production; this completion technique adds another
level of complexity to the operations.
Since 1994, Agencia de Regulación y Control
Hidrocarburífero (ARCH)—the hydrocarbon
regulatory authority in Ecuador—has prohibited
commingling of oil recovered from the reservoirs
in the T and U members of the Napo Formation
with that from the basal Tena Formation member. Most of the wells in Shushufindi have been
completed in both the T and U sands, and to
abide by ARCH regulations, the sands are produced sequentially.
This practice is not conducive to optimizing
incremental production because it defers oil
production; therefore CSSFD evaluated wells
to identify candidates for installing the
IntelliZone Compact modular multizonal management system for intelligent completions.27
This technology allows simultaneous flow and
metering of multiple reservoir zones (left). The
system includes downhole pressure and temperature sensors and provides surface measurements
of oil, gas and water production. These capabilities enable the CSSFD JV to assign production to
each sand and thus satisfy requirements imposed
by ARCH. In addition, engineers at the AIM center continuously monitor the intelligent completion system to identify the behavior of producing
intervals and to make adjustments accordingly.
In December 2013, after a year of study, engineers began installing the IntelliZone Compact
system in the SSF-136D well according to the program objectives prescribed by CSSFD. The following project objectives were established:
• Produce T and U sands simultaneously
• Perform pressure buildup tests in one sand
while flowing from the other sand
• Provide accessibility for independent stimulations
• Configure the well for faster ESP replacements
• Perform rigless pressure buildup analysis
surveys
• Continuously monitor real-time flowing bottomhole pressures and temperatures at CSSFD
offices and the AIM center
• Allow downhole chemical injection at the
sandface
• Isolate sands during workovers to minimize formation damage
• Reduce the footprint of well operations.
Oilfield Review
Following installation, engineers tested the
system’s features. They performed individual
production tests in the T and U sands using the
IntelliZone Compact downhole chokes in the
two-thirds open and full open positions while
monitoring flowing pressures and temperatures
with the IntelliZone Compact sensors and
redundant gauges. Technicians monitored surface flow rates using Vx multiphase well testing
technology and later performed pressure buildups in the lower T and U zones.28 Oil production
from the sands was 700 and 350 bbl/d [110 and
56 m3/d], respectively.
The workover team evaluated wells across the
field to identify wells with high water cut and low
oil production. Engineers then devised a suitable
solution set and ranked the workover candidates.
Schedulers assigned wells to workover rigs and
coordinated operations with a new well drilling
schedule that avoided having rigs on the same
pad simultaneously.
Pilot Waterflood
As stated in the requirements of the contract,
the CSSFD JV must conduct a waterflood pilot
project. Accordingly, the consortium planned and
is on schedule to start water injection during the
fourth quarter of 2014. Two areas of the central
producing region of Shushufindi field were
selected for conducting waterflood pilots.
Reservoir zones in the lower Napo U submember,
in which oil production rates and reservoir pressures have declined to subeconomic levels, are
the target horizons.
At the start of the CSSFD contract, the existing nominal distance between injection and production wells was approximately 600 to 800 m
[1,970 to 2,620 ft], resulting in pattern areas of
about 125 acres; the size of the area depended on
the pattern configuration. Because the team
deemed this pattern area too large, it reviewed
smaller pattern areas with closer well spacing in
an effort to select injection sites that represent
the typical lower U reservoir in the central area.
The JV team decided that pattern injection—
instead of peripheral, or flank, injection from
down structure—was more suitable because pattern injection has better injection efficiency and
flexibility and faster response time, which allow
it to be modified easily. The team also decided to
retain the 125-acre pattern area for the pilots.
In May 2012, CSSFD engineers selected two
locations in central Shushufindi to conduct
waterflood pilots; Pilot Area 1 (PA1) contains
three contiguous inverted five-spot patterns
and, to its south, Pilot Area 2 (PA2) is a single
Autumn 2014
N
Pilot Area 1
Shut-in
Producer
Injector
Abandoned
Pilot Area 2
0
m
0
2,500
ft
10,000
> Waterflood pilot area wells. Two waterflood pilot areas have been selected in
the central production area of the Shushufindi field. Pilot Area 1 contains three
adjoining inverted five-spot patterns. To its south, Pilot Area 2 is a single pattern,
which is on hold because the CSSFD JV is considering it for an EOR pilot.
125-acre pattern (above).29 The recovery factors
for PA1 and PA2 are about 20% and 27% OOIP,
respectively. The CSSFD engineers evaluated
the use of 30-acre [0.121-km2] and 60-acre pattern areas and decided to preserve the current
600- to 800-m pattern spacing. To ensure that
PA1 and PA2 conformed to this spacing, the
team had to drill six wells in PA1 and two wells in
PA2. The wells will drain the reservoir in the
lower T submember under primary conditions
24. Skin is a term used in reservoir engineering theory to
describe the restriction to fluid flow in a geologic
formation or well. Positive skin values quantify flow
restrictions, whereas negative skin values quantify flow
enhancements.
25. A permeability plugging tester is a device used to
evaluate filtrate development over time as well as
assess mudcake thickness and appearance. Results
from this test allow engineers to evaluate the potential
for fluid invasion into formations.
26. For more on PURE technology: Bruyere F, Clark D,
Stirton G, Kusumadjaja A, Manalu D, Sobirin M,
Martin A, Robertson DI and Stenhouse A: “New
Practices to Enhance Perforating Results,”
Oilfield Review 18, no. 3 (Autumn 2006): 18–35.
For more on perforating fluids: Behrmann L, Walton IC,
Chang FF, Fayard A, Khong CK, Langseth B, Mason S,
Mathisen A-M, Pizzolante I, Xiang T and Svanes G:
“Optimal Fluid System for Perforating,”
Oilfield Review 19, no. 1 (Spring 2007): 14–25.
27. Rodriguez JC, Dutan J, Serrano G, Sandoval LM,
Arevalo JC and Suter A: “Compact Intelligent
Completion: A Game Change for Shushufindi Field,”
paper SPE 169483, presented at the SPE Latin American
and Caribbean Petroleum Engineering Conference,
Maracaibo, Venezuela, May 21–23, 2014.
For more on intelligent completions: Dyer S,
El-Khazindar Y, Reyes A, Huber M, Raw I and Reed D:
“Intelligent Completions—A Hands-Off Management
Style,” Oilfield Review 19, no. 4 (Winter 2007/2008): 4–17.
