FIELD OF INVENTION
This invention relates to optimized production via geological mapping
BACKGROUND
5 The easy to access and produce hydrocarbon resources are
being depleted leaving more difficult wells to access and produce. Meeting the
world's growing demand for hydrocarbons resulted in the development of
advanced recovery procedures, often refetTed to as complex recovery
completions and production techniques. These methods may include Steam
10 Assisted Gravity Drainage (SAGD), Thermal Assisted Gravity Drainage
(TAGD), Toe to Heal Air Injection (THAI), Vaporized Hydrocarbon Solvent
(V APEX) production and Fire Flooding. These techniques address the
mobility problem of the heavy oil wells by thermally and/or chemically
altering the viscosity of the bitumen to allow for easy extraction. While each
15 of the complex completion techniques offers a novel approach to heavy oil
extraction, their success may rely on the difficult process of precise placement
of well bores with respect to near-by geological structures.
One difficult scenario includes local deposits that have the
potential to cause steam to break through, resulting in a non-optimal steam
20 chamber. In this case, as steam is injected from the injector well, it breaks
through above or below the deposits and results in insufficient heating of
bitumen and, thus, reduction in production.
In one solution, producer wells are placed using resistivity or
gamma logs to detect fmmation layering from a distance. In this case, a
25 distance to nearby layering is used to optimally place the producer well in the
reservoir by geosteering the drilling. After the producer well is placed, the
injector well is placed with respect to the producer well using ranging devices
that can measure the relative distance and direction between the two wells.
Well-known commercial ap]Jroaches for this technique are
30 based on rotating magnets (e.g., U.S. Patent No. 5,589,775) or magnetic
guidance (U.S. Patent No. 5,923,170) that utilize both wellbores for ranging.
Most of these approaches, however, are undesirable in that they use two
different crews (i.e., wireline and logging while drilling (LWD)), which is not
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cost effective. One prior magnetic approach is based on a single well system
where both the transmitter and the receivers are downhole. This approach,
however, is based on absolute magnetic field measurement for distance
calculation (U.S. Patent No. 7,812,610) that does not produce reliable results
5 due to variations of the cunent on the target pipe.
Additionally, the prior art techniques typically place the
injector well a fixed distance above the producer well. The selection of the
fixed distance may be made heuristically without considering geological and
petrophysical variations. This may result in placement of the injector well at
1 0 non-optimal positions and reduction in volume of accessible hydrocarbons.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a flowchart showing a method for optimizing
production of fluid deposits using geological mapping, according to various
15 examples.
FIG. 2 is a cross-sectional diagram showing a geological
formation having a fluid deposit to be mapped using various embodiments of a
localizing method fi·om a producer well, according to various examples.
FIG. 3 is a flowchart showing an embodiment of the method for
20 localization using electromagnetic (EM) resistivity measurements, according
to various examples.
25
FIG. 4 is a flowchart showing an embodiment of the method for
localization using current leakage measurement, according to various
examples.
FIG. 5 is a flowchart showing another embodiment of the
method for localization using cunent leakage measurement, according to
various examples.
FIG. 6 is a flowchart showing another embodiment of the
method for localization using cunent leakage measurement, according to
30 various examples.
FIG. 7 is a flowchart showing another embodiment of the
method for localization using current leakage measurement, according to
various examples.
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FIG. 8 is a cross-sectional diagram showing a geological
formation with an embodiment of an SAGD steam chamber, according to
various examples.
FIG. 9 is a flowchart showing an embodiment of a method for
5 optimizing production of a fluid deposit, according to various examples.
FIG. 10 is a flowchart showing another embodiment of the
method for optimizing production of the fluid deposit, according to various
examples.
FIG. 11 is a flowchart showing another embodiment of the
I 0 method for optimizing production of the fluid deposit, according to various
examples.
15
FIG. 12 is a cross-sectional view of a geological fmmation in
which a geosteering embodiment of the optimization method is used around a
deposit, according to various examples.
FIG. 13 is a cross-sectional view of a geological fmmation in
which various casing embodiments of the optimization method are used near a
deposit, according to various examples.
FIG. 14 is a diagram of a wireline system embodiment,
according to various examples.
20 FIG. 15 is a diagram of a drilling rig system embodiment,
according to various examples.
DESCRIPTION OF INVENTION w.r.t. DRAWINGS
The embodiments described herein include two steps:
25 localization and measurement of low resistivity fluid deposits and optimization
of production with the given geology infmmation. The localization and
measurement may be perfmmed through downhole or surface resistivity
measurements owing to the low resistivity nature of the deposits. The
localization and measurement step may also be referred to as mapping of the
30 deposits in a geological formation.
The optimization may be performed using multiple methods.
