SPE XXXXX
Intelligent Well Completion: Status and Opportunities for
Developing Marginal Reserves
Michael Konopczynski, SPE; Arashi Ajayi, SPE; and Leigh-Ann Russell, SPE, WellDynamics International Limited
Copyright 2008, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the 32 nd Annual SPE International
Technical Conference and Exhibition in Abuja, Nigeria, August 4-6, 2008.
Introduction
This paper was selected for presentation by an SPE Program Committee following
review of information contained in an abstract submitted by the author(s). Contents
of the paper, as presented, have not been reviewed by the Society of Petroleum
Engineers and are subject to correction by the author(s). The material, as
presented, does not necessarily reflect any position of the Society of Petroleum
Engineers, its officers, or members. Papers presented at SPE meetings are subject
to publication review by Editorial Committees of the Society of Petroleum Engineers.
Electronic reproduction, distribution, or storage of any part of this paper for
commercial purposes without the written consent of the Society of Petroleum
Engineers is prohibited. Permission to reproduce in print is restricted to an abstract
of not more than 300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgement of where and by whom the paper was
presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836,
U.S.A., fax 01-972-952-9435.
A great many of the hydrocarbon accumulations in the
world, by themselves, are not economic to develop or
produce. In many of the more prolific hydrocarbon
basins, multiple reservoirs are encountered stacked one
above the other. Conventional government regulations
and good petroleum practice prescribe that the
production of conventional oil or gas from distinct
reservoirs or pools must remain segregated in the
wellbore. As the Alberta Energy and Utilities Board
explains,
Abstract
“The purpose of maintaining segregation of oil and/or
gas in the wellbore is
Marginal reserves are hydrocarbon accumulations too
small or too difficult to recover to be developed
economically by themselves under prevailing fiscal
terms. Stacked reservoirs containing marginal reserves
are often passed over in favour of more prolific zones
containing economic volumes. The opportunity to
develop the marginal reserves in conjunction with other
marginal reserves, or with larger reserves by
commingling (and by doing so make them economic) is
sometimes overlooked by operators due to government
regulations prohibiting commingling.
This paper explores the concept of developing marginal
and by-passed reserves by commingling using
intelligent well technology. It reviews the current
status of intelligent well technology and government
regulations on commingling in a number of regions.
The potential for exploiting marginal reserves in the
North Sea, Nigeria and the Gulf of Mexico is
considered.


to avoid the potential for wellbore and/or
reservoir conditions that may adversely affect
recovery from pools (for example, in some
cases the cross flow of reservoir fluids between
pools under a commingled-completion
operation may jeopardize recovery from other
pools involved), and
to maintain the ability to gather data on an
individual-pool basis for resource evaluation
and reservoir management.”1
The traditional methods of exploiting multiple
reservoirs from one wellbore are to either develop the
reserves sequentially from bottom up, or to use multistring completions to maintain segregation.
The
drawbacks of the first method are that it can take a great
deal of time to exploit all the reservoirs, and it often
precludes the invocation of tertiary recovery methods
that have the potential to improve the fraction of
hydrocarbons that can be recovered. The drawback of
the second method is that productivity from the
2
M.R. Konopczynski, A. Ajayi, and L.A. Russell
individual zones and from the well in total can be
restricted because the size of the tubing is limited by the
geometry constraints of the casing. Casing size can be
increased to accommodate the larger tubing required for
optimum production, but this is a costly option.





As a consequence, in many of the basins around the
world, smaller hydrocarbon accumulations penetrated
by a wellbore are passed over in favour of the larger
and more prolific pools. Groups of small, uneconomic
hydrocarbon pools remain undeveloped, when
developed together they may become economic. An
operating company may have knowledge, from
exploration and development wells, of “marginal”
accumulations separate or in addition to a primary
economic reservoir. Yet in the current and foreseeable
business climate, these reserves have little chance of
ever being developed.

This situation is true for many regions around the world,
including the Gulf of Mexico, the North Sea, West
Africa, the Middle East and the Asia Pacific region.
SPE
Allocation of production to different reservoirs
Reservoir Management
Prevention of cross flow between reservoirs
Compatibility of reservoir fluids
Ability to exclude production of unwanted
effluent (water, gas)
Well integrity and flow assurance
Commingling Around
Regulatory Issues
the
World
-
The regulations for the commingling of down-hole
production are typically set by government agencies
responsible for oil and gas developments.