For more on the IntelliZone Compact modular
multizonal management system: Beveridge K, Eck JA,
Goh G, Izetti RG, Jadid MB, Sablerolle WR and
Scamparini G: “Intelligent Completions at the Ready,”
Oilfield Review 23, no. 3 (Autumn 2011): 18–27.
28. For more on Vx multiphase well testing technology:
Atkinson I, Theuveny B, Berard M, Conort G, Groves J,
Lowe T, McDiarmid A, Mehdizadeh P, Perciot P,
Pinguet B, Smith G and Williamson KJ: “A New Horizon
in Multiphase Flow Measurement,” Oilfield Review 16,
no. 4 (Winter 2004/2005): 52–63.
29. A five spot is a quadrilateral injection pattern that
comprises four injection wells at the corners and a
production well in the center. An inverted five spot has
production wells at the corners and the injection well in
the center.
57
ments. Because of the long lead times required
for the facility design, material fabrication, delivery and installation, the facilities group needed
to have a general plan for water quality specifications and injection volumes. The CSSFD JV has
constructed a water treatment plant that treats
40,000 bbl/d of water that is in compliance with
water quality specifications (left). The anticipated start of injection is during the fourth quarter of 2014.
> State-of-the-art water treatment plant for the waterflooding pilot.
and serve as injectors into the lower U submember, avoiding casing and cementing problems that
may have occurred if older wells had been used.
The SSFD-151D well was drilled and cored in
June 2012; the core was delivered to the
Schlumberger Reservoir Sampling and Analysis
laboratory in Houston in August 2012. Core testing indicated that rock quality, initial water saturation, wettability and heterogeneity varied by
reservoir zone. The CSSFD team concluded that
conventional injection string designs would not
be satisfactory nor would they meet the requirements to maximize injectivity by zone, increase
vertical efficiency and control injection rates by
zone; achieving these objectives would require
pulling the injection string. Injection in PA2 has
been halted while the CSSFD JV considers it for
an EOR pilot.
Early in the contract, CSSFD recognized that
the existing facilities were inadequate to handle
the water injection volume and quality require-
80
Oil production rate, 1,000 bbl/d
2014 NW
2013 NW
2012 NW
2014 WO
2013 WO
2012 WO
Baseline
60
40
20
0
Feb 2012
Aug 2012
Feb 2013
Aug 2013
Feb 2014
Revived Giant
In the nearly three years since the contract began,
the partnership between Consortium Shushufindi
and the field’s operator, Petroamazonas EP, has
successfully reversed the field’s more than 20-year
decline. Since February 2012, oil production has
increased by more than 60%, from 45,000 bbl/d to
75,000 bbl/d (below left).
The foundation of this rapid turnaround is the
dedicated integrated team of technical and operational experts working with Petromazonas EP
professionals in the field and in the Quito offices.
In addition to providing new reservoir insight,
the team focused on introducing select technologies to the field that improved operational
efficiencies and addressed the subsurface uncertainties. As a result, production has increased
throughout the field. The CSSFD JV established
an AIM center to coordinate continuous realtime monitoring across all operations in the
Shushufindi field. Workover, drilling and completion operations are remotely monitored to
increase safety, anticipate problems, maximize
efficiency and minimize nonproductive time.
The steps that the consortium has taken and
the technologies that it has used to revive
Shushufindi and regain control of its production
have helped the consortium attain its contractual
objective of optimizing incremental production.
In the years ahead, the CSSFD JV will continue
its drilling and IntelliZone Compact completion
strategy, expand secondary recovery waterflooding operations to the entire field and evaluate the
potential for EOR. The giant Shushufindi, rescued from its continued decline, has been given
new life and a brighter future.
—RCNH
Aug 2014
Date
> Proportioning oil production. Total oil production has risen since the contract began in January 2012.
Baseline oil production is in gray. Incremental oil production has been broken out by the year and
divided between workover (WO) activity and drilling and completing active new wells (NW). The largest
and increasing contribution to incremental oil production came from drilling and completing new wells
and from decreasing well spacing. The secondary contribution from workovers has been steady at
about 10,000 bbl/d [1,590 m3/d] since January 2013.
58
Oilfield Review
Contributors
Santiago Pablo Baggini Almagro, based in
Neuquén, Argentina, is a Lost Circulation Control
Champion and Cementing Lead Technical Engineer.
He started his Schlumberger career as a cementing
field engineer in 2010; in subsequent positions he has
contributed to tender preparations and helped introduce new technologies. Santiago obtained a BS
degree in chemical engineering from Universidad
Nacional de Córdoba, Argentina.
Carlos Baumann is a Principal Research Engineer at
the Schlumberger Reservoir Completions Technology
Center in Rosharon, Texas, USA. In 1988, he was a
research fellow at the National Scientific and
Technical Research Council at the Instituto de
Desarrollo Tecnológico, Santa Fe, Argentina. He then
spent two years as a research engineer with Industrias
Metalúrgicas Pescarmona, Mendoza, Argentina. From
1992 to 1997, he was a researcher in computational
mechanics at The University of Texas at Austin. He
then worked as a senior engineer for Altair
Engineering in Austin before joining Schlumberger in
2008. His projects at Schlumberger include the development of the SPAN* PURE* planner and SPAN gun
shock software. He received a mechanical engineering
degree from the Universidad Nacional de Rosario,
Argentina, and a PhD degree in engineering science
and mechanics from The University of Texas at Austin.
Daniel F. Biedma is Production Engineering and
Reservoir Surveillance Manager for Consorcio
Shushufindi and for Tecpetrol SA in Quito, Ecuador.
He began his career in 1995 with Tecpetrol in
Argentina as a reservoir engineer working on projects
related to naturally fractured gas condensate fields
and volatile oil fields. After six years, he joined the reservoir simulation team responsible for black oil and
pseudocompositional simulations. He then became reservoir manager of Tecpetrol southern operations and
was responsible for full field development and several
secondary and enhanced oil recovery projects. More
recently, he has been technical and operational manager for Tecpetrol operations in Venezuela, in charge of
exploration and production related to the Empresa
Mixta project with Petróleos de Venezuela SA. Daniel,
who is a member of the SPE and has authored, coauthored and presented many technical papers, holds a
BSc degree in petroleum engineering from Universidad
Nacional de Cuyo, Mendoza, Argentina.