For example, the drill string (e.g., drill bit) of the injector or producer wells
may be geosteered away from the deposits in a three dimensional fashion (e.g.,
-4-
laterally and/or ve1tically). In another optimization embodiment, the slots
and/or seams of the well casing may be adjusted based on the near-by deposits.
Both types of optimization may be assisted by steam chamber or geo-steering
models that incorporate the local geology and drilling perf01mance related
5 information.
The fluid deposits referred to herein include a low resistivity
fluid deposit. Low resistivity fluid deposits may be characterized by measuring
how strongly the fluid opposes the flow of electric current. A low resistivity
fluid deposit may be defined as any fluid having an electrical resistance of less
. 10 than 300 Ohms which includes most hydrocarbons. The low resistivity fluid
deposit may be referred to as simply a fluid, a deposit, or a fluid deposit and is
assumed herein to be low-resistivity.
FIG. 1 is a flowchart showing a method for optimizing
production of fluid deposits using geological mapping, according to various
15 examples. In box 1 01, a method for localizing and measuring the deposits in a
geological f01mation is initially used. This step maps the size and location of
the deposits. Various embodiments for localizing and measuring the deposits
are illustrated in FIGs. 2-7 and discussed subsequently.
Once the deposits are mapped, production of the deposits may
20 then be optimized in box 103 by adjusting at least one of a drilling parameter
or a production parameter. Various embodiments for optimizing production of
the deposits are illustrated in FIGs. 8-13 and discussed subseq11ently.
FIG. 2 is a cross-sectional diagram showing a geological
formation having a fluid deposit to be mapped using various embodiments of a
25 localizing method from a producer well, according to various examples. It is
noted here that the variations that are included in this illustration are not
necessarily used together and they are shown together mainly for the sake of
contrasting them with respect to each other. As described previously, detailed
geological models of fluid deposits are not typically available a-priori. Seismic
30 surveys do not have a high enough resolution and are not as sensitive to types
of deposits that may cause a steam break-through. The delineations that are
logged with wireline and cored wells may be available but this data is not
contiguous and may not be used to interpolate in between wells. The localizing
- 5 -
and measuring embodiments disclosed in FIG. 2 provide greater accuracy for
later optimization of production.
FIG. 2 shows a well 200 (e.g., producer or injector) drilled
through a geological formation 21 0 and a deposit layer 211. The deposit layer
5 211 may include a low resistivity fluid deposit 205.
An EM tomography measurement embodiment 201 is shown.
This embodiment may include both a transmitter 23 0 and receiver 231 on the
surface, the transmitter 230 on the surface and the receiver 232 in the well 200,
the transmitter 232 in the well and the receiver 231 on the surface, or the
10 transmitter in one well bore while the receiver is in another well bore.
FIG. 2 further shows an L WD deep resistivity reading sensor
tool 202 in the drill string. The tool incorporates a multi-frequency, deepreading,
azimuthal (directional) resistivity sensor that may incorporate tilted
receiver coils. The L WD deep resistivity sensor tool 202 may provide
15 measurements of approximately 20 feet from the well 200. The L WD tool 202
may also be used in an L WD ultra-deep resistivity reading embodiment (e.g.,
> approximately 20 feet).
A current leakage measurement 203 embodiment is illustrated
m relation to the well 200. As discussed subsequently, this embodiment
20 measures the current leakage on one of the pipes to map out the location and
shape of the deposits 205.
FIG. 3 is a flowchart showing an embodiment of the method for
localization usmg electromagnetic (EM) tomography or resistivity
measurements, according to various examples. This embodiment may use EM
25 tomography transmitter/receivers or an EM resistivity L WD tool (e.g.,
azimuthal, non-azimuthal, deep reading, or ultra-deep reading) to perform EM
tomography or EM resistivity measurements.
In block 301, the producer well or injector well is drilled 301 as
shown in FIG. 2. In block 303, the EM tomography transmitters/receivers or
30 EM resistivity LWD tool may then be used.
EM tomography measurement may be perfmmed from surface
to wellbore, wellbore to another wellbore, or surface to surface. It may be
performed as a single-shot measurement or a time-lapse measurement. EM
- 6 -
5
tomography measurements may employ an anay of transmitting antennas and
receiving antennas which may be of magnetic dipole, electric dipole or electric
monopole type. These transmitters and receivers may be towed on trucks,
ships or sub-sea vehicles depending on the type of operating environment.
In EM tomography, a single frequency, multi-frequency or
pulsed electromagnetic signal is transmitted from the transmitter into the
subtenanean formations. Diffused and scattered signals, resulting from the
transmitted signal, are received from the formation by the receivers. The
received electric and/or magnetic fields or voltages are partly indicative of the
10 characteristics of the downhole formations, specifically the resistivity of the
layers.
