US20200291761A1

US20200291761A1 - Unique chemical delivery method for stimulating production in oil and gas wells

Info

Publication number: US20200291761A1
Application number: US16/753,619
Authority: US
Inventors: Glenn R. McCOLPIN
Original assignee: Surgitech Inc
Current assignee: Surgitech Inc
Priority date: 2017-10-05
Filing date: 2017-10-05
Publication date: 2020-09-17
Also published as: WO2019070289A1

Abstract

A method of treating a wellbore in a subterranean formation includes attaching a surface located inert gas generator to an annular space in a wellbore that comprises a tubular element. A heated inert gas is generated using the inert gas generator, wherein the inert gas comprises CO2 and nitrogen. The heated inert gas is placed from the inert gas generator into the annular space. The heated inert gas is circulated from the surface, down the annulus, and returns up through the tubular element back to the surface for a period of time. At least one well treatment chemical is combined with the heated inert gas to form a matrix injection gas, wherein the chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof. The matrix injection gas is delivered to the formation.

Description

RELATED APPLICATION

This application is the National Stage of International Application No. PCT/US2017/055445, filed Oct. 5, 2017 which is specifically incorporated by reference in its entirety herein.

BACKGROUND

The present invention generally relates to the use of treatment chemicals in subterranean operations, and, more specifically, to gas delivery systems for treatment chemicals, and methods of using these delivery systems in subterranean operations.
Oil and gas hydrocarbon fluid producing wells and water producing wells may clog over long periods of production and such clogging causes diminished flow to occur as normal well pressure declines and precipitating chemical processes occur with the production of oil, gas and water. The wells may have scaling compounds, paraffins and also high asphaltenic portions, and are traditionally treated with chemicals in the form of a liquid to clean up the wellbore and pores of the reservoir rock to remove the offending particulates. Liquid pumping rates are relatively slow and due to their high viscosity, treatment chemicals are rarely able to be injected much beyond 15 to 20 feet into the reservoir without using expensive hydro-fracturing. Additionally, in horizontal wells, the entire horizontal lateral must be filled with the chemical of interest in order to attempt a treatment. This requirement for large chemical volumes makes such treatments cost prohibitive in most cases. Thus, there is a need for a treatment chemical delivery system that addresses the present traditional well and horizontal well treatment inadequacies.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to one having ordinary skill in the art and having the benefit of this disclosure.

FIG. 1 is a block diagram of the inert gas generator according to embodiments of the disclosure.

FIG. 2 is a schematic of the inert gas generator and delivery process of treatment chemicals according to embodiments of the disclosure.

FIG. 3 is a schematic of the downhole impact of the treatment processes according to embodiments of the disclosure.

FIG. 4 is a schematic of the propane vaporizer and inert gas reactor according to embodiments of the disclosure.

FIG. 5 is a drawing of a chemical atomizer according to embodiments of the disclosure.

FIGS. 6A-6C are drawings of the chemical atomizer and nozzles according to embodiments of the disclosure.

DETAILED DESCRIPTION

Embodiments of the invention are directed to a process utilizing hot, inert gas as a carrier for treatment chemicals for subterranean oil and gas wells.

