Download Report

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