The EM tomography measurements may be used to calculate
the position of deposits at various depths (e.g., 0-6000 feet). EM tomography
may be used if deposits are relatively large in volume and conductivity
15 contrast. Localization of deposits with the EM tomography method may begin
with an initial estimate of the underlying fmmation layers. This enables the
system to resolve the layers easily and focus on the deposits.
L WD azimuthal resistivity tools may also be used to map out
the deposits. L WD azimuthal resistivity tools may make multiple
20 measurements of resistivity at different azimuthal orientations relative to the
wellbore as the tool rotates with the natural rotation of the drilling. The deep
reading tool may be used in measuring deposits having a shallower nature
(e.g., up to 20 feet range relative to well bore) to enable operators to map out
the resistivity of the reservoir section that is local to the resistivity tool
25 position.
In one embodiment, an azimuthal resistivity tool may be used.
However, another embodiment may use a non-azimuthal tool if a relative
direction of the observed deposit is not needed.
The L WD tool may be placed in the drill string of the producer
30 well and/or the injector well. The resistivity logging data may then be
collected at one or more depths as the drilling continues. Deposits may be
identified from unexpected deviations of the tool responses as the horizontal
drilling commences. They can also be identified from distance to bed
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boundary inversions that can be conducted at different points. Ultra-deep
reading tools may be used to map deposits up to I 00 feet away from the
borehole.
FIG. 4 is a flowchart showing an embodiment of the method for
5 localization using current leakage measurement, according to various
examples. This embodiment may be used from one of the casings (e.g.,
producer or injector) to map out the relative location and shape of the deposits
with respect to the wellbore used.
In the interest of clarity, the following method is described with
I 0 respect to the current being injected on the producer well casing. However, the
terms "producer" and "injector" wells may be swapped and the method would
still operate as described.
In block 401, casing is placed in the producer well. In block
403, drilling of the injector well is begun. A cuiTent may then be injected on
15 the producer well casing, in block 405, from an electrode that is connected to
the wellhead. As the current moves down in the casing in the wellbore, it leaks
out to the geological formation. The leakage at each depth is proportional to
the local resistivity at that region and near-by zones. Any near-by low
resistivity deposit causes the current leak to increase. The leakage difference
20 along the casing may used as an indication of the presence of a near-by
deposit.
In block 407, the current may be detected in the injector well
casing using a ranging tool on an injector well drill string. The current may be
calculated on the producer well at the present measure depth in block 409.
25 This calculated current is subtracted from a past depth current measurement in
order to calculate the current leakage in block 411.
Two different operations 413, 415 may be perfotmed as a result
of determining the cmTent leakage. In one embodiment (i.e., block 413), the
calculated current leakage may be combined with EM resistivity L WD tool
30 data to obtain an improved image of the deposit. In another embodiment (i.e.,
block 415), the calculated current leakage indicates a zone of low resistivity.
Such a zone may be indicative of a low resistivity fluid deposit.
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Effect of resistivity variations may be removed from the
calculations by using well planner software that can simulate an expected
cmTent leak given a well path and geology inf01mation but without the
deposits. Since the producer well is typically placed at a fixed distance with
5 respect to near-by formation layers (through practice of geo-steering), changes
in the leakage correlate well with the low resistivity deposits.
The current leakage may be measured using any one of a
plurality of embodiments that use a measurement of the cmTent at each depth
as the first step. One embodiment may employ current injection on the
10 producer, and L WD magnetic field measurements during the drilling of the
injector. In this case, the magnetic field measurements are directly
proportional to the current on the producer at the section that is closest to the
magnetic field measurement tool in the injector. This may be illustrated in
equation (1) as:
15
H- =I- ¢- (1)
2w
where H is the magnetic field vector, I is the current on the pipe, r is the
shortest distance between the receivers and the pipe and ¢ is a vector that is
20 perpendicular to both z axis of the receiver and the shortest vector that
connects the pipe to the receivers.
The relationship of equation (1) assumes constant casing
cmTent along the casing. However, this embodiment may be extended to any
cmTent distribution by using an appropriate electromagnetic model. This
25 model and configuration may be employed by the ranging tools to place the
injector well at fixed distance and direction with respect to the producer well.
As a result, a ranging tool may be used for the dual purpose of well placement
and also mapping of the deposits. In this configuration, gradient measurements
fi·om the ranging tool can be used to measure the distance and absolute
30 magnetic field measurement so that the measured distance can be used to
calculate the current.
FIG. 5 is a flowchart showing another embodiment of the
method for localization using current leakage measurement, according to
- 9-
various examples. In this embodiment, the current is injected in the producer
and/or the injector and the electrodes are placed in the well where current is
injected.
