Wireline Formation Testers

Wireline formation
testers are used to
obtain
• Pressure profiles
• Formation fluid samples
• Permeability indicators

This information is
crucial during
exploration and
development of oil
and gas fields
Wireline Formation Testers
Different types
Why Wireline Testing?


Proper reservoir management
requires formation pressure
measurements in a wide
range of conditions. Collecting
representative formation fluid
samples and determining
premeability anisotropy are
equally important.
Formation pressure
measurements taken within a
well can be plotted versus
true vertical depth to produce
a pressure profile. The
resulting pressure profile is
extremely valuable in
analyzing virgin and
developed reservoirs.

In developed reservoirs,
wireline testers are used to
• Characterize vertical and
horizontal barriers
• Assess vertical permeability
• Determine hydraulic
communication between wells
• Detect fluid contact
movement

In virgin reservoirs, vertical
pressure profiles are obtained
to
• Determine fluid contact level
• Determine formation fluid
density in situ
• Characterize reservoir
heterogeneities
Why Wireline Testing?


Wireline formation testers are
also used to collect formation
fluid samples, the MDT tool
attempts to improve the
quality of samples by using
techniques for downhole fluid
analysis
Tests from wireline testers
provide mobility profiles that
help to pinpoint zones of
better productivity. The
recorded transient pressure
response at each station can
be analyzed to estimate
permeability



In homogeneous formations,
the multiprobe tester scan
estimate horizontal and
vertical mobilities
In laminated formations, this
tool enables the study of
potential permeability barriers
and their effect on vertical
fluid movement
Wireline formation testing
data are essential for
analyzing and improving
reservoir performance and
making reliable predictions,
which are vital to optimizing
reservoir development and
management
BASIC




Connected directly to the hydraulic power
module, the single-probe module contains a
probe assembly with packer and
telescoping backup pistons, and connects
the tool flowline to the reservoir.
Can be placed anywhere on the string, but
it must be directly connected to the
hydraulic power module
Extends against the borehole wall to
provide a fluid path from the reservoir to
the flowline.
The pretest is used to ensure a good
hydraulic seal, obtain accurate formation
pressure recordings and determine
permeability
•

Max volume pretest chamber 20 cm3
Service unit controls the sampling pressure,
pretest flow rate and volume from the
surface, allows selection of optimal values
for the various formation characteristics
that can occur during a pressure
measurement sequence.
Standard MDT tool




Designed to take several measurements
and fluid samples during one trip in the
well
The configuration, which extend the
capabilities of existing single-probe
testers, provides a basic tool to which
additional modules – and therefore
capabilities – can be added.
Advantages over existing tools include
flowline temperature and flowline fluid
resistivity determinations, collection of
several fluid samples per trip, standard
operations in a larger range of hole sizes,
extended pressure accuracy and dynamic
response, and surface controlled pretest
rate, volume and sampling pressure.
Usually combined with a gamma ray
device for depth control
Schlumberger


Extends against the borehole wall to provide a
fluid path from the reservoir to the flowline.
The pretest is used to ensure a good hydraulic
seal, obtain accurate formation pressure
recordings and determine permeability
•
Max volume pretest chamber 20 cm3
Pressure test sequence
P
High perm
Low perm
tight
t
Supercharging
Supercharging



In low-permeability formations, wireline formation pressure
measurements are sometimes hampered by the “supercharging”
phenomenon.
Caused because the permeability of the mudcake is not exactly
zero but has some small value. This permeability allows a finite
continuous flow of filtrate across the mudcake.
In a low-permeability formation, the resistance to fluid flow
because of the mudcake can be the same order of magnitude as
the resistance of the formation to accepting fluid.
Thus, a standard wireline
pressure measurement will not
be sufficient to measure the
pressure of the virgin
formation, because a residual
finite pressure difference
remains between the formation
at the mudcake interface and
the virgin formation some
distance away.