A review of the published regulations regarding
commingling for a number of these agencies in mature
hydrocarbon producing areas was reviewed for the
purpose of this paper. The U.S. Department of the
Interior Minerals Management Service (MMS)3, the
Railroad Commission of Texas (TRC)4, the Alberta
Energy and Utilities Board (AEUB)5, the Manitoba
Industry Trade and Mines (MITM)6, and the United
Kingdom Department of Trade and Industry (DTI) are
agencies that address commingling in their regulations.
Commingling
The simultaneous production of hydrocarbon from
multiple reservoirs or pools through a single production
conduit is called commingling.
There are multiple economic benefits of commingling
reserves that can provide very large increases in
incremental project NPV for all types of oil and gas
field developments. The benefits of commingling
production from separate reservoirs are:





ability to produce hydrocarbon from multiple
reservoirs which may not be economic to
produce on their own
fewer wells, less infrastructure - lower capital
expense
lower operating expenses
less environmental impact, fewer locations
a sustained production plateau
The CAPEX benefits of commingling flow from
multiple reservoirs, is immediately obvious in high cost,
high productivity deepwater field development
applications. However, regulations and practices
counter to commingling have been identified as a
blocker to the economic development of low
deliverability reservoirs2.
The practical issues associated with commingling can
be classified by the following categories:
The main reasons that the regulatory bodies control the
application of down-hole commingling are as follows:





Potential
for
sub
optimal
recovery
(conservation)
Inability to provide accurate flow estimation
and allocation for each zone (administration)
Concerns about fluid compatibility
Minimisation of interventions
Concerns about lack of control (cross flow
between reservoirs)
There are very few areas of the world that permit
commingled flow from different reservoir intervals
without approved means of control, testing of
segregation, and flow estimation and allocation (FE&A)
for each interval. A down-hole commingling permit,
obtained from the regulatory body is required in most
cases. From a regulatory point of view, commingling
may be justified and approved as an exception in the
following circumstances:



low deliverability of one or more pools due to
reservoir characteristics or depletion of the
pool by production (economic hardship),
small reservoirs that would deplete rapidly
under production,
operational issues that can be handled more
effectively with commingled production, such
as liquid loading in the wellbore, hydrate
formation, or physical limitations in the
3
Intelligent Well Technology: Status and Opportunities for Developing Marginal Reserves
SPE
wellbore (e.g., a casing diameter that is too
small to contain two production strings),
induced communication behind the casing
through a poor cement bond or fracture
stimulation, and
where it has been demonstrated that the
commingling will not affect ultimate recovery
of oil or gas from the field.1
MMbbl each, with potential to increase this range to 20
MMbbl and 80 MMbbl with the appropriate application
of technology. Assuming a subjective average of 30
MMbbl for each of the 24 prospects, and that 15% of
these can be exploited by commingling, an additional
108 MMbbl of reserves should be easily exploited from
just this handful of opportunities. The Niger Delta shelf
has hundreds of these marginal opportunities.
Canada’s Manitoba Industry Trade and Mines Drilling
and Production Regulations are a good example of the
documentation required in an application for an
exception to the rule permitting commingled
production.6 The MITM request the following
information during the application process:
In the United States, stacked reservoirs in the Gulf of
Mexico have typically been exploited by sequential
development10.
Gulf of Mexico shelf operators
perceive that intelligent well flow control valves are to
be used in the same way, replacing the plug back
intervention in the sequential development method with
the closing of the downhole flow control valve.
Operators have not considered using intelligent well
technology for commingling and accelerating or
optimizing production.


i.)
maps showing the interpreted structure, effective
reservoir thickness, areal extent and fluid
interfaces of the pools; and
ii.)
a discussion of:
a) the ultimate reserves associated with each pool
recoverable through the well;
b) the proposed method of allocating production
or injection to each pool, including testing
frequency;
c) reasons justifying the proposed commingling,
including specific economic data; and
d) the impact of commingling production or
injection on ultimate recovery from each pool
and on the correlative rights of owners; and
e) any other information the director may require.
