Methods for increase gas production and load recovery

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention relate to treating formations with compositions prior to, during, and / or after fracturing operations, where the treatment composition improves sand and particle control, improves charge recovery and well productivity, and reduces the contamination of the wellbore zone.

More specifically, embodiments of the present invention relate to treating a formation with a composition that can be applied before, added to the slickwater system, linear gel and crosslinked fracturing fluids, or used after fracturing operations, wherein the treatment composition comprises a phosphate / amine reaction product that improves control of sand, particles and particles, it improves the recovery of the well and the productivity of the well and reduces the incidence of the wellbore zone of fractured formations or the production of production formations in general.

2. Description of the Related State of Technology

Historically, the use of microemulsion systems to remove irrigation of the wellbore zone and increased gas production dates back to at least 1992. US Patent No. 5,310,002 shows microemulsion formulations and the use of microemulsions, where the surfactant blend is composed of ethoxylated alcohols, esters, alkylsulfonates, alkylphosphates, carboxylated tethoxylated tallow amines and where the solvent is composed mainly of mutual solvents such as ethylene glycol monobutyl ether. US Patent No. 6,911,417 shows microemulsion formulations and the use of microemulsions, where surfactant systems contain an alkyl polyglycoside, ethoxylated alcohols and a linear alkyl alcohol.

US Patent No. 7,380,606 discloses the use of a microemulsion for borehole repair comprising a surfactant and a solvent selected from the group of alkyl or aryl esters of short chain alcohols and terpenes.

US 2007/131425 discloses a method of controlling sand or particle migration comprising pumping a formation fluid at a speed and pressure sufficient to control the production or migration of sand and particles to production fluids, wherein the fluid comprises a composition comprising an amine reaction product and a phosphate containing compound resulting in increased gas production and improved charge recovery after fracturing.

US 2007/029085 concerns the prevention of irrigation of wellbore zones and the prevention of condensate retention in oil and gas production as well as the control of sand in underground formations and thereby increasing the production of e.g. gas. The wettability of water-gas-rock systems is determined by observing the contact angle formed by a drop of water on a rock with gas as the third phase.

US 2007/015669 discloses methods for treating underground formation to increase hydrocarbon (oil and / or gas) production from a wellbore in which contact angles are measured to determine the wettability of particles and for identifying suitable compositions to use such methods, e.g. controlling sand production.

Although many fracturing systems are known in the art, there is still a need in the industry for treatment compositions that improve sand and particle control, improve charge recovery and well productivity, and reduce hydration of the wellbore zone when fracturing formations using a fracturing composition including releasing formation water can inhibit gas or oil production by irrigating the wellbore zone. These treatment compositions work in all fracturing compositions such as slickwater systems, linear gel systems, crosslinked systems and / or microemulsion systems.

SUMMARY OF THE INVENTION

compositions

The present invention provides a particulate solid material such as particulates containing metal oxides having improved self-aggregation properties. Improved self-aggregation or aggregation propensity comes from the surface of the solid particles having a coating containing the reaction product of ester / phosphate acid and amine.

The present invention provides a particulate solid material such as metal oxide containing particulates having a coating comprising the reaction product of an amine and phosphate ester / acid, wherein the coating deforms under pressure and increases the aggregation propensity of the particulate.

The present invention also provides an aggregated particulate solid material such as a solid composition with a metal oxide including a solid particle comprising metal oxides coated with an amine and phosphate ester / acid reaction product, wherein the coating is deformable.

The present invention provides a substrate having surfaces completely or partially coated with a composition of the invention comprising an amine and phosphate ester / acid reaction product, where the coating is deformable and where the substrate is ideally suited to filter particles and / or other particulate materials from fluid, especially mining fluids oil / gas, completion, production, fracturing, filling, other processes that increase production or other related applications. The structures can be ceramic or ceramic fibers or wool coated partially or completely with the compositions of the invention. Such structures are well suited to filter materials for use with or without screens. Machining Method

The present invention provides a method of altering the potential or tendency to aggregate a particulate solid material such as metal oxide containing particulates, wherein the method comprises contacting the particulate solid material with a composition comprising an amine and an ester / phosphate acid under conditions sufficient for partial amine and phosphate ester / acid forming reaction or complete coatings on the surfaces of the particulate solid material.

Ways to apply machining methods

fracturing

The present invention provides a method of fracturing a formation, including the step of pumping a fracturing fluid containing a proppant into the production formation at a pressure sufficient to fracture the formation and increase productivity. wherein the proppant supports the open formation after fracturing and wherein the proppant contains solid particles treated with a treatment composition comprising an amine and an ester / phosphate acid under conditions sufficient for the amine and ester / phosphate acid to react to form a partial or complete coating on the surfaces of the particulate solid material.

The present invention provides a method of fracturing a formation, including the step of pumping a fracturing fluid comprising a proppant and an aggregating composition of the present invention into a production formation at a pressure sufficient to fracture the formation and increase productivity. The composition results in a modification of the aggregation propensity and / or zeta potential of the proppant, formation molecules and formation surface such that the formation molecules and / or proppant aggregate and / or adhere to the formation surface.

The present invention provides a method of fracturing a formation, including the step of pumping a fracturing fluid containing the aggregating composition of the present invention into a production formation at a pressure sufficient to fracture the formation and to increase productivity. The composition results in a modification of the aggregation propensity, potential, and / or zeta potential of the center of the formation molecules and the formation surface such that the formation molecules aggregate and / or adhere to the formation surface. The method may also include the step of pumping the proppant containing the coated particulate composition of the present invention after fracturing such that the coated particles support the open fractured formation and tend to aggregate to the surface of the formation and / or formation particles formed during fracturing.

Drilling

The present invention provides a drilling method comprising the step of circulating the drilling mud during drilling to provide drill lubrication, heat removal and removal of casing, wherein the drilling mud comprises an aggregation composition according to the invention. The composition increases the aggregation potential or propensity and / or changes the zeta potential of any solid particle containing metal oxides in the drilling mud or which is trapped in the drilling mud to increase particulate removal. The method can be carried out under overpressure or underpressure conditions or under managed pressure conditions. The method is particularly suitable for underpressure or managed pressure.

The present invention provides a drilling method comprising the step of circulating the first drilling mud during drilling to provide drill lubrication, heat removal and casing removal. When encountering an underground structure that produces undesirable amounts of solid particles, changing the first drilling mud to a second drilling mud containing the composition of the present invention to provide lubrication of the drill, removing heat and removing casing and to increase the aggregation potential or decrease the absolute zeta potential of any solid particles in the drilling mud or which are trapped in the drilling mud to increase the removal of solid particles. The method can be carried out under overpressure or underpressure conditions or under managed pressure conditions. The method is particularly suitable for underpressure or managed pressure.