Chip Corbett is the Director of Curriculum for
Reservoir Engineering Training with Schlumberger
Information Solutions (SIS) and is an Advisor for reservoir simulation and subsurface model construction;
he is based in Houston. He began his career with
Schlumberger as a wireline field engineer in 1981,
moved to SIS in 1990 and joined PetroTechnical
Services in 1996. He has applied his knowledge of
diverse depositional environments to multidiscipline,
integrated field studies for many projects worldwide,
most recently on the Shushufindi oil field in Ecuador.
Chip earned a BS degree in mechanical engineering
from the University of California, Berkeley, USA, and a
master’s degree in petroleum engineering from the
University of Houston.
Autumn 2014
Amine Ennaifer is a Senior Reservoir Engineer with
Schlumberger Testing Services in Clamart, France. He
is involved in the simulation of naturally fractured reservoirs and provides support to testing operations and
engineering. He began his career with the company in
2005 as a mathematician at the Schlumberger Riboud
Product Center in France. Subsequently, he joined the
Schlumberger Dhahran Carbonate Research Center in
Saudi Arabia, working as a research scientist in geophysical modeling. He then turned his mathematics
skills to reservoir modeling and simulation and interpretation support for pressure transient analysis.
Amine received a diplome grande école in applied
mathematics from Ecole Centrale de Paris.
Alfredo Fayard, based in Rosharon, Texas, is a
Perforating Advisor and an Engineering Manager at
the Schlumberger Rosharon Production Services
Center. He manages product development, focusing on
perforating technologies for well intervention, stimulation and completions. He started his career as a wireline field engineer in 1979 and since then has served
in sales, management and training and development
positions in South America and Europe. In 1996, he
moved to the Schlumberger Rosharon Production
Services Center to manage RapidResponse* product
development for perforating products. He next became
the global perforating domain champion in Houston,
providing worldwide technical support for cased hole
completions and was then appointed business development manager in Mexico, where he provided technical
perforating support to Latin American operators. He is
an active member of the SPE and is author and coauthor of several papers. Alfredo has an engineering
degree in electronics and control systems from
Universidad Tecnológica Nacional in Buenos Aires.
Cliff Frates is a Drilling Engineer for Dorado E&P
Partners in Denver. He recently moved from Apache
Corporation in Tulsa, where he was responsible for the
operation of three drilling rigs in the Anadarko basin.
Previously, he was an MWD/LWD and directional driller
with the Schlumberger Drilling & Measurements
Segment for two years in Oklahoma City, Oklahoma, USA.
Cliff earned a BS degree in economics from Hillsdale
College, Michigan, USA, and a BS degree in civil engineering from Oklahoma State University, Stillwater.
Jeremy Garand is a Schlumberger Well Services
Marketing and Sales DESC* design and evaluation services for clients engineer in Tulsa. He works with engineers at the Apache Corporation, providing sales and
marketing support for the PressureNET* lost circulation treatment. He started his career as a cementing
field engineer in 2007 and has held various positions in
the field and in operations support. Immediately prior
to his current position, he was the Well and Completion
Services service manager in Strasburg, Ohio, USA,
where he was responsible for new well services in the
area. Jeremy holds a BS degree in mechanical engineering from The Pennsylvania State University,
University Park, USA.
Palma Giordano, based in Clamart, France, is the
Downhole Measurement Product Champion for
Schlumberger Testing Services. Her responsibilities
include promoting and supporting new sensors for
downhole testing and wireless telemetry. She joined
the company in 2005 in Caracas and has served in field
operations and management positions in Brazil,
Scotland and the Democratic Republic of Congo.
Before assuming her current position, she was a training instructor at the Schlumberger Europe Learning
Center in Paris. Palma received a bachelor’s degree in
chemical engineering from Universidad Simón Bolívar
in Caracas.
Francisco Giraldo is a Petroleum Engineer with
Schlumberger in Quito, Ecuador. He has 33 years of
experience in the oil and gas industry with a background in oilfield operations and asset management;
he has worked for national oil companies, international oil operators and oilfield service companies.
For the last 19 years, he has held project and asset
management positions in various countries in South
America, North America and Europe as well as in
Russia and Libya. He has authored and coauthored
technical projects that received six bronze, three
silver, one gold and one Chief Executive Officer’s
Performed by Schlumberger awards. Francisco
obtained a bachelor’s degree in petroleum engineering
from Fundación Universidad de América, Bogota,
Colombia, a project management professional diploma
from Project Management Institute and a diploma
in risk analysis and uncertainty management in production and exploration projects from Reliability
Risk Management.
Amit Govil joined Schlumberger in 1993 as a field
engineer. During his nine years in the field, he worked
with a variety of clients using cased hole technologies
in India and Qatar. In 2003, he began supporting operations as a cased hole domain champion in India.
Since 2007, he has been a Principal Perforation and
Production Domain Champion for Scandinavia and is
currently based in Tananger, Norway. He has authored
multiple technical papers and is active in the SPE and
the Intervention and Coiled Tubing Association. Amit
has a bachelor’s degree in production engineering
from the University of Pune, India.
Brenden Grove is Principal Engineer and Client
Testing Program Director for Perforating at
Schlumberger Reservoir Completions Technology
Center (SRC) in Rosharon, Texas. His main responsibilities include delivering client-driven perforating
research and technology test programs to optimize
completion and well performance. He began his career
in 1991 as an R&D engineer with Orlando Technology
Inc. in Shalimar, Florida, USA, working on development
testing and numerical design and evaluation of conventional weapons components and systems, including
shaped charges. In 1996, he joined the Schlumberger
Perforating and Testing Center in Rosharon as a product development engineer working on PowerFlow* and
PowerJet* shaped charges. Later, as a research engineer, he worked on the PowerSpiral* gun system,
MultiFlow* charges and low- and zero-debris perforating systems. He subsequently focused his research on
the interactions between perforating systems and the
reservoir, with emphasis on minimizing well skin.
59
Before taking his current position in 2013, he managed
the Schlumberger Perforating Technology and
Advanced Studies groups, which developed the first
members of the PowerJet Nova* charge family,
SPAN Rock* program and related supporting models.
Author of numerous papers and holder of many patents, Brenden received a BS degree from the University
of Florida, in Gainesville, and an MS degree from the
University of Houston, both in mechanical engineering.
