U.S. patent application number 13/977538 was filed with the patent office on 2013-12-26 for method for tracking a treatment fluid in a subterranean formation.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is Ashok Belani, Kreso Kurt Butula, Oleg Yurievich Dinariev, Dimitri Vladilenovich Pissarenko, Sergey Sergeevich Safonov, Oleg Mikhailovich Zozulya. Invention is credited to Ashok Belani, Kreso Kurt Butula, Oleg Yurievich Dinariev, Dimitri Vladilenovich Pissarenko, Sergey Sergeevich Safonov, Oleg Mikhailovich Zozulya.
Application Number | 20130341012 13/977538 |
Document ID | / |
Family ID | 46383357 |
Filed Date | 2013-12-26 |
United States Patent
Application |
20130341012 |
Kind Code |
A1 |
Belani; Ashok ; et
al. |
December 26, 2013 |
METHOD FOR TRACKING A TREATMENT FLUID IN A SUBTERRANEAN
FORMATION
Abstract
A method of tracking a treatment fluid in a subterranean
formation penetrated by a wellbore provides for injecting the
treatment fluid with the plurality of tracer agents into the well
and the formation. Each tracer agent is an object of submicron
scale. The location and distribution of the treatment fluid is
determined by detecting changes in the physical properties of the
formation caused by the arrival of the treatment fluid comprising a
plurality of tracer agents.
Inventors: |
Belani; Ashok; (Paris,
FR) ; Pissarenko; Dimitri Vladilenovich;
(Chatenay-Malabry, FR) ; Butula; Kreso Kurt;
(Zagreb, HR) ; Safonov; Sergey Sergeevich;
(Moscow, RU) ; Dinariev; Oleg Yurievich; (Moscow,
RU) ; Zozulya; Oleg Mikhailovich; (Moscow,
RU) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Belani; Ashok
Pissarenko; Dimitri Vladilenovich
Butula; Kreso Kurt
Safonov; Sergey Sergeevich
Dinariev; Oleg Yurievich
Zozulya; Oleg Mikhailovich |
Paris
Chatenay-Malabry
Zagreb
Moscow
Moscow
Moscow |
|
FR
FR
HR
RU
RU
RU |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
46383357 |
Appl. No.: |
13/977538 |
Filed: |
December 30, 2010 |
PCT Filed: |
December 30, 2010 |
PCT NO: |
PCT/RU10/00803 |
371 Date: |
September 13, 2013 |
Current U.S.
Class: |
166/250.12 |
Current CPC
Class: |
E21B 47/11 20200501;
E21B 28/00 20130101; E21B 43/24 20130101; E21B 43/26 20130101; E21B
43/25 20130101; E21B 43/166 20130101; E21B 47/10 20130101 |
Class at
Publication: |
166/250.12 |
International
Class: |
E21B 47/10 20060101
E21B047/10 |
Claims
1. A method of tracking a treatment fluid in a subterranean
formation penetrated by a wellbore comprising the steps of:
providing a treatment fluid comprising a plurality of tracer
agents, wherein each tracer agent is an object of submicron scale,
injecting the treatment fluid with the plurality of tracer agents
into the well and the formation, and determining the location and
distribution of the treatment fluid by detecting changes in the
physical properties of the formation caused by the arrival of the
treatment fluid comprising a plurality of tracer agents.
2. The method of claim 1 wherein the treatment fluid is selected
from the group consisting of fracturing fluids, drilling fluids,
acidizing fluids, injection fluids, brines and completion fluids,
fluids for EOR/IOR including reservoir flooding fluids.
3. The method of claim 1 wherein the plurality of tracer agents are
low or insoluble gas bubbles having a diameter not more than 500
nm, the treatment fluid is water- or hydrocarbon-based solution and
the treatment fluid with the plurality of tracer agents is a highly
dispersed gas-liquid mixture.
4. The method of claim 3 wherein the gas is selected from the group
consisting of methane, higher molecular weight hydrocarbon gas,
nitrogen or other insoluble inorganic gas or mixtures of
thereof.
5. The method of claim 3 wherein the water-based solution
additionally comprises electrolytes of ferrous ions, manganese
ions, calcium ions, or any other mineral ion such that the
electrical conductivity in the solution is not less than 300
.mu.8.LAMBDA.;m.