The present invention provides a drilling method comprising the step of circulating the first drilling mud during drilling to provide drill lubrication, heat removal and casing removal. When encountering an underground structure that produces undesirable amounts of solid particles, changing the first drilling mud to a second drilling mud containing the composition of the present invention to provide lubrication of the drill, removing heat and removing casing and to increase the aggregation potential or decrease the absolute zeta potential of any solid particles in the drilling mud or which are trapped in the drilling mud to increase the removal of solid particles. After passing through a structure that produces undesirable amounts of solid particles, the change of the second drilling mud to the first drilling mud or the third drilling mud. The method can be carried out under overpressure or underpressure conditions or under managed pressure conditions. The method is particularly suitable for underpressure or managed pressure.

Production

The present invention provides a production method comprising the step of circulating and / or pumping fluid into a working well, wherein the fluid comprises a composition of the invention that increases the aggregation potential or reduces the absolute value of the zeta potential of any solid particle in the fluid or which is trapped in the fluid to increase particle removal solids and reduce the potential of particles to clog the formation and / or the mining duct.

The present invention also provides a method of controlling sand or particle migration including the step of pumping a fluid containing the composition of the present invention through a matrix at a speed and pressure into the formation to control the production or migration of sand and particles to production fluids.

The present invention also provides another method of controlling sand or particle migration including the step of placing the coated particulate solid material of the present invention against screen and sand type particle inspection devices such that sand and / or particles are attracted to coated particles and do not encounter or clog the screen of the device type OSD.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention can be better understood with reference to the following detailed description, accompanied by illustrative drawings in which similar elements are numbered the same:

Figure 1 is a photograph showing the untreated sand and sand scum treated with 5% v / w of the aggregating compositions designated SG-5 and SG-1, respectively;

Figure 2 depicts a flow diagram for a flow rate factor of 2 wt. KCl brine untreated sand and sand screed treated with 5% v / w ten aggregating compositions of the present invention designated SG-1 to SG-5; and

Figure 4 depicts a diagram of the liquid passage device used in the present invention.

Figure 5 depicts a diagram of the gas passage device used in the present invention.

Figure 6 depicts the graph of relative permeability vs. amounts of volumes of porous gas for various treatment compositions.

Figure 7 is a graph of liquid removed from the core by gas displacement vs. number of porous gas volumes for various treatment compositions.

Figures 8A & B illustrate a diagram of contact angle and droplet configuration, and replicates for the data in Table 7 showing the direction of improving properties.

Figure 9 is a graph of relative permeability vs. number of porous gas volumes for untreated and treated core samples.

Figure 10 is a graph of flow rate recovery vs. number of porous gas volumes for untreated and treated core samples.

Figure 11 is a graph of rheological data for the Magnum Frac H system with the additive of the invention designated Appendix 1.

Figure 12 is a graph of rheological data for the DynaFrac HT system with added

Appendix 1.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have found that the composition can be prepared that, when added to solid particles containing metal oxides or other solid materials, or to a suspension or dispersion containing solid particles containing metal oxides or other solid materials, the particles are modified such that the tendency to aggregate is changed. aggregation and / or zeta potential of the particles. The inventors have also discovered that solid particles containing metal oxides or other solid particles having modified surfaces or parts thereof can be produced, where the modified particles have improved tendencies and / or aggregation tendencies or change the zeta potential of the molecules. The inventors have also discovered that compositions and / or modified solid particles containing metal oxides or other solid particles can be used in oil field applications including drilling, fracturing, manufacturing, injection molding, sand control or any other downhole application. The inventors have also discovered that modified solid particles containing metal oxides or particles of any other solid material can be used in any other application where increased aggregation potentials of particles or reduced absolute zeta potentials of particles are desired, which is a means of aggregation propensity. The inventors have also found that compositions comprising coated particulates containing metal oxides can be formed, where the coating is deformable and the coated particles tend to self-aggregate and tend to stick to surfaces having similar coatings or having similar chemical and / or physical properties to those coatings . It is that the coated particles tend to prefer similar compositions that increase their self-aggregation tendencies and increase their ability to stick to surfaces that have similar chemical and / or physical properties. The inventors have found that the coating compositions of the present invention have similar chemical and / or physical properties to these coatings. It is that the coated particles tend to prefer similar compositions that increase their self-aggregation tendencies and increase their ability to stick to surfaces that have similar chemical and / or physical properties. The inventors have found that the coating compositions of the invention are different from known compositions for modifying the aggregation propensity of particles and that the coated particles are ideally suited as proppants, where the particles have changed zeta potentials that change the charge on the particles causing them to attract and agglomerate. Changing the zeta potential or tendency to aggregate causes that each molecule has an increased friction resistance holding the proppant in the gap. The compositions are also ideally suited for reducing the migration of particles to the gap backfilling or for reducing the adverse effect of the migration of particles to the gap backfilling.

New Disclosure

The use of aggregating proppant systems that, when added to water / gel solutions and pumping down the well, apart from coating the proppant will also coat the surface of the formation, changing the wettability more towards neutral values. This effect changes the conditions of the trapped water so the water can be displaced constantly in a more piston way.

Essentially, the difference of this approach to the current use of microemulsions is that this solution uses, among others, alkylpyridine phosphate ester systems that permanently coat any metal oxide surface than a small oil layer that coatings metal oxide systems circumferentially.

Original Disclosure

In the case of drilling, the compositions of the invention can be used to coat formations and cuttings of the formation during drilling, because the particles tend to self-aggregate and / or stick to similar modified formation surfaces. Again, the benefit of self-aggregation is the reduced tendency of the cuttings to clog or clog the screens. Additional benefits are coating the walls of the formation with the composition of the present invention during drilling to consolidate the formation and consolidation or aggregation of particles or particles in the drilling mud to maintain the rheological properties of the drilling mud before changing and increasing the circular replacement density (ECD).

compositions

The invention broadly relates to a composition comprising an amine and an ester / phosphate acid. The composition modifies the surfaces of solid materials or parts thereof, changing the chemical and / or physical properties of the surface. The altered properties allow surfaces to become self-attractive or allow surfaces to attract material with similar chemical and / or physical properties. For particles containing metal oxide particles such as silica, alumina, titanium dioxide, magnesium oxide, zirconia, other metal oxides or oxides containing a mixture of these metal oxides (natural and synthetic), the composition forms a complete or partial coating on the surfaces of the particles. The coating may interact with the surface through chemical and / or physical interactions including, but not limited to, chemical bonds, hydrogen bonds, electrostatic interactions, dipolar interactions, hyperpolarizability interactions, cohesion, adhesion, adhesion, mechanical adhesion or any other chemical and / or physical interaction that allows the formation of a coating on the particles. The coated particles have a greater tendency to aggregate or agglomerate than the uncoated particles. Thus, the particles may be free flowing prior to processing, whereas after coating they do not flow freely but tend to aggregate, aggregate or agglomerate. In cases where the composition is used to coat the surface of a geological formation, a synthetic metal oxide structure and / or metal oxide containing particles, the particles will not only tend to aggregate together, the particles will also tend to stick to the coated formation or structural surfaces.