Jeremy Harvey, Senior Research Scientist for the
Schlumberger Perforating Research Department in
Rosharon, Texas, is the author of the stressed rock
penetration depth model and the dynamic underbalance skin model, which are essential parts of the
SPAN Rock perforating analysis program. Since joining
Schlumberger in 2007, he has worked with the
Productivity Enhancement Research Facility in
Rosharon, performing internal testing of perforating
charges as well as assisting with charge testing for
clients. Before joining Schlumberger, Jeremy was an
assistant research professor of mechanical engineering at the University of Alabama, Birmingham, USA.
Prior to this position, he worked for Raytheon Space
and Airborne Systems, where he conducted his
doctoral research on applications of cryogenic refrigeration. Jeremy holds BS, MS and PhD degrees in
mechanical engineering from the Georgia Institute of
Technology, Atlanta, USA.
Jean-Paul Lafournère is a Principal Reservoir
Petrophysicist and Data Acquisition Specialist in
charge of reservoir characterization for Schlumberger
and Consorcio Shushufindi in Quito, Ecuador. He
began his career with Schlumberger 25 years ago as a
wireline field engineer. Ten years later, he became the
interpretation and development senior petrophysicist
for West Africa. Since then, he has had multiple positions in geosciences, management, business development and marketing. More recently, he has served as
senior petrophysicist and data acquisition specialist
for ultradeepwater exploration well visualization, conceptualization and definition on the Perdido fold belt
offshore Mexico; as geology and geophysics manager
for the Laboratorio Integral de Campo Agua-Fria project within the Chicontepec oil field, Mexico; and as
leader for selective water injection optimization in the
Casabe oil field in Colombia. Jean-Paul, who is author
and coauthor of many technical papers and is a member of the SPE and SPWLA, earned a master’s degree
in geology from Université de Montpellier 2, Sciences
et Techniques, France, and a mining and petroleum
exploration engineering degree from Ecole Nationale
Supérieure de Géologie de Nancy, France.
Gustavo Ariel Marín is a Schlumberger Petroleum
Engineer in Quito, Ecuador. He has 18 years of experience in the oil and gas industry with a background in
operations management, oilfield operations, production
engineering, reservoir engineering and field development planning. For the last 14 years, he has served in
operations, technical and project management positions
in Argentina, the US, Mexico and Ecuador. He has
authored and coauthored many technical publications
and presented at various international conferences.
Gustavo obtained a bachelor’s degree in petroleum engineering from Universidad Nacional del Comahue,
Neuquén, Argentina, and a diploma in project management from Instituto Tecnológico y de Estudios
Superiores de Monterrey, Mexico.
60
Andy Martin, who is the Schlumberger Advisor and
Global Perforating Domain Champion in Cambridge,
England, provides technical support to the Schlumberger
perforating businesses and to Schlumberger customers. After joining Schlumberger Wireline as a field
engineer in 1979, he had various field assignments,
mainly in the Middle East. In 1990, he became a staff
engineer at the Wireline & Testing headquarters in
Montrouge, France, before becoming production services tutor at the British Training Centre in Livingston,
Scotland. His varied work experience includes assignments as an editor for Oilfield Review and as a staff
engineer in the marketing group at the Schlumberger
Rosharon Campus, Texas. Before taking his current
position in 2007, he was Schlumberger perforating
domain champion for the North Sea region. Author of
several papers and holder of several patents, Andy has
a master’s degree in engineering science from the
University of Oxford, England.
Roberto Franco Mendez García, based in Agua
Dulce, Veracruz, Mexico, is the Coordinator of the
Petróleos Mexicanos Multidisciplinary Design and Well
Intervention Group (GMDIP) for the Cinco Presidentes
field. He has more than 26 years of oil industry experience. Prior to his current position, he was in charge of
GMDIP in Comalcalco, Mexico, coordinating high-pressure, high-temperature drilling and workover operations. His responsibilities include designing, coordinating
and evaluating the drilling of new and workover wells.
Roberto Franco earned BSc and MSc degrees in petroleum engineering from the Universidad Nacional
Autónoma de México, Mexico City.
Arnoud Meyer is a Well Integrity Technology Product
Champion in Clamart, France. He began his career
with Schlumberger in 1998 as a Well Services field
engineer in northwest Siberia and has since held various operations, sales, marketing and management
positions throughout Europe, Russia and Asia.
Jock Munro is Schlumberger Perforating Domain
Champion for Europe and Africa; he specializes in perforating solutions for efficiency and maximized well
productivity. Previously, from his location in Aberdeen,
he provided technical support for perforating operations in the North Sea. Jock joined Schlumberger in
Australia in 1990; he has a background in electric line,
completions and perforating. He has held various positions, including FIV* formation isolation valve product
champion at the Schlumberger Reservoir Completions
Technology Center in Rosharon, Texas, and perforating
technical sales for Brunei, Malaysia and the Republic
of the Philippines.
Pedro R. Navarre is Digital Oilfield Manager for
Schlumberger and Consorcio Shushufindi in Quito,
Ecuador. He is responsible for the Consorcio
Shushufindi Asset Integrated Management center. He
began his career with Dowell Schlumberger 25 years
ago as a field engineer working on cementing, fracturing and coiled tubing operations. He moved to well
completions and productivity operations 12 years later
and held technical and marketing positions implementing the ProductionWatcher* business for the
deepwater North Gulf Coast area in the US. Five years
later, he joined PetroTechnical Services and has held
management positions in Mexico, UAE and Colombia.
He has been in his current position with Schlumberger
Production Management since 2012. Pedro received
a BSc degree in mechanical engineering from
Universidad de Buenos Aires and a postgraduate certificate in petroleum engineering from the University
of Tulsa.
Bengt Arne Nilssen, based in Houston, is the Marketing
Communications Manager for Schlumberger Testing
Services. He began his career with the company in
Norway in 1997 as a field specialist in surface well testing. He served in field operations management positions
in the US and Australia then became the training and
development manager for Testing Services at the Paris
headquarters. Before taking his current position in
2013, Bengt was the Schlumberger testing services operations manager for the North Sea GeoMarket* area. He
studied economics and organizational theory at the
University of Bergen, Norway, and computer science at
Høgskolsenteret Rogaland in Stavanger.