6. The method of claim 1 wherein the plurality of tracer agents are
high viscous liquid droplets having a diameter not more than 1000
nm, the treatment fluid is water- or hydrocarbon-based solution and
the treatment fluid with the plurality of tracer agents is an
emulsion.
7. The method of claim 6 wherein the high viscous liquid is crude
oil or toluene.
8. The method of claim 1 wherein the plurality of tracer agents are
solid particles and the treatment fluid with the plurality of
tracer agents is a stabilized solution in aqueous fluids, solvent
based fluids such as alcohols or hydrocarbon based fluids.
9. The method of claim 8 wherein the solid particles are selected
from the group consisting of silica, synthesized copper, magnetite
(Fe304), ferri/ferrous chlorides, barium iron oxide (BaFe12019),
zinc oxide, aluminium oxide, magnesium oxide, zirconium oxide,
titanium oxide, cobalt (II) and nickel (II) oxide, barium sulfate
(BaS04), pyrolectric and piezoelectric crystals etc.
10. The method of claim 1 wherein the treatment fluid comprising a
plurality of tracer agents is provided by mixing the treatment
fluid with the plurality of tracer agents by means of a generator
placed in the wellbore.
11. The method of claim 1 wherein the treatment fluid comprising a
plurality of tracer agents is provided by mixing the treatment
fluid with the plurality of tracer agents by means of the surface
located equipment.
12. The method of claim 1 wherein the treatment fluid comprising a
plurality of tracer agents is injected continuously during the
treatment duration.
13. The method of claim 1 wherein the treatment fluid comprising a
plurality of tracer agents is injected periodically during the
treatment duration.
14. The method of claim 1 wherein the treatment fluid comprising a
plurality of tracer agents is injected at any stage of the
treatment.
15. The method of claim 1 wherein the injection of the treatment
fluid is accompanied by physical treatment performed before, during
or after the injection process.
16. The method of claim 15 wherein the physical treatment is
vibration, or heating, or acoustic treatments.
17. The method of claim 1 wherein the treatment fluid additionally
comprises one or more additives selected from a group comprising
gelling agents, foaming agents, friction reducers, surfactants.
18. The method of claim 1 wherein physical properties of the
formation are acoustic impedance and/or electric conductivity
and/or magnetic permittivity, nuclear magnetic resonance (NMR)
response, thermal propagation and hydrodynamic flow
capabilities
19. The method of claim 1 wherein detecting of physical properties
of the formation is made by seismic, acoustic, electrical,
electrokinetical, NMR, thermal, neutron or gamma-ray means.
20. The method of claim 19 wherein detecting of physical properties
of the formation is made by seismic, acoustic, electrical,
electrokinetical, NMR, thermal, neutron or gamma-ray means located
on the surface.
21. The method of claim 19 wherein detecting of physical properties
of the formation is made by seismic, acoustic, electrical,
electrokinetical, NMR, thermal, neutron or gamma-ray means located
in the wellbore.
22. The method of claim 1 wherein the treatment fluid with the
plurality of tracer agents is flowed back from the subterranean
formation and analyzed for changes in the tracer agents
concentration, size, type and distribution function between the
injected and produced treatment fluid.
23. The method of claim 22 wherein analyzing changes in the tracer
agents concentration, size and type distribution function between
the injected and produced treatment fluids is performed while
flowing in the formation by the acoustics, electric, thermal,
neutron or gamma-ray logging.
24. The method of claim 22 wherein analyzing changes in the tracer
agents concentration, size and type distribution function between
the injected and produced treatment fluids is performed by
comparing samples of the injection and produced fluids.
Description
FIELD OF THE INVENTION
[0001] This invention relates generally to the recovery of
hydrocarbons from a subterranean formation penetrated by a well
bore and more particularly to non-radioactive tracers and methods
of utilizing the non-radioactive tracers for tracking treatment and
reservoir fluids in the formation in order to evaluate and
understand the operations executed in the wellbore and/or in the
reservoir, near wellbore and wellbore processes and fluid
placements such as gravelling packing, hydraulic fracturing, sand
control and cementing and drilling fluids flow and placement.
BACKGROUND OF INVENTION
[0002] The use of various kinds of markers/tracers in the oil and
gas industry is well known. Radioactive and/or chemical tracers
which can be readily identified are used for monitoring of
treatment fluids injection into the reservoir as a means to monitor
hydraulic fracturing, acidizing, water control and other wellbore
and reservoir treatments.
