Note: Descriptions are shown in the official language in which they were submitted.
METHOD OF USING A DISSOLVABLE DEPLOYMENT DEVICE FOR THE
TRANSFER OF ULTRAHIGH RESOLUTION NANOPARTICLE TRACER
ADDITIVES INTO A WELLBORE
BACKGROUND
Field of the Disclosure
mon This
disclosure generally relates to the use of an innovative type of chemical
additive
known as a 'tracer' in a wellbore or other comparable subterranean formation.
The tracer may
be disposed into a dissolvable device, and then transferred into the wellbore.
The tracer may
be flown out from the targeted structure with a resultant produced fluid, then
tested in a
manner that facilitates determination of flow performance, or a model of one
or more
production parameters associated with the wellbore. The disclosure relates to
using ultrahigh
resolution inert nano particle tracer technology in oil, gas and geothermal
wells that need not
necessarily be hydraulicly fractured.
Background of the Disclosure
[0002] A hydrocarbon-based economy continues to be dominant force in the modem
world.
As such, locating and producing hydrocarbons, along with understanding the
flow
performance of subsurface formations, continues to demand attention from the
oil and gas
(O&G) industry. A well or wellbore is generally drilled in order to recover
valuable
hydrocarbons and other desirable materials trapped in geological formations in
the Earth,
which are later refined into commercial products, such as gasoline or natural
gas.
[0003] Once the drilling is finished, a production string is typically placed
all the way into
the wellbore. To gain access to hydrocarbons, selected portions of the
production string (and
formation) are often perforated. Common today to increase or enhance
production in the tight
or unconventional reservoirs is the use of hydraulic fracturing (i.e.,
"fracing") in the
surrounding formations.
[0004] Fracing entails the pumping of fracturing fluids with sand into a
formation in an open-
hole or via perforations in a cased wellbore or other openings in the casing
to form a
fracture(s) in the formation. Fracing routinely requires very high fluid
pressure and pumping
rate and can occur in a multi-stage fracing manner.
[0005] The modern design of shale well with multi-stage hydraulic fracturing
operations
involve pumping from 20 to 100 fracing stages with a cumulative volume of 5 to
20 million
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Date Recue/Date Received 2023-03-03
gallons of water and from 5 to 20 million pounds of sand per well. This
represents the total
cost ranging from 4.0 million to 9.5 million U.S. dollars per well. Fracing
operations are
expensive, increasingly environmentally challenging and emissions intensive,
and can
represent up to 70% of the total cost for each well.
[0006] With such extensive costs, there may be situations where a wellbore is
not subjected
to hydraulic fracturing, but yet it still might be desirous to have some
amount of diagnostic
information about the well. For example, producers may desire to know when
production
occurs from a target formation, such as the bottom/toe end portion of a
wellbore. For the sake
of flow assurance, it might be desirous to have diagnostic information that
may be decoupled
from fracturing. It follows that it might be desirous to have diagnostic
information about (a
part of) the wellbore, but not necessarily a fractured area.
[0007] Production diagnostic tools may be used in order to predict well
performance,
improve well design, or aid in future well development. Typically, diagnostic
or surveillance
tools include fiber, PLT (production logging), fiber-optic, and liquid
chemical tracers.
[0008] Use of fiber optic systems that include distributed acoustic sensing
(DAS) and
distributed temperature surveys (DTS) is known to provide high-end diagnostic
results.
However, fiber is known to be excessive in cost and deployment complexities,
and the time
to obtain useful data may be in the realm of weeks or longer. Depending on the
complexity,
the installation of fiber optic DAS and DTS systems can add as much as $1
million/well to
the completed total costs.
[0009] PLT also has its favored uses and is a historically well accepted
approach, but while
perhaps slightly lower in cost, it is known to provide a short snapshot view
and information
compared to fiber and requires well shut-in and costly wireline intervention.
loom Conventional chemical liquid tracers have enjoyed success but are also
known to have
limitations. These tracers are dissolvable in oil and water phases, and
typically have
fluorescent properties, DNA and ionic, organic materials, or radioactive
diagnostic isotopes.
Such tracers are used to evaluate fracturing performance, ostensibly to
control the
effectiveness of multi-stage hydraulic fracturing stimulation. Owing to
obvious
environmental deficiencies, tracers incorporating radioactive isotopes have
largely fallen out
of favor. Given their soluble characteristics, conventional chemical tracers
must be tailored
for individual fluid types, thereby requiring more, and often exotic,
formulations for a single
stage, increasing the chemical tracer costs appreciably.
loom Each of the aforementioned techniques: fiber, PLT, and liquid chemical
tracer tools
also have temperature limitations (i.e., for use in < 500 F) that make their
use problematic at
2
Date Recue/Date Received 2023-03-03
best in unconventional or igneous geothermal reservoirs, where temperatures
may be as high
as 1,000 F. Moreover, these techniques are routinely coupled with the frac
operation, and
usually used for stages.
[0012] The industry needs a simplistic, low-cost diagnostic method that can be
used for
assessing reservoir quality, completion design, and other wellbore performance
parameters,
especially for target areas of the formation (such as the wellbore bottom or
toe) that need not
be related to a particular 'stage'.
[0013] The need for an ultrahigh resolution nanoparticle tracer that is
versatile, affordable,
highly accurate, non-radioactive, non-intrusive and quick to test is
increasing as never before
for all applications. Thus, there is an urgent need to have accurate,
affordable, timely data on
wellbore performance or other information. What is needed is a new and
improved way of
forming and using a fast, cost-favorable, effective, and reliable way of
evaluating a wellbore
that can be decoupled from a fracturing operation.
SUMMARY
[0014] Embodiments of the disclosure pertain to a method of using a tracer
additive in a
wellbore that may include one or more steps described herein. The method may
include using
a deployment device, the deployment device configured with a hollowed region.
There may
be a tracer additive into the hollowed region.
