Note: Descriptions are shown in the official language in which they were submitted.
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IMPROVEMENTS IN OR RELATING TO INJECTION WELLS
The present invention relates to injecting fluids into wells and more
particularly, to a method for injection testing in appraisal wells to
evaluate thermal stress effect characteristics for reservoir modelling
and so better determine injection parameters for the well.
Current hydrocarbon production is primarily focussed on maximising
the recovery factor from a well. This is because we have already
exploited all the areas which might contain oil leaving only those
that are in remote and environmentally sensitive areas of the world
(e.g. the Arctic and the Antarctic). While there are huge volumes of
unconventional hydrocarbons, such as the very viscous oils, oil
shales, shale gas and gas hydrates, many of the technologies for
exploiting these resources are either very energy intensive (e.g.
steam injection into heavy oil), or politically/environmentally
sensitive (e.g. µfraccing' to recover shale gas).
To improve the recovery factor in a well it is now common to inject
.. fluids, typically water, into the reservoir through injection wells.
This form of improved oil recovery uses injected water to increase
depleted pressure within the reservoir and also move the oil in place
so that it may be recovered. If produced water is re-injected this
also provides environmental benefits.
Reservoir models are used in the industry to analyze, optimize, and
forecast production. Such models are used to investigate injection
scenarios for maximum recovery and provide the injection
parameters for an injection program. Geological, geophysical,
petrophysical, well log, core, and fluid data are typically used to
construct the reservoir models. The properties of the rock in the
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formation are traditionally obtained by taking measurements on
core samples and the results are used in the models.
A known disadvantage in this approach is in the limitation of the
models used and their reliance on the data provided by the core
samples. While many techniques exist to contain and transport the
core samples so that they represent well conditions in the
laboratory, many measurements cannot scale from the laboratory to
the well and there is a lack of adequate up-scaling methodologies.
Additionally, on injecting a cool fluid into warm subterranean
reservoir, a cooling effect will occur around the injector. This alters
the stresses in the region with altered temperature. A consequence
is that the fracture pressure around an injector will vary with time.
The amount of variation will be dependent on the thermal stress
characteristics of the formation. While these can theoretically be
measured on a core sample in the laboratory such a measurement
which is dependent on a pressure/temperature relationship can't be
adequately scaled and they are found to be multiple factors out
when attempts are made to scale to well dimensions.
US 8,116,980 to [NI S.p.A. describes a testing process for testing
zero emission hydrocarbon wells in order to obtain general
information on a reservoir, comprising the following steps: injecting
into the reservoir a suitable liquid or gaseous fluid, compatible with
the hydrocarbons of the reservoir and with the formation rock, at a
constant flow-rate or with constant flow rate steps, and
substantially measuring, in continuous, the flow-rate and injection
pressure at the well bottom; closing the well and measuring the
pressure, during the fall-off period (pressure fall-off) and possibly
the temperature; interpreting the fall-off data measured in order to
evaluate the average static pressure of the fluids (Pay) and the
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reservoir properties: actual permeability (k), transnnissivity (kh),
areal heterogeneity or permeability barriers and real Skin factor
(S); calculating the well productivity. Such injection testing at an
appraisal well has advantages over conventional production testing
in removing the requirement to dispose of produced hydrocarbons
with its incumbent safety and environmental issues. However, such
testing has so far been limited to the determination of fluid
properties, in particular the permeability, and formation damage in
measuring the skin factor, to determine well productivity.
It is therefore an object of the present invention to provide a
method for a well injection program in which injection testing is
used to determine thermal stress characteristics of the well.
It is a further object of the present invention to provide a method
for a well injection program in which injection testing is used to
determine parameters for well interpretation.
According to a first aspect of the present invention there is provided
a method for a well injection program, comprising the steps:
(a) selecting an appraisal well;
(b) selecting a perforation interval and length;
(c) locating at least one downhole sensor to measure pressure
in the well;
(d) injecting a fluid into the well;
(e) varying the flow rate of injected fluid;
(f) measuring the pressure with flow rate variations to provide
measured data;
(g) fitting a first model to the measured data to estimate a
thermal stress characteristic of the well;
(h) inputting the thermal stress characteristic into a second
model; and
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(i) determining injection parameters from the second model.