Pressure profiles
Pressure Profiles




In thick reservoirs with relatively high permeabilities, vertical
pressure profiles are used to determine in-situ fluid densities and
fluid contact level.
This type of pressure measurements requires gauge with high
accuracy and resolution. Standard quartz gauges, although
suitable for fluid gradient determination, require long stabilization
times when subjected to sudden changes in temperature or
pressure, a common occurrence during formation tests.
Strain gauges have a better dynamic response,but do not offer
the accuracy or resolution needed for most fluid gradient
determinations.
A new gauge was needed that could combine the accuracy and
resolution of the quartz gauge with the dynamic response of the
strain gauge. These requirements were met in the CQG (Crystal
Quartz Gauge).
Free water level (FWL) from pressure
Resistivity Wm
0
SW
Pressure bar
1
Oil/water
contact
Free water
level
Resistivity measurements


New features include a flowline resistivity sensor and
temperature sensor and isolation valve.
The resistivity measurement helps to discriminate filtrate
from water-base mud and formation fluids. Also useful
when taking formation water samples in wells drilled with
oil-base mud.
OFA module



The second requirement for the
recovery of PVT-quality fluid samples
is a detection system to indicate fluid
type. The sensor in the probe module
provides a resistivity measurement
over a wide range.
Some conditions, in particular wells
drilled with OBM, may require the
OFA module.
This module, run immediately below
the probe module, uses optical
analysis techniques to identify the
fluid in the flowline
OFA module




OFA (Optical Fluid Analysis) is used for fluid analysis with two sensor systems:
one for liquid detection and analysis and the other for gas detection. The
flowline passes through two independent optical sensors. In one cell,
absorption spectroscopy is used to detect and analyze liquid. In the other
cell, a special type of optical reflection measurement detect gas.
This allows wellsite personnel to decide whether to divert the flow into a
sample chamber, or increase the sampling pressure above bubblepoint.
It can also be used to verify that the formation contains only water or only gas
and that a sample is not required. Thus, the sample chambers in the tool are
kept available for desired fluids only.
Even when OBM is used it is
possible to track the transition from
borehole mud, to filtrate, to connate
oil as long as the two oils differs in
color.
Sampling



Sample chambers available with 1, 2 ¾ and 6 gal. The
software will handle up to 12 sample units, but length
and weight limitations make only 5 or 6 units practical
per trip.
Each chamber has an electromechanically actuated
throttle (seal) valve, which is controlled from the surface
and directs sampled fluid to the selected chamber in any
order. The valve can operate in one of two modes. In
seal mode, the valve can be either fully open or fully
closed. In throttle mode, the valve operates as a variable
orififce that automatically opens and closes to maintain
the flowing pressure constant. The throttle valve is a
dynamic valve, constantly adjusted to maintain a
specified flowline sampling pressure within an error band.
The engineer specifies the operating parameters of this
valve.
In addition, the sample chamber has a drain valve for
connecting the sample drainage equipment and a
transport valve for sealing the sample in the module.
Dual packer


Provides two inflatable packer elements to isolate
a borehole interval for testing and/or sampling.
The pumpout module uses borehole fluid to inflate
the packer elements to about 1000 psi above
hydrostatic pressure. Spacing between the packer
elements varies with the borehole size, min.
distance is about 3 feet (92 cm). The entire
borehole wall is open to the formation, so the fluid
area is several 1000 x larger than with
conventional probes.
Can be used as an alternative to conventional
probes.
Extrapolating pressure gradients


In some reservoirs, the gas-water contact cannot be identified by the
pressure profile of Well 1 or Well 2. Therefore, no estimate of reservoir
volume can be made.
However, by extrapolating the water gradient of well 1 and the gas
gradients of well 2, it is possible to determine the gas-water contacts and
estimate reservoir volume. This extrapolation shows that pressure
readings taken near the wellbore reflect pressures that exist deep within
the formation.
Pressure gradients
Well
I
Well
II
Depth
GWC ?
GWC
Pressure
Barrier detection