[0015] The method may include sending the deployment device into the wellbore
in manner
whereby the deployment device arrives at a target depth of a formation, which
may be in
communication with the wellbore. In aspects, the tracer additive in the
hollowed region may
be initially isolated from contacting the target formation.
[0016] The method may include sufficiently dissolving (or letting dissolve)
the deployment
device so that the tracer additive may be able to come into contact with the
target formation
and/or respective formation fluid. Upon contact with the target formation
fluid for an amount
of time, the method may include returning a remnant fluid that includes at
least a portion of
the tracer additive to a surface.
[0017] The target formation and respective fluid may be part of a geothermal
well, vertical
well, horizontal drilled well, or combinations thereof. In aspects, the
remnant fluid may be
used in an energy generation process. For example, a fluid may be injected
into the
geothermal well, energy (such as heat) added thereto, and then the fluid is
produced to the
surface, where the added energy may be converted in the energy generation
process.
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Date Recue/Date Received 2023-03-03
[0018] An amount of elapsed time to accomplish the step of sufficiently
dissolving the
deployment device may be in a range of at least 36 hours to no more than 240
hours. Other
times of dissolving may be possible. In this respect, the sufficiently
dissolving may be
passive in that no other human interaction is necessary to accomplish the
step.
[0019] In aspects, the tracer additive may have a first tracer composition.
The tracer additive
may be in a solid powder form having an average particle diameter of at least
0.01 gm to no
more than 10 gm. The tracer additive may have an average bulk specific
gravity, such as in a
range of at least 0.6 g/cm3 to no more than 1.6 g/cm3.
[0020] There may be instances where the wellbore (or surrounding formation)
has certain
geological parameters, for example, the wellbore may be associated with a
formation
temperature of at least 200 F to no more than 1,000 F. The wellbore may be a
vertical
wellbore, whereby the sending the deployment device into the wellbore step
does not use
pump down. The wellbore may include a horizontal portion. As such, the sending
the
deployment device into the wellbore step may utilize pump down.
[0021] The method may include other steps, such as any of: taking a sample of
the remnant
fluid; testing the sample in order to analyze the remnant fluid in order to
provide a set of fluid
data; and/or integrating the set of fluid data with other wellbore data in
order to determine a
parameter associated with performance of the wellbore.
[0022] In some aspects, the deployment device may have a desired shape, such
as being a
spherical member configured to be separated into at least two sections. The
deployment
device may have an effective outer diameter in a size range of at least 2
inches to no more
than 5 inches. Other shapes or sizes may be possible. For example, an OD of
2.5 inches, 3.5
inches, 4.5 inches, and so forth.
[0023] The method may include sending a second deployment device carrying a
second
tracer additive into the wellbore. Upon sufficient dissolving of the second
deployment device,
the second tracer additive may come into contact with one or more of the
target formation
fluid, another target formation fluid proximate to the wellbore, or
combinations thereof.
[0024] The second tracer additive may have a different composition from the
tracer additive.
The second tracer additive may be in powder form. The second tracer additive
may have an
average particle diameter, such as of at least 0.01 gm to no more than 10 gm.
The second
tracer additive may have an average bulk specific gravity, such as of at least
0.6 g/cm3 to no
more than 1.6 g/cm3.
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Date Recue/Date Received 2023-03-03
[0025] In aspects, the testing the sample step may include using a
fluorescence response-
based analysis. For example, the fluorescence response-based analysis may
include use of
EDXRF.
[0026] Yet other embodiments of the disclosure pertain to a method of using a
tracer additive
in a wellbore that may include one or more steps of: using a deployment
device, the
deployment device configured with a hollowed region; disposing a tracer
additive into the
hollowed region; sending the deployment device into the wellbore in manner
whereby the
deployment device arrives at a target formation in communication with the
wellbore,
whereby the tracer additive in the hollowed region is initially isolated from
contacting the
target formation; sufficiently dissolving the deployment device so that the
tracer additive
comes into contact with the target formation. The tracer additive may be in a
solid powder
and has a first tracer composition.
[0027] These and other embodiments, features and advantages will be apparent
in the
following detailed description and drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0028] A full understanding of embodiments disclosed herein is obtained from
the detailed
description of the disclosure presented herein below, and the accompanying
drawings, which
are given by way of illustration only and are not intended to be limitative of
the present
embodiments, and wherein:
[0029] Figure lA shows a side view of a system for using a deployment device
for the
transfer of a tracer additive into a wellbore according to embodiments of the
disclosure;
[0030] Figure IB shows a side view of the system of Figure lA with an at least
partially
dissolved deployment device that releases the tracer additive into the
wellbore according to
embodiments of the disclosure;
[0031] Figure IC shows a side view of a system for using a second deployment
device for
the transfer of a second tracer additive into a wellbore according to
embodiments of the
disclosure;
[0032] Figure 2 is a side view of a system where a remnant fluid with a tracer
additive is
produced from a wellbore according to embodiments of the disclosure;
[0033] Figure 3 is a simplified block diagram of an analytical unit used to
test a sample
having a tracer additive according to embodiments of the disclosure;
Date Recue/Date Received 2023-03-03
[0034] Figure 4A shows a side view of a system for using a deployment device
for the
transfer of a tracer additive into a vertical wellbore according to
embodiments of the
disclosure;
[0035] Figure 4B shows a side view of the system of Figure 4A with an at least
partially
dissolved deployment device that releases the tracer additive into the
wellbore according to
embodiments of the disclosure;
[0036] Figure 5A shows a side view of a dissolvable deployment device
according to
embodiments of the disclosure;
[0037] Figure 5B shows a translucent view of the dissolvable deployment device
of Figure
5A with a tracer additive disposed therein according to embodiments of the
disclosure;
[0038] Figure 5C shows a side view of the dissolvable deployment device of
Figure 5A
separated into sections and having a tracer additive disposed therein
according to
embodiments of the disclosure; and
[0039] Figure 5D shows a side view of a variant dissolvable deployment device
according to
embodiments of the disclosure.