In block 501, drilling of the producer well is started and, in
5 block 503, well casing is placed in at least a portion of the well bore. At least
two injection electrodes may be placed at various measurement depths of the
producer casing, in block 505. The electrodes are axially separated by a
distance along the casing that is fixed mechanically and both electrodes are
kept in touch with the casing.
10 In block 507, the voltage between two measure electrodes is
measured at each depth. These measure electrodes may be chosen individually
the same with or different to the injection electrodes. The voltage between the
measure electrodes is directly proportional to the cunent on the pipe between
the electrodes, and it can be used in the estimation. This is based on ohm's
15 law:
I= V (2)
R
where V is the voltage between the electrodes, R is the resistance between the
20 measure electrodes and I is the calculated current. In block 509, the current I
may be calculated on the producer well at each measured depth.
Resistance R can be calculated from well plan or it can be
measured by injecting a known current between the injection electrodes and
measuring the. voltage between the measure electrodes. If deposits are detected
25 through the monitoring of variations in the current leak, the accuracy of the R
parameter is not as important since it is only a multiplication factor.
In block 511, the current calculated at the present depth is
subtracted from a past current that was calculated at the past depth to
determine the current leakage between the present and past depths. This
30 calculated leakage may be used in two ways. In block 513, the calculated
leakage is combined with an EM resistivity L WD tool data to obtain an
improved image of the deposit. In another embodiment (block 515), the
current leakage may be used as an indication of a low resistivity zone.
- 10-
FIG. 6 is a flowchart showing another embodiment of the
method for localization using current leakage measurement, according to
various examples. This embodiment uses an azimuthal magnetic field from a
permanent magnet sensor placed outside of the well bore during construction.
5 In block 601, drilling of the producer well is started and, in
block 603, well casing is placed in at least a portion of the wellbore. The
azimuthal magnetic sensor is then placed outside of the casing in block 605.
The magnetic field measurements are directly proportional to the current at the
section of the pipe that is closest to the magnetic field sensor. Using equation
10 (1 ), this embodiment solves for the unknown current using the measured
magnetic field and distance from the sensor to the center ofthe casing.
In block 607, the current may be calculated on the producer
well at each measured depth. ln block 609, the current calculated at the present
depth is subtracted from a past current that was calculated at the past depth to
15 determine the current leakage between the present and past depths. This
calculated leakage may be used in two ways. In block 611, the calculated
leakage is combined with an EM resistivity L WD tool data to obtain an
improved image of the deposit. ln another embodiment (block 613 ), the
cmTent leakage may be used as an indication of a low resistivity zone.
20 FIG. 7 is a flowchart showing another embodiment of the
method for localization using current leakage measurement, according to
various examples. This embodiment uses a radial electric field sensor
In block 701, drilling of the producer well is started and, in block 703, well
casing is placed in at least a pmtion of the wellbore. The radial electric field
25 sensor is then placed outside of the casing in block 705. The radial electric
field is directly proportional to current leakage and can provide a direct
estimation of the location of a deposit.
In block 707, the current may be calculated on the producer
well at each measmed depth. In block 709, the current calculated at the present
3 0 depth is subtracted from a past current that was calculated at the past depth to
determine the current leakage between the past and present depths. This
calculated leakage may be used in two ways. In block 711, the calculated
leakage is combined with an EM resistivity L WD tool data to obtain an
- 11 -
improved image of the deposit. In another embodiment (block 713), the
cunent leakage may be used as an indication of a low resistivity zone.
In the embodiments of FIGs. 4-6, the leakage current between
two points on the casing may be calculated through a simple subtraction of
5 two cunents along the well at those two points. In practice, if the points are
chosen to too close, accuracy of the current leakage estimate may not be as
accurate as more distant points since only a very small cmTent is being probed.
If the points are chosen too far, the resolution of the leakage measurement may
become too low (which is in the order of the distance between the two
10 electrodes). As a result, there is an optimal distance when both criteria are met.
The optimal distance may vary with the resistivity of the formation and
deposits, but it may be in a range between 1 foot and 50 feet.
The low resistivity fluid deposits may also be located through
acoustic logging tools or borehole seismic methods through reflections or
15 radial profiling applications. If deposits intersect the wellbore, a borehole
imaging or coring method may be employed to collect more diverse data about
the deposits.
FIG. 8 is a cross-sectional diagram showing a geological
formation with an embodiment of an SAGD steam chamber, according to
20 various examples. The SAGD method may be used in combination with the
various optimization embodiments discussed subsequently with reference to
FIGs. 9-13. The SAGD method is shown for purposes of illustration only as
other production methods may be used.