General Measurement Terms and Definitions

Unless otherwise specified or unless the context otherwise clearly requires, any ratio or percentage means by volume.
If there is any difference between U.S. or Imperial units, U.S. units are intended.
Unless otherwise specified, mesh sizes are in U.S. Standard Mesh.
The micrometer (μm) may sometimes be referred to herein as a micron.
Pounds per square inch (psi) may be converted to megapascals (MPa) by dividing psi by 145.04 (1 psi/145.04=1 MPa).
As used herein, into a subterranean formation can include introducing at least into and/or through a wellbore in the subterranean formation. According to various techniques known in the art, equipment, tools, or well fluids can be directed from a wellhead into any desired portion of the wellbore. Additionally, a well fluid can be directed from a portion of the wellbore into the rock matrix of a zone.
Broadly, a zone refers to an interval of rock along a wellbore that is differentiated from surrounding rocks based on mineral composition, hydrocarbon content or other features, such as perforations or other fluid communication with the wellbore, faults, or fractures. A treatment usually involves introducing a treatment fluid into a well. As used herein, a treatment fluid is a fluid used in a treatment. Unless the context otherwise requires, the word treatment in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid. As used herein, a treatment zone refers to an interval of rock along a wellbore into which a treatment fluid is directed to flow from the wellbore. Further, as used herein, into a treatment zone means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.
Process Description
The vast majority of chemical applications to oil & gas wells are delivered by dripping a chemical down the annulus where it is immediately dispersed in the oil or water in the wellbore and then pumped back to the surface with the oil & water. Little or no chemical makes it into the actual reservoir rock where various plugging phenomenon known as skin damage, inhibit oil & gas flow to the wellbore. With the inert gas delivery process in the present disclosure, treatment chemicals are able to be widely dispersed in the rock where they can address skin damage, modify the flow characteristics of the reservoir rock and provide a significantly longer impact than wellbore or near wellbore treatments.
When skin damage needs to be addressed in oil and gas wells, a “squeeze” may be performed to attempt to push the liquid treatment chemical through the perforations and into the rock where the damage is located. With this technique, the entire section of perforations is covered with liquid chemical plus any additional volume that is attempted to be forced into the rock. Once the chemical volume is in the well, a volume of water is usually placed on top of the chemical in an effort to create enough hydrostatic head to push the chemical into the rock. If the chemical of interest has a density that is lighter than water, the chemical may rise through the water and the weight of the chemical will end up pushing the water into the rock rather than the other way around. The water can also dilute certain chemicals and reduce their effectiveness. A squeeze may also be performed by using a pump in an attempt to push the high viscosity liquid deeper into the rock than the hydrostatic method could achieve.
With an atomized or vapor delivery solution like the processes in the present disclosure, the high velocity, inert gas may be used to carry the treatment chemical into the rock where it can provide a benefit. A gas/vapor or gas/mist mixture has a much lower viscosity than a pure liquid and will have less resistance as it moves into the reservoir rock.
In some embodiments, a method of treating a wellbore in a subterranean formation includes attaching a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore; generating a heated inert gas using the inert gas generator, wherein the inert gas comprises CO2 and nitrogen; placing the heated inert gas from the inert gas generator into the annular space; circulating the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned; combining at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and delivering the matrix injection gas to the formation. The treating may occur in a substantially horizontal portion of the wellbore where the high velocity, inert gas is in turbulent flow and able to keep the treatment chemicals in suspension until they enter the treatment zones. The method may further comprise after the circulating step, pressurizing the near wellbore formation by partially closing a wing valve on the return to the surface for an abbreviated period of time, releasing the built-up pressure until the near wellbore return is at least partially clean; and incrementing the time of shut-in in similar abbreviated time increments and rapidly releasing pressure until the formation break-in pressure and a permeable flow rate are established.
Once the formation is able to take the inert gas, a variable volume is injected as a pre-flush, which pushes any existing fluids out of the pore space of the rock. This pre-flush removes native water, which may dilute any subsequent treatment chemicals. A quantity of solvent/surfactant or other chemicals may also be injected in the pre-flush gas to strip hydrocarbons out of the pore space so that subsequent treatment chemicals are not inhibited from acting on the rock or scale that may be present in the pore space.
The well treatment chemicals may be selected from the group consisting of aromatic solvents, acids, scale inhibitors, paraffin dispersants, oxygen scavengers, biocides, beneficial bacteria, nano-materials, foams and combinations thereof.
The method may further include adding the inert treatment gas after the matrix injection gas to chase the matrix injection gas and chemicals and force the matrix injection gas and chemicals further into the formation to widely disperse the chemicals and other products. In some embodiments, compressed air is run through the inert gas generator to convert the oxygen in the compressed air into CO2. In several embodiments, inert gas generator further comprises a heat exchanger, wherein the heated inert gas is cooled in the heat exchanger before placing the heated inert gas into the annular space or through a secondary compression unit, which will multiply the inert gas pressure for use on higher pressure wells. In exemplary embodiments, at least one well treatment chemical is atomized before combining it with the heated inert gas to form the matrix injection gas. In some embodiments, the tubular element may include a downhole pump, the method further comprising circulating heated inert gas to liquefy paraffin in the tubular element, and lifting the paraffin to the surface for collection using the downhole pump.
In an embodiment, a well treatment apparatus includes an inert gas generator comprising: a compressor configured to deliver compressed air to a reactor; a reactor configured to receive compressed air from the compressor and to configured to generate an inert gas from compressed air; an atomizer configured to receive inert gas from the reactor and atomize well treatment chemicals; a pump configured to deliver well treatment chemicals to the atomizer; and a controller configured to operate at least one of the compressor, reactor, pump, and combinations thereof. The apparatus may further comprise a heat exchanger in fluid communication with the reactor discharge and the atomizer. In some embodiments, the apparatus may further comprise a flue gas booster in fluid communication with the reactor discharge and the atomizer inlet.