In this way, by estimating the thermal stress characteristics before
developing the field, injection parameters can be determined for
injection confinement with the greatest injection efficiency.
Additionally, by determining the thermal stress characteristics at the
well, more accurate calibration data is used in the second models
than would be available from measurements on core samples.
Preferably, the method includes the steps of performing a series of
step rate tests and measuring fracture pressure. In this way,
fracturing can occur on the first step and other steps. Alternatively,
the method includes the steps of performing injection cycling and
fall-off analysis.
Preferably, the first model describes the development of the thermal
stresses around the well on the measured data to estimate a
thermal stress characteristic. More preferably the thermal stress
.. characteristic is a thermal stress parameter.
Preferably the second model is a reservoir model or a hydraulic
model. Such models are known in the art for well planning and
optimization. In this way, the present invention can utilize models
and techniques already used in industry.
Preferably, at least one downhole sensor also measures
temperature. Preferably, the sensors data sampling rate is 1 Hz or
greater. There may be a plurality of sensors to ensure redundancy.
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Preferably the downhole sensors transmit data to the surface in
real-time. Alternatively, the downhole sensors include memory
gauges on which the measured data is stored.
5 Preferably the method includes the step of measuring pressure for
different temperatures of injected fluid. In this way, better
characterisation of the effects of the cooling effect can be
determined.
Preferably the method includes the step of measuring pressure at
different zones in the well. In this way, characterisation of fracture
pressure and the thermal stresses can be determined over the
formation.
Preferably, pressure, temperature and flow rate are measured at
the surface of the well. In this way, the injection parameters based
on these values can be better determined.
Preferably, the method includes the step of measuring the pressure
and flow rate during the first injection cycle and shut in/step rate
test and determining fracturing has occurred. In this way, remedial
steps can be taken to ensure fracturing occurs in the second
injection cycle and shut in. Preferably, parameters for the second
injection cycle are determined from the first injection cycle. In this
way, rate ramping schedule and duration of high rate injection can
be optimized. Preferably, these steps are repeated for further
injection cycles/step rate tests.
Preferably, the injected fluid is water. The injected fluid may be
selected from a group comprising: drill water, filtered seawater or
unfiltered seawater. The injected fluid may be treated such as with
a bactericide or scale inhibitor. The injected fluid may further
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include a viscosifier. The method may include the step of
introducing a viscosifier to the fluid during injection. In this way, the
viscosifier can be added if fracturing is not achieved on a first
injection cycle.
Preferably, the appraisal well has a well completion. More preferably
the well completion is with a cemented and perforated liner over an
interval. Other completions may be used such as open-hole screens
with packers.
Preferably, the downhole sensors are run in the well on a string.
The string may be drill pipe, test string or wireline.
Preferably the well injection parameters are selected from a group
comprising: perforation length, injection fluid temperature, fluid
pump rate, fluid pump duration and fluid injection volume.
Preferably, the method includes the further step of carrying out well
injection using the well injection parameters.
Accordingly, the drawings and description are to be regarded as
illustrative in nature and not as restrictive. Furthermore, the
terminology and phraseology used herein is solely used for
descriptive purposes and should not be construed as limiting in
scope languages such as including, comprising, having, containing
or involving and variations thereof is intended to be broad and
encompass the subject matter listed thereafter, equivalents and
additional subject matter not recited and is not intended to exclude
other additives, components, integers or steps. Likewise, the term
comprising, is considered synonymous with the terms including or
containing for applicable legal purposes. Any discussion of
documents, acts, materials, devices, articles and the like is included
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in the specification solely for the purpose of providing a context for
the present invention. It is not suggested or represented that any
or all of these matters form part of the prior art based on a common
general knowledge in the field relevant to the present invention. All
numerical values in the disclosure are understood as being modified
by "about". All singular forms of elements or any other components
described herein are understood to include plural forms thereof and
vice versa.