DETAILED DESCRIPTION
[0040] Regardless of whether presently claimed herein or in another
application related to or
from this application, herein disclosed are novel apparatuses, units, systems,
and methods that
pertain to use of solid inert tracer additives, details of which are described
herein.
Embodiments of the disclosure may refer to "in-wellbore tracer deployment" ¨
where the
tracer is already in the wellbore (in a deployment device) before deployment
of the tracer into
the wellbore occurs.
[0041] Embodiments of the present disclosure are described in detail with
reference to the
accompanying Figures. In the following discussion and in the claims, the terms
"including"
and "comprising" are used in an open-ended fashion, such as to mean, for
example,
"including, but not limited to...". While the disclosure may be described with
reference to
relevant apparatuses, systems, and methods, it should be understood that the
disclosure is not
limited to the specific embodiments shown or described. Rather, one skilled in
the art will
appreciate that a variety of configurations may be implemented in accordance
with
embodiments herein.
[0042] Although not necessary, like elements in the various figures may be
denoted by like
reference numerals for consistency and ease of understanding. Numerous
specific details are
set forth in order to provide a more thorough understanding of the disclosure;
however, it will
6
Date Recue/Date Received 2023-03-03
be apparent to one of ordinary skill in the art that the embodiments disclosed
herein may be
practiced without these specific details. In other instances, well-known
features have not been
described in detail to avoid unnecessarily complicating the description.
Directional terms,
such as "above," "below," "upper," "lower," "front," "back," etc., are used
for convenience
and to refer to general direction and/or orientation, and are only intended
for illustrative
purposes only, and not to limit the disclosure.
[0043] Connection(s), couplings, or other forms of contact between parts,
components, and
so forth may include conventional items, such as lubricant, additional sealing
materials, such
as a gasket between flanges, PTFE between threads, and the like. The make and
manufacture
of any particular component, subcomponent, etc., may be as would be apparent
to one of skill
in the art, such as molding, forming, press extrusion, machining, or additive
manufacturing.
Embodiments of the disclosure provide for one or more components to be new,
used, and/or
retrofitted to existing machines and systems.
[0044] Various equipment may be in fluid communication directly or indirectly
with other
equipment. Fluid communication may occur via one or more transfer lines and
respective
connectors, couplings, valving, piping, and so forth. Fluid movers, such as
pumps, may be
utilized as would be apparent to one of skill in the art.
[0045] Numerical ranges in this disclosure may be approximate, and thus may
include values
outside of the range unless otherwise indicated. Numerical ranges include all
values from and
including the expressed lower and the upper values, in increments of smaller
units. As an
example, if a compositional, physical or other property, such as, for example,
molecular
weight, viscosity, melt index, etc., is from 100 to 1,000. it is intended that
all individual
values, such as 100, 101, 102, etc., and sub ranges, such as 100 to 144, 155
to 170, 197 to
200, etc., are expressly enumerated. It is intended that decimals or fractions
thereof be
included. For ranges containing values which are less than one or containing
fractional
numbers greater than one (e.g., 1.1, 1.5, etc.), smaller units may be
considered to be 0.0001,
0.001, 0.01, 0.1, etc. as appropriate. These are only examples of what is
specifically intended,
and all possible combinations of numerical values between the lowest value and
the highest
value enumerated, are to be considered to be expressly stated in this
disclosure. Numerical
ranges are provided within this disclosure for, among other things, the
relative amount of
reactants, surfactants, catalysts, etc. by itself or in a mixture or mass, and
various temperature
and other process parameters.
7
Date Recue/Date Received 2023-03-03
Terms
[0046] The term "connected" as used herein may refer to a connection between a
respective
component (or subcomponent) and another component (or another subcomponent),
which can
be fixed, movable, direct, indirect, and analogous to engaged, coupled,
disposed, etc., and can
be by screw, nut/bolt, weld, and so forth. Any use of any form of the terms
"connect",
"engage", "couple", "attach", "mount", etc. or any other term describing an
interaction
between elements is not meant to limit the interaction to direct interaction
between the
elements and may also include indirect interaction between the elements
described.
[0047] The term "fluid" as used herein may refer to a liquid, gas, slurry,
single phase, multi-
phase, pure, impure, etc. and is not limited to any particular type of fluid
such as
hydrocarbons.
[0048] The term "utility fluid" as used herein may refer to a fluid used in
connection with
any fluid disposed into a wellbore (akin to an injection fluid). The utility
fluid may be
pressurized, and may be used to carry an additive into the wellbore. 'Utility
fluid' may also
be referred to and interchangeable with 'service fluid' or comparable.
[0049] The term "fluid connection", "fluid communication," "fluidly
communicable," and
the like, as used herein may refer to two or more components, systems, etc.
being coupled
whereby fluid from one may flow or otherwise be transferrable to the other.
The coupling
may be direct, indirect, selective, alternative, and so forth. For example,
valves, flow meters,
pumps, mixing tanks, holding tanks, tubulars, separation systems, and the like
may be
disposed between two or more components that are in fluid communication.
[0050] The term "pipe", "conduit", "line", "tubular", or the like as used
herein may refer to
any fluid transmission means, and may be tubular in nature.
[0051] The term "tubestring" or the like (such as `workstring') as used herein
may refer to a
tubular (or other shape) that may be run into a wellbore. The tubestring may
be casing, a
liner, production tubing, combinations, and so forth. The tubestring may be
multiple pipes
(and the like) coupled together. The tubestring may be used for transfer of
fluids, or used with
some other kind of action, such as drilling, running a tool, or any other kind
of downhole
action, and combinations thereof.
[0052] The term "composition" or "composition of matter" as used herein may
refer to one or
more ingredients, components, constituents, etc. that make up a material (or
material of
construction). Composition may refer to a flow stream of one or more chemical
components.