In several embodiments, the atomizer comprises a vessel including a pressure chamber; an inert gas inlet; a well treatment chemical inlet; a manifold for distributing the well treatment chemicals; nozzles along the manifold for atomizing the well treatment chemicals into the pressure chamber; and an outlet for delivering the inert gas and atomized well treatment chemicals to the well.
In some embodiments, a well treatment system includes: a well treatment apparatus configured to: attach a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore; generate a heated inert gas using the inert gas generator, wherein the inert gas comprises CO2 and nitrogen; place the heated inert gas from the inert gas generator into the annular space; circulate the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned; combine at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and deliver the matrix injection gas to the formation.
FIG. 1 is a block drawing of an inert gas generator 102 used in a well treatment process 100. FIG. 2 is a schematic drawing of the inert gas generator 202 used in the well treatment process 200 according to embodiments of the invention. Referring to both FIGS. 1 and 2, fuel source(s) 104, such as methane or natural gas, propane, bio-diesel, hydrogen or the preferred diesel, for example, can be used to supply a reactor 106 with a fuel or fuels to burn in the presence of compressed gas obtained from a standard compressor 108. A fuel supply line can be also connected to two valves. Diesel can be injected into the combustion chamber of the reactor 106, and ignited with a glow plug all in a manner well known by those skilled in this art. Further, a high pressure, propane vaporizer 105 takes low pressure liquid propane and converts it to a high temperature gas and boosts its pressure for injection into the reactor 106. Combining gaseous and liquid fuels increases the overall combustion efficiency so that soot generation is minimized. Overall control of the inert gas generator 102 is maintained by an integrated controller 110.
The compressed air source 108 feeds in parallel with the fuel source 104 to the reactor 106. Built-in safeguards control the flow of compressed air into the reactor. Shutdown valves (not shown) are electronically controlled by sensors (not shown) that signal the fuel line to immediately stop the flow of air through air supply 108 to the combustion chamber of the reactor 106 if required to prevent further burning. The compressed air supply 108 can also provide a flow control valve arrangement (not shown) to vary as required the amount of gas reaching the gas/gas (not shown) mixer when utilizing alternative gaseous fuel mixes, immediately before the mixed air and fuel is introduced into the reactor 106.
Water 112 supplied to the outlet side of the inert gas generator 102 from source 112 receives a pressure boost from water pump driven by an electronically controlled motor, which can be activated if steam is desired to be used in the well bore. Since water cannot be used in some types of formations, steam may not be useful in all situations, especially in formations have water reactive clays and the like. This water source 112 can also provide coolant for the reactor 106. A check valve can be provided to assure that water does not flow back into the water supply 112. The combustion chamber of the reactor 106 is water cooled in a closed loop system similar to an automobile cooling system. Alternatively, the water could flow from source 112 through the line to the combustion chamber jacket (not shown in this view), then through a radiator or heat exchanger before being returned to the combustion-chamber water jacket for recirculation around the combustion chamber, all in a manner well known to those in this art. The outlet side of the combustion chamber of the reactor 106 can additionally be supplied with a catalytic convertor (not shown), which both removes unwanted NOx pollutants and increases the heat of the output vapor stream of the system. Additionally, a pre-cooler 226 may be utilized to reduce the temperature of the gas leaving the combustion chamber of the inert gas generator 102, 202.
After superheated vapor and/or steam is provided to the wellbore 120, 220 from the reactor 106, chemicals may be transferred from storage vessels 114, 214 to an atomizer 118, 218 using pumps 116, 216. The chemicals are combined with the superheated vapor and or steam from the reactor 106 by using fogging nozzles 219. The atomized chemicals are placed into the wellbore annulus 220, and the tubing 224 in the wellbore 120 may be used to return the superheated vapor to the surface. If higher pressure combustion is required, a flue gas booster package 122, 222 may be utilized where the pressure of the discharge gas from the reactor 106 is further boosted by the flue gas booster 112, 222 and then sent to the atomizer 118, 218 to atomize chemicals from tanks 114, 214.
FIG. 3 is a schematic illustration of the downhole impact of the treatment processes according to embodiments of the disclosure. Treatment chemicals from chemical pump 316 are mixed with superheated gas from the inert gas generator 302 in an atomizer 318. The resulting chemical droplet/gas mixture 319 is sent down the annulus of a wellbore 320 to various zones 324 in the formation. The chemical droplets 328 are carried into the rock 326 by the superheated inert gas and deposited upon the rock 326 that also includes sand grains 330. The treatment chemical droplets 328 coat the rock 326 instead of filling the porosity 100%. This dispersal method of using the superheated inert gas to carry droplets of chemicals, dramatically reduces the volume of chemical needed to contact or coat the rock or scale surfaces.
FIG. 4 is a schematic illustration of the propane vaporizer and reactor utilized in embodiments of the present invention. Combustion chamber 400 accepts the fuel injected by diesel injector 402 and compressed air 404 (or the compressed air and fuel from gas/gas mixer, not shown). The compressed air source 404 feeds in parallel with the diesel fuel source to the diesel injector 402 in the combustion chamber 400. Built-in safeguards control the flow of compressed air into the combustion chamber. Shutdown valves (not shown) are electronically controlled by sensors (not shown) that signal the fuel line to immediately stop the flow of fuel to the combustion chamber 400 if required to prevent further burning. The compressed air line can also provide a flow control valve arrangement 405 and flow meter 407 to vary as required the amount of gas reaching the gas/gas (not shown) mixer when utilizing alternative gaseous fuel mixes, immediately before the mixed air and fuel is introduced into the combustion chamber 400.