Commingling Legislation
However, the Minerals Management Service (MMS),
recognizing the increasing costs of offshore
development in the Gulf of Mexico, is easing the
restrictions on the size of reserves to which
commingling may be applied. The objective of this
change in policy is to maximize the ultimate recovery
and prevent waste of natural resources11,12. The
evolution of intelligent well technology has played a
significant part in this change of policy as a proven
enabler for controlled commingling.
Elements
Necessary
Commingling
for
Controlled
In the United Kingdom, the Department of Trade and
Industry (DTI) sponsored PILOT Undeveloped
Discoveries Workgroup estimated that 15% of
discovered, uneconomic oil reserves in the UK Sector
of the North Sea could be made economic by
commingling7,8. Similar gains in proven reserves
through commingling should be expected in other major
basins.
In order to tackle the concerns and issues of the
government agencies and the operators of commingled
wells, intelligent well solutions must address the
following issues:
In Nigeria, the Department of Petroleum Resources
(DPR) has taken steps to encourage the development of
marginal fields, which they define as any field with
marginal oil reserves or a field that is low in the
portfolio ranking of current operators9. To elaborate,
marginal fields are not considered by license holders for
development because of assumed marginal economics
under prevailing fiscal terms. The DPR has started to
address the development of marginal fields by
identifying 24 fields with booked reserves that have
remained un-produced for a period of over 10 years.
An analysis of the 24 identified prospects indicated
initial reserves ranging between 5 MMbbl and 40
Flow Control refers to the ability, at a minimum, to
open or shut off a zone or reservoir in a commingled
well at will, an unlimited number of times, without
intervention. Higher-level intelligent well systems offer
the ability to restrict flow or choke each particular
interval. The ability to shut-off zones is important to
prevent cross flow between reservoirs and to exclude
production of unwanted effluent (water, gas). The
ability to choke zones is important to balance
production between reservoirs, particularly in tertiary
recovery schemes. Also key is the operability of the
flow control, that is, the reliability and ability to
perform the desired function on demand over time.



Flow Control
Well Integrity
Reservoir Management
4
M.R. Konopczynski, A. Ajayi, and L.A. Russell
SPE
Well Integrity refers to zone or reservoir segregation,
which is affected by the quality of the cement, casing,
packers, and flow control valves. Flow assurance and
the intelligent well system’s susceptibility to
malfunction due to scale, wax, sand, and solids must
also be addressed. Finally, the mechanical integrity and
reliability of the intelligent well system and the
commingled completion must be considered, including
testing of integrity and the provision of contingencies if
one of the critical elements of the completion fails.
Control, Communication and Power Cables. Current
intelligent well technology requires one or more
conduits to transmit power and data to downhole
monitoring and control devices.
These may be
hydraulic control lines, electric power and data
conductors, or fibre optic lines. Optical fibres may be
installed in a dedicated control line, or may share a
control line with a hydraulic line. For additional
protection and ease of deployment, multiple lines are
usually encapsulated.
Reservoir Management covers sensing (pressure,
temperature), flow estimation and flow allocation, well
testing (multi-rate, pressure transient analysis) and
Operating Philosophy (flow control plan). These
elements are critical for the management of the
intelligent commingled well and commingled reservoirs.
Down-hole Sensors. A variety of downhole sensors are
available to monitor well-flow performance parameters
from each zone of interest. Several single-point
electronic quartz crystal pressure and temperature
sensors may be multiplexed on a single electric
conductor, thus allowing very accurate measurements at
several zones. Optical fibres are now widely used for
distributed temperature surveys throughout the length of
a wellbore and provide temperature measurements for
each meter of the well.
Single-point fibre-optic
pressure transducers are now available, and multi-point
or distributed fibre optic pressure sensing is being
developed. Downhole flow meters are available based
on Venturi systems, or pressure drop correlations across
flow control devices. New generation flow meters
based on passive optical fibre acoustic sensing are being
developed. Other new technologies under development
include water cut sensors, fluid density meters, microseismic arrays, formation resistivity arrays, and
downhole chemical analysis sensors.
Intelligent Well Technology
An intelligent well completion is a system capable of
collecting, transmitting and analysing completion,
production, and reservoir data, and taking action to
better control well and production processes. The value
of intelligent well technologies comes from the
capability to actively and remotely modify the zonal
completions and performance through flow control, and
to monitor the response and performance of the zones
through real time down hole data acquisition, thereby
maximising the value of the asset13.