Machined Structures and Substrates

The present invention also extensively relates to structures and substrates treated with the compositions of the invention, wherein the structures and substrates include surfaces that are partially or completely coated with the composition of the present invention. Structures or substrates can be ceramic or metal or fibrous. Structures or substrates can be spun like glass wool or steel wool or can be cellular like catalytic converters or the like that contain channels that force fluid to flow through forced paths so that fluid particles are forced to contact substrate or structural surfaces . Such structures or substrates are ideally suited as particle filters or sand control carriers.

Ways of machining solid particles

The present invention broadly relates to a method of treating metal oxide containing surfaces comprising the step of contacting a metal oxide containing surface with a composition of the present invention. The composition creates a coating on the surface by changing the surface properties so that the surface can now interact with similarly treated surfaces to form agglomerated and / or aggregated structures. Machining can be designed to continuously coat surfaces containing metal oxides and / or surfaces of particles containing metal oxides. If both are treated, then the particles can not only self-aggregate, but the particles can also aggregate, agglomerate and / or adhere to coated continuous surfaces. The compositions can be used in fracturing fluids, in drilling fluids, in finishing fluids, in sand control applications or other in-depth applications. In addition, coated particles can be used in fracturing fluids. Furthermore, structures, screens or filters coated with the compositions of the present invention can be used to attract and remove particles that have been modified with the compositions of the present invention.

Fracturing and / or Propping method

The present invention broadly relates to methods of fracturing a formation, including the step of pumping a fracturing fluid containing a composition of the invention into a production formation at a pressure sufficient to fracture the formation. The composition modifies the aggregation and / or zeta potential of the formation particles and the formation surface during fracturing so that the formation particles aggregate and / or adhere to the formation surface or to each other increasing fracturing efficiency and increasing fracturing formation productivity. The composition of the present invention can also be used at the stage of pre-surfacing to modify the surface of the formation so that during fracturing the surfaces of the formation are pre-coated. The pre-surfacing step involves pumping formation fluid before processing to begin fracturing and exposing the formation surface to fluids intended to protect the formation. In addition to only using the composition as part of the fracturing fluid, the fracturing fluid may also contain particles that have previously been treated with the composition of the present invention, where the treated particles act as proppants to support the open formation after fracturing. If the fracturing fluid also contains the composition, the proppant in the form of coated particles will adhere to the surface of the formation to a greater extent than an proppant in the form of uncoated particles would.

In an alternative embodiment of the present invention, the fracturing fluid comprises particles coated with the composition of the present invention as a proppant. In this embodiment, the particles have a greater tendency to self-aggregation and will tend to aggregate in places that may most need support as open. In all fracturing applications containing proppants coated or coated with the composition of the present invention during fracturing, the coated proppants are likely to have improved formation penetration and adhesion properties. These greater penetration and adhesion or adhesion properties are caused not only by the difference in the surface chemistry of the molecules relative to the surface chemistry of the untreated particles, but also by the deformability of the coating itself. Thus, the inventors believe that when the particles are forced into the formation, the coating will deform to allow the particles to penetrate into place and when pressure is removed, the particles will tend to remain in place due to the interaction of the coating with the surface and due to deformation relaxation shell. In addition, the inventors believe that the altered propensity of particles to aggregate will increase the density of proppant molecules in areas of formation most susceptible to penetration of the proppant, resulting in increased formation support.

Drilling method

The present invention also extensively relates to a drilling method comprising a drilling mud circulation step during drilling to provide drill lubrication, heat removal and casing removal, where the drilling mud comprises a composition of the invention that increases the aggregation potential or reduces the absolute value of the zeta potential of any solid particles in the drilling mud. or which are trapped in the scrubber to increase particulate removal.

The present invention also extensively relates to a drilling method comprising the step of circulating the first drilling mud during drilling to provide drill lubrication, heat removal and removal of casing. When encountering an underground structure that produces undesirable amounts of solid particles containing solid particles containing metal oxides, changing the first drilling mud to a second drilling mud containing the composition of the invention to provide lubrication of the drill, removing heat and removing casing and for increasing the aggregation potential or decreasing the absolute value of the zeta potential of any solid particles including solid particles containing metal oxides in a drilling mud or which are trapped in a drilling mud to increase particulate removal.

The present invention also extensively relates to a drilling method comprising the step of circulating the first drilling mud during drilling to provide drill lubrication, heat removal and removal of casing. When encountering an underground structure that produces undesirable amounts of solid particles containing solid particles containing metal oxides, changing the first drilling mud to a second drilling mud containing the composition of the invention to provide lubrication of the drill, removing heat and removing casing and to increase the aggregation or zeta potential of any solid particle including a solid particle containing metal oxides in a drilling mud or which is trapped in a drilling mud to increase particulate removal. After passing through a structure that produces undesirable amounts of solid particles containing metal oxides, changing the second drilling mud to the first drilling mud or the third drilling mud.

Production method

The present invention also extensively relates to a production method comprising circulating and / or pumping fluid, wherein the fluid comprises a composition of the present invention, which increases the aggregation potential or decreases the absolute value of the zeta potential of any particulates including particulates containing metal oxides in a fluid or that are trapped in a fluid to increase particulate removal and to reduce the potential of particles to clog the formation and / or the mining conduit.

Appropriate Measures

Suitable amines include, but are not limited to, any amine that is capable of reacting with the appropriate phosphate ester / acid to form a composition that forms a deformable coating on the surface containing the metal oxide. Exemplary examples of such amines include, but are not limited to, any of the amines of general formula R¹R²NH or mixtures or combinations thereof, where R¹ and R² are independently a hydrogen atom or a carbyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to meet valence and where one or more carbon atoms can be replaced by one or more heteroatoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus . sulfur or mixtures or combinations thereof and where one or more hydrogen atoms can be replaced by one or more monovalent atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof. Exemplary examples of amines suitable for use in the present invention include, but are not limited to, aniline and alkylanilines or mixtures of alkylanilines, pyridines and alkylpyridines or mixtures of alkylpyridines, pyrrole and alkylpyrroles or mixtures of alkylpyrrole, piperidine and alkylpiperidine or mixtures of alkylpiperidine, pyrrolidine and alkylpyrrolidine and alkylpyrrolidine or mixtures of alkylpyrrolidines, indole and alkylindoles or mixtures of alkylindoles, imidazole and alkylimidazole or mixtures of alkylmidazoles, quinoline and alkylquinoline or mixtures of alkylquinolines, isoquinoline and alkylisoquinoline or mixtures of alkylisoquinolines, pyrazine and alkylpyrazine or mixtures of alkylpyrazine, quinoxaline and alkyl quinidine, and mixtures of alkylquinidine and mixtures of alkylquinidine, and alkylquinazoline or alkylquinazoline mixtures, or mixtures or combinations thereof.