[0003] Thus, U.S. Pat. No. 5,243,190 provides an example of
radioactive elements incorporated within ceramic particles and used
for tracing flow of proppant particles employed in the process of
hydraulic fracturing of wells. The use of radioactive or chemical
substances as tracers sometimes is not desirable and is even
prohibited by environmental regulations.
[0004] Other techniques using non-radioactive tracers have also
been proposed. U.S. Pat. No. 6,725,926 proposes the use of tracer
agents selected from the group consisting of water soluble
inorganic salts, water soluble organic salts, metals, metal salts
of organic acids, metal oxides, metal sulfates, metal phosphates,
metal carbonates, metal salts, phosphorescent pigments, fluorescent
pigments, photoluminescent pigments etc.
[0005] Inexpensive tracers and analysis, with a short reservoir
lifetime of a week or so, thiocyanate, bromide, iodide or nitrate
salts can be used (Hutchins, R. D. et al., Aqueous Tracers for
Oilfield Applications, SPE International Symposium on Oilfield
Chemistry, 20-22 Feb. 1991, Anaheim, Calif., 21049-MS).
[0006] Analysis can be done with ion or liquid chromatography,
which is lab based and expensive, but qualitative tests using "Spot
Plate Tests" are available to detect nitrate, thiocyanate and
iodide to roughly gauge the level by color intensity as simple and
even on-site usage solution. Alternatively Iodide and thiocyanate
salts have simple spectrometer tests that can be used instead
chromatography for quantitative analysis. These ions should not
interfere with the typical fluid crosslinking chemistry used in
hydraulic fracturing, as they are used at levels of 1000 ppm or so
and detectable to 1 ppm. The sodium, ammonium or potassium salts
are soluble and have been used in tracing of fluid movements in the
reservoir.
[0007] Chemical tracers with the explanation of their use and the
methodology of measurements in post frac and long term flowback
analysis are published in Mahmoud Asadi et al., Comparative Study
of Flowback Analysis Using Polymer Concentrations and Fracturing
Fluid Tracer Methods: A Field Study, International Oil & Gas
Conference and Exhibition in China, 5-7 Dec. 2006, Beijing, China,
SPE 101614, and Mahmoud Asadi et al., Post-Frac Analysis Based on
Flowback Results Using Chemical Frac-Tracers, International
Petroleum Technology Conference, 3-5 Dec. 2008, Kuala Lumpur,
Malaysia, IPTC 11891.
[0008] Fluorescent markers and tracers can be made for Water Based
fluids and are used in concentration of 0.018 ml in 180 ml filtrate
and fluorescent markers and tracers for Synthetic/Oil Based fluids
(concentration from 9 to 36 microliters in 180 ml filtrate).
[0009] Though these methods are quite useful there is a need for an
environmentally friendly high resolution method for tracking
treatment fluids that are capable of entering the drilling mud
cake, gravel pack, proppant pack and other large porous media and
also capable of entering without plugging the pore throats into the
pore space (or fractures and fissures) of the reservoir to a
reasonable distance.
SUMMARY OF INVENTION
[0010] It is therefore an object of the invention to provide a
method for tracking a treatment fluid in a subterranean formation
penetrated by a wellbore comprising the steps of providing the
treatment fluid comprising a plurality of tracer agents, wherein
each tracer agent is an object of submicron scale, injecting the
treatment fluid with the plurality of tracer agents into the
wellbore and the formation, and determining the location and
distribution of the treatment fluid by detecting changes in the
physical properties of the formation caused by the arrival of
treatment fluid comprising a plurality of tracer agents.
[0011] The treatment fluid is selected from the group consisting of
fracturing fluids, drilling fluids, acidizing fluids, injection
fluids, brines and completion fluids, fluids for EOR/IOR including
reservoir flooding fluids.
[0012] According to one embodiment, the plurality of tracer agents
are low or insoluble gas bubbles having a diameter of not more than
500 nm and the treatment fluid with the plurality of tracer agents
is a highly dispersed gas-liquid mixture. Suitable gases for use as
the tracer agents are methane, higher molecular weight hydrocarbon
gas, nitrogen or other insoluble inorganic gas or mixtures of
thereof.