Elements of Intelligent Wells
The industry generally recognises the definition of an
intelligent completion, as described at the 2001 SPE
Forum in St. Maxime, France, as one in which “control
of inflow (or injection) takes place down hole at the
reservoir, with no physical intervention, with or without
active monitoring.”
To realize this, the following elements are generally
required:
Flow Control Devices. Most current down hole flow
control devices are based on or derived from sliding
sleeve or ball-valve technologies. Flow control may be
binary (on/off), discrete positioning (a number of preset
fixed positions), or infinitely variable. The motive
force for these systems may be provided by hydraulic,
electro-hydraulic or electric systems.
Feedthrough Isolation Packers. To realize individual
zone control and ensure segregation of separate
hydrocarbon pools, each zone must be isolated from
each other by packers incorporating feedthrough facility
for control, communication, and power cables.
Surface Data Acquisition and Control. With multiple
downhole sensors providing “real-time” production
data, the volume of data acquired can be overwhelming.
Systems are required to acquire, validate, filter, and
store the data. Processing tools are required to examine
and analyse the data to gain insight into the
performance of the well and the reservoir.
In
combination with the knowledge gained from the
analysis, predictive models can assist in the generation
of process-control decisions to optimise production
from a well and asset.
Flow Estimation and Flow Allocation
Flow estimation is the quantification of mass or volume
flow of fluids from each zone, layer or reservoir into the
intelligent well. This is different from flow allocation,
which is the division of a total mass or volume
measurement of fluids into shares representing the
contribution of each zone, layer or reservoir. Both flow
estimation and flow allocation are important in an
intelligent commingled well for reservoir management
and production accounting.
5
Intelligent Well Technology: Status and Opportunities for Developing Marginal Reserves
Flow Estimation and Measurement
Flow estimation is usually derived from measured
parameters, most often pressure (such as in an orifice or
venturi meter), temperature or vibration. The following
methods are typically used in downhole flow
estimation:





Downhole Flow Meter (Single Point)
o Venturi
o Spinner
o Passive Acoustic Optical Fibre
Pressure Drop Across Flow Control Valve
Periodic Testing – Inflow Performance
Modelling
Tubing Performance – Pressure Drop
Thermal Modelling – Distributed Temperature
In addition, a measurement or an estimate of effluent
composition, particularly water cut and gas-oil ratio
must be made for each zone of interest. While downhole water-cut meters and densitometers are available,
suitable estimates of composition can be derived from
periodic well tests of individual zones.
Flow estimation by periodic testing and inflow
performance characterization is attractive as it can
provide a significant amount of information about the
performance of individual zones with a minimum
amount of down-hole instrumentation. While one zone
is being tested, pressure build-ups in the closed in zones
can be monitored and analysed in real-time to identify
skin, kh, and reservoir pressure. By using multi-rate
testing, the production performance of the zone of
interest can be well defined and fluid composition can
be established. Combined with downhole pressure
sensors and continuous monitoring, real-time estimates
of flow from each individual zone are calculated from
the inflow performance relationship and used in zonal
flow allocation. Finally, the testing of individual zones
using the intelligent well flow control valves provides
an opportunity to confirm segregation of the zones and
routinely operate the valves, which may be desirable in
wells with a propensity for scaling.
Flow Allocation
Flow allocation has two purposes. First, flow allocation
is the foundation of production accounting, which is
important for royalties, partner/joint venture shares and
investor information. Second, flow allocation is the
backbone
for
reservoir
management,
which
encompasses reservoir surveillance and production
performance
monitoring,
well
performance
optimisation, voidage replacement, and accurate
SPE
production
forecasting
and
problem/opportunity identification.
production
Allocation of production generally begins with
assessment at the most robust measurement point,
usually a custody transfer or sales point where the most
accurate single phase metering takes place (fiscal
metering), and works its way upstream through the
process and gathering systems to the wells. The
progression of the allocation process upstream through
every production node is the reason it is often called
“back allocation” (figure 1). Where complex geology
or multiple reservoirs are present, the allocation of
fluids must be resolved to the reservoir or zonal level.
Traditional production allocation to the well level has
been based on periodic individual well tests. The well
tests are usually conducted at least once per month,
depending on the stability or transient behaviour of the
well. Changes in produced fluid composition, reservoir
or wellbore pressure, or other influencing factors dictate
more frequent testing requirements. It is generally
assumed that between tests, the performance of the well
does not change significantly.