Liquid propane 406 from a storage tank is transferred to a high pressure propane vaporizer 410 using a liquid propane pump 408. After vaporizing the propane using heat from the reactor coolant the gaseous propane is transferred to a propane vapor injector 416 located on the combustion chamber 400. The flow of propane may be adjusted using the pressure regulator 414 located on the discharge of the propane vaporizer 410 along with pressure relief valve 412. In an embodiment, the high pressure propane vaporizer 410 takes low pressure liquid propane and converts it to a vapor while boosting its pressure to the over 600 psi required for injection in the combustion chamber 400. The addition of propane increases the percent of diesel that is burned, reduces soot generation and minimizes the oxygen content of the resulting gas stream. Most vaporizers are designed to take liquid propane and convert it to a vapor at low pressure, i.e., 60 psi. In an exemplary embodiment of the invention, a 50 layer, plate heat exchanger is used to transfer heat from the reactor coolant 422 to the liquid propane in the propane vaporizer 410 to get it up to the about 600 psi or more pressure needed for the combustion chamber 400. The regulator 414 and emergency pressure relief valve 412 are used to keep the propane pressure below the design rating of the propane vaporizer 410.
Electronically controlled ignition controller 411 energizes the ignition system 418 or spark plug/glow plug in the chamber 400, commencing the combustion. Reactor coolant from the closed loop cooling system 420 is pumped into the jacket 422 formed around the combustion chamber 400. The combustion chamber 400 provides a tapered interior surface 401 to minimize the turbulence in the chamber and to direct the vapor flow out to the process outlet stream 426 of this assembly. The flow of coolant through jacket 422, which surrounds the combustion chamber 400 cools the chamber thereby preventing excessive heat buildup in the combustion chamber body. The outlet port of the combustion chamber 400 is fabricated as a bolted flange body from F9 Chrome, because of its heat tolerance. The reactor design uses a dual material flange system. In an embodiment, the body of the reactor 432 is made from stainless steel. The end plate 434 and exhaust system may be manufactured from F9 chrome, which is a high temp material. The end plate 434 is designed so that the exhaust pipe 428 slides inside the reactor body 436 and can expand and contract without causing stresses that would normally break welds and damage the system.
Reactor operating temperatures range from 1100° F. to 1200° F. under normal conditions, but a combination of the heat exchanging exhaust 428 and the addition of water through the water injector 435 will reduce the inert gas temperature. If the combustion chamber 400 reaches or exceeds a predetermined set point, e.g., 650° F. (343° C.), air, fuel, chemical injection (if any) and water are all automatically shut off and a back-pressure valve 424 is fully opened. If flame out occurs in the combustion chamber 400 as determined by having the temperature fall below 250° F. (121° C.), or excessive pressure is sensed as indicated by a pressure sensor (not shown) experiencing an exhaust pressure above a set point of 390 psi (2.69 MPa), a similar shut down sequence is activated. In some embodiments, the exhaust pressure may be as high as about 3000 to about 4000 psi. Boosting the pressure of this treatment process has a dramatic impact on the miscibility of treatment gas with oil. When CO2 becomes miscible in oil, the CO2 reduces the viscosity of the oil and allows it to flow more easily. The miscibility pressure of CO2 in oil is 1070.6 psia at 87.9° F. The process disclosed in the present invention can compress the treatment gas up to 3000 psia or more using its flue gas compression booster.
The exhaust side 428 of the combustion chamber 400 is directed to the well head flow line (not shown) to supply the superheated combustion gases to the well bore; and will be conducted to the well head by means well known to the oil field trade and process industries. The outlet side 428 of the combustion chamber 400 is monitored for pressure, temperature and rate of flow. If the pressure exceeds acceptable safety limits, it can be vented to the atmosphere through a safety valve (not shown, but well known in this art). The special heat exchanging exhaust pipe 428 allows the combustion chamber 400 to be run at much higher temperatures and truly generate an oxygen free, inert gas.
By careful regulation of the combustion, the amount of remaining oxygen in the outlet flow 426 of superheated gas is reduced to 0.02% to 0.3% oxygen, far less than the 3% to 5% oxygen found in most membrane injection systems. Oxygen content may be measured by oxygen sensor 432, located on the heat exchanging exhaust pipe 428. Programmable logic devices constantly monitor the 02 levels in the system 100 of FIG. 1. The nearly complete combustion minimizes unwanted NOx gases and the use of the alternative catalytic convertor (not shown) removes all remaining pollutants from the superheated stream 426 as well as further heats the vapor coming from the combustion chamber 400. Another benefit of the use of the chemical treatments more fully described below is the effect on free water vapor in the well bore. The use of the alkali metal hydride completely removes all free water vapor from the superheated vapor stream injected into the well bore, leaving only as later described herein, CO2 and N2. If the vapor output temperature is higher than required or above the desired preset at 650° F. (343° C.), e.g., an electronic sensor (not shown) signals the control system 411 to reduce the heat of the system 100 by reducing compressed air, propane, and diesel fuel injection into the chamber 400.
Similarly, a control valve (not shown) can be preset at 390 psi (2.69 MPa) to relieve pressure on the system automatically. An electronically controlled back pressure control valve 424 can provide further control over the system by opening or closing the outlet of the combustion chamber 400 thereby regulating the flow of vapors from the chamber 400. This valve 424 also permits the use of diesel fuel by supporting the auto-ignition sequence in the combustion chamber 400 from the glow plug 418 by substantially closing outlet 428 from the combustion increasing pressure in the combustion chamber 400. Water may be injected into the heat exchanging exhaust pipe 428 at water injector 435.
A chemical supply valve 430 is opened allow the flow of chemicals from source 114 (as shown in FIG. 1) into the line to the outlet side of the combustion chamber 400 or at the wellhead, and can provide a shut down valve to immediately stop the flow of chemicals into the line as determined by the sensors of the electronic control circuitry. A pump can be driven, similarly to other pumps and compressors in this embodiment, by an electronically controlled motor, which responds to signals from the automated control system herein. For safety, a check valve prevents the back flow of chemicals or hot vapors from the supply line. The injection of chemicals into the outlet side of the inert gas generator 102 (as shown in FIG. 1) immediately vaporizes the chemicals allowing them to be carried into the well bore and into the near and extended near well bore production zones.