Flow barriers have prevented formation fluids from reaching equilibrium
over geologic time. Because the fluid has not reached equilibrium, a
potential difference exists on opposite sides of the barrier. This pressure
potential means that formation fluid would flow if the barrier were
removed. Variation in potential can easily be seen when carefully
analyzing gradients and provides a means of identifying flow barriers.
Gradients may not be continuous through what is thought to be a single
reservoir. In these instances, two or more similar of identical gradients
can be identified; however, they can have a potential difference because
of an existing flow barrier. Vertical flow barriers can be identified by this
potential.
Barrier detection
Exercise 1
In a gas reservoir, that consist of sand zones and shale zones, two vertical wells are
drilled (I and II). Well II is situated 500 m east of well I. Well I was drilled through
sand zones A and B, Well II was drilled through 3 sand zones K, L and M. The
thickness of these sand zones is between 20 m to 30 m with zones of shale in
between. In each of these sand zones, to pressure tests were taken (MDT). The chart
below shows the pressure in the different zones:
Well I
Dept (m)
Pressure (bar)
Sanzone A
2600
303
2620
303,5
Sandzone B
2645
302,25
2665
302,75
Well II
Depth (m)
Pressure (bar)
Sandzone K
2610
305
2630
305,5
Sandzone L
2650
305,25
2670
307,25
Sandzone M
2690
303,3
2710
303,8
Plot the pressure points on a depth vs. pressure plot and make a drawing of the
geological structure and fluid system based on these pressure data
-2580
302
303
304
305
306
307
ANSWER
308
Well I
Well II
-2600
A
A
K
K
-2620
Gas
Depth (m)
2637
Gas
GWC
-2640
B
B
L
-2660
Water
Gas
L
-2680
M
-2700
M
Gas
-2720
Pressure (bar)
Sanzone A
Sandzone B
Sandzone K
Sandzone L
Sandzone M
Exercise 2


MDT pressure measurements can be used to estimate
barrier/communication between sandzones. In Figure 1 and Figure 2, the
answer is given with folds and faults between two wells. The points were
the pressure are measured are indicted on the figures (o). GWC is also
known.
Draw on the pressure plot to the left how you expect the pressure points
are situated in relation to each other, for the given geologic structure with
gas-zones and water-zones. GWC and barriers are given on the drawing.
Draw also the gradients (gas and water)
Well 1
Pressureplot
Depth
(meter)
Well 2
Gas
Draw the
Draw the pressure points
and
GWC
Water
GWC
Water
Pressure (bar)
Figure 1
Gas
ANSWER
Depth
(meter)
Well 1
Pressureplot
Well 2
Gas
GWC
Water
GWC
Water
Pressure (bar)
Gas
Well 1
Depth
(meter)
Well 2
Pressureplot
Barrier
Gas
GWC
GWC
Water
Gas
GWC
Water
Water
Water
Water
Pressure (bar)
Figure 2
communication
Depth
(meter)
ANSWER
Well 1
Well 2
Pressureplot
Barrier
Gas
GWC
GWC
Water
Gas
GWC
Water
Water
Water
Water
Pressure (bar)
communication
Exercise 3


MDT pressure measurements are used for barrier studies. Figure 3 shows
a gas field with 8 wells. Figure 4 shows the pressure values for each of
these wells from one sandzone A. Sandzone A has low permeability and
for 3 of the wells the sand is almost tight.
Which 3 wells show almost tight sand (supercharge)? Based on the
pressure plot, draw lines for tight faults/barriers between some of the
wells on figure 3. Estimate the GWC for each segment.
Well 6
Well 3
Well 4
Well 1
Well 8
Well 7
Well 2
Well 5
Figure 3
Pressure plot
-3700
450
460
470
480
490
500
-3800
-3900
well1
Depth (meter)
well 2
well 3
-4000
well 4
well 5
-4100
well 6
well 7
well 8
-4200
-4300
-4400
Figure 4
Pressure (bar)
ANSWER
-3700
450
460
Pressure plot
470
480
490
500
-3800
-3900
well1
Depth (meter)
well 2
well 3
-4000
well 4
well 5
-4100
well 6
well 7
well 8
-4200
-4300
-4400
Pressure (bar)
ANSWER
Well 6
Well 3
GWC=4000 m
Well 4
Well 1
Well 8
Well 7
Well 2
Well 5
Karl Audun Lehne
Education:
University of Oslo & University of London
Experience:
About the Author
UiS, Statoil, Total, IRIS, Statens Kartverk
Address:
UiS
E-mail: Karl.A.Lehne@uis.no
Phone: 91154518