Suitable phosphate-containing compounds include, but are not limited to, any phosphate acid and / or any phosphate ester that is capable of reacting with a suitable amine to form a composition that forms a deformable coating on the metal oxide-containing surface or partially or completely coatings materials molecular. Exemplary examples of such phosphate esters include, but are not limited to, any phosphate esters of general formula P (O) (OR³) (OR⁴) (OR⁵) or mixtures or combinations thereof, where R³, R⁴, and OR⁵ are independently a hydrogen atom or a carbyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to meet valence and where one or more carbon atoms can be replaced by one or more heteroatoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus . sulfur or mixtures or combinations thereof and where one or more hydrogen atoms can be replaced by one or more monovalent atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof. Exemplary examples of phosphate esters include, but are not limited to, alkanol phosphate ester having the general formula P (O) (OH) x (OR⁶) y where x + y = 3 and are independently a hydrogen atom or a carbonyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to meet valence and where one or more carbon atoms can be replaced by one or more heteroatoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, sulfur or mixtures or combinations thereof and where one or more hydrogen atoms can be replaced by one or more monovalent atoms selected from the group consisting of fluorine, chlorine, bromine, iodine or mixtures or combinations thereof such as ethoxyphosphate, propoxyphosphate, or higher alkoxyphosphates or mixtures or combinations thereof. Other examples of phosphate esters include, but are not limited to, alkanolamine phosphate esters having the general formula N [R⁷OP (O) (OH) 2] 3 where R⁷ is a carbenyl group having between about 1 and 40 carbon atoms and the required hydrogen atoms to meet valence and where one or more carbon atoms can be replaced by one or more heteroatoms selected from the group consisting of boron, nitrogen, oxygen, phosphorus, or sulfur thereof mixtures or combinations and wherein one or more hydrogen atoms can be replaced by one or more monovalent atoms selected from the group consisting of fluorine, or phenol phosphate esters. Other exemplary examples of phosphate esters include, but are not limited to, phosphate esters of diols and polyols such as phosphate esters of ethylene glycol, propylene glycol, or higher glycol structures. Other exemplary phosphate esters include any phosphate ester that can react with an amine and when coated with a substrate forms a deformable coating that increases the aggregation potential of the substrate. Exemplary phosphate acids include phosphoric acid, polyphosphoric acid, or mixtures thereof.

Suitable particulate materials suitable for coating the compositions of the present invention include, but are not limited to, metal oxides and / or ceramic, natural or synthetic sinters, metals, plastics, and / or other polymeric solid particles, materials in the form of plant particulates, or any other solid material that has or can be used in downhole applications, or mixtures or combinations thereof. Metal oxides include any solid oxide of the metal element from the periodic table. Exemplary metal oxides and / or ceramic sinters include actinium oxides, aluminum oxides, antimony oxides, boron oxides, barium oxides, bismuth oxides, calcium oxides, cerium oxides, cobalt oxides, chromium oxides, cesium oxides, copper oxides, dysprosium oxides, erbium oxides , europium oxides, gallium oxides, germanium oxides, iridium oxides, iron oxides, lanthanum oxides, lithium oxides, magnesium oxides, manganese oxides, molybdenum oxides, niobium oxides, neodymium oxides, nickel oxides, osmium oxides, palladium oxides, potassium oxides, prometoxides, praseodymium oxides, platinum oxides, rubidium oxides, rhenium oxides, rhodium oxides, ruthenium oxides, scandium oxides, selenium oxides, silicon oxides, samarium oxides, silver oxides, sodium oxides, strontium oxides, tantalum oxides, terbium oxides , tellurium oxides, thorium oxides, tin oxides, titanium oxides, thallium oxides, tulle oxides, vanadium oxides, tungsten oxides, yttrium oxides, ytterbium oxides, zinc oxides, zirconium oxides, ceramic structures made from one or more of these oxides and mixed metal oxides containing two or more of the metal oxides mentioned above. Exemplary examples of plant materials include, but are not limited to, seed shells containing plants such as nut shells, pecans shells, peanut shells, shells of other hard-shelling seeds forming plants, abrasion or other fibrous cellulosic materials, or mixtures or combinations thereof.

EXPERIMENT ACCORDING TO THE INVENTION

Example 1

This example illustrates general procedures used in the preparation and testing of sand treated with the aggregation composition of the present invention.

700 grams of sand 0.853 / 0.422 mm (20/40) was mixed on a pallet at 1000 rpm in distilled water containing 2 wt. KCl in a sand to solution solution of 0.12 g cm-3 (1 lh / gal) for 15 minutes. The aggregating composition of the present invention was then added to the sand slurry at a concentration of 0 to 8 gptg. The resulting suspension was stirred for 15 minutes at 1000 rpm. The treated sand slurry was then poured into a PVC flow rate cylinder and washed with at least 5 volumes of fresh 2 wt. KCl. The flow rate of the 2 wt.% Solution was then measured. KCl by the received treated sand backfill.

Example 2

This example illustrates another set of general procedures used in the preparation and testing of sand treated with the aggregation composition of the present invention.

700 grams of sand 0.853 / 0.422 mm (20/40) was pre-treated with the aggregating composition of the present invention at a concentration of 1.5, 3.0 and 5.0% v / w. The composition was mixed into dry sand using a spatula for 5 minutes. After dry mixing, a 2.0 wt.% Solution was added. KCl by mixing. The resulting slurry of treated sand was poured into a PVC flow rate cylinder and washed with at least 5 volumes of 2.0 wt. KCl. The flow rate of the 2 wt.% Solution was then measured. KCl by sand backfilling.

The following aggregating compositions were prepared and tested according to the procedures described in Examples 1 and 2.