[0053] The term "chemical" as used herein may analogously mean or be
interchangeable to
material, chemical material, ingredient, component, chemical component,
element, substance,
8
Date Recue/Date Received 2023-03-03
compound, chemical compound, molecule(s), constituent, and so forth and vice
versa. Any
'chemical' discussed in the present disclosure need not refer to a 100% pure
chemical. For
example, although 'water' may be thought of as H20, one of skill would
appreciate various
ions, salts, minerals, impurities, and other substances (including at the ppb
level) may be present
in 'water'. A chemical may include all isomeric forms and vice versa (for
example, "hexane",
includes all isomers of hexane individually or collectively).
[0054] The term "reactive material" as used herein may refer a material with a
composition of
matter having properties and/or characteristics that result in the material
responding to a change
over time and/or under certain conditions. The term reactive material may
encompass
degradable, dissolvable, disassociatable, dissociable, and so on.
[0055] The term "dissolvable material" may be analogous to degradable
material. The term as
used herein may refer to a composition of matter having properties and/or
characteristics that,
while subject to change over time and/or under certain conditions, lead to a
change in the
integrity of the material, including to the point of degrading, or partial or
complete dissolution.
As one example, the material may initially be hard, rigid, and strong at
ambient or surface
conditions, but over time (such as within about 12-60 hours) and under certain
conditions (such
as wellbore conditions), the material softens. As another example, the
material may initially be
hard, rigid, and strong at ambient or surface conditions, but over time (such
as within about 12-
240 hours) and under certain conditions (such as wellbore conditions), the
material dissolves at
least partially, and may dissolve completely. The material may dissolve via
one or more
mechanisms, such as oxidation, reduction, deterioration, go into solution, or
otherwise lose
sufficient mass and structural integrity.
[0056] The term "water" as used herein may refer to a pure, substantially
pure, and impure
water-based stream, and may include wastewater, process water, fresh water,
seawater, produced
water, slop water, treated variations thereof, mixes thereof, etc., and may
further include
impurities, dissolved solids, ions, salts, minerals, and so forth. Water for a
frac fluid can also be
referred to as 'frac water'.
[0057] The term "impurity" as used herein may refer to an undesired component,
contaminant, etc. of a composition. For example, a mineral or an organic
compound may be
an impurity of a water stream.
[0058] The term "frac fluid" as used herein may refer to a fluid injected into
a well as part of a
frac operation. Frac fluid is often characterized as being largely water, but
with other
constituents such as proppant, friction reducers, and other additives or
compounds.
9
Date Recue/Date Received 2023-03-03
[0059] The term "produced fluid", "production fluid", and the like as used
herein may refer to
water, gas, mixtures, and the like recovered from a subten-anean formation or
other area near the
wellbore. Produced fluid may include hydrocarbons or aqueous, such as flowback
water, brine,
salt water, or formation water. Produced water may include water having
dissolved and/or
free organic materials. Produced fluid may be akin to `wellbore fluid', in
that the fluid may
be returned from the wellbore. Produced fluid may include utility fluids and
formation fluids.
[0060] The term "frac operation" as used herein may refer to fractionation of
a downhole
well that has already been drilled. 'Frac operation' can also be referred to
and
interchangeable with the terms fractionation, hydraulic fracturing, well
stimulation,
production enhancement, hydrofracturing, hydrofracking, fracking, fracing, and
frac. A frac
operation can be land or water based. Generally, the term `fracing' or 'frac'
is used herein,
but meant to be inclusive to other related terms of industry art.
[0061] The phrase "processing a fluid" as used herein may refer to some kind
of active step
or action, such as man-made or by machine, imparted on the fluid (or fluids).
For example, a
fluid may be received into a device (such as a mixer) and upon processing, may
leave as a
'processed fluid'. 'Processed' is not meant be limited, as this may include
reference to
transferred, treated, tested, measured, mixed, sensed, separated,
combinations, etc. in whatever
manner may be desired or applicable for embodiments herein. It is noted that
while various
steps or operations of any embodiment herein may be described in a sequential
manner, such
steps or operations may be operated in batch or continuous fashion.
[0062] The term "tracer" as used herein may refer to an identifiable
substance, such as a
liquid dye, liquid chemical or a particles powder, which may be followed
through the course
of a mechanical, chemical, or biological process. In the present disclosure, a
tracer may be
used in a well, and the resultant process impact on the tracer evaluated. In
this respect, the
tracer may help evaluate, determine, and otherwise model well production and
performance.
The tracer may be added (and thus may be referred to as a 'tracer additive' or
'additive') to a
utility (or service, injection, etc.) fluid disposed into the well.
[0063] The term "nanoparticle" as used herein may refer to a small particle
that ranges
between 1 to 1000 nanometers in size diameter, and is undetectable by the
human eye. A
tracer in powder form may be nanoparticles. A tracer additive of the present
disclosure may
be in powder form with an average bulk diameter in a range of about 0.01 gm to
about 10
gm.
[0064] The term "EDXRF" (Non-destructive Energy Dispersive X-Ray Fluorescence)
as
used herein may refer to a type of spectroscopy process (and may thus include
use of a
Date Recue/Date Received 2023-03-03
spectrometer) where a sample of material (such as a portion of produced fluid)
is 'excited' in
order to collect emitted fluorescence radiation, which may then be evaluated
for different
energies of the characteristic radiation from each of the different
constituents (or elements) in
the sample. The EDXRF process may be referred to as a fluorescence response-
based
analytical process.
[0065] EDXRF may be considered a non-destructive analytical technique used to
determine
the elemental composition of materials. EDXRF analyzers determine the
elemental
composition of a sample by measuring the fluorescent (or secondary detectable
energy) X-ray
emitted from a sample when it is excited by a primary X-ray source. EDXRF is
designed to
analyze groups of elements simultaneously to determine those elements presence
in the
sample and their relative concentrations - in other words, the elemental
composition of the
sample. Each of the elements present in a sample produces a unique set of
characteristic X-
rays that is a "fingerprint" for that specific element. X-rays have a very
short wavelength,
which corresponds to very high energy. All atoms have several electron
orbitals (K shell, L
shell, M shell, for example). When X-ray energy causes electrons to transfer
in and out of
these shell levels, X-ray fluorescence peaks with varying intensities are
created and will be
present in the spectrum. The peak energy identifies the element, and the peak
height or
intensity is indicative of its concentration.