In this embodiment, the producer well 801 and injector well
25 802 are drilled through the geological formation 800 and into a deposit layer
811. Steam is then injected from the injector well 802. The steam forms a
steam chamber 810 around the producer well 801.
The steam of the steam chamber 81 0 decreases the viscosity of
any hydrocarbons in the deposit layer 811. This may increase the mobility of
30 the hydrocarbons.
In another embodiment, heat may be applied through resistive
means located in the injector well 802. This heat may also form the steam
chamber 810 from any adjacent water. As the steam chamber 810 expands, the
- 12-
two wells 801, 802 are connected hydro-dynamically. The steam distribution
around the wells 801, 802 is typically not uniform and may vary based on the
geological and petrophysical properties of the rocks.
Embodiments of the production optimization method are shown
5 in FIGs. 9-11. These embodiments use geosteering, completion parameter
optimization, or steam characteristics estimation. The embodiments are
applied after localization of the deposits using one of the localization
embodiments described previously.
FIG. 9 is a flowchart showing an embodiment of a method for
I 0 optimizing production of a fluid deposit, according to various examples. This
embodiment uses geosteering as illustrated in FIG. 12.
The deposits are located and measured m block 901.
Embodiments for performing this step have been discussed previously.
In block 903, the drilling of the producer or injector wells are
15 geosteered based on deposit position, shape, and/or resistivity as previously
described. The geosteering may be perfmmed in one or more of the steps in
blocks 905, 907, 909. For example, in block 905, the drilling of the producer
well is geosteered away fi·om the deposits. In block 907, the drilling of the
injector well is geosteered away from the deposits. In block 909, the steam
20 chamber design is geosteered away from the deposits.
FIG. 10 is a flowchmi showing another embodiment of the
method for optimizing production of the fluid deposit. This embodiment
adjusts one or more completion parameters.
After the deposits are located and measured in block 1001, one
25 or more of the completion parameters may be adjusted based on the deposit
relative position, shape, and/or resistivity, as seen in block 1003.
Examples of the completion parameters may include adjusting
local slots and/or seams of the casing based on nearby deposits, as seen in
block 1005. Another example, in block 1007, includes adjusting the slot and/or
30 seam density and/or size based on nearby deposits. In yet another example, in
block 1009, fewer or no slots and/or seams may be used near deposits. In
another example, in block 1011, more slots and/or seams may be used near
deposits.
- 13-
FIG. 11 is a flowchart showing another embodiment of the
method for optimizing production of the fluid deposit, according to various
examples. This embodiment uses a steam chamber model to estimate steam
characteristics of the deposit.
5 In block 1101, the deposits are located 1101. In block 1103, the
deposit data from the localizing operation is fed into a steam chamber model
to estimate the deposit's steam characteristics and/or production
characteristics.
FIG. 12 is a cross-sectional view of a geological formation in
10 which a geosteering embodiment of the optimization method is used around a
deposit, according to various examples. In this embodiment, the producer and
injector wells 1200, 1201 are steered 1202, 1203 away from the low resistivity
deposit 1230 but still within the high production zones in the reservoir 1209.
The geosteering may be accomplished by adjusting the ve11ical
15 or horizontal placement of the wells 1200, 1201. The freedom of optimization
in the vertical direction may be limited due to a limited size of the reservoir in
the ve11ical direction. Producer and injector we111200, 1201 placement may be
optimized individually. Alternatively, the wells 1200, 1201 may be optimized
jointly through the use of a steam chamber model that can produce an estimate
20 of the production amount based on the placement of the wells 1200, 1201 with
respect to near-by fo1mation layers and deposits. The ideal positioning that
optimizes the production is planned. Geosteering and operational limitations
(e. g., maximum dogleg) may also be applied as a constraint in the
optimization.
25 The optimization of production and localization of deposits can
take place simultaneously. For example, as a well is drilled, an LWD tool may
provide data that can localize the deposits. This information may then be used
in real time to determine the ideal well path that is executed through
geosteering. In the new well path, L WD tools collect new data and this process
30 may be repeated. In this embodiment, this optimization may lead to different
distances between the producer well and the injector well as a function of the
presence of nearby deposits.
- 14-
FIG. 13 is a cross-sectional view of a geological formation in
which various casing embodiments of the optimization method are used near a
deposit, according to various examples. This embodiment may use the density
and/or distribution of the slots and/or seams of the casing to accommodate the
5 localized deposits.