While the specification will refer to up and down along with
uppermost and lowermost, these are to be understood as relative
terms in relation to a wellbore and that the inclination of the
wellbore, although shown vertically in some Figures, may be
inclined or even horizontal.
Embodiments of the present invention will now be described, by
way of example only, with reference to the accompanying Figures,
of which:
Figure 1 is a schematic illustration of an injection well test being
performed on an appraisal well according to an embodiment of the
present invention;
Figure 2 is a graph of injection rate versus time during an injection
test in a series of step rate tests;
Figure 3 is a graph of pressure versus time during an injection test
and a first model fit to the measured data; and
Figure 4 is a graph of fracture opening pressure and reservoir
pressure versus time around an injector.
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Referring initially to Figure 1, there is shown a simplified illustration
of an appraisal well, generally indicated by reference numeral 10, in
which an injection test is being performed. An injection test system
12 is used. The injection test system 12 comprises a string 13,
.. being a drill pipe on which is mounted a downhole sensor 14.
Though only one sensor is shown, there may be additional sensors
for other measurements or for redundancy.
The sensor 14 measures pressure and temperature and sends the
measured data back in real-time to a surface data acquisition and
transmission unit 16 via a cable (not shown) to surface 18.
Alternatively the data may be transmitted to the unit 16 by wireless
telemetry. In an alternative embodiment, the data is stored in a
memory on each sensor and then later analysed but this is not
preferred as it does not allow real-time analysis and test program
modifications based on the response of the formations. The unit 16
can also transmit the data to a remote location so off-site analysis
in real-time can be performed. The sensors 14 have a sampling
frequency of 1Hz. Other sampling frequencies may be used but they
must be sufficient to measure changes in the pressure during the
rate ramp-up and when shut-in occurs.
In Figure 1, the appraisal well 10 is shown as entirely vertical with a
single formation interval 22, but it will be realised that while
appraisal wells are typically vertical they can also be slightly
deviated or even horizontal in rare instances. Dimensions are also
greatly altered to highlight the significant areas of interest. Well 10
is drilled and completed in the traditional manner providing a casing
24 to support the borehole 26 through the length of the cap rock 28
to the location of the formation 22. Casing 24 is cemented in place
and a perforated or slotted liner 19, is hung from a liner hanger 20
at the base 30 of casing 24 and extends into the borehole 26
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through the formation 22. Formation 22 is a conventional oil
reservoir. Other completions may also be considered such as an
open-hole screen with packers for example.
At surface 18, there is a wellhead 30. Wellhead 30 provides a
conduit 32 for the injection of fluids from pumps 34 into the well 10.
Wellhead gauges 36 are located on the wellhead 30 and are
controlled from the data acquisition unit 16 which also collects the
data from the wellhead gauges 36. Wellhead gauges 36 include a
temperature gauge, a pressure gauge and a rate gauge. These will
also measure data. Control units may also be mounted on the
surface 18 which will control the pumps 34, to vary their on/off
status, temperature of the pumped fluid and flow rate of the
pumped fluid. For simplification, the pumps 34 may be the cement
pump already present on the rig and the fluid may be held in pits
also as standard on the rig. Additional equipment in the form of a
heat exchanger to vary the temperature of the fluid at surface 18
may also be present.
The injected fluid is water. This may be drill water, filtered seawater
or unfiltered seawater. If desired, the water can be treated with
chemicals, for example bactericide or scale inhibitors depending on
predicted well characteristics obtained from core samples. A
viscosifier may also be used, but it may only be required to be
added if fracturing is not achieved on first injection.