[0066] The term "XRD" may refer to X-ray diffraction, which is a technique for
analyzing
the atomic or molecular structure of materials. It is non-destructive, and
works most
effectively with materials that are wholly, or part, crystalline. The
technique is often known
as x-ray powder diffraction because the material being analyzed typically is a
finely ground
down to a uniform state. Diffraction is when light bends slightly as it passes
around the edge
of an object or encounters an obstacle or aperture. The degree to which it
occurs depends on
the relative size of a wavelength compared to the dimensions of the obstacle
or aperture it
encounters.
[0067] All diffraction methods start with the emission of x-rays from a
cathode tube or
rotating target, which is then focused at a sample. By collecting the
diffracted x-rays, the
sample's structure can be analyzed. This is possible because each mineral has
a unique set of
d-spacings. D-spacings are the distances between planes of atoms, which cause
diffraction
peaks.
[0068] Referring now to Figures 1A, 1B, 1C, 2, and 3, together, a side view of
a system for
using a deployment device for the transfer of a tracer additive into a
wellbore, a side view of
the system with an at least partially dissolved deployment device that
releases the tracer
11
Date Recue/Date Received 2023-03-03
additive into the wellbore, a side view of a system for using a second
deployment device for
the transfer of a second tracer additive into a wellbore, a side view of a
system where a
remnant fluid with a tracer additive is produced from a wellbore, and a
simplified block
diagram of an analytical unit used to test a sample having a tracer additive
according to
embodiments of the disclosure, respectively, according to embodiments
disclosed herein, are
shown.
[0069] System 100 may include one or more components (or subcomponents)
coupled with
new, existing, or retrofitted equipment. System 100 may include one or more
units that are
skid mounted or may be a collection of skid units, and the system 100 may be
suitable for
onshore and offshore environments.
[0070] The system 100 may have various valves, flanges, pipes, pumps,
utilities, monitors,
sensors, controllers, flow meters, safety devices, etc., for accommodating
sufficient universal
coupling between system components and any applicable feedline/feed source of
a material to
be processed, any resultant product material to be discharged or transferred
therefrom, and
anything in between.
[0071] Figures 1A-1C are meant to show in a simplistic manner embodiments
herein, and
may not be to scale. The system 100 may include a subterranean or earthen
formation 101
having a wellbore 103 drilled or otherwise formed therein. The formation 101
may contain
hydrocarbonaceous fluids, such as oil, natural gas, and/or other materials,
generally
designated as F. The formation 101 may include porous and permeable rock
containing liquid
and/or gaseous hydrocarbons. The formation may include a conventional
reservoir, an
unconventional reservoir, a tight gas reservoir, and/or other types of
reservoirs. Moreover, the
illustration of a mover (pump) 107 is not meant to infer other equipment is
not present, of
which one of ordinary skill in the art is well versed. The type of mover 107
used is not meant
to be limited, and other types of movers 107 may be used (even if not shown).
[0072] The system 100 may include one or more additional wellbores, production
wells, etc.
The example wellbore 103 shown in Figure 1 illustrates the wellbore 103 may
have at least a
partial horizontal trajectory. However, any wellbore of the system 100 may
include any
combination of horizontal, vertical, slant, curved, directional-drilled,
and/or other well
geometries.
[0073] The wellbore 103 may be open, closed, cased, uncased, etc. Although not
shown in
detail here, the wellbore 103 may have a tubestring 119 disposed therein, such
as for
deploying tools or fluids into the wellbore 103. In other aspects, the
tubestring 119 may be a
12
Date Recue/Date Received 2023-03-03
production tubing, whereby formation and wellbore fluids may be readily
transported to a
surface or surface facility 102.
[0074] The formation 101 may include a target formation 101a, which may be
believed to be
a hydrocarbon-rich area of the formation 101. The target formation 101a may be
a stage or
zone, which may be part of or associated with a fracing operation. Just the
same, the target
formation 101a may just be part of the formation 101 without the need for
enhanced oil
recovery (EOR) or other type of treatment. At the end of the wellbore 103 may
be the
wellbore end or toe 103a.
[0075] It may be the case that the target formation 101a has perforations,
which may result
from a fracing operation or may naturally exist. In the event of tight
formation characteristics,
such as in the case of an unconventional reservoir, the target formation 101a
may have an
average permeability of about 0.1 nanodarcy to about 1000 nanodarcy. By way of
comparison, the target formation 101a may be disposed in a conventional
reservoir, and thus
may have an average permeability in a range of about 0.1 millidarcy to about 1
darcy (or
more).
[0076] The formation 101 might have other geologic characteristics, including
hot formation
temperatures. For example, the target formation 101a may have an average
formation
temperature T of about 450 F. In embodiments, the average formation
temperature T may be
in a range of about 200 F to about 1,000 F. The formation temperature T may
have a
relationship to the depth, geological environment, and tightness of the
formation 101.
[0077] Diagnostic information about the performance of the wellbore 103, or
particular area
such as by the target formation 101a, may be determined by utilizing a first
tracer additive
105a. The first tracer additive 105a (or other tracer additives described
herein) may be of a
suitable material for use with any type of formation 101. Just the same, the
first tracer
additive 105a may have a (predetermined) first composition A, which results in
characteristics (or traits) suitable for use in the event the formation 101
has conditions
normally undesirable for the use of tracers, namely, liquid tracers.