<td colspan="2">SG-1</td>

<td>components</td><td>wt%</td>

<td>Akolidine 11 (a mixture of alkylpyridines from Lonza, Inc. z / s in NJ)</td><td> 42.46</td>

<td>Phosphate ester formed from 54 wt. polyphosphoric acid, 32 wt. triethanolamine and 14.18 wt. water</td><td> 13.31</td>

<td>methanol</td><td> 44.23</td>

<td colspan="2">SG-2</td>

<td>components</td><td>wt%</td>

<td>Coconut Benzylamide</td><td> 13.83</td>

<td>Genamin T150 (Ethoxylated Amine)</td><td> 10.35</td>

<td>Non-Phenyl Phosphate Ester</td><td> 5.22</td>

<td>Crude Tall Oil</td><td> 3.15</td>

<td>Quaternary Ammonium Chloride</td><td> 57.45</td>

<td>Demulsifier (CIM 940)</td><td> 9</td>

<td>Alkylphenol oxyalkaline resin (DRC 168)</td><td> 1</td>

<td colspan="2">SG-3</td>

<td>components</td><td>wt%</td>

<td>Coconut Benzylamide</td><td> 15.37</td>

<td>Genamin T150 (Ethoxylated Amine)</td><td> 11.5</td>

<td>Non-Phenyl Phosphate Ester</td><td> 5.8</td>

<td>Crude Tall Oil</td><td> 3.5</td>

<td>Quaternary Ammonium Chloride formed from 49 wt. Akolidine 11 (a mixture of alkylpyridines from Lonza, Inc.), 25 wt. Benzyl chloride and 26.08 wt. methanol</td><td> 63.83</td>

<td colspan="2">SG-4</td>

<td>components</td><td>wt%</td>

<td>Quaternary Ammonium Chloride formed from 49 wt. Akolidine 11 (a mixture of alkylpyridines from Lonza, Inc.), 25 wt. Benzyl chloride and 26.08 wt. methanol</td><td> 42.26</td>

<td>Phosphate ester formed from 54 wt. polyphosphoric acid, 32 wt. triethanolamine and 14.18 wt. water</td><td> 13.31</td>

<td>methanol</td><td> 44.23</td>

<td colspan="2">SG-5</td>

<td>components</td><td>wt%</td>

<td>SG-2</td><td> 42.46</td>

<td>methanol</td><td> 44.23</td>

<td>Phosphate ester formed from 54 wt. polyphosphoric acid, 32 wt. triethanolamine and 14.18 wt. water</td><td> 13.31</td>

Zeta Potential Measurements

The zeta potential is defined by the charge that appears on the interface between solid surfaces. The zeta potential is therefore a function of the surface charge of the molecule, any adsorbed layer on the interface, and the nature and composition of the surrounding suspension carrier. In other words, the potential can be affected by (1) changes in pH, (2) carrier conductivity (salinity and type of salt), and (3) the concentration of specific additives (polymer, non-ionic surfactants, etc.).

To obtain Zeta Potential using a Zetasizer (Nano) Z analyzer from Malvern by microelectrophoresis, the system must have solid particles or colloids in the range between 3 nm and 20 μm. To characterize the effect of various additives in the system, Quartz Flour was used instead of 0.853 / 0.422 mm (20/40) sand.

The amount of quartz flour was set to 0.01 g cm^-3 (0.25 ppg) to reduce the effects of settling during test measurements. On the other hand, the only way to get well-defined peaks (as narrow as possible) was to add KCl at concentrations of 0.5% or less.

Table 1 shows the results of the effect of the SG-1 additive on the measured Zeta Potential values ​​when the additive was added to the Quartz Flour suspension with stirring. It was found that the Zeta Potential values ​​changed over time indicating that the increased exposure time allowed the additive to be absorbed on the particle. Although the measured Zeta Potential values ​​were well in the range between -30 and 30 mV, the measurements were not considered reliable when the standard deviations were greater than 250 mV.

TABLE 1

<td colspan="3">Potentials of Zeta-treated Sand SG-1</td>

<td>SG-1 concentration (Pptg)</td><td>Average Zeta Potential (mV)</td><td>Zeta Potential Deviation (mV)</td>

<td> 0</td><td> -47.8</td><td> 38.1</td>

<td> 2</td><td> 4.13</td><td> 377.6*</td>

<td> 4</td><td> -0.6</td><td> 276.9*</td>

<td> 6</td><td> 2.52</td><td> 419.4*</td>

<td colspan="3">* Phase behavior of Zeta Potential measurements was insufficient giving a high deviation of Zeta potential.</td>

<td colspan="2">Final pH 6.16-6.22</td><td></td>

Flow Backfill Sand Test

The influence of sand-catching additives in the flow of 2% KCl solution through pre-treated sand 0.853 / 0.422 mm (20/40) was determined.

Table 2 shows the lack of SG-1 sand pre-treatment effect in 2% KCI brine flow.

TABLE 2

<td colspan="3">Measurements of Sand Speed ​​Through Sand Treated with SG-1</td>

<td>SG-1 concentration (gptg)</td><td>Average flow rate (ml / min)</td><td>Flow Rate Factor (Treatment / Non-treatment)</td>

<td> 0</td><td> 387</td><td> 1.00</td>

<td> 2</td><td> 461</td><td> 1.03</td>

<td> 4</td><td> 419</td><td> 1.08</td>

<td> 8</td><td> 408</td><td> 1.05</td>

Impact of sand pretreatment in dry conditions

The effect of aggregating additives in the flow of a 2% KCI solution through pre-treated 0.853 / 0.422 mm (20/40) sand was determined. In this case, the sand was pre-processed dry before mixing with the 2.0% KCl solution. The sand slurry was then poured into a plastic cylinder and washed with 5 volumes of 2% KCl solution. Then, the flow velocity through the sand bed was measured using a brine solution.

Table 3 shows the effect of SG-1 to SG-5 additives in brine flow after adding to dry sand at a concentration of 5% v / w. In this case, it was observed that only pre-processed sand with SG-1 and SG-5 showed a clear immediate increase in flow rate through the sand system. After mixing dry sand with 5% v / w SG-1 and SG-5, a clear increase in the height of the sand covering was also observed as shown in Figure 1.

Referring now to Figure 2, sand treatment with 5% v / w SG-1 and SG-4 showed the appreciated increase in the flow rate of the 2% KCl solution after initial and after 15 hours of treatment compared to untreated sand. The treatment with SG-2, SG-3 and SG-5 showed a small difference in the flow velocity factor compared to untreated sand.

Referring now to Figure 3, changes in Zeta Potential by adding SG-1 to SG-5 are shown after adding to dry quartz flour and subsequent measurement at 0.03 g cm^-3 (0.25 ppg) quartz flour in a 0.5% KCl solution. In this case, as expected, SG-1 and SG-4 not only show Zeta Potential values ​​between 20 and -20 mV, but also the lowest standard deviation in the measurement.