Ifeanyi Nwagbogu, who is based in Lagos, Nigeria, is
the Operations Manager for Schlumberger Testing
Services for the West Africa region. After joining the
company as a field engineer in Paris in 2001, he held
field operations positions in Tunisia and Saudi Arabia
and then was a field services manager and project
manager for development and exploration projects in
Gabon and Ghana. He moved to Paris as product
champion for Muzic* wireless telemetry in 2011 and
assumed his current position in August 2014. Ifeanyi
holds a bachelor’s degree in electronics engineering
from the University of Benin, Nigeria.
Arturo Ramirez Rodriquez is the Cinco Presidentes
Asset Manager for Petróleos Mexicanos (PEMEX); he
is located in Agua Dulce, Veracruz, Mexico. He started
his career with PEMEX in 1983 as petroleum engineer.
Before taking his current position, he had several management positions in the Muspac and Bellota assets.
Prior to that, he was responsible for designing, coordinating and evaluating the drilling of new wells and
served in the technical information group for well
development. He has more than 31 years of oil industry
experience. Arturo is a member of the SPE and the
Asociación de Ingenieros Petroleros de México. He
has BS and MS degrees in petroleum engineering
from Universidad Nacional Autónoma de México,
Mexico City.
Andy Sooklal, Drilling and Completions Engineering
Manager for Maersk Oil Angola AS in Luanda, has
more than 15 years of experience in the upstream
hydrocarbon industry. He manages the well engineering function to support Maersk Oil drilling, completions and testing commitments for deepwater and
presalt exploration wells. Before moving to Angola in
2012, he worked for Maersk Oil in international operations in Denmark. He began his career as a petroleum
engineer with the Ministry of Energy in Trinidad and
Tobago, where he then spent five years in drilling
engineering positions with BHP Billiton. Andy earned
a BSc degree in mechanical engineering and an
MSc degree in petroleum engineering, both from
The University of the West Indies, St. Augustine,
Trinidad and Tobago.
Oilfield Review
Andreas Suter is the Exploitation Manager for the
Shushufindi Schlumberger Production Management
project in Ecuador; he is based in Quito. He is also a
Principal Geologist with Schlumberger and has
22 years of experience in the oil and gas industry in
Ecuador, Columbia, Mexico and Venezuela and in West
Africa and the Middle East. Previously, he was subsurface manager for the Schlumberger Ecopetrol Casabe
alliance. Since joining Schlumberger in 1992 as a geologist in Nigeria, he has managed data services, geologic data processing, multiwell geologic studies,
reservoir field characterization studies and technical
support for clients in West Africa, working closely with
international oil companies on the deepwater and offshore blocks of Angola and the Democratic Republic of
Congo. Andreas received a diploma in geology from
Université de Neuchâtel, Switzerland. He has authored
and coauthored many technical papers.
Stephane Vannuffelen is the Muzic Project Manager at
the Schlumberger Riboud Product Center in Clamart,
France; he has been in the position since 2008. He
joined the company in 1996 to work on cement studies
at the Dowell Schlumberger support laboratory in
Aberdeen. He then worked as an R&D physics engineer
and project leader in Montrouge, France, and in
Clamart developing gas meters. In 2003, he moved to
the Schlumberger KK Technology Center, Japan, and
worked on the design of the InSitu Fluid Analyzer* system for the Wireline and Drilling & Measurements
Segments. Stephane obtained a diplôme grande école in
physics from the Ecole Supérieure de Physique et de
Chimie Industrielles in France.
Ivan Vela is a Petroleum Engineer for Petroamazonas
EP in Quito, Ecuador. He has 25 years of experience in
the oil and gas industry, both offshore and onshore, with
a background in operations management, well workovers, production engineering and field development.
For the last fifteen years, he has held positions in operations management, water reinjection projects, workover
management and project management in Canada,
Brazil, Peru and Ecuador. Ivan holds a bachelor’s degree
in petroleum engineering from Universidad Central del
Ecuador in Quito, an MBA from Universitat Autònoma
de Barcelona, Spain, and a diploma in probabilistic
analysis of risk in production projects from Instituto
Tecnológico de Monterrey, Mexico. He has authored and
coauthored many technical papers and presented at
various international conferences.
Cesar Velez Terrazas is the Schlumberger Oilfield
Services Account Manager in Villahermosa, Tabasco,
Mexico. He is responsible for new opportunities and
development programs. After joining Dowell
Schlumberger as a cementing and stimulation field
engineer in 1985, he held various field assignments,
mainly in southeast Mexico. In 1994, he moved to drilling fluid services and was in charge of developing the
first Schlumberger drilling fluid business in
Villahermosa. After an assignment in Maracaibo,
Venezuela, he returned to Mexico as a Schlumberger
Information Services account manager and was
responsible for the Productivity Project in southern
Mexico. From 2008 to 2010, he was sales manager for
WesternGeco operations. Cesar earned an industrial
engineering degree from the Instituto Tecnológico de
Chihuahua, Mexico, and an MA degree in marketing
from Universidad del Valle de México, Mexico City.
Guillermo Villanueva is the Well Intervention
Manager for Schlumberger Integrated Project
Management and Consorcio Shushufindi in Quito,
Ecuador. Of his 25 years of experience in the industry,
he has worked for Schlumberger for 13 years as an
advisor on completion and workover design, production and reservoir engineering and technical and operations management. He has applied his expertise in
sand control, stimulation and fracturing in horizontal
wells to projects in Venezuela, Mexico, Brazil and
Ecuador. Guillermo has a postgraduate diploma in
petroleum engineering from Universidad Nacional de
Ingeniería, Lima, Peru. He has authored and coauthored many technical papers and holds patents in
completion sandface equipment.
Carl Walden is the Well Testing and Completions
Superintendent in the development-exploitation
department for Maersk Oil Angola AS in Luanda, Angola.
Wenbo Yang is an Energetics and Well Productivity
Principal Engineer at the Reservoir Completions
Technology Center in Rosharon, Texas. He is responsible for developing new perforating products and
technology. Since joining the shaped charge engineering group in 1995, he has worked in design, engineering, rapid response, research, perforating technology
and energetics groups, focusing on explosive products
and technology for perforating applications. He was a
member of the design teams that developed PowerJet
technology, end-to-end ballistic transfer systems, the
OrientXact* tubing-conveyed oriented perforating
system, the PowerSpiral spiral-phased perforating
system, PURE technology and PowerJet Nova technology. Author of more than a dozen papers and
holder of more than a dozen patents, Wenbo received
BS and MSc degrees in engineering physics from the
Beijing Institute of Technology and MSc and PhD
degrees in geophysics from the California Institute of
Technology, Pasadena.