For the data analysis we need to consider how to define the thermal
stresses. We consider the work of T.K. Perkins and J.A. Gonzalez:
'Changes in Earth Stresses around a Wellbore Caused by Radially
Symmetrical Pressure and Temperature Gradients'. SPE Journal,
April, pp 129 -140, 1984 and 'The Effect of Thernnoelastic Stresses
on Injection Well Fracturing'. SPE Journal, February, pp 78 -88,
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1985, incorporated herein by reference. Both these papers describe
the changes of temperature due to injecting fluid at a constant
temperature (BHT), the BHT being different from the virgin
reservoir temperature (Tres). In turn the stresses are altered in the
5 region with altered temperature. In particular the stress change
(Ao-) is quantified by the following equation (tension negative):
Acy = k AT (BHT -Tres) ....(1)
- k is the shape factor and Perkins and Gonzalez give formulas
for a circular and an elliptical disk;
10 - AT is the thermal stress parameter related to the thernno-
elastic properties of the formation through:
AT= aT E 1(1 - v) ....(2)
- aT is the thermal expansion of the formation
- E is Young's Modulus of the formation
- v is Poisson's ratio of the formation
This tells us that the fracture pressure around an injector will vary
over time and thus the thermal stress parameter is a key factor to
the design of a well injection program and the injection parameters
chosen. From the perspective of hydraulic fracture propagation,
injection confinement essentially depends on three main
parameters:
= Water cleanliness, which can be controlled at surface but is
likely to worsen due to the circulation in the lines and tubing;
= The natural stress contrast between sand and shale at the top
reservoir if any exists; and
= The reduction of the fracture pressure around the injection
well due to the cooling effect.
The latter of these will last throughout the life of a reservoir.
However, if produced water is re-injected, its magnitude will
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decrease over time as more produced water is added to the injected
mix. This is the case as the produced water will increase the
temperature of the injected mix. If we consider injection efficiency
over the years which an injection program can run, the percentage
of produced water, temperature, damaging solids and oil droplets
and fracture pressure all increase over the life of the well with the
injectivity-risk of leakage from an injection zone also increasing for
the life of the well.
Thus the time varying consequences from the thermal stress
parameter mean that it is vital to quantify this parameter prior to
undertaking any field development program.
To determine the thermal stress parameter we undertake injection
testing at the well. Using the arrangement shown in Figure 1 we
perform repeated fracture pressure measurements during step rate
tests and/or fall-off analysis after injection cycles.
We will now consider an example of an Injection Test Sequence,
though it must be remembered that this will be adapted for each
well's situation i.e. time slot, depth, rig, etc. Adaptation to the
formations encountered is also required so the drilling of the well is
followed-up and deviations from the initial program are entered into
the test design model. The logs are analysed to select the optimum
interval to be tested (perforated). The interval should be as
homogeneous as possible with respect to porosity -i.e. both
stiffness and permeability. The perforation length can be revised.
A series of step rate tests with flow and shut in are performed as
shown in Figure 2. For each step rate test 40a-d the water is
injected at an injection rate Q 44 into the well 10 for a period of
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time 42 and then the well 10 is shut-in for a further period of time.
Each period of injection gets progressively longer.
The step rate tests (SRT) are performed with the purpose of
ensuring a clear fracturing of the formation in front of the
perforated interval for each SRT. The design of the SRT is to use
short steps and a large number of them (typically 5nnin and 100
Ipnn). The fracturing during the 1st SRT and some other SRTs should
preferably occur before surface fluid reaches the perforation, thus
the wells should preferably be of sufficient depth but shallow well
conditions can also be accommodated. This design essentially plays
on the (BHT -Tres) term in Equation (1). A typical test duration
may be 24 to 48 hours depending on the results expected with the
reduced time being preferable based on rig costs.
For the injection period, the injection is constant and at a high rate.
This increases the zone affected by the thermal effect during each
injection cycle and thus plays on the k term in Equation (1). This
injection regime also allows for the estimation of the flow properties
of the reservoir during the last long injection period.
For the shut-in periods, these must be hard i.e. occur over a very
brief time period. If measurements can be made in this time period,
this may allow the determination of the fracture closure pressure.
(square root of time, Nolte's G-function, etc.) However, short
fractures are expected and this may prove difficult to measure. As
injection well testing is undertaken by shutting in the well, the shut-
in period here can be used to allow characterisation of the well
environment using the same factors as in standard production well
testing. The shut-in further allows there to be reheating of the fluid
inside the well and this can be measured.