[0013] The nano-bubbles are normally created by dispersion of above
mentioned gas or gases in water- or hydrocarbon-based solutions
Water solutions can be made with different conventional oilfield
salts (NaCl, KCl, CaCl.sub.2, ZnBr.sub.2, CaBr.sub.2, and other
inorganic or organic brines and their mixtures) that are used as
completions solutions (brines and heavy brines) and other oilfield
fluids. Nano-bubbles can be particularly strongly stabilized with
electrolytes of ferrous ions, manganese ions, calcium ions, or any
other mineral ion is added to the aqueous solution such that the
electrical conductivity in the aqueous solution becomes not less
than 300 .mu.S/cm. The nano-bubble is a very tiny bubble having a
diameter of not more than 500 nm, so that the nano-bubble does not
experience buoyant forces and rupture near the fluid surface, which
is observed in normal and micro-bubbles.
[0014] According to another embodiment, the plurality of tracer
agents are high viscous liquid droplets having a diameter of not
more than 1000 nm and the treatment fluid with the plurality of
tracer agents is an emulsion such as crude oil in water, toluene in
water etc. where water is fresh water, solutions of different salts
(inorganic as NaCl, KCl, NH.sub.4Cl, CaCl.sub.2, MgCl.sub.2,
NaBr.sub.2, ZnBr.sub.2, CaBr.sub.2, or of organic nature such as
sodium formate, potassium formate and other brines and their
mixtures commonly used in stimulation, gravel pack and completion
operations including) in water (saturated or under-saturated),
brines and water with other chemicals such as surfactants,
biocides, clay control, iron control, scale control etc. used as
additives. It is not unusual that the emulsions are stabilized with
the use of nano-solid particles, such as silica, for example. Size
of the silica nano-particles ranges between 2-500 nm, The loading
of the solid nano-particles for the purpose of the stabilization
has seen concentrations from 0.1 wt % to 15 wt % depending on the
salinity and the temperature of the system, where the increase in
salinity normally requires an increase in solids concentration for
the stability of the emulsion to be increased.
[0015] According to yet another embodiment, the plurality of tracer
agents are solid particles. These particles can be silica,
synthesized copper, magnetite (Fe3O4), ferri/ferrous chlorides,
barium iron oxide (BaFe12O19), zinc oxide, aluminium oxide,
magnesium oxide, zirconium oxide, titanium oxide, cobalt (II) and
nickel (II) oxide, barium sulfate (BaSO4), etc. and the treatment
fluid with the plurality of tracer agents is stabilized solution in
aqueous fluids, solvent based fluids such as alcohols, [ethylene
glycol], or hydrocarbon based fluids. The particles can be also of
organic origin such as co-polymer suspensions such as latex,
polysteren beads x-linked with di-vinyl benzene and others.
Pyrolectric and piezoelectric crystals may also be used in the
compositions herein.
[0016] The treatment fluid comprising a plurality of tracer agents
is provided by mixing the treatment fluid with the plurality of
tracer agents by means of a generator placed in the wellbore or by
surface located equipment.
[0017] The treatment fluid comprising a plurality of tracer agents
can be injected continuously during the treatment duration or
periodically.
[0018] The treatment fluid comprising a plurality of tracer agents
can be injected at any stage of the treatment including pre and
post-treatment injection, during the complete treatment or
partially.
[0019] The injection into the formation may be complemented with
physical treatment such as vibration, heating acoustic treatments
performed before, during or after the injection process is
performed.
[0020] In another embodiment, the method can include adding to the
treatment fluid comprising a plurality of tracer agents one or more
additives selected from a group comprising gelling agents, foaming
agents, friction reducers, surfactants, demulsifiers,
inhibitors.
[0021] Physical properties of the formation are acoustic impedance
and/or electric conductivity and/or magnetic permittivity, nuclear
magnetic resonance (NMR) response, thermal propagation and
hydrodynamic flow capabilities.
[0022] The detecting of physical properties of the formation is
made by seismic, acoustic, electrical, electrokinetical, thermal,
NMR, neutron or gamma-ray means that can be located on the surface
and/or wellbore or cross wellbore.
[0023] The treatment fluid with the plurality of tracer agents can
be flowed back from the subterranean formation and analyzed for
changes in the tracer agents concentration, size, type and
distribution function between the injected and produced treatment
fluid.
[0024] The analysis of the changes in the tracer agents
concentration, size and type distribution function between the
injected and produced treatment fluids can be performed while
flowing in the formation by the acoustics, electric, thermal,
neutron or gamma-ray logging or by comparing samples of the
injection and produced fluids.