FIG. 13 shows producer and injector wells 1310, 1311 that each
have casings/liners. The casings include varying densities of slots and/or
seams 1320-1326 depending on the locations of the deposits 1300, 1301. For
example, fewer or no slots and/or seams may be placed in areas with nearby
10 deposits so that steam can be focused on the areas where production can be
increased. An opposite strategy may also be used to use more (or wider) slots
and seams in areas with deposits to compensate for the loss of steam in the
desired volume. Determination of which strategy to use can be made based on
a steam chamber hydro-dynamic and petrophysical model.
15 FIG. 14 is a diagram showing a wireline system 1464 and FIG.
15 is a diagram showing a drilling rig system 1564, according to various
examples. The systems 1464, 1564 may thus comprise portions of a wireline
logging tool body 1420 as part of a wireline logging operation or of a down
hole tool 1524, including the EM tomography or L WD EM resistivity tools
20 described previously, as part of a down hole drilling operation.
FIG. 14 illustrates a well that may be used as either an injector
well or a producer well. In this case, a drilling platform 1486 is equipped with
a derrick 1488 that supports a hoist 1490.
Drilling oil and gas wells is commonly carried out using a
25 string of drill pipes connected together so as to form a drillstring that is
lowered through a rotary table 1410 into a wellbore or borehole 1412. Here it
is assumed that the drillstring has been temporarily removed from the borehole
1412 to allow a wireline logging tool body 1420 to be lowered by wireline or
logging cable 1474 (e.g., slickline cable) into the borehole 1412. Typically, the
30 wireline logging tool body 1420 is lowered to the bottom of the region of
interest and subsequently pulled upward at a substantially constant speed.
During the upward trip, at a series of depths various
instruments may be used to perfmm measurements on the subsurface
- 15 -
geological formations 1414 adjacent to the borehole 1412 (and the tool body
1420). The wireline data may be communicated to a surface logging facility
1492 for processing, analysis, and/or storage. The logging facility 1492 may
be provided with electronic equipment for various types of signal processing.
5 Similar fmmation evaluation data may be gathered and analyzed during
drilling operations (e.g., during L WD/MWD operations, and by extension,
sampling while drilling). The data may be used for localizing and measuring
the deposits as previously described.
In some embodiments, the tool body 1420 is suspended in the
1 0 well bore by a wire line cable 14 7 4 that connects the tool to a surface control
unit (e.g., comprising a workstation 1454). The tool may be deployed in the
borehole 1412 on coiled tubing, jointed drill pipe, hard wired drill pipe, or any
other suitable deployment technique.
Referring to FIG. 15, it can be seen how a system 1564 may
15 also fmm a portion of a drilling rig 1502 located at the surface 1504 of a well
1506. The drilling rig 1502 may provide support for a drillstring 1508. The
drillstring 1508 may operate to penetrate the rotaty table 1410 for drilling the
borehole 1412 through the subsurface formations 1414. The drillstring 1508
may include a drill pipe 1518 and a bottom hole assembly 1520, perhaps
20 located at the lower pmtion of the drill pipe 1518.
The bottom hole assembly 1520 may include drill collars 1522,
a dowu hole tool 1524, and a drill bit 1526. The drill bit 1526 may operate to
create the borehole 1412 by penetrating the surface 1504 and the subsurface
formations 1414. The dowu hole tool1524 may comprise any of a number of
25 different types of tools including MWD tools, LWD tools, and others.
During drilling operations, the drillstring 1508 (perhaps
including the drill pipe 1518 and the bottom hole assembly 1520) may be
rotated by the rotm·y table 1410. Although not shown, in addition to, or
alternatively, the bottom hole assembly 1520 may also be rotated by a motor
30 (e.g., a mud motor) that is located down hole. The drill collars 1522 may be
used to add weight to the drill bit 1526. The drill collars 1522 may also operate
to stiffen the bottom hole assembly 1520, allowing the bottom hole assembly
- 16-
1520 to transfer the added weight to the drill bit 1526, and in turn, to assist the
drill bit 1526 in penetrating the surface 1504 and subsurface fo1mations 1414.
During drilling operations, a mud pump 1532 may pump
drilling fluid (sometimes known by those of ordinary skill in the art as
5 "drilling mud") from a mud pit 1534 through a hose 1536 into the drill pipe
1518 and down to the drill bit 1526. The drilling fluid can flow out fi·om the
drill bit 1526 and be returned to the surface 1504 through an annular area 1540
between the drill pipe 1518 and the sides of the borehole 1412. The drilling
fluid may then be returned to the mud pit 1534, where such fluid is filtered. In
10 some embodiments, the drilling fluid can be used to cool the drill bit 1526, as
well as to provide lubrication for the drill bit 1526 during drilling operations.
Additionally, the drilling fluid may be used to remove subsurface formation
cuttings created by operating the drill bit 1526.