Lang Zhan is a Research Reservoir Engineer in the
unconventional gas and tight oil department at Shell
International Exploration and Production Inc., Houston.
From 2001 to 2012, he was a senior reservoir engineer
at the Schlumberger Rosharon Campus in Texas,
where he worked on dynamic reservoir evaluations,
perforating software development and coupled geomechanical and reservoir modeling for Schlumberger
Testing Services and the advanced perforating studies
research group. Lang holds BS and MS degrees in engineering mechanics from Tsinghua University in Beijing
and a PhD degree in petroleum engineering from the
University of Southern California in Los Angeles.
An asterisk (*) denotes a mark of Schlumberger.
Coming in Oilfield Review
Seismic Guided Drilling. Drilling is fraught with
uncertainty that arises from incomplete knowledge
about the subsurface geology, geophysics, mechanical
properties, in situ stresses, pressures and temperatures of a drilling prospect. What is known about a
drilling prospect is estimated from seismic and offset
well data—well logs, cores, well tests and drilling
reports. Reducing these uncertainties and associated
risks is a key industry driver. Seismic guided drilling is
an integrated process that generates predictive structural and pore pressure models ahead of the bit by
honoring seismic reflection data and all the data from
the well being drilled.
Autumn 2014
Integration for Deepwater Operations. To meet
the demands of operating in deep water, the E&P
industry sought and adapted numerous, sometimes
radical, innovations in a relatively short time. As
operators move into ultradeep water, the industry will
need to embrace the long discussed but rarely practiced concept of cross-discipline integration.
Wireline Logging Cable Innovation. Other than
introducing stronger components, wireline logging
cable designers have made few changes over the
past several decades. Deep and ultradeep well logging have revealed shortcomings in traditional cable
designs that threaten wireline data acquisition in
deepwater offshore environments. Engineers have
developed and recently introduced a new cable design
that addresses many of the weaknesses associated
with traditional logging cables. Complementary downhole and surface equipment have also been developed
to facilitate deep and ultradeep well logging.
Interactions Between Wildlife and E&P
Activities. Operators, who are expanding their
quest for extractable oil and gas reserves, must follow regulations that guard the environment against
potential adverse effects. Because of the presence
of human-made sounds, light and installations on
both land and sea, interactions between the E&P
industry and the Earth’s wildlife are unavoidable.
Decades of research and observations have been
devoted to evaluating the environmental impact on
various species such as migratory birds, fish and
marine mammals. Results from these studies are
being heeded and applied by the industry to curtail
potential negative impacts on wildlife.
61
BOOKS OF NOTE
useful primer for those who need to
produce infographics.
“Winds of Change: A Revolution Is Taking
Place in How to Visualise Information,”
The Economist 407, no. 8843 (July 6, 2013):
81–82.
‡PowerPoint is a registered trademark of Microsoft
Corporation in the US and/or other countries.
Curious: The Desire to Know
and Why Your Future Depends
on It
Ian Leslie
Basic Books, a Member of
The Perseus Books Group
250 West 57th Street, Suite 1500
New York, New York 10107 USA
2014. 240 pages. US$ 26.99
ISBN: 978-0-465-07996-4
Easy access to information via the
Internet does not guarantee the growth
of curiosity and in fact stifles it, argues
author Ian Leslie, because instantaneous answers do not beget insight and
innovation, characteristics of a sustained quest for understanding—which
he defines as true curiosity. The author
examines what feeds curiosity and what
starves it by drawing on research from
psychology, economics, education and
business; he balances his research with
stories, case studies and practical advice.
Contents:
• How Curiosity Works: Three
Journeys; How Curiosity Begins;
Puzzles and Mysteries
• The Curiosity Divide: Three Ages of
Curiosity; The Curiosity Dividend;
The Power of Questions; The
Importance of Knowing
• Staying Curious: Seven Ways to
Stay Curious
• Afterword: Bjarni
• Notes, Bibliography, Index
Leslie . . . writes convincingly . . .
about the human need and desire to
learn deeply and develop expertise.
Broughton PD: “Book Review,” The Wall Street
Journal (September 4, 2014), http://online.wsj.com/
articles/book-review-curious-by-ian-leslie-1409872348
(accessed September 23, 2014).
A searching examination of
information technology’s impact
on the innovative potential of
our culture.
“Book Review,” Kirkus Review (June 30, 2014),
https://www.kirkusreviews.com/book-reviews/
ian-leslie/curious-desire-to-know/ (accessed
September 24, 2014).
62
Data Points: Visualization that
Means Something
Nathan Yau
John Wiley & Sons
10475 Crosspoint Boulevard
Indianapolis, Indiana 46256 USA
2013. 320 pages. US$ 39.99
ISBN: 978-1-118-46219-5
Data analysis becomes storytelling in
the hands of author Nathan Yau, who
explores the intersection of data and
design. Yau uses art, design, computer
science, statistics, cartography and
online media to help viewers visualize
the stories data tell and to help those
who use data find new ways to illustrate
such data.
Experimenting on a Small Planet:
A Scholarly Entertainment
William W. Hay
Springer-Verlag
Heidelberger Platz 3
14197 Berlin, Germany
2013. 983 pages. US$ 27.95
ISBN: 978-3-642-28559-2
Contents:
• Understanding Data
• Visualization: The Medium
• Representing Data
• Exploring Data Visually
• Visualizing with Clarity
• Designing for an Audience
• Where to Go from Here
• Index
A detailed handbook, Data Points
is especially useful for those working
on scientific data visualization,
guiding the reader through fascinating examples of data, graphics,
context, presentation and analytics.
But this is more than a mere how-to
manual. Yau reminds us that the real
purpose of most visualization work is
to communicate data to pragmatic
ends. . . . There is much to learn from
studying what Yau does here.
Frankel F: “Drawing Out the Meaning,”
Nature 497, no. 7448 (May 9, 2013): 186.
Mr Yau’s book does an excellent
job of explaining what makes a good
data illustration. In the past, this
would have been the sort of stuff that
might appeal to graphic designers.