[0078] As a first characteristic, the first tracer 105a may be a solid tracer
in the form of a
powder. The use of powder form makes the first tracer 105a attractive for use
in high
temperature conditions. The first tracer 105a may comprise powder
nanoparticles. In
embodiments, the particles of the first tracer 105a may have an average
particle diameter of
about 0.1 gm to about 10 gm. The first tracer 105a may have a first tracer
specific gravity. In
embodiments, the first tracer 105a may have an average bulk specific gravity
of about 0.6
g/cm3 to about 1.6 g/cm3. The first tracer 105a may be disposed into a first
deployment
13
Date Recue/Date Received 2023-03-03
device 124. Although not meant to be limited, the first deployment device 124
may be
spherical in nature. The deployment device 124 may have an outer diameter. The
outer
diameter may be in the range of about 2 inches to about 5 inches. For example,
the outer
diameter may be 2.5 inches, 3.5 inches, 4.5 inches, and so forth.
[0079] Referring briefly to Figures 5A, 5B, and 5C, a side view of a
dissolvable deployment
device, a translucent view of the dissolvable deployment device with a tracer
additive
disposed therein, and a side view of the dissolvable deployment device of
separated into
sections and having a tracer additive disposed therein, respectively,
according to
embodiments disclosed herein, are shown.
[0080] Figures 5A-5C together, show the deployment device 524 may be
spherical, with a
(inner) hollowed region 527. The tracer additive 505 may be a solid
particulate material like
that of tracer additives described herein. The deployment device 524 may be
separable into
one or more sections 525a, 525b, etc., whereby the additive 505 may be
disposed therein.
[0081] The additive 505 may be packed tightly so that as the sections 525a,
525b are coupled
back together, the additive adheres or otherwise stays within the hollowed
region, thus
avoiding any spillage or material loss of significance. While the additive 505
could be
liquidous, the use of solid material means there will not be any liquid
seepage.
[0082] In order to easily secure the sections 525a, 525b together, there may
be respective
mating features, such as male and female threads. However, forms of a
deployment device
are possible. For example, Figure 5D shows a side view of an alternative
embodiment of the
deployment device 524, where there may be a removable cap or plug 531 that may
securingly
dispose or otherwise fit within an opening 531.
[0083] The deployment device 524 may be made of a reactive material configured
to
dissolve, at least partially, based on wellbore fluid composition. Reactive
materials may
include materials suitable for and are known to dissolve, degrade, etc. in
downhole
environments [including extreme pressure, temperature, fluid properties, etc.]
after a brief or
limited period of time (predetermined or otherwise) as may be desired). In an
embodiment, a
component made of a reactive material may begin to react within about 24 to
about 60 hours
after exposure to a reaction-inducing stimulant.
[0084] In embodiments, any deployment device of the present disclosure may be
made of a
metallic material, such as an aluminum-based or magnesium-based material. The
metallic
material may be reactive, such as dissolvable, which is to say under certain
conditions the
respective component(s) may begin to dissolve, and thus alleviating the need
for drill thru.
These conditions may be anticipated and thus predetermined. In embodiments,
the
14
Date Recue/Date Received 2023-03-03
components may be made of dissolvable aluminum-, magnesium-, or aluminum-
magnesium-
based (or alloy, complex, etc.) material.
[0085] Returning again to Figures 1A, 1B, 1C, 2, and 3, together, the
deployment device 124
may be sent or disposed into the wellbore 103 via carrier fluid 104. For
example, the pump
107 may be used to pump the carrier fluid 104 from the source 111 toward a
wellhead
(injection point) 117, and through the tubestring 119.
[0086] Sufficient pressure and flowrate may be selected and used in order to
adequately
provide the deployment device 124 to the target formation 101a. After an
amount of time
(which may be predetermined or otherwise known), the deployment device 124 may
dissolve
sufficiently enough that the first tracer 105a may begin to disperse in or at
the target
formation 101a. The amount of time for dispersion to begin may be about 24
hours to about
60 hours. In embodiments, the amount of time may be about 2 days.
[0087] The first tracer 105a may be completely miscible with the wellbore
fluids. The first
tracer 105a may be inert in the respect that there is no effect by the first
tracer 105a on the
carrier fluid 104 and/or the formation 101 (or target formation 101a) and/or
vice versa.
[0088] The tracer 105a (or at least a portion thereof) may have an average
residence time in
the target formation 101a. The first tracer additive 105a may be selected for
its particular
uniqueness, and thus preferably has a different tracer characteristic
(fingerprint) from other
tracer additives used so that fluid returned to the surface may be identified.
The tracer
characteristic may be the chemical identity of the tracer additive used, such
as composition or
specific gravity. The tracer characteristic may be distinguishable from the
tracer
characteristic(s) of any other tracer additives used.
[0089] Figures 2 and 3 illustrate whereby the first tracer 105a may be brought
back to the
surface 102 for testing. For example, after the predetermined time period, a
remnant fluid
104b may be produced. The remnant fluid 104b may include, at least partially,
(some of) the
first tracer 105a, the carrier fluid, and formation fluids F. A sample of the
remnant fluid 104b
may be produced on a desired frequency, such as daily. The sampling can occur
during the
desired frequency over a predetermined timeframe, which may be days or months
(e.g., 6
months).
[0090] Once the remnant fluid 104b is produced from the wellbore 103, a sample
113 may be
taken or extracted from sample point 112. The rest of the remnant fluid 104b
may be
transferred to a desired destination 114, which may be a tank, a pond, another
well, or other
suitable storage.
Date Recue/Date Received 2023-03-03
loom The sample 113 may now be tested via test unit 120. The test unit 120 may
include
analysis equipment 115, which may be in operable communication with computing
system
118. The computing system 118 may be configured for use in using analytical
data associated
with use of the test equipment 115. The test equipment 115 may provide a
fluorescence
response-based process, such as EDXRF and XRD.
[0092] The computing system 118 may be useful to further analyze data and
other
information in order to provide an indication related to performance of the
wellbore 103. This
may pertain to, for example, the time the tracer additive was detected, the
location where the
tracer additive was use, the type and composition of the tracer additive
detected, the amount
or concentration of tracer additive detected, and/or other measurements
provided by the
equipment 115 and the system 118.
[0093] The computing system 118 may have Artificial intelligence (A.I.) based
flow
diagnostics. The computing system 118 may access input data 121, which may be
related to
other aspects of the formation 101, such as geological information, fractures,
and the like.