[0025] Another aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
DETAILED DESCRIPTION
[0026] A treatment fluid comprising a plurality of tracer agents,
wherein each tracer agent is an object of submicron scale, is
injected into the wellbore and the formation. Typical
diameter/length dimension of a tracer agent is within the range
between 1-1000 nm.
[0027] The injection or flow of objects of submicron scale (so
called nano-tracers) that are contained within the treatment fluid
serve as markers/tracers because their property of staying in bulk
of the transport fluid without gravity segregation and no change in
type of distribution function of the markers within time of the
duration of the formation treatment and measurement operation.
Further the nano-tracers have the main advantage that because of
their size will occupy the whole volume that the fluid has created
in the formation, including pore space or ultra small fissures
where the fluid leaked off. This is in particular important in
matrix acidizing where fluid is injected into pore space or in
shale gas fracturing where swarms of fissures are created in the
process of hydraulic fracturing. In contrary to the microseismic
measurements in the shale fracturing where the registration of
events is scarce and not necessary related to the treatment fluid
propagation within the formation and hence the monitoring is
therefore incomplete, the proposed method would allow for complete
coverage of the hydraulically created fracture area.
[0028] Here the micro and nano-mixtures refer to a portion or full
volume of the treatment fluid mixture of: [0029] Gas and liquid,
whereas the gas is a low or no soluble gas bubbles in the liquid
and liquid can be any mixture of water, brine, acids, hydrocarbons
with any combination of additives such but not limited to as
gelling agents, foaming agents, friction reducers etc. Gas used can
be hydrocarbon gas such as methane or higher molecular weight
hydrocarbon gas, nitrogen or other inorganic gas or mixtures of
thereof. The liquid phase is the prime phase and the gas the
secondary phase dispersed in the mixture with known size
distribution, and life span and determines the physical and
chemical properties of the mixture; [0030] Liquid-Liquid, so-called
an emulsion which can be a presence of the high viscous liquid
inside the low viscous liquid, as well as the presence of smaller
droplets inside the larger one called double, triple etc. emulsion;
[0031] Liquid-solids, where the presence of the solid object inside
the main liquid phase can be produced by the introducing the solid
particles, crystallization, chemical reaction, biological processes
etc. The tracer agents can be of various shapes, ellipsoid, plate
or needle-like, spherical, irregular etc. depending on the material
used.
[0032] The creation of the treatment fluid with the plurality of
tracer agents is carried out by either down-hole nano-tracers
mixture generator placed in the wellbore or by surface located
equipment which can be in form of generators or various types of
tanks or canisters supplying the volume required for injection of
the mixture. The example of such surface generator of nano bubbles
is well explained in U.S. Pat. No. 7,059,591. Various fine size
bubble generators are described in Japanese Patent Application
Publication No. 2001-276589. 2002-11335, 2002-166151, and No.
2003-117368, Japanese Patent No. 3682286, EP application 2020260
and similar can be envisioned.
[0033] The generation of solid nano particles is explained in
several instances and also in US patent application No.
2009/0107673 and PCT patent No. WO2009/079092.
[0034] The mixture can be injected continuously during the
treatment duration or periodically at any rate and concentration.
The mixture can be injected at any stage of the treatment including
pre and post-treatment injection, during the complete treatment or
partially. The injection into the formation may be complemented
with physical treatment such as vibration, heating, acoustic
treatments performed before, during or after the injection process
is performed. The mixtures can be different in terms of type of
base fluid and/or gas utilized for each treatment, or during the
stage of the treatment allowing to distinguish the various stages
within the single treatment or the multiple treatments within the
same wellbore or the multi-wellbore completion.
[0035] Thereafter measurements are then performed to determine the
location and distribution of the treatment fluid and to evaluate
its geometric distribution and diversion by the means of measuring
the change in physical properties of porous environment of the
formation and placed hydraulic or natural fractures and fissures.
It also allows monitoring and evaluating of near wellbore and
wellbore processes and fluid placements such as fracturing,
frac-pack treatments, matrix acidizing, scale inhibition squeezes,
gravel packing, sand control and cementing and drilling fluids flow
and placement of other various chemical and physical treatments of
underground formation such as injection of surfactants, wetability
modifiers, demulsifiers, alcohols, solvents, hot water or hot
chemical injections, under positive pressure compared to the
formation pressure.