TABLE 3

<td colspan="5">Measurements of Flow Speed ​​Through Pre-treated Sand</td>

<td>Processing agent</td><td>Average Flow Speed immediately (after 15 h) (mL / mm)</td><td>Flow Rate Coefficient treated / untreated immediately (after 15 hours)</td><td>Potential Zeta^/(MV)</td><td>Observation</td>

<td>Control</td><td> 352 (352)</td><td> 1.00 (1.00)</td><td> -47.85 ± 38.19</td><td></td>

<td>SG-1</td><td> 480 (500)</td><td> 1.36 (1.42)</td><td> -11.72 ± 13.81</td><td>increase in the height of the backfill</td>

<td>SG-2</td><td> 367 (333)</td><td> 1.03 (0.94)</td><td> 9.9 ± 55.5</td><td></td>

<td>SG-3</td><td> 375 (353)</td><td> 1.06 (1.00)</td><td> 13.28 ± 71.83</td><td></td>

<td>SG-4</td><td> 467 (467)</td><td> 1.32 (1.32)</td><td> 17.72 ± 15.99</td><td>increase in the height of the backfill</td>

<td>SG-5</td><td> 352 (342)</td><td> 1.00 (0.97)</td><td> 11.28 ± 61.75</td><td></td>

<td colspan="5">/ In 0.03 g cm^-3 (0.25 ppg) Quartz flour and 0.5% KCl solution</td>

NEW EXPERIMENTAL PART

GOAL

The charge recovery properties were assessed by sand and core backfill tests using commercial and experimental microemulsions, fluorosurfactants as well as

Appendix 1.

Appendix 1

Appendix 1 is a composition containing the following list of components in the indicated amounts as shown in Table 4.

TABLE 4

<td colspan="2">Ingredients and Weight Percentages for Appendix 1</td>

<td>components</td><td>wt%</td>

<td>Akolidine 11⁺</td><td> 59.0</td>

<td>Phosphate Ester *</td><td> 8.3</td>

<td>methanol</td><td> 32.7</td>

<td colspan="2">⁺alkylpyridine mixture available from Lonza, Inc. z / s in NJ^/ Reaction product 78.50 wt. polyphosphoric acid and 21.50 wt. triethanolamine Appendix 1</td>

<td>is similar in composition to SG-1 above.</td><td></td>

The results were used to correlate changes in the contact angle in Berea sandstone as well as the measured surface tension to the type of treatment composition used.

BACKGROUND

Injecting aqueous solutions during stimulation treatments, whether in matrix stimulation or fracturing conditions, will increase water saturation and reduce the relative permeability to oil / gas in the acquired zone of the treated tank. The return of oil / gas permeability to baseline depends on how effectively invasive fluids can be purified.

Historically, surfactants have been added to stimulation treatments to accelerate fluid recovery and minimize damage to relative permeability. It has been shown that the efficiency of level reduction and / or oil / gas recovery directly depends on the amount of capillary pressure. The data indicate that the lower the capillary pressure, the higher the charge recovery will be.

In a gas well, capillary pressure (Pc) can be determined by the LaPlaceYoung equation

Ρ_Γ = 2 ecos U.

where σ is the liquid-vapor interfacial tension (surface tension), 0 is the contact angle between the liquid and the surface of the solid particles and Rc is the curvature factor in the porous matrix.

To reduce capillary pressure in gas wells, historically, the surface tension variable has been reduced to 20-30 dyne / cm using conventional hydrocarbon surfactant and fluorosurfactants. Recently, interest has been paid to the use of microemulsions or wetting systems that are designed to change the contact angle between the substrate (mainly silicate) and injected water closer to 90 degrees so water can be displaced more piston resulting in reduced water saturation and higher gas relative permeability.

CONCLUSIONS

Of 18 commercial and experimental charge recovery systems, Appendix 1 and the WNE-348LN Microemulsion gave the highest brine flow through sand backfill 0.853 / 0.422 mm (20/40), the highest relative permeability at different porous volumes of injected gas in 50 mD Berea Sandstone and higher porous volumes of liquid collected in core infiltration tests.

Assessments of Berea Sandstone treatment with Appendix 1 increased the contact angle to 56.8 ° whereas when treated with Berea Sandstone with WNE-348LN, the contact angle increased to only 30.3 °. The contact angle of the untreated core was 18.5 °.

Appendix 1 changes the contact angle of the formation surface to a wettability value that is closer to the neutral wettability value than surfaces would have if not treated with Appendix 1. This change in wettability value towards the neutral wettability value is accompanied by an increase in gas production, a fall in the wellbore zone and improved formation charge recovery after fracturing operations. The reaction products of the present invention, such as Appendix 1, form a deformable coating, total or partial, on the formation surfaces change contact angle values, wettability values, zeta potential values ​​and other related surface properties. These altered properties not only allow improved gas and water production, the surface tends to attract particles, particles, and proppants with or without prior treatment with reaction products, so that the particles, particles and / or proppants adhere to the surface of the formation reducing migration of particles (sand), particles, and / or proppants acting as a sand control treatment, while improving the fluidity of water and gas through the formation and into the production fluids and mining line.

PROCEDURE

Sand Powder Tests

The treated and untreated sand was tested by mixing 700 grams of Badger 0.853 / 0.422 mm (20/40) sand in suspensions with a concentration between 0.5 and 3 gal / Mgal of charge recovery additive in 2% KCl in salt water.

The sand was poured into a transparent PVC plastic cylinder (internal diameter 3.8 cm (1.5 inches) and length 56 cm (22 inches)), where at the other end the slotted plate only allows the passage of liquids and particles.

After washing with at least 10 porous volumes of 2% KCl, the flow rates by gravity through the sand backfill were compared for various test treatments.

Core Failure Tests

Core tests were performed in Berea sandstone cores with a N2 permeability of 50-55 mD. The core itself had a diameter of 3.8 cm (1.5 inches) and a length of 8.9 cm (3.5 inches).

Tests were started by measuring the brine permeability at a flow rate of 120 cc / min until 5 porous volumes were collected and the flow mode checked according to Darcy's law.

The nitrogen flow was started at a differential pressure of 6.89 x 10⁴ Pa (10 psi) recording the liquid collected at the other end of the core as well as the gas flow rate for two hours.

Liquid saturation was then restored by injecting 5 porous volumes of treated brine with a charge recovery agent.

Then the nitrogen flow was resumed with a differential pressure of 6.89 x 10⁴Pa (10 psi) measuring the collected liquid and gas flow velocity at the other end of the core.

In all tests, the overburden pressure was set in the radial and axial direction of 6.89 x 10⁶ Pa (1000 psi) and temperature at 21 ° C (70 ° F).

Determination of Surface Tension / Contact Angle

The contact angle and surface tension were determined.

Saturation Restoration

In preparation for measuring wettability, Berea core samples were saturated with a representative formation fluid. In this study, a 3% KCL solution was selected as the representative or control fluid.