The computing system 118 may include programs, scripts, and/or other types of
computer
instructions that generate output data 122, which may be based on the input
data 121. The
output data 122 may include descriptions of fluid flow patterns in the
formation 101, which
may identify paths of fluid flow in the wellbore 101, wellbore breaches or
cross-
communication (such as to a proximate offset well), fracture locations, fluid
flow rates,
and/or other information.
[0094] Figure 1C shows that a second deployment device 124a may be disposed
into the
wellbore 103, which may be directed to the same or different target formation.
The second
deployment device 124a may be disposed into the wellbore 103 in a similar
manner as that of
the deployment device 124. The second deployment device 124a may have a second
tracer
additive disposed therein (not viewable here).
[0095] The second tracer additive may be like that of the first tracer
additive 105b, and thus
have similar composition and characteristics; however, the second tracer
additive may have a
second composition B different from that of the first composition A. The use
of a different
composition B provides a unique identifier and fingerprint as compared to that
of the
composition A.
[0096] The second composition B may be different from the first composition A,
yet the
second tracer may have characteristics similar to that of the first tracer
105a. For example, the
second tracer may be an inert solid (in powder form) having a respective
average particle
16
Date Recue/Date Received 2023-03-03
diameter of about 0.01 gm to about 10 gm. The second tracer may have a
respective average
bulk specific gravity of about 0.6 g/cm3 to about 1.6 g/cm3.
[0097] As before with the first tracer 105a, after the predetermined time
period, a remnant
fluid 104b may be produced. The remnant fluid 104b may include, at least
partially, (some
of) the first tracer 105a, the second tracer, the carrier fluid, and formation
fluids F.
[0098] Once the remnant fluid 104b is produced from the wellbore 103, a sample
113 may be
taken or extracted from sample point 112.
[0099] The system 100 may be modified or adjusted based on the detection of
tracers
released from the formation 101. For example, well system tools, and/or other
subsystems
may be installed, adjusted, activated, terminated, or otherwise modified based
on the
information provided by the tracers. Additional fractures can be formed in the
formation 101,
and/or other modifications can be made based on information provided by the
tracers. In
some embodiments, modifications of the system 100 may be selected and/or
parameterized to
improve production from the formation 101. For example, the modifications may
improve the
sweep efficiency. Modifications of well system 100 may be selected and/or
parameterized by
the computing system based on data analysis performed by the computing system.
Other or
additional tracer additives and/or deployment devices may be used as desired.
pion] Referring now to Figures 4A and 4B together, a side view of a system for
using a
deployment device for the transfer of a tracer additive into a vertical
wellbore, and a side
view of the system with an at least partially dissolved deployment device that
releases the
tracer additive into the wellbore, according to embodiments disclosed herein,
are shown.
pion Figures 4A and 4B show a system 100 that may be like that of other
systems herein,
and thus may have a formation 101 with a wellbore 103 disposed therein, which
may be
understood to one of ordinary skill in the art as having a vertical
orientation. A carrier fluid
104a may be used to dispose a first deployment device 124 into the wellbore
103. In aspects,
the deployment device 124 may be dropped, and the effect of gravity brings the
deployment
device to a target formation 101a, which may be the bottom of the wellbore
103. The
deployment device 124 may have a first tracer additive 105a disposed therein
(such as in a
hollowed region (not viewable here) of the device 124). After an elapse of
time, the
deployment device 124 may dissolve, at least partially, in a sufficient manner
whereby the
first tracer additive 105a may disperse into the area proximate the target
formation 101a.
Then, a remnant fluid 104b (which may include at least some of the first
tracer additive 105a)
may be produced from the wellbore 103, which may also be tested via test unit
120 in
accordance with the disclosure.
17
Date Recue/Date Received 2023-03-03
[00102] Any of the Figures herein may pertain to a geothermal well instead of
a producing oil
and gas well. There may still be a formation 101 with a wellbore 103 disposed
therein.
Instead of a hydrocarbon formation, the formation 101 may be associated with a
geothermal
energy-creation process. In this respect, a utility fluid having a deployment
device 124 may
be disposed into the wellbore 103 (or dropped via gravity feed).
[00103] Like shown in Figure 2B or Figure 4B, the deployment device 124 may
dissolve, at
least partially, such that the tracer additive 105a may disperse therefrom and
come into
contact with the target formation fluid. The mixing thereof may result in a
remnant fluid
104b.
[00104] The geothermal properties of the formation 101 and the fluids F may
result in the
remnant fluid 104b having substantial thermal energy associated therewith. As
such, the
remnant fluid 104b may be used in an energy generation process, such as being
used to create
steam in order to turn a turbine. The remnant fluid 104b (e.g., a sample
thereof) may also be
tested via test unit 120 in accordance with the disclosure.
[00105]
Example
[00106] Embodiments herein provide for a method of using ultrahigh resolution
nanoparticle
tracer technology. Methods of the disclosure may provide for a tracer
portfolio that integrates
advanced computational methods using Artificial Intelligence (A.I.). Such use
may provide
accurate, actionable, near real-time performance-flow-profile data. This may
allow oil and
gas operators to: optimize completion strategies; achieve the best production
per foot; reduce
completion and fracturing cost; and/or reduce environmental footprint.
[00107] Tracer technology described herein may be based on proprietary inert
submicron
particles and other environmentally friendly and cost-effective additives that
are used to
manufacture the right composition of each tracer. This tracer technology may
utilize special
inert particles fingerprinting with certain atoms as special indicators that
enhance the
properties of each tracer. These may then detected at the sub-atomic structure
level using
robust capabilities of EDXRF-type spectroscopy measurements, and therefore
ensuring
superior accuracy for each tracer's detection and characterization from
different subsurface
environments.