FIG. 5 is a schematic drawing of a chemical atomizer 500 according to embodiments of this disclosure. Atomizer 500 may include a pressure chamber 502, an inert gas inlet 504, a well treatment chemical inlet 506, a manifold for distributing the well treatment chemicals 508, nozzles along the manifold 510 for atomizing the well treatment chemicals into the pressure chamber 502, and an outlet 512 for delivering the inert gas and atomized well treatment chemicals to the well. In some embodiments, there is a mesh screen 514 surrounding the pressure chamber 502, manifold 508, high pressure lines 509 and nozzles 510. The mesh screen 514 may be supported by a ring 516 near the base of the pressure chamber 502. In some embodiments the Atomizer 500 is attached to a device with wheels (not shown) which can be used to facilitate moving the device.
As seen in FIG. 6A, the chemical manifold 608 is connected by individual lines 609 in series and/or parallel to various nozzles 610 on the outside surface of the pressure chamber 602. As gas enters 604, the chemicals from a chemical transfer pump 606 are fogged into the pressure chamber 602 resulting in a gas and chemical outlet combination 612. The chemicals may be at least one of vaporized, atomized, and combinations thereof upon leaving the pressure chamber 602. FIG. 6B shows a cross-sectional schematic of the chemical atomizer 600 where the inert gas inlet 604 is located in the center of the pressure chamber head and the fogging nozzles 610 spray the chemicals from the inner wall of the pressure chamber 612 to the center of the chamber 602. In an embodiment as shown in FIG. 6C, the nozzle 610 comprises a pipe hex plug 610 that is screwed into the wall of the pressure chamber 602. There are pipe fittings 614 on the outer portion of the hex plug 616 and allow the chemical manifold pipe 609 to be attached to the nozzle 610. The hex plug 616 also provides for the attachment of a fogging nozzle insert 618 inside of the pressure chamber 602. In one embodiment, the nozzle insert 618 is a BETE™ fogging nozzle insert available from BETE Fog Nozzle, Inc. in Greenfield, Mass.
In some embodiments, the carrier gas has about 60 times less viscosity than a typical treatment liquid like xylene. This allows the gas to easily move through the reservoir rock. In some embodiments, suspended in that carrier gas are either microscopic droplets of treatment chemicals or the chemical in a vapor state. The impact on the overall carrier gas viscosity is negligible and due to the high velocity of the carrier gas, the droplets or vapor are easily pushed into the pore space. In many embodiments, there is virtually no dilution of the treatment chemical, the volume of chemical can be significantly reduced yet provide the same or better benefit, and one has the added benefit of using a carrier gas that will further reduce the viscosity of oil to make it flow more easily, and the compressed gas may re-energize reservoir pressure so that the well flows oil as if the well were years younger.
In some embodiments, a fixed or mobile inert gas generator is first plumbed into a port on the casing annulus of an oil and/or gas well. The inert, carrier gas generation process is initiated, and the gas is injected down the annular space between the well's casing and production tubing. In some embodiments, it is not necessary remove the downhole pump, rods or tubing during this process.
The temperature of the inert carrier gas may be varied to suite different applications. In some embodiments, the gas coming out of the generator can be as hot as about 1200° F. or can be reduced through multiple methods to about 200° F. or less. With certain treatment chemicals, there is a benefit to using a hot gas that will put the chemical into a pure vapor state. With other treatment chemicals, lower temperatures may be required, in which case, the chemicals may be introduced into the carrier gas stream in an atomized state. These initial particles of chemical may be on the order of about 30 micron droplets or smaller.
Where paraffin in the formation is an issue, the raw carrier gas may be injected into the annular space for a period of 30 minutes or more in order to transfer heat to the well's tubing and liquefy any paraffin that may reside in the tubing. The well's downhole pump may then be used to lift the liquefied paraffin to the surface for collection. In some embodiments, high temperature steam may be added to the inert gas in order to carry more BTUs downhole to heat up the wellbore.
In some embodiments, once the tubing is heated and cleaned, the treatment operator assess how plugged the downhole perforations or fractures are by observing the injection rates and pressures. If the perforations or fractures are not initially taking gas, pressure may be built up and then released by opening a valve at the surface and releasing the inert gas. This build up and blow down process allows some portion of the high pressure gas to enter the perforations or fractures, and when the well is blown down rapidly, the high pressure gas may blow plugging material out of the perforations, allowing the material to fall to the bottom of the hole. In some embodiments, once the operator sees that he has good injectivity into the rock, he may start adding the chemical to the hot, inert gas stream and begin treating the rock matrix with the chemical.
In some embodiments, during the matrix injection portion of the treatment, the hot, inert, gas is used as a transport media for one or more treatment chemicals. Gas flow and temperature may be adjusted during the matrix injection in order to accommodate different treatment chemicals. In an exemplary embodiment, initially the gas could be run hot with an aromatic solvent to clean up near wellbore skin damage and clean organic material or hydrocarbons off the rock. In some embodiments, that initial solvent cleaning and pore space purging may be followed with an acid that will dissolve scale, calcite and other plugging materials. In further embodiments, the acid may be followed with a scale inhibitor or paraffin dispersant to keep the flow paths in the rock open for multiple months.
In many embodiment, after the last doses of the treatment chemicals have been delivered to the rock, a quantity of inert gas may be used to chase the chemicals and further push them into the reservoir. The inert treatment gas may also act to increase production by re-energizing the pore space, reducing the viscosity of the oil so that it has greater mobility. As the gas expands, it will sweep oil through the pore space.
In some embodiments, post treatment, various treatment chemicals may be produced back with the oil, but in extremely low concentrations. This metering of the treatment chemicals may allow the treatment chemicals to provide a benefit for significantly longer than you would get with a traditional liquid application with its limited rock penetration. In several embodiments, the oil and gas production is monitored post treatment, and the process is repeated once the plugging or skin damage re-appears.
Additionally, post treatment, there may be a dramatic reduction in produced water volumes. This may be occurring because by super saturating the near wellbore with gas, the process is modifying the relative permeability of the rock so that it preferentially passes oil & gas vs water.