In some fields, fluid from multiple reservoirs that is
produced from separate wells is then commingled at
surface in a common gathering and separation system.
Production allocation based on periodic well tests has
long been accepted practise in the industry for this
application, although the preferred method is to keep
production from separate pools separated until
measured downstream of group three phase separators.
The introduction of wellhead multi-phase flow meters
has greatly improved the quality of well-level flow
allocation, though it is still limited in its application14.
In an intelligent well, production allocation at the
reservoir or zone level may be based on downhole flow
estimates, downhole flow measurements, constituent
mass balance (geo-chemical fingerprinting), or a
statistical combination of these methods. Intelligent
well flow allocation offers a measured improvement
over conventional flow allocation methods because flow
estimates are made with greater temporal resolution
than the monthly well test and daily group production
methods. The real-time measurements from intelligent
wells better cope with changes in operating conditions,
transient response and unstable behaviour in the wells.
Applications
In the North Sea, Shell U.K. has applied intelligent
wells in its Tern Field to enable controlled commingling
of the Lower Ness/Etive and the Broom/Rannoch/Upper
Ness formations.16 Previous development of these
6
M.R. Konopczynski, A. Ajayi, and L.A. Russell
reserves was by sequential development of first the
more prolific Lower Ness/Etive followed by the Broom
/Rannoch/Upper Ness.
The proposed completion
consisted of 2 x 3 ½” hydraulic ICVs, 1 x 9 5/8”, 1 x 7”
feed thru production packers and dual encapsulated
control line with clamps. The well include including 3
x 4 ½” gaslift mandrels with the 3 ½” tail string
extending to the 7” liner section. The application of
intelligent well technology enabled production from the
wellbore to be switched between the Lower
Ness/Broom and Triassic formations. Selective testing
of the two formations allowed production splits and
water cuts to be obtained without the requirement of
production logging. The authors estimated a gain of
accelerated oil production of some 430,000 bbl, and
risked 85,000 bbl of incremental oil production using
the proposed intelligent well completion.
Conclusions
Intelligent Well Technology (IWT) provides the
optimum solution to enable exploitation of multiple
reservoirs from one wellbore, while satisfying
regulations governing down-hole commingling.
Some of the benefits of controlled commingling
discussed include:
 Fewer wells, less environmental impact, less
infrastructure - lower capital expense and
lower operating expenses
 Less environmental impact, fewer locations
 Better understanding of reservoir performance,
and improved reservoir .
By accepting and encouraging the use of controlled
commingling enabled by intelligent well technology,
government regulatory agencies can improve the
recovery of hydrocarbons from by-passed and marginal
reservoirs while maintaining a healthy economic
environment for the development of these reserves.
Successful application of the IWT for developing
marginal reservoirs in the North Sea, Gulf of Mexico
and Niger Delta were cited.
In the Gulf of Mexico, the Canyon Express Project of
the Aconcagua, Camden Hills and King’s Peak fields
are using intelligent well completion technology to
optimise a marginal reserve base.17
Each well
penetrates up to 4 distal turbidite sand reservoirs
producing gas. The reservoirs are commingled and
completed with intelligent well equipment installed in 9
of the 10 development wells permitting the selective
shut-off of water from each reservoir, and potential
independent choking to optimise production without
intervention. The fields are located in 6200 to 7200 ft
of water. The intelligent well design consisted of
production packer with electric and hydraulic bypass,
gauge package for measuring shut-in and flowing
pressure from the controlled zones, and 2 control valves
with metal-to-metal seal to control flow from the
producing intervals.
In the Niger Delta, the Nigerian Agip Oil Company,
was the first to embrase the technology by installing an
electro-hydraulic 4 level intelligent well system in the
Kwale field18. The design includes for each zone: One
infinite variable ICV equipped with two sets of pressure
and temperature gauges, one HF-1 packer and blast
joints specially designed to fully cover the electrohydraulic communication link (Flat Pack) in front of
perforations. One HES Durasleeve XD SSD is
positioned above the topmost production packer to
further displace annular fluid when necessary.
Adjustable flow control with pressure and temperature
feedback to surface is available through electrohydraulic communication link. One HES SP non
elastomer SCSSV is set below surface for safety. The
authors concluded that the trial remains a technical
success and opens the door to real time reservoir
management. Though it is too early to appreciate the
full economical benefit of such completion as at the
time the paper was written.