[00108] Deployed tracers are then recovered with production flowback or
produced fluids
from treatment or/and adjacent wells. During the back flowing of the well,
reservoir oil/gas
samples are taken on a regular basis, such as for the first 10 to 40 days. The
number of days
18
Date Recue/Date Received 2023-03-03
may as desired, such as up to 180 days. A small amount of the sample is
analyzed using
appropriate methods to detect the presence and concentration of tracer
compound. Samples
from traced and/or offset wells may be collected on a predetermined basis
(such as daily)
from production flowback at the wellhead or other suitable sample point. The
sample may
then be tested via a fluorescence response-based process, such as EDXRF and
XRD. Such
analytical techniques may be used to determine the elemental composition and
crystallinity of
the samples.
[00109] EDXRF is designed to analyze groups of elements simultaneously to
determine those
elements presence in the sample and their relative concentrations - in other
words, the
elemental composition of the sample. Each of the elements present in a sample
produces a
unique set of characteristic X-rays that is a "fingerprint" for that specific
element. X-rays
have a very short wavelength, which corresponds to very high energy.
loom] Due to sub-atomic accuracy of both detection methods, it is possible to
precisely
determine the elemental composition, crystallographic structure, and the
various
combinations of hyperfine interactions in the samples, which enables very
accurate
identification of the tracer additives on the sub-atomic or quantum level.
[00111] Laboratory analysis that may include or incorporate advanced
computational methods
and proprietary diagnostics capabilities for each stage or target formation
provides accurate,
calibrated, actionable and cost-effective production diagnostics results. This
enables
operators to reduce operational cost and increase the production in oil and
gas wells.
[00112] Embodiments herein may produce and achieve an extensive and long-term
dataset
from tracer additives during production flow profile analysis at each target
formation. This
information may be used together with advanced computational methods using
Artificial
Intelligence (A.I.) coupled with artificial neural network may provide precise
completion
optimization workflows for oil and gas wells.
[00113] Embodiments herein pertain to a method(s) of using a tracer additive
in a wellbore. The
method may include one or more steps, which may vary in sequence and scope.
The method
may include obtaining a deployment device, and disposing a tracer additive
therein. The
deployment device may then be disposed or otherwise transferred into the
wellbore, such as
via a carrier fluid.
[00114] The carrier fluid may flow at a sufficient flow rate and pressure so
that the
deployment device comes into contact with a target formation (in communication
with the
wellbore). A such, the flow rate and pressure may be adequate to transfer the
deployment
device through a tubestring, into the wellbore, and then into contact with the
target formation.
19
Date Recue/Date Received 2023-03-03
[00115] Upon contacting or proximately locating the deployment device with the
target
formation for an amount of time (which may be predetermined or as otherwise
desired), the
deployment device may begin to, at least partially, dissolve. As such, the
deployment device
may be made a reactive material suitable for reacting with wellbore fluids.
[00116] Upon at least partial dissolving, the first tracer additive may
disperse into the
wellbore. The method may include at some point later returning (producing,
etc.) a remnant
fluid to a surface. One of skill would appreciate the surface refers to above-
ground
production equipment, facilities, and so forth, being common in production
operations.
[00117] The method may include taking a sample of the remnant fluid, and then
testing the
sample in order to analyze the remnant fluid in order to provide a set of
fluid data. The
method may include integrating (or otherwise analyzing, comparing, etc.) the
set of fluid data
with other wellbore data in order to determine a parameter associated with
performance of the
wellbore.
[00118] The method may utilize the tracer additive having a first tracer
composition. The
tracer additive may be in powder (i.e., solid) form having an average particle
diameter of at
least 0.01 gm to no more than 10 gm. The tracer additive may have an average
bulk specific
gravity. For example, the average bulk specific gravity may be in a range of
at least 0.6 g/cm3
to no more than 1.6 g/cm3.
[00119] The method may include additional steps, such as disposing a second
deployment
device that may have a second tracer additive disposed therein into the
wellbore. The
disposing step may be done in such a manner that the second deployment device
may come
into contact with one or more of the target formation, another target
formation proximate to
the wellbore, or combinations thereof.
[00120] The second tracer additive may have a different composition from the
first chemical
tracer, but otherwise may also be in powder form, may have an average particle
diameter of
at least 0.1 gm to no more than 10 gm, and may have average bulk specific
gravity of at least
0.6 g/cm3 to no more than 1.6 g/cm3.
[00121] The testing the sample step may include using a fluorescence response-
based analysis.
In aspects, the fluorescence response-based analysis may include use of EDXRF.
In aspects,
the fluorescence response-based analysis many include use of XDR.
[00122] Embodiments herein may be used in manner that is decoupled from the
use of a
fracturing operation. As such, any deployment device of the disclosure may be
used in a
wellbore (and respective tubestring) that does not have a fluid isolation
device (e.g., frac
plug, bridge plug, etc.) disposed therein.
Date Recue/Date Received 2023-03-03
Advanta2es
[00123] Embodiments herein may provide for a new and improved method and
system related to
the use of tracers in various settings associated with an earthen formation,
such as an oil and gas
well.
[00124] The tracer may be cost-effective and inert, stable at (excessively)
high temperatures,
compatible with formation fluids, non-intrusive to completion design, easy to
use, and quickly
tested. Other advantages may include use of tracers that are of a cost-
effective material, inert
and lightweight, easily deployed, non-hazardous and non-radioactive, a single
tracer for water
and oil phases, and precise sub-atomic accuracy.
[00125] The tracer may be deployed via a transportation or deployment device,
which may be
made of a reactive material that dissolves over a period of time. Thus, the
tracer is not
directly mixed into a pump-down stream; instead, the tracer deploys once the
transportation
device sufficiently dissolves in order to release the tracer.
[00126] While embodiments of the disclosure have been shown and described,
modifications
thereof may be made by one skilled in the art without departing from the
spirit and teachings
of the disclosure. Accordingly, the scope of protection is not limited by the
description set out
above but is only limited by the claims which follow, that scope including all
equivalents of
the subject matter of the claims. Each and every claim is incorporated into
the specification as
an embodiment of the present disclosure.
21
Date Recue/Date Received 2023-03-03