The well cleaning process according to embodiments of the invention may use mobile, truck mounted gas generators to create a high velocity flow of inert gas into the well. With the ability to vary the gas temperature to suit the particular chemical being used, the process can either carry the chemical as a pure vapor or as an atomized liquid. By using the inert gas as a carrier for the treatment chemicals, a vapor or microscopic droplets of the chemical in its pure form, can be delivered directly to the reservoir rock without dilution. Due to the high flow rate of the gas (about 700 cubic ft/min or more) the treatment chemicals are less likely to drop out as it traverses the distance from the earth's surface to the reservoir rock. By dispersing the chemicals with the inert gas, the process can coat the pores of the rock without having to use large quantities of chemicals. As an example, 10,000 cubic feet of rock with 15% porosity can hold 11,229.75 gallons of liquid. If instead of filling the entire pore space with chemical, just a thin film is left on the rock face, the total liquid volume used to coat the rock may be significantly reduced. These chemical films, as a non-limiting example, may range from about 0.4 nm to about 80 nm in thickness and are dependent on the pore size, gas pressure and the fluid properties.
Methods of Use
The methods of the present invention may be employed in any subterranean treatment where treatment fluids may be used. Suitable subterranean treatments may include, but are not limited to, drilling, fracturing treatments, sand control treatments (e.g., gravel packing), and other suitable treatments where a treatment fluid of the present invention may be suitable.
After the fluids are placed into the wellbore, the fluids may enter the subterranean formation via lost circulation zones for example, depleted zones, zones of relatively low pressure, zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth.
In embodiments, the disclosed wellbore treatment chemicals may be prepared at a well site or at an offsite location. Once prepared, a treatment fluid of the present disclosure may be placed in a tank, bin, or other container for storage and/or transport to the site where it is to be used. In other embodiments, a treatment fluid of the present disclosure may be prepared on-site, for example, using continuous mixing, on-the-fly mixing, or real-time mixing methods. In certain embodiments, these methods of mixing may include methods of combining two or more components wherein a flowing stream of one element is continuously introduced into flowing stream of another component so that the streams are combined and mixed while continuing to flow as a single stream as part of the on-going treatment.
In some embodiments, the systems described herein can further comprise a mixing tank that is upstream of the pump and in which the treatment fluid is formulated. In various embodiments, the pump (e.g., a low pressure pump, a high pressure pump, or a combination thereof) may convey the treatment fluid from the mixing tank or other source of the treatment fluid to the tubular. In other embodiments, however, the treatment fluid can be formulated offsite and transported to a worksite, in which case the treatment fluid may be introduced to the tubular via the pump directly from its shipping container (e.g., a truck, a railcar, a barge, or the like) or from a transport pipeline. In either case, the treatment fluid may be drawn into the pump, elevated to an appropriate pressure, and then introduced into the tubular for delivery downhole.
Embodiments of the present invention may facilitate delivery of treatment chemicals in horizontal wells where traditional liquid applications would be cost prohibitive. Additional embodiments may include delivery of treatment chemicals in pipelines or deep wells where traditional liquid applications would be cost prohibitive. Further embodiments may include delivery of treatment chemicals in large petroleum tanks where the inert gas would be non-explosive and the vaporized or atomized chemicals would contact the entire metal surface with minimum chemical volume. Additionally embodiments may include cleaning up paraffinic wells where the heat can be used to accelerate the paraffin breakdown process.
Advantages of the processes of the present invention may include, but are not limited to: The volume of chemical being dramatically reduced because it is being transported by an inexpensive, inert gas and then deposited in the pore space as a thin film instead of filling the entire pore volume. Also, the chemicals may be deposited significantly deeper into the reservoir because the gas/chemical vapor mixture or gas/chemical droplet mixture has a viscosity that is about 60 times less than that of treatment chemicals in their liquid form, therefore requiring less energy to push the chemical into the rock. Further, instead of having too high of a concentration of chemical in the near wellbore where it is rapidly produced back, by widely distributing the chemicals suspended in an inert gas stream, the chemicals will be produced back over a significantly longer time period and provide a benefit for a much longer time. In addition, by suspending the chemicals in the inert gas stream the gas may be used to strip away free water and deposit the chemicals in the rock with minimal dilution. This may allow the chemicals to react with portions of the rock that were never previously treated. With liquid chemical treatments, the products are typically pushed with water. Significant mixing may occur, which causes dilution of the chemicals and reduces their effectiveness.
Additional advantages include the situation where with a pure liquid treatment, the entire pore space must be filled with chemical in order to continue pushing the product deeper into the rock. With the carrier gas method, the vast majority of the pore space is filled with cheap, inert gas and the chemical droplets are moved along with the gas stream where they leave a thin film on the rock as they move through the pore space. Also, some treatment chemicals such as paraffin solvents have a much higher reaction rate when heated. With the processes according to this disclosure, the carrier gas may be injected at 350° F. or more, which increases the effectiveness of the chemical. This heat may also be used to liquefy paraffin in the upper section of wells, which again may reduce the quantity of chemical needed and eliminates the need for damaging processes like hot oiling or hot watering. Further, the carrier gas is typically composed of both carbon dioxide and nitrogen but may be composed of other gases. After the chemicals are deposited, the CO₂component of the carrier gas becomes soluble or miscible in oil depending on the pressure and may reduce the oil's viscosity and make it easier to flow. The nitrogen component will not be soluble or miscible in oil and will continue to expand after the treatment ceases. This gas expansion will add significant energy to the subsurface system and further help to push the thinned oil to the wellbore to be produced.
The invention having been generally described, the following examples are given as particular embodiments of the invention and to demonstrate the practice and advantages hereof. It is understood that the examples are given by way of illustration and are not intended to limit the specification or the claims to follow in any manner.