[0036] The detection and measurement mechanism is based on seismic,
acoustic, electrical, electrokinetical, thermal, neutron and
gamma-ray measurements that can be conducted from surface and/or
wellbore or cross wellbore.
[0037] In the instance where formation and treatment fluid is flown
back to the wellbore and then to the surface the fluid and
nano-tracers can be analyzed for changes in the tracers
concentration, size, type (if multiples types of mixtures of
different markers are used) distribution function between the
injected and produced fluid. The analysis can be performed either
downhole or at surface with the adequate method of the analysis
depending on the nature of the markers used. The analysis can then
provide additional information on the space that the tracers have
occupied such but not limited to the permeability and conductivity
of the fracture, effective permeability of the formation, the
fluids that the markers interacted with and the PVT conditions they
were exposed, the amount of fluid returned to surface vs. the
amount of fracturing fluid that has leaked off.
[0038] The nano-tracers can have various subsurface
applications.
[0039] Different types of nano-tracers can be added to the proppant
or to the fracturing fluid at different times during the placement
of proppant or treatment fluids (such as main fracturing fluids,
spacers or pre-flush or flush in proppant fracturing or acids,
spacers, pre-flushes or flushes in acid fracturing) during or after
the fracturing process. The injection can be done during the main
fracturing treatments as well as during the test-fracturing that is
typically performed before the main fracturing treatment (so called
injection, calibration step rate tests or mini-frac tests),
cool-down stages preceding the main frac treatment or even after
the main fracturing treatment as post-treatment injection into the
pre-existing fracture. Thereafter various measurements are then
performed to detect where the fluid has been injected. The
detection and measurement mechanism is based on seismic, acoustic,
electrical, electrokinetical, neutron, thermal and gamma-ray
measurements that can be conducted from surface and/or wellbore or
cross wellbore.
[0040] Different types of nano-tracers can be added to the gravel
and gravel pack fluids. Various measurements can be performed after
the gravel packing operations to detect where the fluid and the
gravel pack materials have been injected/placed. The detection and
measurement mechanism is based on seismic, acoustic, electrical,
electrokinetical, neutron, thermal and gamma-ray measurements that
can be conducted from surface and/or wellbore or cross
wellbore.
[0041] The nano-tracers can be mixed with acids, solid acids
pre-flushes and flushes such as brines, solutions of surfactants,
chemical washes, scale and asphaltene inhibitor and their
solutions, solvents and demuslfiers, gases, foams, diverter
materials (solids, liquid and gaseous) or other compounds used in
the treatment sequence to track/monitor completion related
operations. The measurements on the placement of the fluids allow
for fluid placement and fluid diversion detection in wellbores,
multi zone stimulation and treatments, injection monitoring and
flowback of the treatment and reservoir fluids.
[0042] The release of tagging nano-tracers into the flow can be
used to obtain flow velocity or flow profile. In inclined and
horizontal wellbores indication of fluid stratification, phase
flow, fluid lagging, or fluid flow directions can be
interpreted.
[0043] Nano-tracers injection and/or release can be used for
identification/monitoring, of flood front allocation, of various
techniques of Enhanced Oil Recovery techniques, where water, foams,
gases (nitrogen, carbon dioxide, steam and others), surfactants,
miscible and immiscible hydrocarbon, are injected in injector wells
and with or without additional application of heat to increase the
recovery factor of the reservoir. While these techniques are widely
used in the industry, further improvements in oil recovery can be
achieved by monitoring the flood front and controlling and
optimizing the injection and production system of the field or
field sector.
[0044] Nano-tracers can be used to track fracturing fluids in tight
gas shale where swarms of fissures are created in the process of
hydraulic fracturing. In contrary to the microseismic measurements
in the shale fracturing where the registration of events is scarce
and not necessary related to the treatment fluid propagation within
the formation and hence the monitoring is therefore incomplete and
incorrect, the proposed method where the fracturing fluids contain
nano tracers would allow for complete coverage of the hydraulically
created fracture area.
[0045] Different nano-tracer types can be used in combination to
perform any of the operations disclosed herein.
[0046] While the invention has been described with respect to a
preferred embodiments, those skilled in the art will devise other
embodiments of this invention which do not depart from the scope of
the invention as disclosed therein. Accordingly the scope of the
invention should be limited only by the attached claims.
* * * * *