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The test is followed up and analysed in real-time either on site or
remotely. The first injection cycle is analysed during its shut-in to
ensure that fracturing has occurred and at which pressure/rate. If
fracturing has not occurred a switch of pumps can be undertaken or
the introduction of a viscosifier to increase the fluid viscosity can be
considered. If it has the occurrence of a clear break-down, this must
be accounted for. The second cycle may be modified based on the
results of the first cycle from which modifications in the form of rate
ramping schedule and duration of high rate injection can be
modified. The analysis is repeated for each cycle.
Referring to Figure 3, there is illustrated a graph of the change in
pressure 46 versus time 42, with the data shown as individual
points 48a-f across a number of SRTs. We then fit a model 50
describing the development of the thermal stresses around the well
on the measured data to estimate the thermal stress parameter.
Those skilled in the art will appreciate that the fit can be a manual
fit or use linear Lagrangian optimization.
To fully interpret the data we look at fracture pressure (Pfrac)
against injected volume (V). Those skilled in the art will recognize
that closed form solutions or numerical models can be used. In
either case, the injection history (injection rate Q and bottom hole
temperature BHT) is discretised: more precisely the BHT versus
injected volume (V) curve is created.
For the closed form solutions, the temperature distribution in the
region affected by heat convection is established; the kernel
solutions provided by Perkins and Gonzalez are used in conjunction
with the superposition theorem -i.e. linear problem -to compute the
stress changes in the region affected by the thermal effects; and
the variation over time of the fracture pressure near the well is
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calculated. Figure 4 shows an illustration of the measured fracture
pressure 52 variation over time 42 around an injector. This is shown
both in real-time 54 and by back analysis 56. This illustrates that
the reservoir pressure 58, injection temperature and cold zone
development all affect the fracture pressure.
For the numerical models, two solutions are possible to compute the
variation of the fracture pressure around the well over time. The
"classic" approach consists of using a flow model which accounts for
heat convection (usually finite difference based) and then couples it
with a mechanical model (usually finite element based).
Alternatively a fully coupled model solving simultaneously for flow,
heat transfer and mechanics can be used. However, this requires
complex numerical techniques not commonly used in the oil
industry -e.g. mixed element, mesh refinement, etc.
For either case a hydraulic fracture model can also be considered
i.e. either a numerical model or asymptotic solutions (PKN, GdK,
etc.).
Values can be incorporated into a reservoir model or other known
models known to those skilled in the art from which the injection
parameters can be calculated. Such injection parameters will be
injection fluid temperature, fluid pump rate, fluid pump duration
and fluid injection volume. These values will also provide an
indication of pump requirements.
Injection testing therefore provides two main pieces of information
needed for the optimum field development planning:
-The value of the large-scale thermal stress parameter for the
design of the water injection system.
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-Large scale flow properties of the reservoir through well test
interpretation, which can be used as calibration points for the
reservoir model.
5 Those skilled in the art will be aware that production testing i.e. Drill
Stem Testing (DST) is rarely performed in appraisal wells because
of the need to store the produced oil and the environment
consequences of flaring the gas. Thus large scale flow of new fields
is left to models. There are advantages of injection testing
10 compared to production testing as the pumps are available on the
rig and the pits to store the injected fluid are there too. The
environmental impact is also limited as no hydrocarbons are
produced. Additionally, by fracturing the injection well in a
conventional reservoir we allow for the use of a produced water re-
15 injection program.
The principle advantage of the present invention is that it provides a
method for a well injection program in which injection testing is
used to determine thermal stress characteristics of the well.
A further advantage of the present invention is that it provides a
method for a well injection program in which injection testing is
used to determine parameters for well interpretation.
The foregoing description of the invention has been presented for
the purposes of illustration and description and is not intended to be
exhaustive or to limit the invention to the precise form disclosed.
The described embodiments were chosen and described in order to
best explain the principles of the invention and its practical
application to thereby enable others skilled in the art to best utilise
the invention in various embodiments and with various
modifications as are suited to the particular use contemplated.
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Therefore, further modifications or improvements may be
incorporated without departing from the scope of the invention
herein intended.