Examples

Wells treatments using the processes in this disclosure have observed a reduction in produced water after gas is injected in the well. This reduction has occurred on the order of about 50% to about 75%. Reduced water volumes may result in reduced operating expenses and a longer economic life for each well. Several wells treated using the processes in the present disclosure have started treating wells with high water rates specifically to reduce the water production and get the wells back to where they can be economically produced. In some locations, water disposal costs may be very high.
One skilled in the art may conclude that the processes in this disclosure are a different delivery method for oil and gas chemicals that results in reduced chemical usage and significantly deeper penetration of the chemicals into the reservoir rock. The processes likely yield better results at a lower cost. While natural gas, CO₂, nitrogen or any other carrier gases may be used, an embodiment of the disclosure uses a CO₂/Nitrogen mixture that has superior oil sweep properties over a pure gas.
Further, the processes in this disclosure by design, generate a hot, inert gas. Unlike using liquid CO₂or nitrogen that have to have significant energy added to gasify the liquid, the gas mixture of the present disclosure comes out of the reactor in one embodiment at about 1200° F. This native heat may be used to liquefy paraffin, enhance the impact of the treatment chemicals, and accelerate chemical reactions. Gas mixtures of this composition typically have to be cooled prior to compression. The processes of the present invention use a high pressure combustion process which eliminates the need for any pre-cooling or expensive liquid to air heat exchanging hardware.
Additionally, other gas generation methods like membrane separation of nitrogen, may pass up to 5% oxygen which can be detrimental to oil & gas reservoirs. The gas utilized by processes according to the preset disclosure can have oxygen contents in some embodiments as low as about 0.02%.
For horizontal wells, the processes according to the preset disclosure may be the only cost effective method to deliver treatment chemicals into the pore space of the rock. Due to the long lateral lengths and the volumes involved, liquid treatments on horizontal wells are cost prohibitive in most cases. Further, when compared to pure gases, that could be used for horizontal well treatments, the processes according to the present disclosure use a combination of gases which have been shown to provide significantly better oil sweep efficiency.
Wells treated with this technique typically experience a reduction in produced water in addition to an increase in hydrocarbon production. This water shut off effect reduces operating expenses (water treating and disposal costs) and extends the economic life of each well. Many producing formations contain clays which irreversibly swell in the presence of water impede the movement of hydrocarbons through the rock. The processes according to the preset disclosure may be virtually a water free production enhancement technique.
Embodiments disclosed herein include:
A: A method of treating a wellbore in a subterranean formation comprising attaching a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore; generating a heated inert gas using the inert gas generator, wherein the inert gas comprises CO2 and nitrogen; placing the heated inert gas from the inert gas generator into the annular space; circulating the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned; combining at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and delivering the matrix injection gas to the formation.
B: A well treatment apparatus comprising an inert gas generator comprising: a compressor configured to deliver compressed air to a reactor; a reactor configured to receive compressed air from the compressor and to configured to generate an inert gas from compressed air; an atomizer configured to receive inert gas from the reactor and atomize well treatment chemicals; a pump configured to deliver well treatment chemicals to the atomizer; and a controller configured to operate at least one of the compressor, reactor, pump, and combinations thereof.
C: A well treatment system comprising a well treatment apparatus configured to attach a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore; generate a heated inert gas using the inert gas generator, wherein the inert gas comprises CO2 and nitrogen; place the heated inert gas from the inert gas generator into the annular space; circulate the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned; combine at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and deliver the matrix injection gas to the formation.
Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein the treating occurs in a substantially horizontal portion of the wellbore. Element 2: further comprising after the circulating step, pressurizing the near wellbore formation by partially closing a wing valve on the return to the surface for an abbreviated period of time, releasing the built-up pressure until the near wellbore return is at least partially clean; and incrementing the time of shut-in in similar abbreviated time increments and rapidly releasing pressure until the formation break-in pressure and a permeable flow rate are established. Element 3: wherein the well treatment chemicals are selected from the group consisting of aromatic solvents, acids, scale inhibitors, paraffin dispersants, oxygen scavengers, biocides, beneficial bacteria, nano-materials, foams and combinations thereof. Element 4: further comprising adding the inert treatment gas after the matrix injection gas to chase the matrix injection gas and force the matrix injection gas further into the formation to widely disperse the chemicals and other products. Element 5: wherein compressed air is run through the inert gas generator to convert the oxygen in the compressed air into CO2. Element 6: further comprising a heat exchanger, wherein the heated inert gas is cooled in the heat exchanger before placing the heated inert gas into the annular space. Element 7: wherein the at least one well treatment chemical is atomized before combining it with the heated inert gas to form the matrix injection gas. Element 8: wherein the tubular element includes a downhole pump, the method further comprising circulating heated inert gas to liquefy paraffin in the tubular element, and lifting the paraffin to the surface for collection using the downhole pump. Element 9: wherein the formation comprises porous rocks and the matrix injection gas is applied to the rock face in the pores as a thin film. Element 10: wherein the thin film thickness is in the range of about 0.4 nm to about 80 nm. Element 11: further comprising a heat exchanger in fluid communication with the reactor discharge and the atomizer. Element 12: further comprising a flue gas booster in fluid communication with the reactor discharge and the atomizer inlet. Element 13: wherein the reactor can receive an exhaust pipe that slides inside the reactor body, wherein the exhaust pipe is between reactor and the atomizer. Element 14: wherein the reactor comprises a cooling jacket surrounding a combustion chamber, wherein the cooling jacket contains coolant. Element 15: further comprising a propane vaporizer in fluid communication between a propane supply line and the reactor. Element 16: further comprising a propane vaporizer in fluid communication between a propane supply line and the reactor, wherein the propane vaporizer is configured to receive coolant from the reactor to vaporize propane and elevate its pressure. Element 17: wherein the coolant used to vaporize the propane is sent back to the reactor cooling jacket after it has passed through the propane vaporizer. Element 18: wherein the exhaust pipe is a heat exchanging exhaust pipe.
The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents, the definitions that are consistent with this specification should be adopted.
Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable.