SPE
Acknowledgments
The authors gratefully acknowledge the management of
WellDynamics for permission to publish this work and
would also like to thank their co-workers for their
contributions to the material presented herein.
References
1.
2.
3.
4.
5.
Alberta EUB Guide 65: Resources Applications for
Conventional Oil and Gas Reservoirs, Section 3.1 Commingled Production (June 2000).
Cranfield, C., “Intelligent Wells - Impact on
Regulatory Authorities” Presentation at the SPE
'Smart Wells' Forum, Sainte Maxime, 23-28 Sept.
2001
“Guidelines for Deepwater Operations Plan for a
Subsea Project”, Minerals Management Service NTL
No. 96-4N, www.mms.gov
Texas Administrative Code, Economic Regulation,
Part 1: Railroad Commission of Texas, Chapter 3: Oil
and Gas Division, Rule 3.6: Application for Multiple
Completion – amended Feb 28 1986, Rule 3.10:
Restriction of Production of Oil and gas from
Different Strata – amended May 14 1996.
Alberta Regulation 151/71 -Oil and Gas Conservation
Act, Oil and Gas Conservation Regulations, Sections
3.040 – 3.060, 11.150
7
6.
7.
8.
9.
10.
11.
12.
13.
14.
Intelligent Well Technology: Status and Opportunities for Developing Marginal Reserves
Drilling and Production Regulations 52(1), Manitoba
Industry Trade and Mines
Cranfield, Naylor “Unlocking the Potential from
UKSC Low Deliverability Reservoirs, SPE 78331,
SPE 13th European Petroleum Conference 2002
‘Progressing Partnership Workgroup - Final
Contractors Report’, 2003, PILOT (UK Industry Oil
and Gas Task Force)
Ofurhie, M.A., “Analysing the Final Qualification
Stage of the Marginal Fields”, presented at IBC’s 2nd
Annual Nigeria Energy Conference, Houston, Texas,
12th November 2002.
Buddell, M and Han, J.T., “An Innovative Approach
to Depleting the Gulf of Mexico ‘Shelf’ Assets”,
paper presented at the Oil and Gas Journal High–
Tech Wells Conference & Exhibition, Galveston,
Texas, February 11-13, 2003
United States Department of the Interior Minerals
Management Service Gulf of Mexico OCS Region
NTL No 99 G-19 ‘Downhole Commingling Policies’
United States Department of the Interior Minerals
Management Service Gulf of Mexico OCS Region
NTL No 99 G-20 ‘Downhole Commingling
Applications’
Moore, W. R., Konopczynski, M. R. and JacksonNielson, V.: “Implementation of Intelligent Well
Completions Within a Sand Control Environment,”
paper SPE 77202, presented at the IADC/SPE Asia
Pacific Drilling Technology held in Jakarta,
Indonesia, 9–11 September 2002.
Theuveny, B.C. and Mehdizadeh, P., “Multiphase
Flowmeter Application for Well and Fiscal
15.
16.
17.
18.
SPE
Allocation”, SPE 76766 presented at the SPE
Western Regional/AAPG Pacific Secion Joint
Meeting held in Anchorage, Alaska, 20-22 May 2002
Martinez, J. K., and Konopczynski, M. R.,
“Integrated Reservoir Management in an Intelligent
Well Environment,” paper SPE 77853, presented at
the SPE Asia Pacific Oil and Gas Conference and
Exhibition held in Melbourne, Australia, 8–10
October 2002
Akram, N., et. Al., “Intelligent Well Technology in
Mature Assets”, SPE 71822 presented at the Offshore
Europe Conference, Aberdeen, Scotland, 4 – 7
September 2001.
Jackson Nielsen, V.B. et al., “Aconcagua, Camden
Hills, and King’s Peak Fields, Gulf of Mexico,
Employ Intelligent Completion Technology in
Unique Field Development Scenario,” paper SPE
71675, presented at the 2001 SPE Annual Technical
Conference and Exhibition, New Orleans, 30
September – 3 October 2001.
Osakwe L. O., Burrafato S., and Adewale S. B.:”
Application of Intelligent Completion System in the
Development of Kwale Oil Reserves”, paper
presented at at the 27th Annual SPE International
Technical Conference and Exhibition in Abuja,
Nigeria, August 2001.