But today every professional interacts
with data and charts, be it by poring
over a spreadsheet, watching a
PowerPoint‡ presentation or reading
a newspaper. . . . Data Points is a
In this introduction to climate science
and global climate change, the author
posits that human activity has played a
role in climate change not just through
the past few hundred years, but
throughout the past few millennia. The
book—which begins with the basics in
physics, chemistry and biology as
related to climate change then transitions to climate science specifics—is
intended for both the general public
and scientists.
Contents:
• The Language of Science
• Geologic Time
• Putting Numbers on Geologic Ages
• Documenting Past Climate Change
• The Nature of Energy Received
from the Sun: The Analogies with
Water Waves and Sound
• The Nature of Energy Received
from the Sun: Figuring Out What
Light Really Is
• Exploring the Electromagnetic
Spectrum
• The Origins of Climate Science:
The Idea of Energy Balance
• The Climate System
• What’s at the Bottom of Alice’s
Rabbit Hole
• Energy from the Sun: Long-Term
Variations
• Solar Variability and Cosmic Rays
• Albedo
• Air
• HOH: The Keystone of Earth’s
Climate
• The Atmosphere
• Oxygen and Ozone: Products and
Protectors of Life
• Water Vapor: The Major
Greenhouse Gas
• Carbon Dioxide
• Other Greenhouse Gases
• The Circulation of Earth’s
Atmosphere and Ocean
• The Biological Interactions
• Sea Level
• Global Climate Change: The
(Geologically) Immediate Past
• Is There an Analog for the Future
Climate?
• The Instrumental Temperature
Record
• The Future
• Figure Sources, Index
. . . a highly readable tour through
the multidisciplinary science behind
Earth’s oceanographic and atmospheric warming and cooling on both
geologic and anthropogenic timescales, by a major contributor with a
phenomenal grasp of the whole. Here
are the diverse topics that comprise
all the sciences within that huge field,
each given a history and indepth
treatment with easily understood (but
not dumbed-down) explanations of
complex causes, effects, and
interactions.
Hamilton W: “Book Review,” GeoScientist 24,
no. 4 (May 2014): 22.
Hay presents clear explanations
and examples of climate chemistry,
physics and oceanography for professional scientists as well as teachers
and anyone interested in the scientific
underpinnings of the current paradigm shift in understanding climate
change. . . . Each chapter is a concise
explanation of a specific scientific
discipline of physics, chemistry,
geology, oceanography, and
climatology.
Scott RW: “Book Review,” AAPG Bulletin 97,
no. 12 (December 2013): 2257–2258.
Oilfield Review
DEFINING PERMEABILITY
Flow Through Pores
Richard Nolen-Hoeksema
Editor
Permeability, which is the capacity of a porous material to allow fluids to
pass through it, depends on the number, geometry and size of interconnected pores, capillaries and fractures (right). Permeability is an intrinsic
property of porous materials and governs the ease with which fluids move
through hydrocarbon reservoirs, aquifers, gravel packs and filters.
Permeability is defined in units of area, which relates to the area of open
pore space in the cross section that faces, or is perpendicular to, the direction of flowing fluid. In the International System of Units (SI), the unit for
permeability is m2. The common unit is the darcy (D) [about 10−12 m2]; this
unit is named for the French engineer Henry Darcy, who conducted experiments with water flowing through sand. These experiments led to the formulation of Darcy’s law, which describes the steady-state flow of fluid
through porous media. In most oilfield applications, the common unit is the
millidarcy (mD) [about 10−15 m2].
Permeability is not to be confused with mobility or with hydraulic conductivity. Mobility is the medium’s permeability divided by the dynamic
viscosity of the fluid flowing through the medium. Hydraulic conductivity,
or transmissivity, is the discharge, or effective, velocity of fluid flow
through the medium and is equal to the fluid flux—volume of fluid passing
through a cross section during a time interval—divided by the cross-sectional area. Mobility and hydraulic conductivity are collective characteristics that combine properties of the fluid with those of the porous medium.
Factors Affecting Permeability
In many materials, permeability is almost directly proportional to the material’s porosity, which is the fraction of the material’s total volume that is
106
Extremely well
0.840
0.590
0.420
Very well
Well
Sorting
Moderate
Permeability, mD
105
Poor
0.297 Median grain
0.210 size, mm
Very poor
0.149
104
0.105
0.074
103
102
20
25
30
35
40
45
50
Porosity, %
> Permeabilty as a function of porosity, grain size and sorting. Samples of
artificially mixed and packed sands were measured for porosity and
permeability. Each symbol corresponds to a particular grain size, and red
dotted lines connect similarly sorted packs. Permeability increases with
grain size and degree of sorting. Each data point represents an average
value of porosity and permeability. [Data from Beard DC and Weyl PK:
“Influence of Texture on Porosity and Permeability of Unconsolidated
Sand,” AAPG Bulletin 57, no. 2 (February 1973): 349–369.]
Oilfield Review Autumn 2014: 26, no. 3.
Copyright © 2014 Schlumberger.
> The importance of connectivity. Connected pores (green) give rock its
permeability, allowing fluid to flow (black arrows).
occupied by pores, or voids. However, this is not an absolute rule. Textural
and geologic factors determine the magnitude of permeability by increasing
or decreasing the cross-sectional area of open pore space. These factors
affect the geometry of the pore space and are independent of fluid type.
Materials formed from stacked arrays of identical solid spheres, be they
cannonballs, marbles or ball bearings, have equal porosities. However, the
pore cross-sectional areas differ dramatically; thus the permeabilities of
these arrays also differ dramatically. The permeability for rocks made of
large, or coarse, grains will be higher than those of small, or fine, grains
(below left).
Sorting is the range of grain sizes that occurs in sedimentary materials.
Well-sorted materials have grains of the same size, while poorly sorted materials have grains of many sizes. Permeability decreases as the degree of sorting varies from good to poor because small grains can fill the spaces between
large grains.
Permeability is also influenced by grain shape. Measures of grain shape
are sphericity, roundness and roughness. Sphericity is the degree to which a
grain’s shape approximates that of a sphere. Roundness relates to the amount
of smoothing of the grain surface, ranging from angular to round. Roughness
is the degree of texture on grains. Grain shape affects packing, the 3D
arrangement of grains. Variability in grain shape can prevent grains from
reaching their closest possible packing arrangement, which has an impact on
permeability. As the degree of packing increases from loose to tight, a single
grain contacts an increasing number of neighboring grains. Consequently, the
spaces between grains and the cross-sectional areas open to flow decrease,
leading to lower permeability.