Claims

What is claimed is:

1. A method of treating a wellbore in a subterranean formation comprising:

attaching a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore;

generating a heated inert gas using the inert gas generator, wherein the inert gas comprises CO₂and nitrogen;

placing the heated inert gas from the inert gas generator into the annular space;

circulating the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned;

combining at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and

delivering the matrix injection gas to the formation.

2. The method of claim 1, wherein the treating occurs in a substantially horizontal portion of the wellbore.

3. The method of claim 1, further comprising after the circulating step, pressurizing the near wellbore formation by partially closing a wing valve on the return to the surface for an abbreviated period of time, releasing the built-up pressure until the near wellbore return is at least partially clean; and incrementing the time of shut-in in similar abbreviated time increments and rapidly releasing pressure until the formation break-in pressure and a permeable flow rate are established.

4. The method of claim 1, wherein the well treatment chemicals are selected from the group consisting of aromatic solvents, acids, scale inhibitors, paraffin dispersants, oxygen scavengers, biocides, beneficial bacteria, nano-materials, foams and combinations thereof.

5. The method of claim 1, further comprising adding the inert treatment gas after the matrix injection gas to chase the matrix injection gas and force the matrix injection gas further into the formation to widely disperse the chemicals and other products.

6. The method of claim 1, wherein compressed air is run through the inert gas generator to convert the oxygen in the compressed air into CO₂.

7. The method of claim 1, further comprising a heat exchanger, wherein the heated inert gas is cooled in the heat exchanger before placing the heated inert gas into the annular space.

8. The method of claim 1, wherein the at least one well treatment chemical is atomized before combining it with the heated inert gas to form the matrix injection gas.

9. The method of claim 1, wherein the tubular element includes a downhole pump, the method further comprising circulating heated inert gas to liquefy paraffin in the tubular element, and lifting the paraffin to the surface for collection using the downhole pump.

10. The method of claim 1, wherein the formation comprises porous rocks and the matrix injection gas is applied to the rock face in the pores as a thin film.

11. The method of claim 10, wherein the thin film thickness is in the range of about 0.4 nm to about 80 nm.

12. A well treatment apparatus comprising:

an inert gas generator comprising:

a compressor configured to deliver compressed air to a reactor;

a reactor configured to receive compressed air from the compressor and to configured to generate an inert gas from compressed air;

an atomizer configured to receive inert gas from the reactor and atomize well treatment chemicals;

a pump configured to deliver well treatment chemicals to the atomizer; and

a controller configured to operate at least one of the compressor, reactor, pump, and combinations thereof.

13. The apparatus of claim 12, further comprising a heat exchanger in fluid communication with the reactor discharge and the atomizer.

14. The apparatus of claim 13, further comprising a flue gas booster in fluid communication with the reactor discharge and the atomizer inlet.

15. The apparatus of claim 12, wherein the atomizer comprises:

a vessel including

a pressure chamber;

an inert gas inlet;

a well treatment chemical inlet;

a manifold for distributing the well treatment chemicals;

nozzles along the manifold for atomizing the well treatment chemicals into the pressure chamber; and

an outlet for delivering the inert gas and atomized well treatment chemicals to the well.

16. The apparatus of claim 12, wherein the reactor can receive an exhaust pipe that slides inside the reactor body, wherein the exhaust pipe is between reactor and the atomizer.

17. The apparatus of claim 12, wherein the reactor comprises a cooling jacket surrounding a combustion chamber, wherein the cooling jacket contains coolant.

18. The apparatus of claim 12, further comprising a propane vaporizer in fluid communication between a propane supply line and the reactor.

19. The apparatus of claim 17, further comprising a propane vaporizer in fluid communication between a propane supply line and the reactor, wherein the propane vaporizer is configured to receive coolant from the reactor to vaporize propane and elevate its pressure.

20. The apparatus of claim 19, wherein the coolant used to vaporize the propane is sent back to the reactor cooling jacket after it has passed through the propane vaporizer.

21. The apparatus of claim 16, wherein the exhaust pipe is a heat exchanging exhaust pipe.

22. A well treatment system comprising:

a well treatment apparatus configured to:

attach a surface located inert gas generator to an annular space in a wellbore comprising a tubular element, wherein a cylindrical wall surrounds the tubular element in a manner that an annular space is formed between the tubular element and the cylindrical wall in the wellbore;

generate a heated inert gas using the inert gas generator, wherein the inert gas comprises CO₂and nitrogen;

place the heated inert gas from the inert gas generator into the annular space;

circulate the heated inert gas from the surface, down the annulus, and returning up through the tubular element back to the surface for a period of time until the tubular element has been at least partially cleaned;

combine at least one well treatment chemical with the heated inert gas to form a matrix injection gas, wherein the at least one well treatment chemical is at least one of suspended in the heated inert gas as droplets, in a vapor state of the chemical, and combinations thereof; and

deliver the matrix injection gas to the formation.