To ensure complete sample saturation, selected cores were placed in a pressure chamber with multiple access ports. One port was connected to a vacuum source, and the other port was connected to a saturation fluid source. This sealed pressure vessel was placed under vacuum for 8 hours to ensure that all air was removed from the vessel. After 8 hours of emptying, prepared impregnation liquid was filled in to fill the pressure vessel. After the pressure vessel was filled with saturation fluid, the fluid pressure was gradually increased to 1000 psig and allowed to stabilize under pressure for 4 hours. At the end of this stabilization time, the chamber pressure was slowly reduced and after compression, the samples were removed and stored in the saturation fluid until testing was performed.

Wetting angle measuring equipment / IFT

Contact angle and / or surface tension (IFT) measurements were carried out using a Kruss DSA 100 camera. This device was equipped with proprietary software for capturing contact angle and IFT data. The range and accuracy of the contact angle measurement are from 0 ° to 180 ° with a resolution of +/- 0.1 °. IFT measurements were from 1x10^-2 up to 100mN / m with a resolution of 0.01mN / m. This equipment also provided digital imaging.

Contact angle measurement

For this study, contact angle measurements were made at 20 ° C. The following procedures were used to measure contact angles: (1) DSA 100 was calibrated before testing; (2) the saturated core plug was placed in a non-reflective, non-distorting glass container filled with saturation fluid or a selected fluid; (3) with a syringe, a drop of droplet fluid (mineral oil) was placed on the surface of the substrate selected to represent the state in situ; (4) the zoom and focus of the camera were set so that a clear image without obstacles was shown on the monitor; and (5) the drops were allowed to stabilize for a short period of time and when the drop became stable, the contact angle of the drop was captured and the contact angle was measured using proprietary software. Contact angle was measured using the YoungLaplace method.

Phase-to-phase voltage measurement

Phase-to-phase voltage data for this study was also measured at 20 ° C. The surrounding phase for this IFT measurement system was air. The following procedures were used in IFT measurements: (1) DSA 100 was calibrated before testing; (2) using a syringe from the DSA 100 apparatus, a sample fluid drop for IFT measurement was injected onto the test surface; (3) the zoom and focus of the camera were set so that a clear image without obstacles was shown; (4) when the drop stabilized, the parameters of the fluids, the droplet phase and the surrounding phase were entered into the DSA 100 software and IFT calculated with the image of the droplet taken. The method used for IFT measurements was known as the Pendant Drop technique.

With reference to Figure 4, a diagram of a Core Testing Apparatus for determining liquid permeability is shown, while Figure 5 is a diagram of a Core Testing Apparatus for determining gas permeability.

RESULTS

Table 5 compares the effect on the flow rate of 2% KCl through 0.853 / 0.422 mm (20/40) sand backfill after pretreatment with 1 gal / Mgal microemulsion from Magnablend (MB1, MB2, MB3, MB4), microemulsion with March (W- 32, W-32MB, W-32MB2) and our current WNE-348LN commercial product from Weatherford. After treatment with the charge recovery agent of the present invention and washing with 5 porous volumes of 2% KCl brine, the only system that showed an increase in flow rate through the sand bed by 10% or more was the WNE-348LN Microemulsion.

TABLE 5

<td colspan="3">Comparison of Flow Speed ​​Through 700 gr of Sand Backfill Column (20/30) Using Different Microemulsion Systems with Pre-treated Sand Slurry</td>

<td>Treatment</td><td>Fi (%) ^f</td><td>F₂4(%)*</td>

<td>Starting material (2% KCl)</td><td>343 mL / min (0%)</td><td>324 mL / min (0%)</td>

<td>Starting material + 1 gal / Mgal MB1</td><td>324 mL / min (-6%)</td><td>318 mL / min (-2%)</td>

<td>Starting material + 1 gal / Mgal MB2</td><td>327 mL / min (-5%)</td><td>327 mL / min (1%)</td>

<td>Starting material + 1 gal / Mgal MB3</td><td>330 mL / min (-4%)</td><td>330 mL / min (2%)</td>

<td>Starting material + 1 gal / Mgal MB4</td><td>333 mL / min (-3%)</td><td>290 mL / min (-10%)</td>

<td>Starting material + 1 gal / Mgal W-32</td><td>330 mL / min (-4%)</td><td>333 mL / min (3%)</td>

<td>Starting material + 1 gal / Mgal W-32MB</td><td>318 mL / min (-7%)</td><td>310 mL / min (-4%)</td>

<td>Starting material + 1 gal / Mgal W-32MB2</td><td>333 mL / min (-3%)</td><td>343 mL / min (6%)</td>

<td>Starting material + 1 gal / Mgal WNE-348LN</td><td>387 mL / min (13%)</td><td>371 mL / min (15%)</td>

+ Initial Flow Rate (Percentage increase compared to Untreated) tFlow Rate after 24 hours (Percentage increase compared to Untreated)

Table 6 compares the effect on the flow rate of 2% KCl through 0.853 / 0.422 mm (20/40) sand after pre-treatment with Dupont fluorosurfactants (Amphoteric Zonyl® FS-500, non-ionic Zonyl® FSH and Ethoxylated non-ionic Zonyl® FSO) and Fluorosurfactant with 3M (polymer fluoroaliphatic ester FC-4430 and FC-4432). In this case, only after treatment with 2 gal / Mgal FSO an increase in flow rate of 10% or more was observed compared to untreated sand backfill.

TABLE 6

<td colspan="3">Comparison of Flow Speed ​​Through 700 gr (20/30) Sand Backfill Columns Using Different Fluorosurfactant Systems with Pretreated Sand Slurry</td>

<td>Treatment</td><td>Fr / or</td><td>F₂4(%)*</td>

<td>Starting material (2% KCl)</td><td>313 mL / min (0%)</td><td>311 mL / min (0%)</td>

<td>Starting material + 1 gal / Mgal Zonyl FS-500</td><td>272 mL / min (-13%)</td><td>267 mL / min (-14%)</td>

<td>Starting material + 1 gal / Mgal Zonyl FSH</td><td>319 mL / min (2%)</td><td>313 mL / min (1%)</td>

<td>Starting material + 1 gal / Mgal Zonyl FSO</td><td>338 mL / min (8%)</td><td>340 mL / min (9%)</td>

<td>Starting material + 0.5 gal / Mgal Zonyl FSO</td><td>342 mL / min (9%)</td><td>333 mL / min (7%)</td>

<td>Starting material + 2 gal / Mgal Zonyl FSO</td><td>368 mL / min (17%)</td><td>370 mL / min (19%)</td>

<td>Starting material + 1 gal / Mgal FC4430</td><td>283 mL / min (-10%)</td><td>305 mL / min (-2%)</td>

<td>Starting material + 1 gal / Mgal FC4432</td><td>330 mL / min (5%)</td><td>323 mL / min (4%)</td>

<td colspan="3">+ Output Flow Rate (Percentage increase compared to Untreated) Φ Flow Rate after 24 hours (Percentage increase compared to Untreated)</td>

Table 7 compares the effect on the flow rate of 2% KCl through 0.853 / 0.422 mm (20/40) sand backfill after pretreatment with the experimental additive charge recovery agent 1, WEC / GeoSafe experimental surf-1 and Surf-3 surfactants and experimental WEC FreeFlo 1 and Free Flo 2 microemulsions. Appendix 1 was the only system that increased the flow rate through sand backfilling by over 10%. In fact, Appendix 1 was the system that gave the fastest flow speed through the sand backfill.