The workstation 1454 and the controller 1496 may include
15 modules comprising hardware circuitry, a processor, and/or memory circuits
that may store software program modules and objects, and/or firmware, and
combinations thereof. The workstation 1454 and controller 1496 may be
configured to control the direction and depth of the drilling in order to geosteer
the drilling as discussed previously. For example, in some embodiments, such
20 modules may be included in an apparatus and/or system operation simulation
package, such as a software electrical signal simulation package, a power
usage and distribution simulation package, a power/heat dissipation simulation
package, and/or a combination of software and hardware used to simulate the
operation of various potential embodiments.
25 Additional embodiments may include:
Example 1 is a method for optimizing production in a well, the
method comprising: localizing low resistivity fluid deposits in a geological
formation; and optimizing production of the fluid deposits from the geological
formation based on the localizing by adjustment of at least one of a drilling
30 parameter or a production parameter.
In Example 2, the subject matter of Example 1 can further
include wherein localizing comprises electromagnetic tomography using a
- 17-
transmitter on a surface of the geological formation and a receiver m a
borehole through the geological formation.
In Example 3, the subject matter of Examples 1-2 can further
include wherein localizing comprises electromagnetic tomography using a
5 transmitter in a borehole through the geological formation and a receiver on a
surface of the geological formation.
In Example 4, the subject matter of Examples 1-3 can further
include wherein localizing comprises electromagnetic tomography using a
transmitter and receiver on a surface of the geological fmmation.
10 In Example 5, the subject matter of Examples 1-4 can further
15
include wherein localizing comprises using an azimuthal resistivity tool.
In Example 6, the subject matter of Examples 1-5 can futiher
include wherein using the azimuthal resistivity tool comprises measuring a
cunent leakage from a casing through the geological formation.
In Example 7, the subject matter of Examples 1-6 can further
include wherein the casing is a production well casing and measuring the
cunent leakage comprises: injecting a cunent on the production well casing;
and measuring a magnetic field within an injector well.
In Example 8, the subject matter of Examples 1-7 can further
20 include wherein the casing is a production well casing and/or an injector well
casing and measuring the cmTent leakage comprises: injecting a cunent on the
production casing and/or the injector casing; and measuring the magnetic field
within the casing on which the current is injected.
In Example 9, the subject matter of Examples 1-8 can further
25 include wherein measuring the current leakage comprises: measuring the
magnetic field fi·om magnetic sensors located outside of well casing.
In Example 10, the subject matter of Examples 1-9 can futiher
include wherein optimizing production comprises geosteering a drill head.
In Example 11, the subject matter of Examples 1-10 can further
30 include wherein optimizing production comprises adjusting slots and/or seams
in a casing of a production well.
In Example 12, the subject matter of Examples 1-11 can further
include wherein adjusting the slots and/or seams in the casing comprises at
- 18 -
least one of: adjusting the slot and/or seam design based on the fluid deposit
and/or adjusting the slot and/or seam density and/or size based on the fluid
deposit.
In Example 13, the subject matter of Examples 1-12 can further
5 include wherein optimizing production comprises estimating steam
characteristics and/or production characteristics of the fluid deposit.
Example 14 is a method for optimizing production in a well, the
method comprising: drilling a production or an injector well in a geological
formation; localizing, with the production or injector well, low resistivity fluid
10 deposits in the geological formation by: electromagnetic tomography, current
leakage measurement, or logging while drilling deep-reading to map low
resistivity fluid deposits in the geological formation; and geosteering drilling,
adjusting casing parameters, or estimating steam characteristics of the fluid
based on the localizing.
15 In Example 15, the subject matter of Example 14 can further include
wherein the geosteering drilling comprises geosteering a drill bit in the
production well in three dimensions through the geological formation.
In Example 16, the subject matter of Examples 14-15 can further
include wherein localizing fluid deposits in the geological fmmation
20 comprises using a logging while drilling tool.
Example 17 is a drilling system comprising: a down hole tool
comprising an electromagnetic tomography tool, a current leakage
measurement tool, or a logging while drilling deep-reading too configured to
map low resistivity fluid deposits in a geological formation; and a controller
25 coupled to the down hole tool and configured to control optimization of
production of the fluid by controlling a drilling parameter or a production
parameter based on the mapping of the fluid.
In Example 18, the subject matter of Example 17 can further include
wherein the down hole tool comprises a logging while drilling tool having a
30 non-azimuthal, azimuthal, deep-reading, or ultra-deep reading function.
In Example 19, the subject matter of Examples 17-18 can further
include wherein the controller is further configured to control geosteering of a
drill string based on the mapping of the fluid.
- 19-
In Example 20, the subject matter of Examples 17-19 can further
include well casing in an injector well wherein the well casing comprises a slot
or seam design in response to the mapping of the fluid.