Diagenesis is the alteration of a rock’s original mineralogy and texture.
Dissolution, dolomitization, fracturing or other rock-altering processes create
additional, or secondary, porosity that may increase permeability. Precipitation
of cement between mineral and rock grains decreases permeability. Clay minerals may form crystals that line pore walls or grow as fibers and plates that
bridge the pore volume. Authigenic interstitial clays, those that develop in
place between grains, may fill pore space and reduce permeability. Allogenic
clays, those that have been transported into pores, can plug them.
Stress and pressure increase as rocks are buried deep in sedimentary
basins. In response, the rock’s bulk and pore volumes are compressed, causing
permeability to decrease. Fluid pressures also affect permeability; an increase
in fluid pressure opens pores, while a decrease causes pores to close.
Most rocks exhibit some degree of permeability anisotropy, which is the
variation of permeability with direction. Grain sphericity and the presence of
fractures are factors that affect the directionality of permeability. Spherical
For help in preparation of this article, thanks to Mark Andersen and Denis Klemin, Houston.
Autumn 2014
63
DEFINING PERMEABILITY
grains form isotropic packs that allow fluid to flow equally well in all directions. Oblate (flattened) and prolate (elongated) grains tend to rest horizontally and parallel to one another and form layers that affect the ease of fluid
flow. Anisotropic permeability is higher when fluids flow parallel to a layer
than when perpendicular to it. Fluids flow more easily through open fractures than between grains. If the fractures have a preferred alignment, permeability is highest parallel to this direction and is anisotropic.
As a consequence of the textural and geologic factors that influence permeability, the path that fluid takes through rock may be longer, with many
turns and bends, than the direct linear distance between start and end points
(below). Tortuosity is the ratio of the actual distance traveled divided by the
straight-line distance. Permeability is inversely proportional to tortuosity.
Measuring Permeability
Permeability can be measured in the laboratory and indirectly determined
in the field. In the laboratory, analysts flow a single-phase fluid through a
rock core of known length and diameter. The fluid has known viscosity and
flows at a set rate. When the flow reaches steady state, an analyst measures
the pressure drop across the core length and uses Darcy’s law to calculate
permeability. For routine core analysis, the fluid may be air, but is more
often an inert gas, such as nitrogen or helium.
In an alternative laboratory method, analysts apply gas pressure to the
upstream side of a sample and monitor as the gas flows through the sample
and the pressure equilibrates with the downstream pressure. During this
unsteady-state, or pressure-decay, procedure, analysts use the time rate of
2.3
mm
2.3
mm
2.3 mm
> Tortuosity and hydrodynamic pore flow simulation. Engineers conducted a
hydrodynamic pore flow simulation (left) of a tracer test through limestone.
The grains are transparent in the model, and the pore space is saturated
with brine (light blue). Flow starts at the bottom. Four steps of the tracer test
are shown; from earliest to latest, the steps are colored blue, red, green and
gold. The flow path of the tracer is controlled by the tortuosity of the
interconnected pore space. The digital rock model was obtained from a
core plug of limestone; a 2D grayscale X-ray image used to construct the 3D
model is on the right. The model was coupled with digital fluid descriptions
to simulate reservoir flow. The limestone sample had 16% porosity and
12-mD permeability.
64
change of pressure and effluent flow rate to solve for permeability. The
pressure-decay method is particularly good for measuring the permeability
of tight, or low-permeability, samples because steady-state flow through
these samples takes a long time to achieve.
Analysts apply corrections to compensate for differences between laboratory and downhole conditions. They account for stress differences by
applying confining stress to one or more representative plug, or core, samples. To determine stress-related effects on permeability, analysts often use
several confining stresses on a few samples and then apply a correction
factor for the reservoir confining stress to the other samples.
Gas flow in pores is faster than liquid flow because liquids experience
greater flow resistance, or drag, at pore walls than do gases. This gas slippage, or higher flow rate of gases compared with liquids, is an effect that
can be corrected by incrementally increasing the mean gas pressure in the
plug, which compresses the gas and increases its drag at the pore wall. The
Klinkenberg correction is an extrapolation of these measurements to infinite gas pressure, at which point gas is assumed to behave like a liquid.
In the field, permeability can be estimated in the near-wellbore region
using well logging data. The primary logging data come from nuclear magnetic resonance (NMR) tools. Permeability estimates from NMR measurements require knowledge of the empirical relationship between the
computed permeability, porosity and pore-size distribution; estimates are
often calibrated to direct measurements on core samples from the well or
from nearby wells. Permeability may also be determined from downhole
pressure and sampling tool measurements.
Permeability on the reservoir scale is typically determined with drillstem tests (DSTs). Pressure transient analysis from DSTs assesses the average in situ permeability of the reservoir. To match the transient behavior to
that predicted by a formation model, interpreters use several techniques.
They can estimate an average effective permeability from the flow rate and
pressure during steady-state production measured during specific tests at
established flow rates. An average permeability can also be calculated from
production-history data by adjusting permeability until the correct history of
production is obtained.
Multiphase Flow
Permeability in a porous medium that is 100% saturated with a single-phase
fluid is the absolute permeability, or synonymously, the intrinsic permeability or specific permeability.
Multiphase flow is the simultaneous flow of multiple fluids in a porous
material partially saturated with each fluid. Each fluid phase flows at its
own rate and competes for flow paths with the other phase or phases. Its
admittance through the porous space is determined by its effective permeability, or phase permeability. The fractional flow of each fluid is related to
its relative permeability, which is the ratio of the fluid’s effective permeability divided by a reference value, typically the absolute permeability.
Multiphase flow is also affected by wettability, which is the preference
that solids have to be in contact with one fluid phase rather than another.
Wetting affects the local distribution of phases, which has an impact on
their relative abilities to flow.
Permeability is the simplest measure of the producibility and injectivity of
subsurface formations. In formations of sufficient permeability, operations
such as producing fluid hydrocarbons or water, conducting secondary and tertiary recovery and sequestering carbon dioxide can be accomplished.
Oilfield Review
Th
eL
as
Oilfield Glossary
Available in English and Spanish, the Oilfield Glossary is a rich accumulation of more than 5,800 definitions from
18 industry disciplines. Technical experts have reviewed each definition; photographs, videos and illustrations
enhance many entries. See the Oilfield Glossary at http://www.glossary.oilfield.slb.com/.
tW
ord