Table 7

<td colspan="3">Comparison of Flow Velocities Through 700 gr (20/30) Sand Backfill Columns Using Different WEC / CEOSAFE Systems for Experimental Surfactants and Microemulsions</td>

<td>Treatment</td><td>Fi (r%</td><td>F₂4(%)*</td>

<td>Starting material (2% KCl)</td><td>342 mL / min (0%)</td><td>360 mL / min (0%)</td>

<td>Starting material + 1 gal / Mgal Appendix 1</td><td>431 mL / min (26%)</td><td>454 mL / min (26%)</td>

<td>Starting material + 1 gal / Mgal Surf 1</td><td>325 mL / min (-5%)</td><td>342 mL / min (-5%)</td>

<td>Starting material + 1 gal / Mgal Surf 2</td><td>325 mL / min (0.95)</td><td>342 mL / min (0.95)</td>

<td>Starting material + 1 gal / Mgal FreeFlow-1</td><td>342 mL / min (0%)</td><td>359 mL / min (4%)</td>

<td>Starting material + 1 gal / Mgal FreeFlow-2</td><td>340 mL / min (-1%)</td><td>340 mL / min (-6%)</td>

<td>Starting material + 3 gal / Mgal FreeFlow-2</td><td>340 mL / min (-1%)</td><td>340 mL / min (-6%)</td>

<td colspan="3">+ Output Flow Rate (Percentage increase compared to Untreated) Φ Flow Rate after 24 hours (Percentage increase compared to Untreated)</td>

Figure 6 shows the results of changes in relative gas permeability as a function of the porous volume of gas injected after being impregnated with 5 porous volumes of solutions of 1 gal / Mgal WNE-348LN, Appendix 1, Zonyl® FSO and FC-4430. The first three systems were chosen because of their good performance in sand backfill, and the last additive was chosen because Fluorosurfactant used by another service company.

Compared to untreated cores, treatment with 1 gal / Mgal WNE-348LN and Appendix 1 gave higher relative permeability. Weaker effects were observed when treating the cores with Zonyl® FSO and FC-4430.

Figure 7 shows how water displacement during core tests up to 15 minutes after permeability testing was done to test the liquid flow recovery rate. In this case, much higher water recovery was observed when the cores were treated with Addendum 1 and WNE-348LN than when the cores were treated with fluorosurfactant Zonyl® FSO and FC-4430. Testing was performed after 15 minutes because it is not possible to determine the amount of liquid lost by evaporation after the first gas escape through the core without back pressure. Table 8 shows the results obtained for the contact angle and surface tension when treating Berea sandstone with Appendix 1 and WNE-348LN. In this case, it was observed that Appendix 1 had a higher effect on changing the contact angle by increasing it to 55.8 °, while WNE348LN had a higher effect on surface tension reducing it to 29.9 dynes / cm.

TABLE 8

<td colspan="3">Surface Tension WNE-348LN and Additive 1 I Contact Angle of Injected Water for Berea Sandstone when Untreated and Treated with a solution of 1% Additive 1 and WNE-348LN in 3% KCl brine</td>

<td>Berea sandstone</td><td>Contact angle (degrees)</td><td>Surface tension (dyne / cm)</td>

<td>untreated</td><td> 18.5</td><td> 72</td>

<td>Treated with Appendix 1</td><td> 55.8</td><td> 40.7</td>

<td>Treated with WNE-348LN</td><td> 30.3</td><td> 29.9</td>

With reference to Figure 8A, the contact angle diagram and the appearance of the droplets at different contact angles are shown, while Figure 8B shows the data of Table 8 with arrows indicating the desired improvement direction for contact angle and surface tension in improving gas permeability and charge recovery speed. It has been observed that the additive of the present invention acts as a coating on the surface of the formation by changing the contact angle towards the contact angle associated with a neutral value, which improves gas well cleaning by displacing the water piston with the final result of reducing water saturation and achieving higher relative gas permeability. Appendix 1 should reduce capillary pressure by increasing the contact angle to 56 ° C as observed in Berea sandstone and reducing surface tension to 40.7 dynes / cm.

With reference to Figure 9, a comparison of the relative gas permeability vs. number of porous volumes of gas for an untreated core sample, a core sample treated with 1 gal / Mgal of Appendix 1 and a core sample treated with 1 gal / Mgal of NWE-348LN microemulsion. Both systems showed improved performance compared to the untreated core, but the core treated with Appendix 1 showed significantly improved performance even with respect to microemulsions.

Referring to Figure 10, a comparison of the relative gas permeability after 15 minutes after treatment of an untreated core sample, a core sample treated with 1 gal / Mgal of Appendix 1 and a core sample treated with 1 gal / Mgal of NWE-348LN microemulsion is shown. Both systems showed close equivalent gas flow recovery compared to the untreated core sample.

With reference to Figure 11, a comparison of rheological fracturing properties using a Magnum Frac H system with 1 gal / Mgal of Appendix 1 in the NWE-348LN microemulsion fracturing fluid is shown. It has been observed that the Appendix 1 / NWE-348LN system gave higher initial viscosities, but its breaking profile is very similar to the breaking profile of the output or control system.

With reference to Figure 12, a comparison of rheological fracturing properties using a DynaFrac HT system with 1 gal / Mgal Additive 1 in NWE-348LN fracturing fluid is shown. It was observed that the Appendix 1 / NWE-348LN system behaved essentially identically to the output system or control system.

Proxy:

LAW FIRM ATTENTION 'BELLEPAT'

Izabela Szych niska-Hawranek ul Słowackiego 44 37-700 Ptzentwśl tel (016) 7u2-37-77 fax: (016) &lt;&gt; 75-02-87 mobile phone 106081503-081 e-mati <a href="mailto:tellepat@op.pl">tellepat@op.pl</a> NIP: 795-207-16-72 REGON: 1803505; 6

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