In Example 21, the subject matter of Examples 17-20 can further
5 include wherein the slot or seam design includes density and/or locations of
slot and/or seams of the well casing.
10
In Example 22, the subject matter of Examples 17-21 can fmther
include wherein the controller is further configured to steer a steam chamber
away from the fluid.
The accompanying drawings that form a part hereof, show by way of
illustration, and not of limitation, specific embodiments in which the subject
matter may be practiced. The embodiments illustrated are described in
sufficient detail to enable those skilled in the art to practice the teachings
disclosed herein. Other embodiments may be utilized and derived therefrom,
15 such that structmal and logical substitutions and changes may be made without
departing from the scope of this disclosure. This Detailed Description,
therefore, is not to be taken in a limiting sense, and the scope of various
embodiments is defined only by the appended claims, along with the full range
of equivalents to which such claims are entitled.

WE CLAIM:
1. A method for optimizing production in a well, the method comprising:
localizing low resistivity fluid deposits in a geological formation; and
optimizing production of the fluid deposits from the geological
5 formation based on the localizing by adjustment of at least one of a drilling
parameter or a production parameter.
2. The method of claim 1, wherein localizing comprises electromagnetic
tomography using a transmitter on a surface of the geological formation and a
10 receiver in a borehole through the geological formation.
15
3. The method of claim 1, wherein localizing comprises electromagnetic
tomography using a transmitter in a borehole tln·ough the geological formation
and a receiver on a surface of the geological formation.
4. The method of claim 1, wherein localizing comprises electromagnetic
tomography using a transmitter and receiver on a surface of the geological
formation.
20 5. The method of claim 1, wherein localizing comprises using an
azimuthal resistivity tool.
6. The method of claim 5, wherein using the azimuthal resistivity tool
comprises measuring a current leakage from a casing through the geological
25 formation.
30
7. The method of claim 6, wherein the casing is a production well casing
and measuring the cmTent leakage comprises:
8.
injecting a current on the production well casing; and
measuring a magnetic field within an injector well.
The method of claim 6, wherein the casing is a production well casing
and/or an injector well casing and measuring the current leakage comprises:
- 21 -
5
10
injecting a current on the production casing and/or the injector casing;
and
measuring the magnetic field within the casing on which the current is
injected.
9. The method of claim 6, wherein measuring the current leakage
compnses:
measuring the magnetic field from magnetic sensors located outside of
well casing.
10. The method of claim 1, wherein optimizing production comprises
geosteering a drill head.
11. The method of claim 1, wherein optimizing production comprises
15 adjusting slots and/or seams in a casing of a production well.
12. The method of claim 11, wherein adjusting the slots and/or seams in
the casing comprises at least one of: adjusting the slot and/or seam design
based on the fluid deposit and/or adjusting the slot and/or seam density and/or
20 size based on the fluid deposit.
25
13. The method of claim 1, wherein optimizing production comprises
estimating steam characteristics and/or production characteristics ofthe fluid
deposit.
14. A method for optimizing production in a well, the method comprising:
drilling a production or an injector well in a geological fmmation;
localizing, with the production or injector well, low resistivity fluid
deposits in the geological fmmation by: electromagnetic tomography, current
30 leakage measurement, or logging while drilling deep-reading to map low
resistivity fluid deposits in the geological formation; and
geosteering drilling, adjusting casing parameters, or estimating steam
characteristics of the fluid based on the localizing.
-22-
5
10
15. The method of claim 14, wherein the geosteering drilling comprises
geosteering a drill bit in the production well in three dimensions through the
geological formation.
16. The method of claim 14, wherein localizing fluid deposits in the
geological f01mation comprises using a logging while drilling tool.
17. A drilling system comprising:
a down hole tool comprising an electromagnetic tomography tool, a
current leakage measurement tool, or a logging while drilling deep-reading
tool configured to map low resistivity fluid deposits in a geological formation;
and
a controller coupled to the down hole tool and configured to control
15 optimization of production of the fluid by controlling a drilling parameter or a
production parameter based on the mapping of the fluid.
18. The system of claim 17, wherein the down hole tool comprises a
logging while drilling tool having a non-azimuthal, azimuthal, deep-reading,
20 or ultra-deep reading function.
19. The system of claim 17, wherein the controller is further configured to
control geosteering of a drill string based on the mapping of the fluid.
20. The system of claim 17, futiher comprising a well casing in an injector
25 well wherein the well casing comprises a slot or seam design in response to the
mapping of the fluid.
21. The system of claim 20, wherein the slot or seam design includes
density and/or locations of slot and/or seams of the well casing.
22. The system of claim 17, wherein the controller is further configured to
30 steer a steam chamber away from the fluid.